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Chapter1—Introduction

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The development of petroleum geology

The modern petroleum geologist

Some maintain that there is no such thing as 憄etroleum geology,? there is only the science of geology applied in the search for petroleum; in which case this text ought to be entitled 慓eology as applied to Petroleum?in the style of Illing (1942)! Alternatively, a contemporary title such as 慞etroleum Systems Geology? emphasizes the highly integrative nature of petroleum exploration and exploitation! However, as a title, 慞etroleum Geology? conveys a 憂o-frills, meat-and-potatoes? approach to a branch of geology that is first and foremost a commercial enterprise concerned with the exploration and economic development of petroleum!

The role of the 憄etroleum geologist? is also becoming increasingly complex and although the majority of professional geoscientists typically have a specialist skill, perhaps as a sedimentologist or stratigrapher for example, the professional geologist must also increasingly integrate traditional skills with the new, in an increasingly complex world. A 憄etroleum geologist? must have a solid understanding of historical geology and stratigraphy, structural geology, sedimentary geology, mineralogy and petrology, geophysics and an understanding of subsurface fluids, petroleum geochemistry, statistics, various aspects of engineering, a solid appreciation of economics and an understanding of local, national, and international politics. However, first and foremost one must be a geologist!

The historical development of geological concepts related to petroleum

Before 1901 In the days before 1901, 憄etroleum geologists? as such did not exist. Oil exploration theory was very rudimentary. In fact, most of the significant 憃il-finds? were discovered using the presence of natural seeps of petroleum at the Earth's surface (example: Baku or the Appalachians) or detected by various 慼ome-spun? methods! Legend has it that one fabled 憃il finder? would drill wherever his hat came off whilst riding his horse; the popular attitude that oil seemed to have no known prerequisites seemed prevalent in the nineteenth century!

In 1842, William Logan, who later became the first Director of the Geological Survey of Canada, noted the presence of seepages of oil from anticline structures in Paleozoic rocks of the Gasp? Quebec. During a subsequent survey of the 慻um beds? of Enniskillen, Ontario, soil samples were sent to Thomas Hunt for analysis. Hunt subsequently reported that the soil did indeed contained petroleum. Recognizing the association, he proposed his anticlinal theory in a publication in 1861. In that publication Hunt stated (p. 249):

揟hese wells occur along the line of a low broad anticlinal axis which runs nearly east and west through the western peninsular of Canada and brings to the surface in Enniskillen the shales and limestones of the Hamilton Group, which are there covered with a few feet of clay. The oil doubtless rises from the Corniferous Limestone, which as we have seen contains petroleum; this being lighter than the water which permeates at the same time the porous strata, rises to the higher portion of the formation, which is the crest of the anticlinal axis where the petroleum of a considerable area accumulates and slowly finds its way to the surface through vertical fissures in the overlying Hamilton shale, giving rise to the springs of the region?. Hunt (1861).

That same year E.B. Andrews published a paper describing the anticlines of southeast Ohio and Cow Creek in Virginia (Figure 1). In that publication Andrews states 搮 in broken rocks, as found along the central line of a great uplift, we meet with the largest quantity of oil? (p. 88), also adding 搮 at the anticlinal line are gas and oil springs? (p. 92) Andrews (1861).

Figure 1. Anticlinal section on Cow Creek, Virginia. Oil and gas springs occur at the crest (A)

(redrawn from Andrews, 1861).

A1

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Both Hunt and Andrews made significant steps towards defining a concept of how petroleum is retained in rock and in defining a 慻eological trap,? however their work appeared to go largely unnoticed! The exploration for oil remained primarily influenced by the thinking of the time, which relied upon the presence of natural seeps in clastic sedimentary rocks around creeks and streams. Because the writings of Hunt and Andrews had not been 憄opularized? or embodied into a formal theory, there was no systematic search for oil or the development of a ?play? and consequently many dry holes were drilled. To further complicate thinking, many early finds actually occurred within unrecognized stratigraphic traps and not anticlines! The ability of the early explorationist to unravel the complexities of the subsurface was very rudimentary, with geological data typically derived by outcrop. Because early workers had no drill core, drill cuttings, or wireline logs to guide them, correlations between wells also did not exist. With no formal theory to guide them, some felt that the best way to drill a 慸ry hole? was to employ a geologist!

After Spindletop The 1901 Spindletop discovery in Texas and the discovery of oil beneath large anticlinal structures in Kansas, Oklahoma and California, helped formalize the 慳nticlinal theory? of Hunt and Andrews. The apparent demonstrable link between economic accumulations of oil and anticlinal structures captivated the thinking of explorationists throughout North America.

In 1917, the Bolivar Coastal field in Venezuela was discovered also using the association of surface seeps, but in contrast to Spindletop the petroleum was retained in a homoclinal trap, not an anticline. Unfortunately, this discovery had little impact, especially within North America where the reliance upon surface seeps and the application of the 慳nticlinal theory? completely dominated the thinking of the day. So entrenched was the apparent demonstrable link between economic accumulations of oil and anticlinal structures, explorationists feared they were running out of prospective plays. As was documented later (Hedberg, 1971), explorationists were not running out of plays, just running out of ideas! It was time for a geological revolution in thinking; a change that led to the discovery of the great East Texas Pool in which oil and gas were discovered within a stratigraphic trap and without the presence of seeps of any kind!

The East Texas Pool and beyond No longer could the explorationist simply look for seeps and folded structures, convention after convention was set aside as explorationists dared to think out of the box. What followed was the development of petroleum geology, as we know it today, with the development and application of exploration methodologies, the formulation of trap classifications, and the systematic analysis of reservoirs. It became apparent that geologists had a significant part to play in the exploration of petroleum through their understanding of the subsurface, subsurface fluids, and the application of new exploration technologies.

In short, petroleum geology as we know it was born!

The development of an industry

Some industry 憇tatistics?

It is generally believed that there are more than 6,500 drilling rigs of varying size and depth rating currently available or in use. More than 3.7 million wells have been drilled globally within the last 100 years and on average, approximately 12 ? 107 meters of hole is drilled per year. However, the success rate (i.e., commercial viability) for 憌ildcat? or new wells is approximately 10%. There are approximately 18,000 producing oil fields in the USA, more than 3,000 in the former CIS, 1,000 in Canada, more than 1,000 throughout Europe (including the North Sea), more than 2,000 in Australia and Asia, but less than 150 in the Middle East. The largest single oil field in the world, the Ghwahar, occurs in the Middle East, and a 憈ypical? oil well in the Middle East produces more than 103 m3 of oil per day. This is in stark contrast to the 慳verage? North American well that produces approximately 3 m3 per day. Approximately 70% of all North American wells yield less than 1.6 m3 (10 barrels) per day!

The member countries of OPEC (Organization of Oil Exporting Countries) currently produce more than 75% of the world抯 oil, with Saudi Arabia, Iran, Iraq, and Kuwait producing over 50% of the world抯 total. The countries of the Middle East (e.g., Saudi Arabia, Kuwait, Iran, Iraq, and Kuwait) hold approximately 64% of all known recoverable oil reserves (Figure 2), which is estimated to be 673.9 billion barrels. In contrast, South America has 9% (89.5 billion barrels), North America 8% (85.1 billion barrels), Africa 7% (75 billion barrels), Eastern Europe (incl. Russia and Ukraine) 6% (64.7 billion barrels), Asia and Australasia 4% (43 billion barrels), and Western Europe about 2% of the current known recoverable oil reserves. The current distribution of natural gas is quite different; the United States,



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Global distribution of conventional oil

Middle East

64%

Africa

7%

Western

Europe

2%South America

9%North America

8%

Eastern Europe

6%

Asia &

Australasia

4%

Global distribution of natural gas

S America

4%

N America6%

Western Europe

4%

Africa

7%

Middle East

34%

Eastern

Europe

38%

Asia &

Australasia

7%

Canada, Algeria, Saudi Arabia, and Iran, plus countries of Eastern Europe hold 75% of all known gas reserves, of which Iran and Eastern Europe hold 40% of the total (IEA, 2004).

Figure 2. The known (2004) global distribution of oil (left) and natural gas (right) per geographic region

(Data source: IEA, 2004: http://www.iea.org/Textbase/stats/index.asp).

The historical context of the petroleum industry

Early beginningsReferences to petroleum (i.e., pitch) exist within the Bible, in the works of Confucius (c. 600 BC), and Herodotus (c. 450 BC). Tar and pitch were obtained from natural seeps, such as those within the Middle East, and used as an illuminant, to waterproof boats and water containers, and very effectively used in warfare. By about 600 BC hand dug pits in China were created for the extraction of oil and, due to a steady development in technology, Chinese drilling tools had reached the unprecedented depth of 1,000 m by 1132 AD. By 1800 AD, the Yenangyaung oil field had more than 500 wells producing about 35,350 cubic meters (216,000 bbl) of oil per year. In contrast, the first European oil well was spudded at Pechelbronn (France) in 1745, and wells were successfully completed as oil producers in North America at Oil Springs (Ontario, Canada) and at Oil Creek (Pennsylvania, U. S.A). in 1859 (Brantley, 1971; Beaudrow et al., 2001).

The birth of a market Prior to the middle of the nineteenth century there was little need for oil due to the availability and use of other abundant materials, such as wood, coal and charcoal for heat and refined whale oil as an illuminant. Industrial production was fueled by coal. Coal was extensively used to raise steam to drive both industrial machinery and locomotives. Coal was plentiful, cheap, and reliable and coal was king! Throughout Europe and North America, the preferred domestic illuminant was kerosene, which was refined from whale oil. Whale oil was very easy to refine. However, during the nineteenth century a rapid increase in population and the continued urbanization of both Europe and North America led to an unprecedented increase in the demand for kerosene, which increased the demand for whale oil, which was in short supply. This in turn drove up the price of kerosene, prompting a search for a new and cheaper source of kerosene.

In 1854, Dr. A. Gesner, who was both a geologist and chemist, developed a process that could generate kerosene from coal; the word kerosene is derived from keros, the Greek word for wax. Because coal was very abundant and a cheap resource, coal rapidly replaced whale oil as the raw material for kerosene. As the popularity of kerosene increased, the search for a cheaper raw material continued. It was soon discovered that crude oil was a better raw material for kerosene, because it was both cheaper and easier to refine, although sources of crude oil were, at that time, limited. Therefore, new sources of crude oil were sought in North America, Europe, Russia, and Asia. This was the beginning for the 憃il industry.?

Development and expansion In 1858, James Miller Williams began drilling at Oil Springs, Ontario, Canada. Initially drilling for water, he struck oil at a depth of 14 feet; the well was subsequently completed in August 1859 (Beaudrow et al., 2001). The first intentionally drilled oil exploration well was drilled by 揢ncle Billy? Smith and his sons, at Oil Creek in Pennsylvania, United States, in 1859, led by 慍olonel? Drake. Drake抯 well was completed also in August 1859 at a depth of 69 feet (Brantley, 1971). Both wells were drilled using percussive cable drilling rigs, which was a rather slow and a potentially dangerous process because the rigs lacked the safety features common on modern drilling systems. However, within a year of the discovery of oil at Oil Creek, oil mania had struck and dozens of rigs were drilling wells in Pennsylvania.



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Imperial Russia was not far behind. Capitalizing on the vast natural oil pits at Baku, Russia was able to produce by 1870 27,500 cubic meters (168,000 bbl) of oil per year. Expansion of the industry was rapid in both Russia and the USA, and by 1871, 687,300 cubic meters (42,000,000 bbl) of oil per year (91% world production) was coming from the oil fields of Pennsylvania. Due to limited domestic demand and fierce competition from the Standard Oil Co., the Canadian industry languished and eventually perished. This was not the case in Russia. The Swedish Nobel Brothers rapidly developed the Russian oil industry with capital investment, technology, and the adoption of modern refining techniques, and by 1890 the annual production at Baku was more than 3,900,000 cubic meters (240,000,000 bbl) of oil per year, equaling the production of the United States (Brantley, 1971; Yergin, 1993).

Many significant events took place at the dawn of the twentieth century; perhaps the most significant of which was the invention of the internal combustion engine and the development of the automobile. Oil companies, such as Standard Oil, became 憊ertically integrated,? through the control of exploration, exploitation, production, and distribution. With the creation of companies like Royal Dutch Shell, the oil industry also became an international enterprise.

The emergence of the 慚 ultinationals?The First World War was a true milestone for petroleum, especially concerning the economic and strategic importance of oil and gasoline. The First World War was the first mechanized war fought on a global scale. The rapid development of the car, the truck, armaments (e.g., the tank), and the airplane, all of which relied heavily on petroleum and derivatives, increased demand for oil and drove the economic fortunes of the oil industry. Those four years very rapidly transformed the oil industry and the way in which governments viewed oil, with governments realizing that in addition to its commercial importance, oil also had a strategic importance (Yergin, 1993).

Following the First World War and the break-up of the Standard Oil Company, the global exploration, production, and distribution of petroleum was dominated by seven large international corporations: British Petroleum, Royal Dutch Shell, Esso (Exxon), Gulf, Texaco, Mobil, and Socal (Chevron). These companies acquired true 憁ultinational? status during the 1920s and 1930s through their various overseas operations. Exploration within North America continued, but was often overshadowed by the exploration and development of the oil fields of North Africa, the Middle East, Asia, and South America. With the creation of Corporate Centers and the establishment of Regional Centers of Operation within each foreign country, a complex network of corporate dependency was born that is still with us today! The formation of Aramco (Arabian-American Oil Co.) from Socal, Texaco, Mobil, and Exxon in the 1930s is significant because it gave both multinational corporations and the countries of the west a long-standing interest in the affairs of the Middle East, an interest that is still in evidence today.

The post-war period from the 1950s through to the mid 1980s was an era notable for several new developments. Exploration of many high-risk areas, such as the Alaskan Shelf, the North Sea, the East Coast of Canada, and the Gulf of Mexico for example all occurred during that time. Explorationists drilled deeper wells, drilled offshore in ever-increasing water depths, drilled highly geopressured formations, drilled deviated wells, employed enhanced recovery techniques, and drilled many high-risk wells that would have previously deemed unthinkable (e.g., Arctic). Wells were drilled often with very long periods of development between discovery and 慺irst oil.? The reason was, in part, due to the establishment and activities of OPEC.

OPECOPEC (Organization of Petroleum Exporting Countries) was founded in 1960 at Baghdad and initially comprised of Iraq, Iran, Kuwait, Saudi Arabia, and Venezuela. However, OPEC was subsequently expanded to include Algeria, Dubai, Ecuador, Gabon, Indonesia, Libya, Nigeria, Qatar, and the United Arab Emirates. The criteria for membership was, and remains, that the exportation of crude oil is the main source of revenue for a potential member state, thereby excluding the U.S.A., Russia, the Ukraine, and Mexico!

OPEC抯 primary objective was the appropriation of 憂ational? assets and to control the price of crude oil to the advantage of member countries, whose predominant revenue was derived from the exportation of oil! Probably the most significant achievement of OPEC was, and remains, the control of individual members via production quotas and price stabilization. Cash-strapped member states have often threatened in the past to increase their individual output, thereby seeking to increase their own revenues. But the threat and ability of Saudi Arabia to flood the market with oil with the subsequent depression of the price of oil has held most member countries to line. Production quotas and the maintenance of the price of oil were two of OPEC抯 successes during the 1970s. Several wars in the Middle East, and an increase in demand for oil in the west, helped increase the price of oil. Of course that spurred the exploration of 慼igh risk杊igh cost? areas, like the North Sea, and the rapid development of many oil fields that are beyond OPEC抯 immediate influence. This was to perhaps lessen the influence of OPEC, but not destroy it since the constant demand for oil within developed countries means a continued dependency on OPEC derived oil!



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Into the future

Some geologists are of the opinion that there will be little in the way of new 慴ig? finds, suggesting that plays will probably become more elusive, smaller, more challenging, and more expensive with a higher element of risk! There will most certainly be an increase in the application of enhanced recovery techniques, especially in known or marginal fields by a variety of methods. Reservoir engineering and reservoir geology will become increasingly important as companies attempt to maximize their production. Dilling techniques, such as horizontal drilling, will come into greater use, especially since this form of exploitation/development increases the profitability of marginal pools. Already the industry has shown signs of diversification! Many companies are now involved in activities other than the exploration of conventional crude oil. The active exploration for natural gas began in the 1950s and 1960s, but in recent years has steadily gained a renewed level of importance, which now includes shale gas, coal bed methane, and enhanced coal bed methane development and the exploration of biogenenic gas pools. Other ancillary activities include energy diversification beyond petroleum, such as the research and pilot testing of CO2 sequestration into the earth and oceans.

The recent discoveries of gas hydrates off the western and northern coasts of North America and the development of deep gas plays off the Continental Shelf of Brazil and North America challenge us to constantly think outside the box. Perhaps more typically, we will re-evaluate old oil and gas fields using enhanced data management systems (Video 1), and new technology such as virtual reality (Video 2) to find passed-over oil or gas. Of all the activities related to the exploration and exploitation of natural gas, perhaps enhanced coal-bed methane will be the most sustainable activity in the near future! An examination of the global distribution of natural gas and the global distribution of coal reveal a telling story (Figure 3). The countries of Eastern Europe and the Middle East both account for more than 70% of all currently known reserves of natural gas. Eastern Europe has both a distribution system and a market close to hand (Western Europe) and the Middle East has only recently begun to export liquefied natural gas, predominantly to Asia. However, the greatest demand for natural gas occurs perhaps not in Europe or Japan but within North America, which has only 6% of the world抯 share in natural gas but 26% of the world抯 known coal reserves. This is reflected in coal-bed methane research and development, which is at a more advanced state within North America than anywhere else in the world (IEA, 2004).

There are many uncertainties and unknowns for the future. What will be the role of OPEC in the future? Will revenues diminish in the face of the Kyoto Accord? Will the demand by western countries and the rapid industrialization of China keep prices high? What will be the role of non-OPEC oil-producing countries and their state-owned companies? Will those companies spearhead new initiatives or be reduced to ineffectual industrial liabilities? How will rising prices affect the economies of the west? Will Governments be able to maintain the high level of taxation of gasoline and gas? Will the west experience yet

Global distribution of coalNorth

America

26%

Eastern

Europe

23%

South

America

1%

Western

Europe

12%

Middle East

0.2%

Africa

7%

Asia &

Australasia

31%

Global distribution of natural gas

S America

4%

N America

6%

Western

Europe

4%

Africa

7%

Middle East34%

Eastern Europe

38%

Asia &

Australasia7%

Figure 3. The global distribution of coal and natural gas by geographical region (Data source: IEA, 2004; http://www.iea.org/Textbase/stats/index.asp).

Video 1. Data management systems. From 揟 he Making of Oil,? (? 1997 Schlumberger, Ltd. used with permission).

Video 2. A virtual reality view of the subsurface. From 揟 he Making of Oil,? (? 1997 Schlumberger, Ltd. used with permission).



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another oil-induced recession, or will the high price of oil spur the development of energy alternatives. These are important questions especially with government deficits rising. How will the major multi-national companies operate in the next century? Will it be amalgamation, diversification, increased development, or extinction as new technologies are developed and evolve? Do recent or past trends give some indication? One thing is certain, the 21st Century will not be a repeat of the 20th Century.

The economics and business of oil

Economics

Profit/loss The economic viability of any oil or gas company can be simply expressed by the following equation (Rose and Thompson, 1992):

Profit (or loss) = Revenue ? Costs (1)

However, the reality of modern business practice renders this simple equation inadequate. For example, the existence of multiple levels of taxation and varying types of taxation, complex tax provisions (i.e., write-offs), and modern accounting methods complicate the financial side of the business. Oil companies are also significant employers of skilled personnel and for all employers there are variable overheads and maintenance costs to meet, which typically rise with time. Furthermore, modern petroleum ventures typically involve the long-term investment of capital many years before the generation of revenue, and probably longer before the generation of profit (Figure 4).

Profits are not received like lottery-ticket windfalls, in a lump sum, or even in predictable installments! The price of oil is determined by 憁arket forces? andis highly variable. However, the moment in time when ventures start to generate a profit depends upon many factors. Generally, onshore oil or gas wells begin to generate profit within a year; offshore the duration can vary from 3 to 4 years or more. Unlike onshore production, offshore exploration wells are typically not used for production. Production is controlled via substantial purpose-built production platforms, which delays 'first oil' and increases the capital investment. As the two curves in Figure 4 convey, all successful ventures require capital at the onset (hence, negative cash-flow) but should, in time, be cash generating (positive cash-flow).

Net revenue interest

In reality, producers pay 100% of the costs, but receive a reduced proportion (e.g., 70 to 85%) of the revenue from production, which is known as the net revenue interest (NRI).

Profit/loss = [(NRI x reserves x wellhead price) - wellhead taxes - operating costs - govt. taxes - investment]

Within this equation there is uncertainty concerning all of the factors except the NRI. Such uncertainties include or could relate to:

Reserves: e.g., revised subsurface interpretations, premature 憌atering-out?

Wellhead price: e.g., the price of oil is highly variable (e.g., crash of 1986)

Wellhead taxes: e.g., politics and royalties driven by the perception of profit

Operating costs: e.g., cost of infrastructure and recovery costs

Government taxes: e.g., a change in fiscal policy due to change in government

Investment: e.g., loan repayment terms

Force Majauer e.g., war or natural disaster

Figure 4. Example cash-flow streams for two hypothetical wells:

onshore (-----) and offshore (-----). NCF = net cash flow. Note the

time difference at which profits are received.



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It is the collective responsibility of all professionals to estimate accurately the magnitude of reserves, production rates, and costs, and to reduce the level of uncertainty (i.e., risk). Estimates and uncertainty levels must be conveyed to upper management accurately and with a degree of consistency because capital budgeting and the exploration of an oil/gas prospect is a long-term commitment. This is especially true in the case of large offshore prospects, in which case the time between discovery and the production of 慺irst-oil? (i.e., revenue generating) can be considerable. For example, the Hibernia oil field off the East Coast of Canada was initially discovered in 1979? 980 but the development of the field required the commitment of many large corporations throughout a period of 15 years and the investment of hundreds of millions of dollars. The decision to continue with any play is constantly monitored (Figure 5) and always subject to numerous levels of scrutiny. New prospects are typically supported by established production. It should also be apparent that producing wells should not only support their own costs and overheads of the operating oil company but also provide revenue to support ongoing capital- intensive exploration programs. Each oil or gas production unit goes through a 憀ife cycle? (Jahn et al., 1998) and skillful managers will seek to overlap the life cycle of each production unit, using the revenue of existing mature fields to support new prospects.

The life cycle of an oil or gas field

Introduction As discussed in the previous section, exploration geologists have been searching for oil for more than a century. Unlike the early part of the 20th Century, when the time between discovery and 慺irst oil? may have been short, the development of some oil and gas fields have lead times of 10? 0 years or more. Furthermore, the period during which the revenue of a producing unit attains a maximal 憄lateau? (Figure 6) varies considerably. For example, the oil and gas fields of the North Sea, which have been producing for some 25 to 30 years, may go into decline in the near future. There are some fields, such as those within the Williston Basin and those in Texas, that would have been in serious decline were it not for the recent injection of capital and the utilization of new tertiary recovery methods. Like many natural phenomenon, oil and gas fields have a 憀ife cycle.? If prospective, they are initiated, production grows (youth), eventually reaches a plateau (matures), subsequently declines (old age), and they are subsequently decommissioned (Figure 6).

The exploration phase Exploration remains a high-risk venture, despite the development of excellent tools, such as 3-D Seismic and a growing wealth of information. Why? Simply because plays are becoming increasingly subtle, expensive, or smaller. If we include unknowns such as a volatile stock market, politics, complex tax and environmental regulations, the decision to develop a play remains solidly a business decision. The play must have the potential for commercial success. Ideas have to be worked, from initial inception through to prospect evaluation, supported by fieldwork (if possible) and various subsurface reconnaissance

Figure 5. A hypothetical sequence of posible activities and business decisions during the evolution of an exploration play (after Jahn et al., 1998; with permission from Elsevier).

Figure 6. A graphical representation of the 慞roduction Phase?within the Life Cycle and Business Model for a hypothetical oil orgas field (after Jahn et al., 1998; with permission from Elsevier).



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(geophysical) techniques. The acquisition of seismic is costly, especially offshore where projects and rising costs can easily spiral out of control. The culmination of the exploration phase is the commitment, by management, to the drilling of the very first well, which in an unproven area is known as the 憌ildcat well.?

Appraisal phase Once the initial well has been drilled, logged and tested, a decision must be made. If the well is non-productive or water wet the question must be asked, should both the well and play be abandoned? Or, is a second well justified in the light of new geological information if the seismic data has been re-interpreted. If potential is still perceived, is the risk so great that partners must be found?

Alternatively, if hydrocarbons are encountered, the process of evaluation may intensify because the potential of the discovery must be quickly determined. If hydrocarbons are encountered and the prospects look good, management must decide to:

Immediately proceed with (early) development and hasten the onset of 慺irst oil?and early revenue,

or

conduct an appraisal program and delay revenue generation.

Early development The early development and 慺irst oil? generates income within a short period of time; however, the production and distribution facilities (i.e., infrastructure) may, in time, be inadequate if at some later date the eventual field becomes much larger than initially thought. This situation limits the production and can affect the ultimate profitability of the field.

Appraisal program In contrast, the appraisal program may delay the onset of 慺irst oil,?but may be technologically superior and lengthen the life span of the field. Appraisal is more concerned with reducing uncertainties,rather than finding more oil or gas! However, even during production, appraisal is on-going and the viability of the field is constantly monitored (Video 3). For example, many low production wells (less than 1.5 m3 per day) in North America are sub-economic when the price of oil goes below $12 per barrel. Also, woe is the company that hastens a project that requires oil at $27 per barrel, then once 慺irst oil? comes on stream the price drops to $15 barrel!

Also during the appraisal the economic viability of the field must be evaluated! There must be a market, either in place or in development, to justify production. The need for infrastructure to facilitate the development of the field must be planned, which if not already in place must be factored into the overall cost of development. For example, it is unlikely that the gas fields of the North Sea or the Canadian Scotian Shelf would have been developed for a small local market of 1 to 2 million people. The proximity of the United Kingdom and Europe easily justified the development of the North Sea, and similarly the presence of the U.S. eastern seaboard creates a huge potential market for the Scotian Shelf gas fields!

Development planning Depending upon the outcome of the 慳ppraisal phase? and associated 慺easibility studies,? if the field is economically viable a development plan will be formulated. The principle goal at this stage is to determine the optimum (i.e., most cost-effective) means of exploiting the field. This includes the subsurface optimization for effective drainage and the necessary surface facilities required for distribution. The culmination of this activity may be the creation of a Field Development Plan and Budget. Once the Field Development Plan and Budget are in place the facilities have to be designed, constructed, installed, and commissioned.

Production phase The commercial production of 慺irst oil? through the wellhead marks the beginning of the production phase. Economically, this is an important point in the life-cycle of the field, since revenue is now being generated that can be used to pay back investors, or fund other new projects. Every business plan seeks to minimize the time between discovery and 慺irst oil.?

Video 3. Appraisal. From 揟 he Making of Oil,? (?1997 Schlumberger, Ltd. used with permission).



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Production is largely controlled by reservoir characteristics, the means of recovery, and infrastructure. All this is embodied in a Production Profile, which outlines the facilities required, the number of wells required for effective drainage, and their phasing during production. Maintenance of the field is also a significant part of the production profile. There are three components to the production phase.

Build-up Recently drilled producing wells are brought on stream.

Plateau Older wells begin to decline while new wells are brought on stream. Production is at a constant rate.

Decline This is the final component of production, during which revenue from all producing wells gradually declines.

Decommissioning phase Once the net cash flow of a field turns permanently negative, the field no longer remains economically viable and must be decommissioned. This point in the life cycle occurs when the gross income from the field no longer covers operating costs plus royalties and taxes. There are many examples in Texas and the Williston Basin, however, where fields or wells that had produced during the 1950s and 1960s and subsequently decommissioned, regained life through the application of horizontal drilling, the use of surfactants and more recently, the application of CO2 injection techniques. This example illustrates one of the possible management decisions that must occur at this point. Should the well or field be abandoned (hence decommissioned) or can enhanced recovery techniques prolong profitability. This decision will, again, be driven by economics; the capital costs of enhanced recovery versus the price of oil! For offshore fields (e.g., Norwegian Arctic) the costs may be too great, whereas onshore (e.g., Texas) the costs are significantly less.

Decommissioning costs will also vary depending upon local and national (or international when offshore) legislation and environmental concerns. It is unacceptable to simply abandon a field and facilities, typically wells have to be 慿illed? and sealed and all surface facilities removed. This final phase incurs costs with no revenue from the field. The field has become a financial liability.

References

Andrews, E. B., 1861, Rock oil, its geological relations and distribution: Am. J. Sci., ser. 2, v. 32, p. 85-93.

Atkinson, N., 2004, The International Crude Oil Market Handbook: Energy Intelligence Research (online): http://www.energyintel.com/Research.asp.

Beaudrow, A., J. Piitz, and T. Auranen, 2001, Black gold: Canada抯 oil heritage, Canada抯 Digital Collections, Industry Canada: http://collections.ic.gc.ca/blackgold.

Brantly, J. E., 1971, History of oil well drilling, Gulf Publishing Co., Houston, Texas, 1525 p.

Hedberg, H. D., 1971, Petroleum and progress in geology, 24th William Smith Lecture: J. Geol. Soc. London v. 127, p. 3-16.

Hunt, T. S., 1861, Notes on the history of petroleum or rock oil: Canadian Naturalist, v. 6, p. 241-255.

Illing, V. C., 1942, Geology applied to petroleum: Proc. Geol. Assoc., v. 53, p. 156-187.

International Energy Agency (IEA), 2004, Oil information: IEA Statistics, International Energy Agency, London, 734 p., IEA statistics online: http://www.iea.org/dbtw-wpd/Textbase/stats/oilresult.asp.

Jahn, F., M. Cook, and M. Graham, 1998, Hydrocarbon exploration and production: Elsevier, Amsterdam, 384 p.

Rose, P. R., and R. S. Thompson, 1992, Part 2. Economics and risk assessment in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, AAPG, p. 23-56.

Schlumberger, 1997, 揟he Making of Oil, Plankton to Production:? Schlumberger Limited, Sugarland, Texas.

Yergin, D., 1993, The Prize: The Epic Quest for Oil, Money, and Power: Touchstone Books, 880 p.


Chapter 2—Petroleum: Composition and Characterization

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Composition

Elemental composition

The word petroleum is derived by combining the Latin words petra and oleum, which mean rock and oil respectively. Petroleum, like the source material kerogen, is predominantly comprised of organic compounds containing principally the elements hydrogen and carbon. Table 1 shows the approximate elemental composition for natural gas, oil, asphalt, different kerogen types, and two coals. Note that the relative proportion of carbon and hydrogen is greater for gas and oil as compared to kerogen, and that the relative proportion of oxygen decreases as the hydrogen content increases! The most fundamental characteristic of kerogen is hydrogen content! A high hydrogen-bearing kerogen (e.g., 10 wt. %) has a greater potential to generate oil and gas than kerogen with a low-hydrogen content (e.g., 4 wt. % hydrogen). Also because hydrogen is the lightest element, oils with higher hydrogen content have a lower specific gravity. The significance of specific gravity as a means of characterizing crude oil is discussed later.

Molecular composition

Hydrocarbon and non-hydrocarbon Petroleum contains a wide variety of molecular structures and compounds; the smallest molecule is methane (molecular weight = 16) and the largest are the asphaltene compounds (m.w. 1,000 +). Between these two extremes are hundreds of molecular structures and compounds that are grouped depending upon structural form, chemical affinity, chemical and physical properties, and means of isolation (Figure 7). For example the alkane group, comprised of open-chained molecules with single bonds between each carbon atom, form a homologous series that can be readily separated from oil using liquid chromatography. The unifying feature for all hydrocarbon groups is the presence of an atomic skeleton comprised of carbon plus hydrogen. However, if the molecular structure contains elements other than carbon and hydrogen (e.g., oxygen) then that compound is a non-hydrocarbon because it contains a heteroatom.Such structures are informally known as NSO抯 if they contain the elements nitrogen, sulfur and

Figure 7. Fractions within crude oil (from Tissot and Welte, 1984;reprinted with kind permission of Springer Science and Business Media).

Table 1. Approximate elemental composition (in wt. %) of selected organic matter (after Hunt, 1979, 1996).

Element Gas Oil Asphalt Kerogen (immature) Coal

Type I Type II Type II Lignite Bituminous

Carbon 76.0 84.5 84.0 76.0 72.6 72.7 68.0 83.0 Hydrogen 24.0 13.0 10.0 9.4 7.9 6.0 5.0 5.0 Oxygen 0.0 0.5 2.0 8.8 12.4 19.0 22.0 8.0 Sulfur 0.0 1.5 3.0 3.8 4.9 0.0 2.0 2.0 Nitrogen 0.0 0.5 1.0 2.0 2.1 2.3 2.5 1.0 (Trace elements) 0.0 0.0 0.1 0.5 0.0 0.1 0.0 h i g h l y v a r i a b l e



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oxygen (NSO) within their molecular structure. The presence of NSO-bearing molecular structures within a crude oil can be very significant because NSO-structures can determine the character and reactivity of a crude oil. Typically NSO-bearing compounds are associated with heavy crude oils and oils of high specific gravity and low API gravity (e.g., 10 to 15 API? . Some NSO-bearing structures, such as the resins and asphaltenes, have a very high molecular weight (e.g., m.w. = 600+) and can account for 10 to 40% of all compounds within some heavy, degraded crude oils.

Some crude oils, such as the Boscan crude from Venezuela, contain metal elements (Figure 8) such as vanadium (V), nickel (Ni) and iron (Fe). Metal elements are typically incorporated as metal chelate complexes, which are molecular structures that contain a trace element surrounded by a closed ring or a hydrocarbon framework (e.g., porphyrin). Because many trace elements have an undesirable catalytic potential in fuels and during late stage refining process; they are removed during the refining or upgrading process.

Generally, as the relative proportion of resins and asphaltenes (i.e., NSO-bearing compounds) increase within a crude oil, so the proportion of trace elements increases. Metal and trace element content is invariably the highest in naturally degraded oils (e.g., Venezeula抯 Boscan crude and the heavy oils of Alberta and Saskatchewan, Canada). However, the presence of certain trace elements (e.g., vanadium) can enhance the economic worth of a given crude, if the trace element(s) can be economically recovered!

Saturated hydrocarbons

Alkanes (paraffins)

Hydrocarbons that have a carbon skeleton in which carbon is bound to other atoms of carbon or hydrogen by single bonds are saturated compounds and commonly known as alkanes, saturated hydrocarbons, or paraffins. If the carbon skeleton is arranged linearly then the structure is a normal alkane (nalkane). If there are branches subtending from the main structure, then the structure is an isomer and known as a branched alkane or iso-alkane. All alkanes have the empirical formula CnH2 n+2. The first four members of the alkane group (methane, ethane, propane, and butane) are gases, whereas compounds above C16H34 are solid at STP (Standard Temperature and Pressure1). Alkanes are insoluble in water but soluble in organic solvents such as chloroform and benzene. There are various ways of reporting alkanes. Alkanes can be referred to by their name or by reference to the number of carbon atoms within the structure, for example: the compound C4H10 which is normalButane, can be reported as nButane, as C4H10, or simply as C4. Generally, for compounds of small molecular size we typically use the name (e.g., methane), whereas the larger compounds (e.g., hexadecane) are often referred to using their carbon number (e.g., C16). There are also a number of ways of graphically showing the spatial arrangement of the carbon and hydrogen atoms within a given alkane. To go to an example click on the following link (alkane).

Isomers

Isomers are alkanes that have the same empirical formula as their normal alkane counterparts, but have molecular branches. As molecular size increases, so does the number of possible molecular variants, each differing in the spatial arrangement of their branches. For example, Butane (C4) has only one isomer, Pentane (C5) has three, Heptane (C7) has nine and C30 has an unbelievable 4,000,000,000 + isomers! The terminology for naming isomers has changed throughout the last few years and an example is given that follows the (new) UPAC convention (isomer).

1

STP = 760 mm Hg or 101 kPa, 60oF or 15.6oC

Figure 8. A cross-plot of Ni vs. V contained within numerous crude oils (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).



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Cyclic alkanes (naphthenes)

Naphthenic hydrocarbons represent one of most common constituents of conventional crude oil. Naphthenic hydrocarbons are saturated ring-based structures and have 2 hydrogen atoms less than straight chain nalkanes equivalents (e.g., cyclopentane, Figure 9) and have an empirical formula of CnH2n. Naphthenic compounds consists of rings of either 6 or 5 bonded carbon atoms and typically the number of rings within a structure increases with an increase in carbon number as illustrated in Figure 9.

The naphthenes shown in Figure 9, appear as flat two-dimensional structures; in reality such structures are not flat. The spatial arrangement (i.e., stereochemistry) of ring-based structures is extensively used by petroleum geochemists to identify and recognize 憃il families,? conduct oil to source correlations, derive the maturity of oils, and determine the origin and depositional environment of reservoired oils. The hydrocarbons that are used in this way are collectively known as biomarkers or geochemical fossils and the form of analysis is generally known as biomarker analysis (Peters and Moldowan, 1993; Peters

et al., 2004).

Unsaturated hydrocarbons

AlkenesAlthough alkenes can be generated during laboratory pyrolysis experiments, straight chain unsaturated hydrocarbons are rare in nature partly because they are very reactive. They will not be discussed further.

Aromatics Carbon is capable of forming compounds by bonding to other carbon atoms. Aromatic hydrocarbons are molecular structures consisting of six-member rings of carbon, bearing alternate double and single bonds. The double bonds are very stable, and the basic structure of this compound class is the benzene ring, which has a general formula CnHn. Since the exact location of the double bonds within an aromatic structure are unknown for a given instant in time, a circle within the six-member ring is often used to represent the presence of double bonds (Figure 10). Aromatic hydrocarbons are liquid at STP and often occur as relatively minor constituents within light oils, but generally increase in abundance with decreasing 癆PI. Aromatic compounds of increasing structural complexity are typically and informally grouped according to the number of aromatic rings within a given structure consisting of mono-aromatics (single ring), di-aromatics (two), tri-aromatics (three) up to, and including, polycyclic-aromatic. The structure in Figure 11 is the di-aromatic compound C19 Alkyltetrahydro-phenanthrene.

Figure 9. Example Napthenic compounds.

Figure 10. Three 2-dimensional alternative methods of portraying benzene.

Figure 11. A di-aromatic (alkyltetrahydro-phenanthrene).



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Physical states of petroleum

Introduction

Petroleum is a complex mixture of various compounds; in the previous section we examined the chemical nature of those compounds according to molecular group. In this section, the various constituents of petroleum will be examined according to their physical state; i.e., either gaseous, liquid, or ?plastic?states at STP.

Gas

Natural gas at the wellhead may include both hydrocarbon and non-hydrocarbon gases; such as nitrogen, carbon dioxide, and hydrogen sulfide. Hydrocarbon gases are gases that do not condense at 20oC and at atmospheric pressure (Patm), such as methane (C1), ethane (C2), propane (C3) through to n-butane (nC4), see Table 2.

Dry gas is a natural gas, comprised predominantly of methane (i.e., methane = 96% +), or where the C2:C1 ratio is greater than 10-6:1. If the proportion of ethane exceeds 4 to 5% of the natural gas total, then the natural gas is called wet gas. At the earth抯 surface, where pressures and temperatures are significantly lower than those encountered in the reservoir, low molecular weight gases (i.e., C5 to C7) may condense, forming a liquid known as condensate. Condensates typically have API gravities that range between 45? to 62? and vary in color from clear to yellow or whitish-blue!

These gases should not be confused with other gas liquids such as Liquefied Natural Gas (LNG), which is methane liquefied at -160? C and Patm, andLiquefied Petroleum Gases (LPG) which is liquefied propane or butane. LNG and LPG are refinery and industrial products, whereas condensate and wet gas are complex mixtures of natural gas in the natural state.

慡olid gases? can also occur when a gas (e.g., methane) is both water wet and frozen. Gas hydrates (Figure 12) form via clathration when gas molecules such as methane, ethane, or iso-butane become entrapped within the lattice-like structure of ice. Approximately 1.0 m3 of gas hydrate may hold 50 to 170 m3 of natural gas, making gas hydrates very prospective!

Liquid and 憄lastic?states

LiquidThis of course includes crude oils. Crude oil has been defined (SPE/WPC/AAPG/SPEE, 2006, p. 46) as 搮 thatportion of petroleum that exists in the liquid phase in natural underground reservoirs and remains liquid at atmospheric conditions of pressure and temperature,? noting also that crude oil may include small amounts of non-hydrocarbon. There is a wide variety of crude oils, that exhibit a range of specific gravities, sulfur content, pour point, cloud point, and molecular composition; we will examine these characteristics in a following section.

Figure 12. Samples of gas hydrate readily burn with a yellow-orange flame (image courtesy of NOAA): http://www.oceanexplorer.noaa.gov.

Table 2. Significant data of low molecular weight hydrocarbons (after Hunt, 1979, 1996; Tissot and Welte, 1984; and others).

Name Formula Mol. wt. Boiling point Solubility (癈 Patm) (g 10? g water)

Methane CH4 16.04 -162 24.4

Ethane C2H6 30.07 -89 60.4

Propane C3H8 44.09 -42 62.4

Isobutane C4H10 58.12 -12 48.9

n-Butane C4H10 58.12 -1 61.4

Isopentane C5H12 72.15 30 47.8



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Plastic statePetroleum in the plastic to solid state includes a variety of high molecular weight substances generally known as bitumen, asphalt, and resin. Bitumen is a broad class of natural substances that exhibit a great deal of compositional variation and as a consequence vary in their 慼ardness? and degree of volatility. Bitumen is composed principally of hydrocarbons, but also contains a variable amount of non-hydrocarbon (i.e., NSO) compounds. Bitumen can also be a solid, plastic, or semi-liquid at STP. Bitumen is often considered as a compositional intermediate between crude oil and kerogen and is typically associated with kerogen and petroleum generation. Pyrobitumen is a specific type of bitumen and has many examples, such as Albertite, Wurtzilite, and Impsonite. Pyrobitumens are often hard, solid, and possess a molecular structure that is polycyclic and highly graphitic (Figure 13), that is they have a discernible molecular order that is detectable by X-ray diffraction and create an optical texture in crossed polarized reflected white light microscopy.

Resins represent a residuum that is insoluble in liquid propane but soluble in n-pentane, whereas asphaltenes are natural substances defined on the basis of solubility and represent a class of compounds that are soluble in carbon disulfide but insoluble in chilled n-pentane. Asphaltenes have a very high molecular weight and are agglomerations of molecules containing condensed aromatic and naphthenic rings linked by alkanes (paraffins). The 憄recipitation? of asphaltenes during the production of heavy or degraded oil is a common problem.

Finally, do not confuse bitumen, asphaltenes, or resins with refinery by-products such as asphalt, which includes either straight-run residues or the oxidation products of crude oil residuum. Asphalt typically contains heavy oils, resins, asphaltenes, and other high-molecular-weight waxes.

The classification of crude oil

The need to classify

During processing, petroleum may yield a range of distillate hydrocarbon groups, which may include: gasoline and naphtha, containing 4 to 10 carbon atoms; kerosene and illuminating oils, with 11 to 13 carbon atoms; diesel and light gas oils, containing 14 to 18 carbon atoms; heavy gas oils, home heating oils, with 19 to 25 carbon atoms; lubricating oils, containing 26 to 40 carbon atoms; and residual heavy fuel oils, with 40 or more carbon atoms (Hunt, 1996).

The composition and character of crude oil can and does vary from sedimentary basin to basin, within a sedimentary basin, or from pool to pool. Crude oil properties, such as color, viscosity, smell etc., vary due to differences in composition, reservoir depth, the maturity and nature of the source material, and subsequent post emplacement changes. Therefore, the type and range of distillation products that can be derived from crude oil will vary from crude to crude. Hence the economic worth of crude oil is in part determined by the type and range of products derived during distillation and refining. Furthermore, because crude oil is an internationally traded resource we require various means of comparing and distinguishing between various crude oils. There are a number of properties that are used to classify and distinguish differing crude oils, and these depend to some extent upon the purpose of classification (i.e., geological, scientific, commercial, etc.).

There are 161 different internationally traded crude oils (Atkinson, 2004) traded through the International Petroleum Exchange or the New York Mercantile Exchange. Because differing crude oils can vary in composition, buyers and sellers have found it easier to refer to a limited number of reference, or benchmark, crude oils, against which other crude oils are compared for the determination of value. There are two benchmark crude oils in the United States, the West Texas Intermediate (38? to 40? API and 0.3% sulfur) and the West Texas Sour (33? API and 1.6% sulfur). The North Sea benchmark crude oil is the Brent crude (38? API and 0.3% sulfur), whereas the Asian and Middle East benchmark crude oil is the Dubai crude oil (31? API and 2.0% sulfur). Another benchmark used by OPEC, known as the 慜PEC basket,? is an average of seven crude oils that includes Algeria抯 Saharan Blend, Indonesia抯 Minas,Nigeria抯 Bonny Light, Saudi Arabia抯 Arab Light, Dubai抯 Fateh, Venezuela抯 Tia Juana Light, and Mexico抯 Isthmus(a non-OPEC crude oil). OPEC uses the price of this basket to monitor world oil market conditions.

Figure 13. Pyrobitumen as seen in reflected light under crossed polarized light (image courtesy of L. Stasiuk).



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癆PI gravity The density of a crude oil forms the basis for a common means of distinguishing between various crude oils. Crude oil is typically lighter than water and therefore the density of crude oil can be simply determined by a hygrometer! However, density varies with temperature and in the United States, the density of oil is defined by the American Petroleum Institute (API), 2007, in terms of gravity units (癆PI), according to the following formula:

The determination of density under standardized conditions is critical since 癆PI gravity determinations are only comparable if they are conducted at 60 degrees Fahrenheit, or 15.5 degrees Celsius. Water has an 癆PI of 10, whereas the 癆PI of crude oil varies from 5 to 55癆PI. Light oils have 癆PI gravities between 35 to 45, medium oils range in 癆PI from 25 to 35, and heavy oils have an 癆PI gravity below 25. As stated earlier, because hydrogen is the lightest element, oils with high hydrogen content have a lower specific gravity, for example:

Penn. crude (hydrogen = 14.2%) s.g. = 0.862 (33? API)

Coalinga crude (hydrogen = 11.7%) s.g. = 0.951 (17? API)

Also note that 癆PI gravity units are inversely proportional to specific gravity. Light oils (e.g., 40? to 50? API) that have relatively high hydrogen content have a specific gravity of 0.83 and generally a low viscosity. In contrast, heavy oils, containing relatively less hydrogen, have 癆PI gravities less than 15? a specific gravity approaching 1.0, and a generally high viscosity.

Sulfur content (sweet and sour) When sulfur-bearing fossil fuels are burned, oxides of sulfur are formed (e.g., SO2) and sulfur dioxide in particular is a pollutant and known to form acid rain. If a crude oil contains sulfur, it must therefore be removed at the refinery. Crude oils are consequently classified as 憇weet? or 憇our? based on their sulfur content. Sweet crude oils, such as the West Texas Intermediate and Brent crude, have a sulfur content less than 1.0 wt %. In contrast sour crude oils, such as the West Texas Sour and Dubai crude, have a sulfur content of more than 1.0 wt %. Most of the sulfur in crude oil exists as heteroatoms.

Pour point All normal crude oils contain alkanes (molecular composition) that are commonly referred to as paraffins. High-molecular-weight, straight-chain paraffins with between 20 to 30 carbon atoms are generally known as 憌axes,? that is, they are solid at STP but remain in liquid form at the elevated temperatures and pressures found within a reservoir. When present, paraffin waxes can solidify when a waxy crude oil is brought to the surface due to a decrease in temperature and pressure. The waxes are characterized by a clearly defined crystal structure (Figure 14) and have the tendency to be hard and brittle. Because waxes can create production problems due to their tendency to solidify at STP, the wax content of an oil is often determined. The pour point and cloud point of a crude oil are rule-of- thumb guides as to the wax (paraffin) content of oil and the tendency of those waxes to solidify.

The lowest temperature at which a crude oil will pour before it forms a 憇olid? is referred to as the pour point. Most crude oils exhibit pour points between +52? C to -60? C (+125? F to -75? F). Pour point is determined by heating a sample of crude oil within a tube at a temperature of 46? C (115? F) to dissolve the wax. The tube is then cooled in a water bath that is approximately 11? C (20? F) below the estimated pour point (ASTM D5853-95). The temperature at which the oil will not flow is the pour point. Cloud point is the temperature at which the oil first appears cloudy as the wax begins to form. Cloud points are approximately 2? C (4? F) higher than the pour point. The methodology for determining cloud point is set by ASTM D2500 (http://www.astm.org).

Figure 14. Atomic Force Microscope image of a paraffin wax crystal (C36H74), measuring 14 microns along the base (image by R. Williamson; SPM Group Bristol image courtesy of DoITPoMS Cambridge).



16

Units of measurement

Crude oil There are two universally accepted volumetric units of measurement for crude oil. The unit of measurement generally used within the United States (often called an 慐nglish Unit? is the barrel (bbl). One barrel holds 42 U.S. gallons or 34.97 Imperial gallons. Countries using the metric system use the cubic meter (m3). One cubic meter of oil is equal to 6.29 bbl. Alternatively, metric tons are often used when crude oil is shipped from place to place. However, the volume of a metric ton varies with 癆PI gravity and temperature.

Gas The preferred unit of measurement for natural gas in the United States is a cubic foot (cf). However, gas volumes vary with temperature and pressure, therefore the unit of measurement is referenced to standard conditions (15? C and 101.325 kPa, or 60? F and 14.65 psi). The referenced unit is known as standard cubic feet (scf). Because gas volumes in reservoirs can be large, units are abbreviated thus: Mcf (thousand cf), MMcf (million cf), Bcf (billion cf) and Tcf (trillion cf). Under the metric system, the volume of gas is given in cubic meters (m3). One cubic meter is 35.315 scf.

Geochemical characterization

Broad composition

This is a straightforward scheme (Figures 15 and 16) based upon the proportion of paraffinic (normal and isoalkanes),naphthenic (cycloalkanes), aromatic, and NSO compounds present within an oil normalized to 100%, once 憈opped? at 200? C to remove low molecular weight compounds. Although geologists do not commonly use this scheme, it is included here because it will help illustrate crude oil composition in the context of properties discussed above. Non-degraded or medium- to light-gravity crude oils can be referred to as either paraffin-based oil or napthenic-based oil, but more typically, non-degraded crude oils are classified as:

paraffinic oils, containing mostly normal and isoalkanes, and less than 1% sulfur

paraffinic-naphthenic oils, containing both linear- and cyclo-alkanes, and less than 1% sulfur

aromatic-intermediate oil, containing less than 50% saturated hydrocarbons, and usually more than 1% sulfur

However, crude oils altered in situ within the reservoir may exhibit a modified molecular composition. For example, the continued maturation (cooking) of crude oil within the reservoir (Figure 15) may result in a decrease in high-molecular weight compounds and a relative increase in low weight molecular compounds. In contrast, the in-situ

Figure 15. Ternary diagram showing the composition of six crude oils from 541 oil fields (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).

Figure 16. A Ternary diagram showing the main trends of alteration and thermal maturation of crude oils (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).



17

alteration of crude oil within the reservoir by oxidation or biodegradation (e.g., microbial degradation) is typically associated by a shift away from the paraffin pole, due to the relative loss in alkane content and a relative increase in poly-cyclic aromatic and NSO-bearing compounds (Figure 16).

A comparison of two oils A comparison of two oils will attempt to relate the significance of composition. Please refer to the two gas chromatograms in Figure 17. Chromatogram (A) represents the alkane fraction of a high-wax Indonesian crude oil whereas chromatogram (B) is a sample of Brent crude oil. Each chromatogram 憆uns? left to right, with lower molecular weight compounds on the left and higher weight molecular compounds on the right. Each peak, or spike, represents an individual compound (for example C30); the height of each peak is indicative of the relative abundance of that compound within the crude oil. Even though the analyses were conducted under slightly different conditions, they are aligned so that two 憆eference peaks? (indicated by the red arrows) lie above or below each other for comparison. You should notice that oil (A) has a much higher proportion of nalkanes in the C27 to C33 range compared to oil (B) whose nalkane distribution is skewed towards the lighter end (which is marked by *).

Here is the paradox; both oils are paraffin rich andhave a similar API gravity (~API 34? to 38? . However, the Indonesian crude has relatively low abundance of low molecular and a high proportion of C26 to C35 paraffins. Therefore, this oil is a 慼igh wax?oil or a 憌axy? oil. In contrast, the Brent crude oil has a relatively greater proportion of lower-molecular weight paraffins and naphthenes of 15-carbon atoms or less. Thus, the relatively high hydrogen content of the Indonesian crude is derived from the relatively higher wax content, whereas the Brent crude is associated with low-molecular weight paraffin and naphthene compounds. Although the two crude oils have similar API gravities, their pour point and cloud points are dissimilar. The Indonesian crude is almost solid at STP (standard temperature and pressure), with a pour point of +50? C (+120? F), because of the high wax content, whereas the Brent crude remains a liquid with a pour point of -3? C (+27? F). Furthermore, despite having similar gravities (API or S.G.), the variety and range of distillate fractions derived through refining will be markedly different. This simple comparison should indicate that the labeling of any crude oil by a single, simplistic characteristic such as API gravity can be misleading!

References

American Petroleum Institute, 2007: http://api-ec.api.org/Standards.

American Standards and Testing Materials (ATSM): http://www.astm.org/.

Atkinson, N., 2004, The International Crude Oil Market Handbook: Energy Intelligence Research (on-line): http://www.energyintel.com/Research.asp.

Hunt, J. M., 1979, Petroleum geochemistry and geology: Freeman and Co., San Francisco, 642 p.

Hunt, J. M., 1996, Petroleum geochemistry and geology 2nd Ed.: Freeman and Co., New York, 743 p.

SPE/WPC/AAPG/SPEE, 2006, Petroleum reserves and resources: classification, definitions and guidelines, DRAFT, September 2006, 60 p.

Peters, K. E., and J. M. Moldowan, 1993, The Biomarker Guide, Interpreting molecular fossils in petroleum and ancient sediments: Prentice Hall, 363 p.

Peters, K. E., C. W. Clifford, and J. M. Moldowan, 2004, The biomarker guide, 2nd ed., v. 1 and v. 2: Cambridge University Press, 1155 p.

Tissot, B., and D.H. Welte, 1984, Petroleum formation and occurrence: 2nd rev. ed.: Springer-Verlag, Berlin, 699 p.

Figure 17. A gas chromatogram (a.k.a. ?fingerprint?) of the alkane fraction of a high wax Indonesian crude (A) matched against a marine-sourced Brent crude oil (B). Note that the occurrence of reference compounds in each chromatogram is indicated (red arrows); also note that the Indonesian crude oil has a greater proportion of peaks around the C27 to C30

range, whereas the Brent crude (A) oil has a significantly greater number of peaks at the C9 to C12 range (indicated *).


Chapter 3—Petroleum: From Organism to Trap

18

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Sedimentary organic matter

Definitions and terms

The previous section ended with an examination of the molecular composition of petroleum, accompanied by definitions for various molecular components of petroleum. Therefore, before we examine the origin and generation of petroleum it is fitting that we begin by defining many of the terms that will be used throughout this section.

Source rock A petroleum source rock is generally recognized as a fine-grained sedimentary rock that has naturally generated and released enough hydrocarbons to form a commercial accumulation of oil and/or gas (Tissot and Welte, 1984).Implicit in this definition is that a source rock meets the following geochemical requirements (Peters and Cassa, 1994):

the source rock contains sufficient quantity of organic matter

the organic matter is of sufficient quality to generate oil and/or gas, and

the source rock attained a level of thermal maturity capable of generating and expelling hydrocarbons

The term potential source rock describes an organic-rich, fine-grained sedimentary rock that is not sufficiently mature to generate petroleum (i.e., oil), but under the right conditions could generate petroleum.

Kerogen Although not specifically mentioned in the definition of a source rock given above, the existence of kerogen is an implicit key characteristic of all source rocks. Kerogen is generally defined as sedimentary organic matter that is insoluble in common organic solvents and aqueous alkaline solvents (Tissot and Welt, 1984). On this basis, kerogen is rendered distinct from humic (organic) matter within soil because humin is soluble in aqueous alkaline solvents. Kerogen is distinguished from petroleum because common organic solvents are used to extract bitumen and oil from rock! The organic matter that is kerogen is commonly a mixture of different types of organic matter, the composition of which is largely dependent upon the composition of the original biologic precursor.

Macerals The term maceral was originally coined to describe the microscopic constituents of coal, that are recognizable under a microscope (Stopes, 1935), but has since been broadened to include all recognizable organic matter in sedimentary rocks (Figure 18). Generally, macerals represent the organic remnants of plant or animal matter and readily distinguishable by differences in morphology, various optical properties, and technological property (Bend, 1992; Taylor et al., 1998). Although macerals can be broadly distinguished by differences in chemistry and/or technological property, maceral identification and name designation is best achieved using a reflected light microscope (Figure 18).

Figure 18. Examples of macerals. (a and b) The macerals Alginite (A) and Fluorinite (F) are both autofluorescent under u.v. light. In these images Alginite (A) appears yellow to yellow-green, whereas the Fluorinite (F) appears a dull red-brown. (c) Under reflected white light, the med-grey maceral Telinite (T) has retained much of the original texture of the original plant material. Telinite (T) is in-filled by a darker-grey maceral known as Collinite (C). Images (a) and (b) are in reflected autofluorescent light and (c) in reflected white light.

Figure 18. Examples of macerals. (a and b) The macerals Alginite (A) and Fluorinite (F) are both autofluorescent under u.v. light. In these images Alginite (A) appears yellow to yellow-green, whereas the Fluorinite (F) appears a dull red-brown. (c) Under reflected white light, the med-grey maceral Telinite (T) has retained much of the original texture of the original plant material. Telinite (T) is in-filled by a darker-grey maceral known as Collinite (C). Images (a) and (b) are in reflected autofluorescent light and (c) in reflected white light.



19

The production and accumulation of organic matter

The carbon cycle The creation of a fossil fuel begins with the creation and accumulation of organic matter at the earth抯 surface. Organic matter is defined as ?material comprised solely of organic molecules in monomeric or polymeric form, that are derived directly or indirectly from the organic part of organisms... deposited or preserved in sediments? (Tissot and Welte, 1984 p. 3). The production of organic matter starts with photosynthesis, with sunlight of course being the primary source of energy. The primary producers, such as photosynthetic bacteria and blue-green bacteria, are known as phototrophs because they use light (energy) to produce glucose.

h.v (energy)

6CO2 + 12H2O C6H12O6 + 6O2 + 6H2O

(674 kcal)

An equation for photosynthesis. Please note that oxygen is a by-product.

Phototrophic organisms are found on land or in the euphotic zone of the water column. Organisms that utilize carbon dioxide as their sole source of carbon are autotrophs, whereas those that derive their carbon from existing organic structures are known as heterotrophs; this is the basis of the food pyramid.

Welte (1972) estimated that the total amount of organic carbon produced within the biosphere is 6.4 x 1015 t. In contrast the global preservation of organic carbon within sediments is less than 0.1% of all organic carbon production. Therefore, the bulk of all organic carbon produced is either bound within inorganic sediments or recycled within the biosphere as carbon dioxide. Some carbon dioxide does escape from the major cycle (Figure 19) into isolated environments, but of all the organic carbon produced, approximately 0.1 to 0.01% becomes fossil fuel, which is indicated as a 憀eakage? in Figure 19.

ProductionThere are two main factors that govern the creation and accumulation of organic matter in sediments (Demaison and Moore, 1980). They are the production of organic matter and organic matter preservation. Both are of equal importance, because both influence the amount of organic matter that occurs within a given potential source rock. However, without production, preservation becomes moot!

Biological activity within an aquatic environment (e.g., marine) is mainly controlled by sunlight, temperature, and the availability of nutrients, such as nitrates and phosphates. Therefore, the greatest level of biological production is concentrated in the upper 60 to 80 m of the water column, which is known as the euphotic zone.

The productivity of organic carbon (C org.) within coastal water, which averages approximately 100g C org ma-1, is about twice that of the open ocean (Tissot and Welte, 1984; Hunt, 1996). Continental margins that experience the phenomenon of up-welling (e.g., western South America) are especially productive, generating 300 g C org ma-1.However, most of the primary organic matter is either lost to the food chain or lost during sedimentation. The preservation of organic matter, therefore, plays a key role in the creation of a source rock.

Figure 19. A simplified organic carbon cycle (after Welte, 1972; Tissot and Welte, 1984; Hunt, 1996; and others).



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Preservation Approximately 80% of all primary organic matter presently produced in the ocean is consumed (Menzel, 1974). The most effective consumers are zooplankton and aerobic microorganisms. It therefore follows, that the duration of time a given particle of organic matter spends suspended within oxygen-rich water has a direct impact upon the successful accumulation of organic matter within sediment. The preservation potential of organic matter can be enhanced by the adsorption of organic matter onto the surface of mineral particles, which effectively increases the mass of the organic matter, enabling it to sink faster.

However, the most effective means of attaining preservation is to decrease the amount of oxygen within the water column, or at the water/sediment interface. Depositional settings generally considered favorable for the production and preservation of organic matter are those in which bottom waters contain very little dissolved oxygen (Demaison and Moore, 1980). Such depositional environments are considered by Tyson and Pearson (1991) to include dysoxic (2.0 to 0.2 ml oxygen per liter water), suboxic (0.2 to 0.0 ml oxygen per liter water), and anoxic (0.0 ml oxygen per liter water). Within an oxygen-rich environment (>2.0 ml oxygen per liter water), aerobic bacteria utilize oxygen to degrade organic matter and generate the by-products carbon dioxide and water. In contrast, within an anoxic environment, anaerobic bacteria must acquire oxygen via a sulfate reduction process, which is a relatively slower process. Therefore, aerobic bacteria are much more efficient at consuming organic matter than their anaerobic counterparts, although it is important to note that the removal of organic matter does not cease under anoxic conditions, but occurs at a significantly slower rate; a rate that favors the preservation, rather than removal, of organic matter (Figure 20).

There are a number of reasons why anoxia may occur within the water column or sediment. The most common cause of anoxia is a respiratory demand for oxygen that is greater than the available amount of dissolved oxygen. In an open marine environment oxygen is constantly replenished; however, situations can arise that restrict the vertical exchange of water and promote the creation of anoxia (Figure 21). For example, within Lake Tanganyika, East Africa, the presence of a thermocline prevents the vertical mixing of water and the promotion of anoxic conditions at depth. Therefore, sediment deposited under anoxic conditions is associated with relatively higher organic matter content. The presence of sill at the entrance of the Black Sea (i.e., Bosporous, Figure 21) restricts the exchange of water, promoting the development of a halocline and anoxic conditions at depth (Demaison and Moore, 1980).

Figure 21. Two contemporary basins that are considered to be examples of an anoxic depositional setting. The water in Lake Tanganyika is stratified because of a permanent thermocline, whereas limited water exchange over a shallow sill has promoted the development of a permanent halocline in the Black Sea. The existence of a thermocline or halocline promotes anoxia within the water column (after Demaison and Moore, 1980).

Figure 20. The preservation potential of organic matter as related to the presence of oxic or anoxic bottom-water conditions. In the presence of free iron, the sulfate reduction process will promote the formation of pyrite, whereas in the absence of iron, hydrogen sulfide is produced (after Demaison and

Figure 20. The preservation potential of organic matter as related to the presence of oxic or anoxic bottom-water conditions. In the presence of free iron, the sulfate reduction process will promote the formation of pyrite, whereas in the absence of iron, hydrogen sulfide is produced (after Demaison and Moore, 1980).



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The sedimentary environment and organic matter

Sediment permeability The mineralogy of the host sediment can also influence the preservation potential of organic matter (Figure 22). Clay-sized particles can adsorb organic matter (onto their surfaces) and are more readily coated with organic matter than coarse-grained siliciclastics. Also, clay particles are often transported further and deposited in low-energy environments. In contrast, sands are deposited in higher-energy environments; environments that are often associated with the presence of oxygenated water, higher sedimentation rates, and an abundance of aerobic micro-and macro-biota. The presence of any, or all, of these characteristics will conspire against the deposition and preservation of organic matter.

Sediment particle size is also important because the relative decrease in permeability associated with clay-sized particles restricts the exchange of oxygen-depleted water by oxygen-rich water (Figure 22). Whereas, the higher porosity and permeability of recently deposited sands enables oxygen rich waters to permeate the upper few meters of sediment, thereby promoting the removal of organic matter by scavenging metazoan (Figure 22). The existence of fine laminae within a fine-grained sedimentary rock is generally attributed to the presence anoxia within the depositional environment and the absence of bioturbation (Raiswell and Berner, 1985).

Carbonate rocks Carbonate rocks are interesting in that they can be both source and reservoir. Although bioherm and reef carbonates often make good reservoir rocks, they generally have diminished potential as source rocks because of the high rate of scavenging within those environments. The most favorable depositional environment for the creation of a carbonate source rock include environments that favor:

the formation of a halocline (water stratification) and anoxic conditions at depth

the growth of algal-rich sediments

Argillaceous rocks Rocks predominantly comprised of clay minerals (i.e., claystone, mudstone, and shale) are argillaceous. However, as discussed above, not all argillaceous rocks have source potential; generally, clay deposited under anoxic conditions possess the greatest potential (Figure 23). Argillaceous rocks that have the highest organic carbon content and the greatest generating potential may:

be very finely laminated due to the absence of bioturbation

contain pyrite (or some other sulfide)

be micro-fractured (possibly due to over pressuring)

have a high trace element/metal content (e.g., Mg2+, U4+, etc.)

contain the remnants of micro- and macro-biota (as either kerogen or skeletal remains)

be black to dark brown or dark gray, although Paleozoic source rocks typically deviate from this generalization.

Figure 22. Preservation potential due to lithology. A comparison between an argillite (top) and 憇and? (bottom). Oxygenated water can penetrate the more open pore network of the sand promoting the removal of organic matter (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).

Figure 23. An example of shale (cut perpendicular tobedding) in reflected white light. A 憊itrinite particle? isindicated by V, a wisp of kerogen indicated by K, and atrail of generated hydrocarbons emanating from thekerogen is indicated by H. Width of image 250 microns.



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The chemical composition of organic matter

The biological precursor The distribution of organic matter is not capricious. Living species form natural associations that reflect the habitat of a given environment. For example, the type of species that typify a fresh-water, terrestrially bound lake is markedly different from those that are found in a coastal-marine setting. Therefore, the type of organic matter within a potential source rock will vary according to depositional setting and the type of species that occur within that environment. The natural association of species within given environment gives rise to the concept of organic facies (Rogers, 1980; Jones, 1984). But before we examine the significance of organic facies, we need to examine the composition of organic matter.

Organic matter consists of various groups of molecular constituents: i.e., proteins, carbohydrates, lipids, and (in higher plants) lignin. However, significant differences in the relative proportion of each molecular group1 exist for various types of organic matter. For example, note the variation in protein content between terrestrial plants, such as Spruce wood and Scots pine, and marine zooplankton (Table 3). Similarly, the terrestrially derived examples contain lignin, which is absent in the other three examples.

Therefore, the chemical composition of organic matter within a source rock is determined by the type and variation of living precursor within a given depositional environment; which in turn are dependent upon a number of environmental factors. Living organisms within the marine realm are affected by light, temperature, the availability of nutrients and oxygen, and the presence of land barriers; whereas terrestrial habitats are influenced by climate, the type and availability of nutrients, and the availability oxygen (Tissot and Welte, 1984).

The factor of geological time is also relevant, due to the evolutionary development of species. Source rocks of the Lower Paleozoic (e.g., Cambrian and Ordovician), are typically devoid of organic matter derived from higher plants, since the diversification of vascular plants did not occur until the Devonian (Thomas and Spicer, 1986).

For example, the kukersites of Upper Ordovician age (Figure 24) within Estonia and North America (Hutton, 1987; Fowler and Douglas, 1984; Douglas et al., 1991) are dominated by the blue-green alga Gloeocapsomorpha prisca (Zalessky, 1917). Because these source rocks are of Upper Ordovician age, they do not contain terrestrially derived material such as spores, or the macerals cutinite and resinite, or macerals from the vitrinite group.

1 Proteins are highly ordered polymers made from individual amino acids and account for most of the N2 within an

organism. They can be broken down, either by enzymes or by hydrolyzation. Carbohydrates have a generalized formula of Cn(H2O)n and are essentially the hydrated forms of carbon (e.g., cellulose,

chitin, and mono-, and poly-saccharide). Higher plants contain high amounts of cellulose whereas algae and marine organisms are devoid of cellulose.

Lipids are water insoluble and include waxes, plant or animal oil and fats, oil-soluble pigments, terpenoids, and steroids. With respect to the formation of hydrocarbons, lipids are the most important group.

Lignin (and tannin) are complex 3-D aromatic molecules that give plants structural rigidity.

Figure 24. Kukersite of U. Ordovician age from the Williston Basin, Saskatchewan, Canada, containing G. prisca (G).

Table 3. The composition of living matter (examples) (data from Hunt, 1996).

Organic matter type Molecular group1

Proteins Carbohydrates Lipids Lignin

(wt. % ) (wt. % ) (wt. % ) (wt. % )

Spruce wood 1 66 4 29 Scots-pine needles 8 47 28 17 Phytoplankton 23 66 11 0 Diatoms 29 63 8 0 Zooplankton 60 22 18 0



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Kerogen Type

Introduction Because sedimentary organic matter can and will vary in amount and type from place to place for reasons previously outlined, geoscientists need a classification scheme that differentiates between various types of sedimentary organic matter, better known as kerogen. A hypothetical example was given in the previous section that contrasted the petroleum generative potential of a terrestrially derived kerogen against a marine-sourced kerogen. It was speculated, in that example, that the terrestrially derived kerogen would contain molecular remnants and modified material derived from lignin, cellulose, and other carbohydrates, and minor amounts of lipid material (i.e., relatively low hydrogen content); whereas the marine-sourced kerogen would contain molecular remnants and modified material derived from lipids, carbohydrate, and proteins (i.e., relatively higher hydrogen content). We also reviewed earlier (Chapter 2) that petroleum, like kerogen, is predominantly comprised of organic compounds containing principally the elements hydrogen, carbon, and oxygen. With respect to the generation of petroleum, the most fundamental characteristic of kerogen is hydrogen content, because under optimal conditions a hydrogen-rich kerogen will generate more oil than a hydrogen-lean kerogen. Therefore, by determining the elemental composition of kerogen it is possible to differentiate and classify kerogen, and broadly predict the type of petroleum a given kerogen will generate in the subsurface under the right conditions.

Atomic ratio method The van Krevelen diagram is an x-y cross-plot of the Atomic Ratio of the elements Hydrogen/Carbon (H/C) against the Atomic Ratio of Oxygen/Carbon (O/C) obtained by elemental analysis (Figure 25). For example, the bulk analysis of a hypothetical marine-sourced kerogen may contains carbon (76.4 wt. %), hydrogen (8.3 wt. %), and oxygen (13.1 wt. %), which gives H/C and O/C Atomic Ratios of 1.3 and 0.13 respectively. Our hypothetical marine-sourced kerogen plots as an immature Type II on the diagram. In contrast, our hypothetical terrestrial kerogen contains carbon (72.7 wt. %), hydrogen (6.0 wt. %), and oxygen (19.0 wt. %), which gives H/C and O/C Atomic Ratios of 0.9 and 0.2 respectively and plots as an immature Type III kerogen.

Hydrogen or oxygen index Probably the most common means of characterizing kerogen is via bulk pyrolysis, which is typically obtained by RockEval pyrolysis. Part of the appeal of this approach is convenience and the wealth of data obtained during analysis. Data is derived by pyrolyzing the kerogen under standardized conditions (Espitalie et al., 1980, etc.), which yields data that can be plotted in an analogous way to the van Krevelen-type diagram. The Hydrogen/Oxygen Index cross-plot (Figure 26) also designates kerogen into one of three main petroleum generative kerogen Types. A fourth kerogen Type also exists (Type IV) but is generally considered non-generative. Continuing to use our hypothetical example kerogen, the immature marine example may generate a Hydrogen Index of 620 mg HC/g TOC and an Oxygen Index of 75 mg CO2/ g TOC (i.e., Type II kerogen). In contrast, the terrestrial kerogen may generate a Hydrogen Index of 110 mg HC/g TOC and an Oxygen Index of 125 mg CO2/ g TOC (i.e., Type III kerogen).

Figure 25. A cross-plot of the atomic ratios H/C versus O/C, generally known as a 憊an Krevelen diagram? showing the broad evolutionary paths for Types I, II, and III kerogen and the empirically determined three areas of thermal maturity known as diagenesis, catagenesis, and metagenesis (after van Krevelen, 1960; Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; and others).

Figure 26. The Hydrogen and Oxygen Index cross-plot, showing the evolutionary paths for Type I, II, III, and IV kerogen (after Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; and others).



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Type I kerogen Kerogen of this type has the highest hydrogen content of all kerogen types and is strongly oil prone. Type I kerogen is derived from organic matter rich in lipids and is generally subdivided into Alginite A, representing the accumulation of algal material, e.g., Tasmanites, Gloeocapsomorpha prisca, Botryococcus or Pila (Figure 27), or Alginite B, hydrogen-rich amorphous organic matter (Figure 27c). The G. prisca-rich Ordovician kukersites of North America represent an example of Type I kerogen.

Characteristicsvan Krevelen diagram: a high initial H/C (e.g., 1.3+) and a low O/C (i.e., less than 0.1) Atomic Ratio. HI/OI plot: a very high Hydrogen Index (600 to 900) and very low Oxygen Index (10 to 30).

Type II kerogen This is perhaps the most commonly reported type of kerogen, which is probably a chemical averaging artifact due to the bulk analysis of complex kerogen mixtures within a given source rock. True Type II kerogens possess relatively high initial hydrogen content and a moderate amount of oxygen (Figure 28). Examples of Type II kerogen include marine organic matter, phytoplankton, zooplankton, and bacteria deposited in a reducing environment, and some terrestrially derived material also (Figure 28b, c), although marine-derived Type II kerogen is more common.

Typically Type II kerogen is associated with a lower oil yield than an equivalent volume of Type I kerogen. The Jurassic Kimmeridge clay (North Sea basin) contains a prolific Type II kerogen. Type II kerogens may also be subdivided on the basis of sulfur content (Hunt, 1996).

Characteristics van Krevelen diagram: a moderately high initial H/C (1.0 to 1.3) and a moderate O/C (0.03 to 0.15) Atomic Ratio. HI/OI plot: a high Hydrogen Index (550 to 600) and moderate Oxygen Index (50 to 100).

Type III kerogen This kerogen type releases little in the way of aliphatic material during thermal maturation and, therefore, true Type III kerogens are not usually considered oil prone. Type III kerogens are typically derived from terrestrially derived vascular plant material, i.e., vitrinitic, not liptinitic (Figure 29a, b). The Manville shale (U.S.A. and Canada) is an example of a Type III kerogen.

Figure 27. Examples of Type I Kerogen known as Alginite. Image (a) contains Pila (P); image (b) contains Tasmanites

(T), and image (c) contains amorphous organic matter (A). All images in reflected autofluorescent light (image 27c

courtesy of L. Stasiuk).

Figure 28. Examples of Type II Kerogen. Image (a) contains the maceral Sporinite (S); images (b) and (c) contain the macerals Resinite (R) and Cutinite (C).



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Characteristics van Krevelen diagram: a low H/C Atomic Ratio (i.e., less than 1.0) and an initial O/C ratio between 0.2 to 0.3.

HI/OI plot: a low initial Hydrogen Index (i.e., less than 150) and an high initial Oxygen Index (e.g., 150+).

Type IV and residueSome recognize a fourth type of kerogen, known as Type IV. However, the oil and gas generation potential of this kerogen is extremely low and typically considered non-generative. An example of this type of kerogen is the maceral Fusinite, which is derived by the oxidation of derived vascular plant material (Figure 29c).

Organic facies

As stated earlier, the chemical composition of organic matter within a source rock is determined by the type and variation of living precursor within a depositional environment; that is dependent, in turn, upon a number of environmental factors. Living organisms within the marine realm are affected by light, temperature, the availability of nutrients and oxygen, and the presence of land barriers, whereas terrestrial habitats are influenced by climate, the type and availability of nutrients, and the availability of oxygen (Tissot and Welte, 1984). Furthermore, since the early Devonian, the diversity and number of species has increased, giving rise to natural associations of increasing differentiation and complexity due to variations in depositional setting (Figure 30) and evolution. Therefore, the chemical composition of a given kerogen is largely dependent upon depositional environment and the natural association of plant and/or animal species present within that environment (Figure 30). This in turn influences the generative potential of the kerogen (i.e., gas prone or oil prone). For example, a marine source rock may contain organic matter principally derived from marine plankton, composed of proteins, carbohydrates and lipids. In contrast, a terrestrially derived source rock may contain organic matter derived from vascular plants, mainly composed of lignin, carbohydrates, and some lipid material. It would be reasonable to anticipate (following this example), that the marine-derived kerogen would be oil prone, whereas the terrestrially derived kerogen would probably be gas prone.

Lateral and vertical variations in association of organic matter are increasingly described and interpreted in terms of organic facies (Rogers, 1980; Jones and Demaison, 1982; Jones, 1984, 1987; Jacobsen, 1991). Organic facies are determined by the type of organic matter within the rock unit, which is generally considered linked to the paleodepositional environment (Figure 31) (Rogers, 1980).

Jones (1984) defines an organic facies as a mapable subdivision of a designated stratigraphic unit, distinguished from the adjacent subdivisions on the basis of the character of its organic constituents, without regard to the inorganic

(a) (b) (c)

Figure 30. A section through the Earth's crust showing possible generalrelationships between depositional setting, available oxygen supply, and broaddifferences in organic matter type (marine/terrestrial/algal).

Figure 29. Examples of Type III and Type IV kerogen. Image (a) is a Type III kerogen-bearing shale (K); image (b) is a Vitrinite-rich sediment (V); image (c) contains Fusinite (F) as an example of a Type IV kerogen (image 29c courtesy of L. Stasiuk).



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aspects of the sediments. Tyson (1995) notes that this definition does not limit the definition to any given technique or methodology. This is significant since organic matter within sediment can be characterized by microscopy, by geochemical analysis, or better still by integrating the two. The organic facies concept can be used as an exploration tool by the petroleum geochemist to map source rock characteristics and also to predict the occurrence, quality, and generative potential of source material within a basin or stratigraphic sequence. For a detailed account of organic facies please refer to Tyson (1995).

The generation of petroleum

Thermal maturationThermal maturation is the natural transformation of kerogen into petroleum in response to increased thermal stress, which is due to an increase in burial depth throughout geological time. The maturation threshold for each kerogen type differs because the transformation of kerogen into petroleum involves the thermal rupture of chemical bonds, and is dependent upon the molecular make-up of a given kerogen due to differences in (bond) dissociation energy, in which carbon-sulfur and carbon-oxygen bonds generally have lower dissociation energies than carbon-hydrogen bonds (Hunt, 1996).

Following deposition and preservation, the subsequent transformation of organic matter into kerogen and the generation of petroleum involves three discrete,

Figure 31. The relationship between selected organic facies and sedimentary environment and climate, according to Jones (1987) (from Tyson, 1995; reprinted courtesy of Springer Science and Business Media). A listing of Organic facies (i.e., D, C, B, etc.) and a summary of respective characteristics is given below in Table 4.

Figure 32. The three stages of kerogen transformation, with the relative production of biogenic gas, oil, and thermogenic gas. Within the nine inset figures, inherited hydrocarbons are indicated in solid black, whereas generated hydrocarbons are in gray (from Tissot and Welte, 1984; reprinted with kind permission of Springer Science and Business Media).

Table 4. Organic facies and selected characteristics (after Jones, 1984, 1987; Jones and Demaison, 1982; Tyson, 1995).

Organic H/C Atomic Ratio Pyrolysis yield Generation facies at %Ro ~ 0.5 HI OI potential Dominant organic matter Sedimentary structure

A > 1.45 > 850 10 to 30 oil Algal; amorphous AB 1.35 to 1.45 650 to 850 20 to 30 Amorphous; minor terrestrial Laminated B 1.15 to 1.35 400 to 650 30 to 80 Amorphous; commonly terrestrial Well bedded to laminated BC 0.95 to 1.15 250 to 400 40 to 80 mixed Mixed; some oxidation Poorly bedded C 0.75 to 0.95 125 to 250 50 to 150 mixed Terrestrial; some oxidation Poorly bedded to bioturbated CD 0.60 to 0.75 50 to 125 40 to 150+ gas Oxidized; reworked D < 0.6 < 50 20 to 200+ none Highly oxidized; reworked Massive, bioturbated



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sequential stages of alteration (Figure 32) known as: diagenesis, catagenesis, and metagenesis (Espitalie et al., 1980; Tissot and Welte, 1984). Each stage of alteration is characterized by a different process. The diagenetic stage is predominantly biochemical, within which microbial processes predominate. Catagenesis immediately follows diagenesis and represents the principal stage of petroleum generation. When kerogen crosses the chemical boundary (a.k.a. threshold) between diagenesis and catagenesis, thereby entering the catagenesis stage, the kerogen is said to be thermally mature with respect to petroleum generation. The final stage, known as metagenesis, is typically associated with the generation of dry gas and non-hydrocarbon gases.

DiagenesisDiagenesis (Figures 32 and 33) is the immature stage and typically associated with the progressive biochemical transformation of organic matter into kerogen. Diagenesis commences within the water column and continues within the subsurface until a temperature threshold of 50 to 75? C, or a vitrinite reflectance minimum of om 0.5%, is reached2. It is within the diagenetic stage that the crucial process of preservation occurs. Some hydrocarbons may co-exist with the immature kerogen (Figure 32), however, they are either inherited hydrocarbons from biological organisms (e.g., biomarkers), or metabolic by-products (e.g., biogenic methane); shown in black within the nine inset diagrams in Figure 32. Examples of inherited hydrocarbons include the tricyclic and pentacyclic biomarkers, terpenoids, certain isoprenoids, and waxes. Typically, the generation of petroleum, via the thermal rupture of chemical bonds, is not considered a characteristic of diagenesis. However, bitumen and heavy oil generation is known to occur in carbonate-rich, sulfur-bearing kerogen, such as Type IIS (Horsfield and Rullk鰐ter, 1994; Hunt, 1996) because of differences in bond dissociation energy (Hunt, 1996).

CatagenesisThe onset of petroleum generation and the thermal degradation of kerogen marks the beginning of catagenesis (Figures 32 and 33). The generation of petroleum is indicated by a significant decrease in atomic H/C (e.g., 1.25 to 0.5 in Type II) due to a net loss of hydrogen from the kerogen. This process can be effectively depicted on a van Krevelen diagram (Figure 33) with data derived from the elemental analysis or Rock Eval pyrolysis of kerogen. Despite the apparent synonymous nature of catagenesis and the 憃il window,? catagenesis is widely recognized as having both an oil generating and wet gas-generating zone, in that order depending upon the kerogen Type. The oil window is defined as that part of catagenesis in which oil generation exceeds gas generation, whereas wet-gas formation is associated with diminished oil generation. Vassoevich et al.(1969) described the petroleum generation process during catagenesis as having a principle zone of oil generation, now simply known as the oil window (Figures 33 and 34), the boundaries of which are routinely defined by using techniques such as vitrinite reflectance or RockEval pyrolysis. However, because of differences in activation energy, the 憃il window? varies for different kerogen Types. For example, it is lowest ( om 0.5% and a Tmax 430oC) for Type IIS kerogen and highest for a Type I kerogen (~ om 0.65% and a Tmax 440oC) due to differences in the presence of different elements. Throughout catagenesis, kerogen becomes increasingly aromatic and greatly depleted in paraffinic/naphthenic compounds (Figure 34, numbers 2 to 4) due to the process of oil/gas generation. This progressive increase in aromaticity creates changes within the kerogen (e.g., increase in light opacity, red-shift in autofluorescence; see Figure 34) that form the basis of many indices of maturation (e.g., Heroux et al., 1979) as used by organic petrographers and petroleum geochemists.

2

The vitrinite reflectance parameter % om indicates that the vitrinite reflectance value represents the arithmetic mean ( ) of a number of values measured using oil immersion (o) and non-polarized light (m) under standardized conditions.

Figure 33. The thermal evolution of kerogen as depicted on a van Krevelen type diagram. Note the color-coded kerogen maturity zones diagenesis, catagenesis and metagenesis for each kerogen type. Each recognized kerogen type has an evolutionary tract, along which kerogen of similar composition but of increased level of thermal maturity plot. The attained level of thermal maturity is determined by analyzing the residual amount of elemental hydrogen, oxygen and carbon within a sample of kerogen and calculating the appropriate atomic ratios (after van Krevelen, 1960; Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; and others).



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MetagenesisThis zone represents the thermal cracking of previously generated hydrocarbons, should any remain within the source rock (Figure 33) and the additional generation of methane (C1) directly from the remaining kerogen. Metagenesis is considered to be the final stage in the generation of oil and gas, and is simply a process of organic metamorphism due to the relatively higher temperatures that typically occur deep within a basin. During metagenesis, oil is thermally cracked to produce dry gas (methane) and a carbonaceous, aromatic-rich residue (Figure 34; number 5).

Figure 34. Changes in composition and appearance in response to thermal maturation, using Type II kerogen as an example. Five infrared spectra, representing changes in a Type II kerogen during thermal maturation (shown on the left), are stacked to show the relative changes in molecular structure due to the process of thermal maturation. A series of spore 憄alynomorphs? exhibiting the sequential changes in opacity are also shown, alongside the corresponding level of thermal maturity. On the right, a van Krevelen diagram shows the approximate equivalent of thermal maturity as determined by the atomic ratios of H/C and O/C. This example is for illustrative purposes only (stacked infra-red spectra modified from Tissot and Welte, 1984, with kind permission of Springer Science and Business Media; spore micrographs modified from Combaz, 1980, courtesy of Editions Technip; van Krevelen diagram modified after van Krevelen, 1960; Tissot et al., 1974; Durand, 1980; Tissot and Welte, 1984; and others).

Note within each of the stacked infrared spectra, the area and height of each peak corresponds to the abundance of a given molecular group (e.g., C=O). Note that changes in kerogen chemistry (i.e., decrease in oxygen functional groups, aliphatic C-H, and an increase in aromatic C-H) due to thermal maturation are accompanied with changes in spore opacity due to an increase in the adsorption index. The changes in molecular group and changes in spore opacity are reflected by successive differences in the atomic ratios H/C and O/C.

Note specifically:

#1: Recent organic matter that is thermally immature (diagenesis). Note the high C=O peak, high aliphatic peaks, and very low aromatic peaks. Correspondingly this immature kerogen has a relatively high H/C and moderately high O/C Atomic Ratio. Spores are clear to pale yellow.

#2: Onset of catagenesis: entering the 憃il window? (marginally mature). Note the decrease in C=O and aliphatic compounds, loss of H and O relative to C in the Atomic Ratio, and a darkening of the spore.

#3: Peak of hydrocarbon generation (mature), catagenesis. Continued decrease in C=O and aliphatic compounds with a significant increase in aromatic content, marked loss of H relative to C in the Atomic Ratio, and a further darkening of the spore to a dark orange color.

#4: End of hydrocarbon generation (post mature) and start of metagenesis. C=O and aliphatic compounds are markedly reduced with an accompanying increase in aromatic content. Note also the continued loss of H relative to C in the Atomic Ratio and a further darkening of the spore to a dark brown.

#5: Metagenesis. The aliphatic content is significantly reduced whereas the aromatic content has increased. The H/C and O/C Ratios are greatly diminished and the spore is black.



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Source rock assessment

There are many techniques available to determine the thermal maturity of a potential source rock, some are standardized by scientific organizations (e.g., The Society for Organic Petrology or the International Committee for Coal Petrology), and some are not. Without doubt, the two most universally accepted techniques used by industry include RockEval pyrolysis (Tmax) and vitrinite reflectance (% om). Vitrinite reflectance measures the amount of light reflected from the surface of a polished fragment of vitrinite (i.e., Type III kerogen), whereas RockEval pyrolysis indirectly derives the hydrogen, carbon, and oxygen content of kerogen from a crushed sample plus a host of other useful parameters (e.g., Tmax, PI, etc). Neither technique is without flaw, since both have well-known limitations. However, they permit the rapid determination of thermal maturity for a given sample and provide a suitable framework by which other techniques can be compared. For example, by reference to specific values, such as om 0.5 to 0.6% and Tmax values of 430o to 435o, the boundary for the onset of oil generation can be rapidly determined, easily defined, and universally understood.

Migration and Accumulation of Petroleum

Introduction

DefinitionsThe economic accumulation of petroleum generally occurs in a relatively coarse-grained porous and permeable rock that contains little or no insoluble organic matter (i.e., kerogen). It is, therefore highly probable that petroleum compounds underwent some form of migration phenomenon from their place of origin to place of accumulation.

The release of petroleum compounds from kerogen and their subsequent movement within the fabric of the source rock has been termed primary migration. Secondary migration is the movement of petroleum from the source rock, through the larger pore-throats of more permeable beds or permeability conduits, to the trap. Tertiary migration is the movement of petroleum from a previous accumulation to either the earth抯 surface or a shallower trap.

Compaction Sediment compaction creates an increase in bulk density, a marked reduction in porosity, and changes in pore geometry. The rate at which compaction occurs is largely governed by the properties of the sediment, the process of mineral diagenesis, the rate of fluid expulsion, rate of deposition, and burial depth. Within shale in particular, the greatest decrease in porosity occurs at relatively shallow depth, with a rate that generally decreases with increasing depth; accompanied by a marked decrease in average pore diameter, with final values of between 1.0 to 2.5 Nm (Figure 35). Hall et al., (1986) reported porosities of 5.2% for the Cherokee Shale (Oklahoma) and 4.3% for the Bakken Formation (N. Dakota). Both are proven source rocks. The reported median pore diameters were 7.0 nm and 5.0 nm respectively. However, the laboratory derived values of Hall et al., (1986) would probably be reduced by the presence of chemi- or physi-sorbed water and the presence of structured water. Such values may then be closer to the median value of 3 nm proposed by Momper (1978).

The effective diameter of petroleum molecules varies greatly and generally increases with increasing molecular weight, as shown in Figure 35 and Table 5 (Welte, 1972; Hunt, 1979, 1986; Tissot and Welte, 1984). When compared to the 慳verage? shale pore diameter, most complex molecules are either similar in size or larger. So how does the oil or gas get out of the source rock?

Figure 35. Generalized relationship between depth, temperature, pressure, and porosity (modified after Tissot and Welte, 1984, with kind permission of Springer Science and Business Media).



30

Primary migration

Chemical and physical constraints A number of mechanisms have been proposed for the process of primary migration, including petroleum moving as discrete molecular entities, as a continuous oil or gas phase, as individual oil droplets or gas bubbles (globules), as colloidal and micelle solutions, or as true molecular solutions! Theoretically, primary migration could involve a variety of mechanisms. In reality, petroleum generation causes migration. The mechanism of primary migration is not yet unequivocally known, but is generally considered to occur via processes involving diffusion, solution, and/or hydraulic pressure.

DiffusionA diffusional process is one in which molecules move from high concentration to lower concentration. Diffusion preferentially favors the smallest molecules, such as methane (Table 5) compared to other gaseous hydrocarbons (Welte, 1972; Magoon and Claypool, 1983; Krooss and Leythaeuser, 1997).

Solution Benzene and toluene are highly soluble in water3 (Price, 1973, 1976; McAuliffe, 1966). In contrast methane is relatively insoluble in fresh water at low temperature and pressure (McAuliffe, 1966), although at higher temperature and pressure a solubility increase of 300 times was reported at 6,096 m (20,000 feet) (Culberson and McKetta, 1951). Generally, the solubility of petroleum compounds decreases in the order: aromatics cycloalkanes normal alkanes, although the majority of petroleum compounds have solubilities in water that is less than 1.0 mg liter (McAuliffe, 1966) at 25 癈. Most economic accumulations of petroleum consist of compounds that are insoluble in water.

Hydrocarbon phase migration The pressure-driven, hydrocarbon-phase movement of petroleum is shown in Figure 36 (Ungerer et al., 1983). A source rock containing organic carbon (4.0 wt. %) is equal to 9.8% organic matter by volume. At depths greater than 1,500 m the organic matter would occupy a significant proportion of available pore space. A source rock containing more than 4% Corg would become 憃il wet? (with an associated high resistivity). The presence of networks of both bitumen and oil increases the oil wettability of shale, possibly facilitating oil-phase migration (Hunt, 1996). During the transformation of solid kerogen into liquid hydrocarbons, or gas, there is an increase in fluid pressure (i.e., pore pressure) (Momper, 1978; Ungerer etal., 1983). The combined effects of oil generation, the thermal expansion of connate water, rapid burial, and partial transfer of geostatic stress from rock fabric to pore fluid are thought to generate pressure centers within the source rock; which induces micro-fracturing, along which migrating hydrocarbons are expelled (Figure 36). This pressure driven mechanism of primary migration is thought to involve many repeat cycles:

pressure build-up microfracturing hydrocarbon expulsion pressure release oil generation expansion

(repeated many times)

3 Price (1973, 1976) and McAuliffe (1966) report solubilites of 1,740 ppm (+17) and 1,780 ppm (+45) respectively for benzene, and 554 ppm (+15)

and 515 ppm (+17) respectively for toluene at 25? C

Table 5. Effective diameter of selected molecules

Molecule Effective diameter (Nm)

Water ~0.32 Carbon dioxide 0.33 Methane 0.38 Pentane 0.46 Benzene 0.47 n-alkanes 0.48 Cyclo-hexane 0.54 Complex ring structures 1.00 to 3.00 Asphaltene molecules 5.00 to 10.00

Source: Stewart (1928), Welte (1972), Hunt (1979, 1986), Tissot and Welte (1984)

Figure 36. Microfracture-induced hydrocarbon-phase migration during oil generation. (A) Represents the initial stage prior to oil generation, in which the bulk of the source rock is water-wet. (B) Oil generation has occurred with the creation of an oil-wet pore network around the kerogen. The generation of oil creates an increase in pore pressure that either opens existing fractures or creates new ones. The oil is then expelled along oil-wet microfractures (modified and redrawn from Ungerer et al., 1983).



31

Secondary migration

Secondary migration is defined as the movement of petroleum through more permeable and porous carrier beds and reservoir rocks. Secondary migration terminates once the hydrocarbons encounter a trap, but may be re-initiated by tectonic events; known as 憆e-migration? or 憈ertiary migration.? Secondary migration and the subsequent entrapment of petroleum is controlled by three parameters: the buoyant rise of petroleum in water-saturated porous rocks, capillary pressure, and hydrodynamic flow.

The main driving force for secondary migration is considered to be density, in which hydrocarbons move in the direction of decreasing energy. Because oil and gas have lower densities than the surrounding, subsurface, aqueous pore fluid, the process of secondary migration is essentially driven by buoyancy, due to differences in density. The density differences are:

Oil s.g. = 0.5 to 1.0 g cm-3

gas s.g. = less than 0.01g cm-3

pore fluid s.g. = 1.0 to 1.2 g cm-3

Countering the buoyant rise of petroleum is capillary pressure. Within a multi-phase system consisting of immiscible phases (e.g., water and oil), an interfacial tension will exist across the contact interface. Capillary pressure is the pressure difference across the multi-phase interface. The greater the difference in interfacial tension between two phases, the greater the capillary pressure. When a small drop of oil is added to water, the oil globule assumes a shape of least surface area (Figure 37), which is a sphere due to interfacial tension ( ). The force required to distort that sphere, and subsequently drive the oil droplet through a small pore throat, is often referred to as the driving force or more correctly the injection pressure (Berg, 1975).

As a general rule, capillary pressure increases with increasing interfacial tension and/or decreasing pore throat diameter. The termination or continuation of movement is determined by an interplay between the driving force (e.g., density) and the resisitive force (i.e., capillary pressure). As shown in Figure 38, to drive an oil globule between the two grains, considerable energy must be exerted on the globule to overcome surface tension effects, increase the curvature of contact, and reduce the effective radius of the oil. When the upper and lower radii (r) within the distorted globule are equal to one another, the capillary force is overcome and the globule can rise due to buoyancy.

Subsurface water flow may assist, modify, or even counter the movement of hydrocarbons. The existence of high capillary pressure within narrow rock pore throats is the main cause for hydrocarbon entrapment. Video 4 shows oil and water moving through porous media.

Figure 37. Surface tension on a droplet; the arrows show the pull of the attractive forces.

Figure 38. The movement of an oil globule (black)through a pore throat in water-wet rock (blue).The buoyant movement of the oil globule isopposed by capillary pressure until both thecurvature contact and the internal radius (r)decrease and are equal at the lower and upperends of the globule (right) (after Berg, 1975; andothers). P = internal pressure within the globule

= interfacial tension

r = globule radius

rp = globule radius outside the pore

rt = globule radius inside the pore

Video 4. Oil and globules of water moving through a water-wet pore network.Note that each grain is coated with water (i.e., water wet); also note that water globules, e.g., 慩?are 慸istorted? as they pass through the pore throats as shown in Figure 38 (Dong et al., 2007, used with permission).



32

Post emplacement processes

Introduction

揟he history of petroleum does not end when petroleum products are pooled into reservoirs? (Connan, 1984, p. 299). Changes, sometimes subtle, effect petroleum after it leaves the source rock. Beyond the changes in composition that can occur during migration (e.g., fractionalization) several post-accumulation processes have the potential to modify petroleum within the reservoir or even during migration. For the most part, the alteration is generally considered destructive or a degrading process. For example, increases in temperature within the reservoir (i.e., in-reservoir maturation) will lead to a decrease in the relative proportion of higher molecular weight compounds (i.e., C15+) and a relative increase in the low molecular fraction. A decrease in pressure within the reservoir could lead to the deasphatling of petroleum through the precipitation of higher molecular weight compounds within the reservoir.

Perhaps the two most prevalent alteration processes to effect reservoired petroleum include water-washing and microbial biodegradation. Degradation by the process of water-washing and the microbially-derived process of biodegradation is a widespread phenomenon; for example, the seven largest super-giant accumulations of tar sands (degraded crude) contain as much oil as the 264 largest conventional oil fields (e.g., Athabasca tar sands, Western Canada, = 700 to 1000 ? 109 bbl), due to the degradation of a medium-gravity crude oil into a tar sand with an associate API gravity <10? (Larter et al., 2006; Koksalan et al., 2006).

Several stages of degradation are typically referred to, such as incipient, minor, moderate, and extensive to severe (e.g., Blanc and Connan, 1994) or given a numeric value using the scheme of Peters and Moldowan (1993).

Thermal cracking

The thermal cracking of pooled petroleum can occur when the temperature within the trap increases. The characteristic changes of thermal cracking of pooled oil are considered (Blanc and Connan, 1994) to include an increase in the gas-to-oil-ratio (GOR), an increase in light hydrocarbon content, and the production of a solid residue that is often, incorrectly, referred to as pyrobitumen. An excellent micrograph of pyrobitumen from Western Canada, displaying an optical texture, is given in Figure 39. Pyrobitumen contains very little hydrogen and is insoluble in a chlorinated solvent.

The temperature at which thermal cracking is considered to occur varies from region to region, depending upon the pressure and temperature regime of the area. In general, an increase in pressure increases the thermal cracking threshold. For example, in Western Canada the threshold temperatures are considered to be between 93? to 104? C, in contrast to 150? C within the Niger delta and up to 175? to 204? C in parts of California (Blanc and Connan, 1994).

Water washing

This process involves the removal of water-soluble compounds by flowing water within the trap. Low-weight aromatic compounds (especially benzene and toluene) are the most soluble compounds, whereas the C15+ normal alkanes are typically unaffected. Consequently accumulations of pooled oil effected by water washing may exhibit a slight decrease in API? gravity and a loss in those compounds (Connan, 1984; Palmer, 1984).

Deasphalting

The precipitation of solid residue containing asphaltene compounds can occur either because a decrease in pressure occurs within the reservoir or can be due to the introduction of gas into the pooled oil. The introduction of gas into the oil reservoir decreases the average molecular weight of the oil, promoting the precipitation of a solid residue (Blanc and Connan, 1994).

Figure 39. An example of pyrobitumen from Western Canada displaying an optical texture as seen in reflected white light using crossed polarized light (image courtesy of L. Stasiuk).



33

Biodegradation

The transformation and degradation of petroleum within a reservoir by living organisms (primarily bacteria) is considered to occur at relatively shallow depth in the presence of flowing water (Connan, 1984); although the bacterial degradation of oil can occur under both oxic and anoxic conditions (e.g., Zengler et al., 1999). High rates of degradation are seen within shallow reservoirs that are flooded by meteoric water (high sulfate and low salinity). For example, within Saskatchewan (Canada) reservoirs of Mississippian age the degree of biodegradation increases as the influx of low saline and sulfur rich water increases.

Bacteria cannot live by oil alone! A sufficient supply of nutrients, such as nitrate and phosphate, are required in addition to a diet of hydrocarbons! Furthermore, the bacterial degradation of petroleum takes place at the oil-water interface, not within oil and at a rate that is dependent upon the oxic-anoxic conditions of the flowing water. Aerobic bacteria are the most effective, whereas anaerobic, sulfur-reducing bacteria are less effective (Connan, 1984; Aeckersberg et al., 1991).

The time thought necessary to degrade petroleum within the reservoir petroleum was thought to be fairly long (e.g., ZoBell, 1973). However, recent work has suggested that under optimal conditions, the anaerobic biodegradation of reservoired oil can occur at rates of 10-6 to 10-7 a year at 60 癈, and 10-2 to 10-1 a year at the earth抯 surface (Larter et al., 2000, 2003). This would suggest that some transformation could occur within the life-span of many oil fields if care is not exercised during production.

Changes due to biodegradation Non-biodegraded oils are generally paraffinic, paraffinic-napthenic, or moderately aromatic in nature (see Chapter 1). In contrast, biodegradation leads to recognizable changes in oil type; and the effect on gross properties is summarized in Table 6. The preferential removal of gases or compounds within the gasoline range generates a residuum of increased viscosity and 癆PI gravity. A similar effect can also occur by water-washing, evaporation, and/or atmospheric photo-oxidation. With progressive biodegradation, compositional changes include the removal of C15+ alkane and aromatic compounds and a relative increase in NSO-bearing compounds. Figure 40 shows a progression of effects upon reservoir oil due to biodegradation (Deroo et al., 1974). The relatively non-biodegraded oil from the Bellshill Lake property contains the expected range of nalkanes, in contrasted to oils from the Edgerton, Flat Lake, and Pelican Lake properties respectively, that show a marked increase in biodegradation marked by a progressive loss in nalkane content and a large pronounced 慴aseline-hump.? Such changes are associated with a decrease in 癆PI gravity, from an API of 28? for the Bellshill Lake oil down to 14? to 16?API for the Pelican Lake crude oil.

Figure 40. Gas chromatograms (alkanes) of progressively biodegraded oil from pools within Western Canada showing varying degrees of biodegradation. The small bar- charts show the relative distribution of nalkanes, isoalkanes and cycloalkanes (from Deroo et al., 1974; reprinted by authority of the Canadian Society of Petroleum Geologists).

Table 6. A summary of changes in composition due to biodegradation (after Connan, 1984).

1. Dry and wet gas (C1 to C6) [DECREASE]

2. Gas/oil ratio [DECREASE]

3. Gasoline range (C6 to C15) [DECREASE]

4. APIo gravity [INCREASE]

5. Viscosity [INCREASE]

6. Compositional changes in C15+ compounds

alkanes [DECREASE]

aromatics [DECREASE]

NSO-bearing compounds [INCREASE]

7. Sulphur / sulfur content [INCREASE]

8. Nitrogen content [INCREASE]

9. Metal content (e.g., V and Ni) [INCREASE]

10. Pour Point [DECREASE]

11. Possible changes in oil type

Original oil type Altered oil type

Paraffinic Naphthenic

Paraffinic-naphthenic Aromatic-Naphthenic

Paraffinic condensate Naphthenic condensate

Condensate Light oil

Aromatic-intermediate Aromatic-asphaltic



34

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36

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Chapter 4—Reservoir, Trap, and Basin

37

RRReeessseeerrrvvvoooiii rrr ,,, TTTrrraaappp,,, aaannnddd BBBaaasssiiinnn

IntroductionSedimentary basins are of great importance in the exploration and exploitation of petroleum because they provide good prospects for:

an accumulation of sufficient source rock

the attainment of sufficient temperatures to transform kerogen into petroleum

the existence of petroleum migration pathways

the presence of reservoir rock

the existence of a seal

the opportunity to form a trap

We have already examined the compositional states of petroleum and reviewed the general theory concerning source rock geochemistry, petroleum generation, and migration. In this section we will examine the nature and character of the reservoir rock, various types of trap and the role of the sedimentary basin (for a quick overview see Video 5).

Oil and gas are mobile fluids and migrate within the subsurface from zones of relative high pressure (e.g., the source) to zones of relative low pressure, and unless that movement is arrested within the subsurface, migrating oil and gas will eventually escape to the earth抯 surface. Therefore, an arresting mechanism must be in place to halt the upward migration of oil and/or gas, a mechanism commonly known as a trap. A trap is basically any geometrically arranged strata, within the subsurface, bound by a sealing surface that is capable of retaining petroleum. A trap therefore, must be capable of receiving and retaining petroleum (a term known as charge). Regardless of trap type, all traps share a few common elements; which include both the presence of a reservoir rock and a sealing surface or seals. The reservoir rock must have good effective porosity and be permeable (Figure 41), whereas the seal must have either a relatively low effective porosity or high capillary entry pressures. Furthermore, the reservoir rock within a trap is typically water-wet, so in addition to receiving petroleum, a trap must allow the expulsion of displaced water during charge, and subsequently be capable of re-admitting water during the production of petroleum.

Reservoir rock

Introduction and definition

A reservoir is defined as 搮 a subsurface rock formation containing an individual and separate natural accumulation of moveable petroleum that is confined by impermeable rock or by water barriers and is characterized by a single-pressure system? (SPE/WPC/AAPG, 2001, p. 8). This definition uses several key terms to distinguish a reservoir rock from non-reservoir rock. The existence of a single-pressure system is highly significant in that it recognizes the importance of fluid continuity within a reservoir; the definition further recognizes that a natural accumulation of petroleum must be capable of being moved (recovered), and that the reservoir is bounded (confined) by fluid barriers and is therefore a container. This chapter

Figure 41. Scanning electron microscope image ofreservoir rock. This dolomite (Midale Formation, Williston Basin, Saskatchewan, Canada) contains pore throats that range in size from 2 to 15 m.

Video 5. From sediment to trap. From 揟 he Making of Oil,? (? 1997 Schlumberger, Ltd. used with permission).


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area in between the large grains becomes increasingly in-filled with finer material. Sorting also affects the size range of available pore throats and tortuosity. Tortuosity is an expression of the physical distance an oil globule may take when moving through the reservoir (Figure 42). Tortuosity normally increases as the degree of sorting decreases.

Packing: The geometrical arrangement of grains has a marked influence upon porosity, especially a reservoir rock comprised of spherical uniform grains! Six theoretical packing arrangements are recognized (North, 1985), in which the proportion of pore space varies from case to case. For example, Case 1 (cubic close packing) has a theoretical maximum porosity of 47.6%, whereas Case 4 (orthorhombic) has a theoretical maximum porosity of 39.5% and Case 6 (rhombohedral) has a theoretical maximum porosity of 26% (North, 1985). Cementation and matrix material: Cementation typically leads to a reduction in porosity within siliclastic rocks. Shape: Generally, higher porosities are associated with well-sorted, angular to subangular, grains. Grain / particle size: The influence of grain size would appear to be masked by particle sorting.

Secondary porosity

Porosity that is formed in response to post-depositional or diagenetic processes is traditionally termed secondary porosity. Diagenetic mechanisms such as compaction, cementation, dissolution, and recrystallization (neomorphism)modify the original (i.e., primary) pore network of a sedimentary rock; as a consequence, secondary porosity can be greater or lower than the original primary porosity. Different diagenetic processes act upon siliciclastic and carbonate rocks to alter porosity.

Carbonate reservoirs: Changes in porosity occur mostly due to the solution, neomorphism (incl. dolomitization), fracturing, and cementation of grains.

Siliciclastic reservoirs: Changes to primary porosity include the reduction of porosity through the interlocking of grains due to compaction, contact-solution, and cementation.

Compaction: During burial, sediments (for example, sand) undergo mechanical compaction due to a net increase in overburden pressure. Porosity is reduced at a rate that is typically rapid at shallow depths, decreasing with burial depth (Figure 43). Porosity is lost due to one or more of the following: the geometrical rearrangement of individual grains into a tighter packing arrangement by the fracturing and crushing of brittle grains, or the plastic deformation of ductile grains and pressure solution (McBride, 1984). Pressure solution takes place at the interface of fossils, flints, and interruptions to bedding. During the process of pressure solution, insolubility residues, including clay minerals and/or organic matter, are concentrated into fine layers (stylolites).

Cementation: The cementation of grains during diagenesis typically reduces original pore space (McDonald and Surdam, 1984), although Wilson and Pittman (1977) note that original porosity can be preserved if cementation protects the rock from further compaction.

Dissolution: The dissolution of less chemically stable minerals can increase both porosity and permeability (Schmidt etal., 1977). An example of dissolution in carbonates is karstification, which can lead to the creation of vugs, potholes, and caverns in limestone (Tucker and Wright, 1990).

Recrystallization and Neomorphism include the processes of replacement and recrystallization in carbonates (Folk, 1959, 1965). A replacement fabric occurs where there has been a change (i.e., replacement) in mineralogy (neomorphism), whereas recrystallization involves a change in crystal size without a change in mineralogy.

The classification of porosity

Siliciclastic rocks In contrast to carbonate rocks, the treatment of porosity for siliclastic rocks is less complex. Pittman (1979) recognizes four basic types of porosity in sandstone rocks (Figure 44), which include: Intergranular porosity, which is the porosity that exists between grains. Microporosity is characterized by pore-throats that are less than 1 m (Pittman, 1979) and

Figure 44. A schematic of the four basic pore types for siliciclastic rocks: intergranular, microporosity, dissolution and fracture as proposed by Pittman (1979) (after Cone and Kersey, 1992).

Figure 43. The relative decrease in porosity forsandstones of differing geological age due to depth of burial (after Athy (1930); North (1985); Levorsen (1954); and others.



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difficult to detect with a 10x binocular microscope. Dissolution porosity is porosity formed by the partial or complete dissolution of framework grains and/or the cement. Fracture porosity is recognized as porosity created by the natural fracturing of the rock fabric (Cone and Kersey, 1992).

Carbonate rocks Because porosity within a carbonate rock is the product of diagenetic processes and/or conditions of deposition (Lucia, 1995), a greater number of pore types have been identified for carbonate rocks than for the siliciclastic rocks (i.e., sandstone). The classification scheme of Choquette and Pray (1970)initially subdivides porosity into three groups (Figure 45), known as Fabric Selective, Not Fabric Selective, and Fabric Selective or Not Fabric Selective. Within the Fabric-selectivegroup, the character of the grains or particles (i.e., the fabric) of the rock defines the pore type. In contrast, the Not Fabric Selective porosity cross-cuts the rock fabric, and in FabricSelective or Not Fabric Selective, pores may or may not display a fabric control! For an in-depth discussion on porosity in carbonates see (Choquette and Pray, 1970; Fl黦el, 1982; Longman, 1980; Tucker and Wright, 1990; Lucia, 1992, 1995;among others).

Permeability

First, we will explore concepts that influence permeability.

Fluid saturation: Fluid saturation is the volume of a given fluid, within reservoir rock, expressed as a fraction (or percent) of the total pore space.

Surface tension: Surface tension occurs at the fluid interface of an immiscible fluid. An attractive force (i.e., cohesive force)exists between molecules within the fluid. However, molecules at the surface do not have like molecules on all sides and as a consequence cohere more strongly to other like molecules within the surface layer. This cohesiveness creates a surface 慺ilm,? known as surface tension. Figure 46 shows a droplet of fluid (e.g., water). Because the cohesive forces within fluid are greater than any possible attraction between the droplet and the surrounding fluid (in this case air), the cohesion of molecules within the fluid surface creates a surface 慺ilm? causing it to act like a stretched elastic membrane pulling the droplet into a spherical shape. When the attractive force is between unlike molecules (e.g., glass/water), the force is considered to be an adhesive force.

Wettability: Wettability is the ability of a fluid (i.e., the wetting phase) to coat the grain or mineral surface within a rock. In a three-phase system (i.e., rock, oil and water), cohesive and adhesive forces act within and between the fluids and the rock surface. The fluid with the greater affinity for the solid surface is the wetting fluid. In a water-wet, oil-charged reservoir the oil will exist within the central area of the pore space (Figure 47) whereas the water will be restricted to grain surfaces and as irreducible water within the micropores of the reservoir rock. When the cohesive force is greater than the adhesive force, the liquid is nonwetting.When the adhesive force is greater than the cohesive force, the liquid is wetting. The wetting phase forms the acute angle with the rock/mineral surface, whereas the non-wetting phase forms the obtuse angle (Figure 48). How thick is the wetting layer? Maher et al. (1992) determined the thickness of the wetting layer to be no more than 3 molecule layers (10-3

microns) within the Piper sandstone, North Sea Basin.

Figure 45. A schematic of the three basic porosity-types for carbonate rocks: fabric selective, not fabric selective and fabric selective or not fabric selective, and sub-types (after Choquette and Pray, 1970).

Figure 46. Surface tension on a droplet, the arrows show the pull of the attractive forces.

Figure 47. Water, as awetting phase (blue),coating grain surfaces.

Figure 48. Determining wettability: (a) when the acute angle 憏? is less than the obtuse angle 憐? the fluid is wetting; (b) water as the wetting phase; (c) oil as the non-wetting phase.



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Capillary pressure: Capillary pressure in rock is controlled by interfacial tension, wettability, and pore-throat size distribution; specifically interfacial and surface tension and wettability, as discussed above. If a capillary tube is placed into a wetting fluid (Figure 49), adhesive forces (between the fluid and solid) draw the fluid into the tube. The wetting phase (Pw) will rise in the tube, to a height (h) above the free surface, until gravitational and adhesive forces balance. The difference in pressure between the wetting (Pw) and nonwetting phase (Pnw) across the meniscus in the capillary tube (Figure 49) is referred to as the capillary pressure. Within a capillary tube, the wetting fluid will rise to a height which depends upon the tube radius, surface tension, liquid density, and the contact angle between the solid and the liquid. Capillary pressure increases as the diameter of the capillary tube decreases.

Saturation height and capillaries: A reservoir contains pores and pore throats of different size. Representing reservoir pore throats by a series of capillary tubes of differing diameter (Figure 50) permits an explanation of fluid saturation height within the reservoir. The largest diameter capillaries determine the depth below which water saturation is 100%. This point is the oil-water contact (OWC, Figure 50) where Sw = 100%. In contrast, the narrowest capillaries determine the depth above which only irreducible connate water will occur (Swirr, Figure 50). A transition zone occurs between these two points, characterized by a gradual change in water saturation; the height of the transition zone depends upon the size-distribution of pore throats within the reservoir and the difference in density between water and a given oil. The free water level (FWL, Figure 50) is that point where capillary pressure is zero. As a reservoir is charged with oil, water is displaced downward commencing with the largest pores (lowest capillary pressure) and ending with the finest pore throats.

Irreducible water (Swirr): The percentage of effective porosity that is occupied by a wetting phase fluid (i.e., water) that cannot be removed by a non-wetting phase (i.e., oil) is known as irreducible.

Coefficient of permeability Permeability (K) is the ability of a rock to transmit fluids, without changing the structure of the rock or a displacement of its components. Permeability, K, is traditionally derived using Darcy's Law (Darcy, 1856). However, from the standpoint of the petroleum reservoir rock the coefficient of permeability, k, maybe simply derived by:

k = Nl2 (4)

where: N = is a dimensionless number representing a given group of rock characteristics (grain shape, packing).

l = the length of the pore structure of the rock (pore size and tortuosity).

The field unit for permeability is the Darcy (D) or more typically millidarcy (mD). Essentially 1 Darcy represents a permeable rock that will release 1 cm2 of fluid from 1 cm2 of rock in 1 second, although petroleum geologists and engineers typically use the mD because reservoir rocks typically possess significantly lower permeabilities (Table 7).

Figure 49. A single capillary tube. The wetting phase will rise to height (h) above the free surface when adhesive and gravitational forces balance. Pnw: pressure (non wetting phase), Pw: pressure (wetting phase) NB not to scale.

Figure 50. Saturation-height within a trap shown against a series of capillaries of differing diameter, in which SSwirr: irreducible water saturation; OWC: oil-water contact; FWL: free water level; note for simplicity only water is shown within the reservoir.



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There is also an SI unit1 of permeability, based upon the square micrometer ( m2), where 1.0 Darcy = 0.987 m2. Oil reservoirs associated with good permeability have values ranging from 50 to 200 mD, whereas poor oil reservoirs would have values of 15 mD or less. In contrast, gas reservoirs can often have lower permeability values, due to the lower viscosity of gas compared to oil. Table 7 gives a comparison between 憅ualitative assessments? of permeability, milliDarcies, and SI units.

Effective permeability Absolute permeability (i.e., k) is considered to be independent of fluid viscosity. However, if water and oil (or water + gas, or oil + gas + water) are present within the reservoir absolute permeability is essentially irrelevant because the relative saturation of each immiscible fluid as well as the nature of the reservoir (e.g., pore throat size/distribution, porosity) affect the effective permeability. Effective permeability is the ability of a reservoir to preferentially transmit a particular fluid when other immiscible fluids are present in the reservoir. Effective permeabilities for immiscible fluids are given the following notation ko

(oil), kg (gas), and kw (water), and range from 0 to k (i.e., 0 to 100% or 0.0 to 1.0), but are typically less than k.Furthermore, summations of effective permeability are always less than 1 because interference effects are retarding not enhancing.

Relative permeability Relative permeability (kr) is the ratio of

the effective permeability of a given fluid, at a given saturation, to absolute permeability at 100% fluid saturation, expressed as a percentage or decimal. In a single fluid system, the relative permeability of that fluid would be 1.0.

Reservoirs are initially saturated with connate water. As oil (or gas, or a mixture of oil and gas) moves into a reservoir, the connate water must be displaced; expelled from the reservoir and/or driven into finer and finer pores, where it will eventually be held by capillary forces as irreducible water. Therefore, in a water-wet reservoir undergoing oil charge, as the water saturation (Sw) decreases and the relative permeability to oil (kro) increases (Figure

51, inset [a] to [d]). The ability to

1 Syst鑝 e International d'unit閟 (International System of Units), which includes: length (metre), mass (kilogram), time (second),electric current (ampere), thermodynamic temperature (kelvin), amount of substance (mole), luminous intensity (candela).

Figure 51. Fluid saturation and relative permeability. The presence of more than one fluid changes the potential of other fluids to flow. Four fluid saturation examples are identified on the oil and water curves (points a, b, c, and d), corresponding to water saturations of 1.0, 0.9, 0.6, and 0.2 respectively, as discussed in the text (after Clark, 1960; Arp, 1964; and others).

Table 7. A comparison of qualitative assessments of permeability and values expressed in both Darcy and SI units.

Qualitative assessment permeability (mD) permeability (SI units: m2)

Poor to fair 15 or less 14.85 or less Moderate 15 to 50 14.85 to 49.35 Good 50 to 200 49.35 to 246.75 Very good 250 to 1000 246.75 to 987 Excellent 1000 or greater 987 or greater



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produce water-free oil, or a limited amount of water during oil production is in many respects governed by the saturation and relative permeability of each fluid (Figure 51).

At a water saturation of 1.0 (Sw=100%, Figure 51, inset [a]), kro is 0.0 and

only water is produced. At relatively high levels of water saturation (e.g., Sw=90%, Figure 51, inset [b]), oil may exist as discontinuous globules within the largest pores of the reservoir and although the relative permeability to water (krw) is 0.65, the relative permeability to oil (kro)

remains at 0.0 because water is the only continuous phase. Hence only water is produced. At a water saturation of 0.6 (Sw=60%, Figure 51, inset [c]) oil exists as both a continuous phase and as discrete, isolated globules. Only the continuous phases will flow and as a consequence both oil and water will be produced, but in reduced amounts because the two fluids also interfere with each (Video 6). This interference also causes a net reduction in effective permeability, to less than 0.4 (40%) of the total permeability of the rock ?kro+ krw? line, creating relative permeability

values of kro = 0.19 and krw = 0.17 respectively. At a water saturation of

0.3 or less (Figure 51) the relative permeability to water becomes effectively zero because water is adhered to the surfaces of grains (i.e., bound) and also confined to the finest pores within the reservoir; water has become irreducible (Swirr) and the reservoir will yield only oil (Figure 51, inset [d], Sw = 20%, krw = 0.0, and kro = 0.95). The relative permeability curves shown in

Figure 51 are for illustrative purposes only. The shape of each curve and points of cross-over will vary from reservoir to reservoir depending upon the size distribution of pore throats, fluid viscosities, wettability characteristics of the rock, and the height of the oil column.

Figure 51 illustrates the generalized interaction of fluids within a reservoir. From a practical point of view, the 憈ransition zone? presents many challenges to the petroleum geologist and engineer. When water exists as a continuous phase and oil as the isolated phase (e.g., Sw = 0.6, Figure 51) the continuous phase will be preferentially produced (for a given reservoir pressure). To produce isolated oil (oil globules) the surface tension must be reduced (e.g., use of surfactant), or overcome by an increase in driving pressure (e.g., water drive), or the pore throats must be increased (e.g., reservoir acidification). Oil that remains within a reservoir is typically called 憆esidual oil.?

Reservoir rock characteristics

The heterogeneity of reservoirs Traps rarely consist of a single homogeneous reservoir rock. Reservoir rocks typically possess lateral and vertical variations in grain size, sorting, porosity, and permeability, reflecting differences in depositional (primary) or diagenetic (secondary) process (Biddle and Wielchowsky, 1994; Morse, 1994), typically creating various degrees of reservoir complexity. Further information regarding the depositional setting of siliclastic and carbonate rocks is available in Scheihing and Atkinson(1992) and Lucia (1995).

Heterogeneity exists at a variety of scales, creating intra-reservoir fluid-flow barriers and preferential directions of fluid movement (anisotropic permeability). Studies of reservoir heterogeneity describe the geological complexity of a reservoir and the impact of that complexity upon fluid flow (Slatt and Galloway, 1992). Heterogeneity within a reservoir (i.e., intra-reservoir heterogeneity) can segment reservoirs into compartments, each of which can have separate petroleum-water contacts, differing capillary entry pressures, and different fluid pressures; all representing complications of a single trap (Biddle and Wielchowsky, 1994) or the subtle interplay of differing seals (D. Powley and J. J. Bradley, 1987, personal communication) creating a hierarchy of flow units (Ebanks et al., 1992) and fluid pressure compartments (Bradley and Powley, 1994).

Figure 52. Scales of reservoir heterogeneity recognized in the siliclastic reservoirs of the Bartlesville Sandstone in the Glenn Pool field, Oklahoma (after Kuykendall and Matson, 1992).

Video 6. Oil and water moving through a pore network. Note that grains are . water wet. This example is close to Sw=60%, Figure 51, inset (c).(after Dong et al., 2007, used with permission).



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Kuykendall and Matson (1992) demonstrate this point well in their review of the Bartlesville sandstone of the Glenn Pool field, Oklahoma (Figure 52). A detailed analysis of the alluvial-deltaic and alluvial valley-fill systems that comprise the Glenn Pool field reveal a reservoir consisting of differing scales of heterogeneity; reservoir heterogeneity that includes variability in grain size, sorting, porosity, and permeability discernable at the megascopic scale (km to tens of m), the macroscopic scale (tens of m to m), the mesoscopic scale (m to cm), down to the microscopic scale (cm to mm and mm to m). Although Kuyendall and Matson (1992) do not use the term nanoscopic (i.e., m to mm), the term nanoscopic completes the range, since it conveys a level of heterogeneity that exists at a level that is visible using a high magnification petrographic microscope or a scanning electron microscope (i.e., mm to m). Recognition and the determination of reservoir heterogeneity is especially critical when reservoir production methods switch to enhanced recovery methods (such as water injection); maximum efficiency and maximal effectiveness of any enhanced recovery method adds additional reserves and increases the profitability of the field. Therefore, the acquisition and description of drill core is as fundamental to the understanding of reservoir heterogeneity as is the use of petrophysical logs, determination of porosity and permeability (e.g., porosimetry), and the application of computer reservoir modeling and vizualization tools. The core box images in Figure 53 show the Campanian Sussex sandstone in the House Creek area, Wyoming (Bergman, 1999); stratigraphic top is upper left of box 1 and stratigraphic bottom is lower right of box 2 (Figure 53). As you examine the core box images, consider the heterogeneous nature of this segmented reservoir and the probable variations in porosity and permeability due to variations in grain size, sorting, the presence or absence and type of sedimentary features. For example, porosity and permeability will probably be greater in the coarser grained units and be greatly diminished in the mudstone layers.

Figure 53. Core box images of Campanian Sussex sandstone in the House Creek area, Powder River Basin, Wyoming, U.S.A.; Milestone #14-9 Federal SW SW 9-42N-71W (core photographs courtesy of K. M. Bergman).

The core is 10 cm (4 inch) in diameter and has been cut lengthways. Stratigraphic top is to the upper left of box 1 whereas stratigraphic bottom is at the lower right of box 2. Depth markers are in feet, scale bars in cm, and the small black arrows indicate way up. The cylindrical holes (e.g., box 1) are sampling points (i.e., sample removed for porosimetry analysis).

Note variations in lithology and the presence of sedimentary features, some of which are shown in the eight enlarged images, that run from stratigraphic bottom (lower right) to stratigraphic top (upper left).

Box 2 (a): note the presence of coarse-grained sandstone (i), a dark gray to black mudstone containing silty lenses (ii), and the sharp contact at the base of the Sussex sandstone (arrow).

Box 2 (b): showing (i) a bioturbated mudstone interspersed by thin small cross-laminated very fine to fine sandstone beds; many of the sandstone beds have bioturbated tops.

Box 2 (c): a fine- to medium-grained sandstone (i) that overlies a bioturbated sandstone and mudstone (ii) and is overlain by fine interbeds of mudstone (arrow). Asymmetrical small-scale cross laminations are visible within (i).

Box 2 (d): pebbly to medium-grained sandstone (i), overlain by cross-bedded sandstone(ii).

Box 1 (e): medium-grained sandstone (i) overlain by bioturbated sandstone (ii and iii).

Box 1 (f): a pervasively bioturbated fine- to medium-grained sandstone (i) with burrows (ii).

Box 1 (g): a bioturbated and burrowed sandstone (i) overlying a highly bioturbated fine-grained sandstone and mudstone unit (ii).

Box 1 (h): a cross-bedded conglomerate (i) underlies a very fine- to fine-grained bioturbated sandstone (ii and above).



45

Seals and sealing surfaces

Introduction

So far, we have focused upon the reservoir and the many concepts that principally deal with the geological characterization of reservoir rocks. Successive sections of this chapter will deal with trap type and the role of the basin; however, it is appropriate to examine the role of sealing surfaces since an effective seal is an integral component in the entrapment of petroleum, and there are a number of initiatives, such as the Australian APCRC program, with a mandate to better understand seal integrity and seal characteristics.

A seal (Figures 54 and 55) is a relatively impermeable lithology such as shale, anhydrite, or salt, that forms a barrier above and around a reservoir rock within a trap so that entrapped petroleum fluids cannot migrate beyond the reservoir (Downey, 1994; Sneider et al.,1997). A sealing surface is a continuous seal (i.e., barrier) that isolates a fluid compartment, either within a reservoir or between discrete reservoirs. Rocks that serve as seals typically have pore throats too small and/or poorly connected to allow the passage of petroleum (Downey, 1994). The majority of seals are water wet and function as capillary seals, although, as we shall see, non-capillary seals are also recognized.

Types of seals

Figure 54 shows the relative location of a top seal, lateral seal, and bottom seal for a simple stratigraphic trap, although there are many possible ways of describing and classifying seals, sealing surfaces and sealing lithologies. For example, Bradley and Powley (1994) differentiate between a pressure seal and a capillary seal, Sneider et al. (1997) recognize a number of seal types based upon the height (of a column of 35 癆PI oil) above the free water level. Ulmishek (1988) differentiates between regional seals, such as those that 憆oof? migrating petroleum within a stratigraphic sequence or basin, and local seals that confine petroleum within a trap. Furthermore, geological faults can be both sealing and non-sealing (Downey, 1994), and even within an individual fault plane sealing properties can change. In general, the ability of a fault to seal depends upon the juxtaposition of faulted lithologies, the alteration and deformation of lithologies within the fault plane, and the vertical permeability of the fault (Hippler, 1997).

Sealing mechanisms

Capillary seals Lithologies are inherently water wet. Also recall that capillary entry pressure increases as the diameter of the capillary tube decreases2. Petroleum moving through a reservoir rock is driven by buoyancy (buoyancy pressure), which is a function of (1) the density difference between wetting and non-wetting phases, and (2) the height of the oil above the free water level. Countering this upward movement of oil is a resistive force, which is a function of the minimum capillary entry pressure, which is in turn influenced by: (1) the surface tension that exists between the wetting phase and the non-wetting phase, (2) wettability, and (3) the radius of the largest pore throat within the sealing surface (Sneider et al.,1997). The minimum capillary entry pressure defines the maximum height of an oil column that can be trapped (Al-Bazali et al., 2005).

2

Capillary entry pressure is inversely proportional to the square root of the permeability.

Figure 54. Top, lateral and bottom seals, (from Sneider et al., 1997).

Figure 55. A schematic cross section through the Gidgealpa field,Eromanga Basin, Australia, showing the location and the derivation ofseals, and probable petroleum migration pathways (from Boult et al.,1997).



46

The effectiveness of a seal is determined by the minimumcapillary entry pressure required to displace water within the pores of a seal, and as a general rule the smaller the mean pore throat radius within a sealing surface, the higher the column of oil (above the free water level). The effectiveness of any seal is dependent upon the weakest point (e.g., presence of a fracture, pore-throat distribution, water density) within a given sealing surface.

Pressure seals A pressure seal restricts the passage of petroleum and formation water and is formed wherever the pore throats are effectively closed, that is the permeability approaches zero. Fluid pressure compartments (Figure 56) within a (compartmentalized) reservoir are often due to the existence of pressure seals (Bradley and Powley, 1994).

Trap

Common terms and features

A trap is basically any geometrically arranged strata, within the subsurface, bound by a sealing surface that is capable of retaining petroleum. A trap therefore, must be capable of receiving petroleum (a term known as charge), and secondly, it must be able to prevent the petroleum from escaping. The most basic, type of trap is the anticline (Figure 57) which is used here to illustrate the terms commonly used in describing some of the features and characteristics of traps.

Classification of Traps

Historical There are numerous classification schemes for traps, depending upon the specific emphasis of the author (e.g., seal characteristics, trap geometry), although closure style has tended to predominate. Even the early schemes (e.g., Wilson, 1934) sought to differentiate on the basis of closure recognizing:

1. Traps formed by the local deformation of strata (i.e., anticline),

2. Traps formed by changes in porosity (stratigraphic),

3. Traps formed by a combination of both,

4. Open reservoirs (i.e., seep), and

5. Traps formed by no detectable means of closure!

Attempts were also made to differentiate traps on the basis of trap genesis. For example, the scheme of Heroy (1941) recognized the existence of depositional, diagenetic, or deformational traps; whereas Wilhelm (1945) based his system upon trap genesis which included: convex traps, permeability traps, pinchout traps (lenticular body), fault traps, and piercement traps. The most common distinction, in the western world, has been largely genetic and many trap classification schemes have a common initial subdivision based upon that of Levorsen (1954, 1967), which are:

i. Structural,

ii. Stratigraphic, and

iii. Those that combine both elements.

Figure 56. A simplified depth/pressure plot showing thecreation of two fluid compartments due to the existencepressure seals (from Bradley and Powley, 1994).

Figure 57. An oil and gas charged trap. This is a cross-section through an idealized trap, annotated with terms that are often used to describe the relative fluid zones and fluid interfaces within a gas/oil-bearing (i.e., charged) trap.



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Structural traps are formed by the syn- to post-depositional deformation of strata which includes folding, faulting, piercement, or a combination of any of these. In contrast, closure in a stratigraphic trap exists solely as a result of stratigraphic elements (Foster and Beaumont, 1992) such as changes in facies, changes in porosity/permeability, or by simple erosion. The combination trap type is perhaps more complex because closure is achieved by a combination of stratigraphic and structural influences.

Structural trapsThe rearrangement of strata into a geometrical feature known as a structural trap is achieved by the syn- to post-depositional deformation of strata. Most attempts to subdivide structural traps seek to differentiate between folded, faulted and piercement structures (Figure 58), which is dependent upon the quality of the available information. According to Biddle and Wielchowsky (1994) traps formed by gently dipping strata beneath an erosional unconformity are often excluded from the structural trap category. The most straightforward subdivision of structural traps is to differentiate on the basis of fold dominant versus fault dominant, with piercement structures forming a third category. However, in reality pure fault traps are uncommon (North, 1985).

Fold-dominant structural traps A simple fold cannot trap petroleum because such structures posses only one axis and no closure. A folded structure in which strata dip in all directions creates a convex 慸omal?structure that contains a structural high point and closure (Figure 59). Also fold-dominant structures can be created by both tectonic and non-tectonic

process. Examples of tectonically derived fold-dominant structures include: the arches/domes, thrust-fold assemblages, and the compressive-block trap types of Harding and Lowell (1979) (Figure 60); the buckle-and-thrust and bending fold traps of North (1985); the compressional anticlines of Selley (1985); the fault-related fold structures and the fault-free fold 憀ift off?and chevron/kink band structures of Biddle and Wielchowsky (1994). The non-tectonic category of fold-dominated structures includes those formed by drape folding, slumps, and differential compaction. The term fold will be retained herin, however, because the term describes the general structural style of the trap.

Figure 59. A 慸omal?structure in plan view,o/w=oil water contact.

Figure 58. Categories of structural trap (A to D) (from Biddle andWielchowsky, 1994).

Figure 60. Structural trap types from Harding and Lowell (1979).



48

Examples of fold-dominated structural traps

Tectonically derived

Fold-dominated traps formed by compression are most likely to be found adjacent to an active plate margin (i.e., subduction), or associated with the transcurrent movement of two plates.

The Laojunmiao oil field, in the Gansu Province of the People抯 Republic of China, has been in production since 1941, and contains more than 800 wells, which produce oil from the Miocene Baiyanghe Formation. The Laojunmiao traps (Figure 61) consist of asymmetrical folds formed during the Neogene by basinward thrusting (Guangming and Jianguo, 1992). Closure on the fold is approximately 800 m and the northern flank of the fold is bisected by normal and reverse faults.

The Portachuelo field, in the Talara Basin of Peru, is geologically complex, (Figure 62) although interpretations have evolved throughout time it is now recognized as a highly segmented reservoir (Roe and Millar, 1992). Initially, water distribution was considered typical for a folded (anticlinal) trap, especially since gas was encountered towards the top of the section. However, gas-oil and oil-water contacts were inconsistent. Reservoir pressure data strongly supported the interpretation that the Salinas reservoir was initially charged as a pure fold structure (Figure 62 [A]) that was subsequently 慺lattened? by post-early Eocene faulting (Figure 62 [B]). Roe and Millar (1992) estimate that 40% of the original oil may have been lost from the reservoir during this 慺lattening?event.

Unlike the previous two examples, the fold-dominated traps within the Oligo-Miocene Asmari limestone of Iranare less complex and significantly larger. The Asmari limestone, which reaches a thickness of more than 300 m, was folded into structures with wavelengths of 20 to 100 km and amplitudes of 2 to 5 km (Figure 63), during the Alpine-Himalayan orogeny. The overlying evaporite, being weak under compression, flowed away from the rising anticlinal crests, accumulating in the flanks. Because the Asmari limestone underwent ductile deformation, folding occurred without much faulting. Most of the traps are the result of compressive forces along a plate margin.

Non-tectonically derived

This type is often included under the class of fold-dominant structures, although there is a high degree of control by the underlying surface. Such traps include those formed over a preexisting depositional feature, a paleotopographic surface, or a structurally deformed basement complex.

However, the distinction between a true drape structure and a compactional anticline

Figure 61. The fold-dominated trap of the Laojunmiao oil field, in the Gansu Province of the People抯 Republic of China (from Guangming and Jianguo, 1992).

Figure 62. A portion of the Eocene Salinas Formation of the Portachuelo field, in the Talara Basin of Peru, before (A) and after (B) faulting (from Roe and Millar, 1992).

Figure 63. Cross-sections through numerous oil fields in western Iran, showing the presence of compressional folds within the Asmari limestone, with amplitudes of 2 to 5 km and wavelengths of 20 to 100 km (from Lees, 1953; reprinted by permission of Oxford University Press; www.oup.com).



49

depends upon the nature of the underlying lithology. A compactional fold may form over a (block) faulted basement in which closure of the trap is achieved by the differential burial and compaction of sediments on the crest and flanks of the faulted basement (Figure 64), whereas a drape structure occurs over a non-faulted surface (e.g., reef). One of the best examples of a drape structure over a reef occurs in the Leduc oil/gas field, Western Canada, in which the Devonian dolomite reservoir rock (D2) has been draped over the (non-compatible) D3 reef reservoir separated by sealing shale. Traps within the Viking Graben, North Sea, were initially ascribed to the formation of compactional anticlines (Blair, 1975). More recently (Kirk, 1980), it has been suggested that the actual trapping mechanism is not caused by the convexity of overlying sediment, but by the truncation, by an unconformity, of homoclinally dipping strata.

Fault-dominant structural traps Faults can greatly influence the viability of a given trap, not only through the geometrical rearrangement of strata, but also through the creation of seals or leaks as discussed in the previous section on Seals. Fault planes can act as petroleum conduits or barriers to fluid movement and the variability in sealing capacity of faults is well illustrated within the Piper field in the Scottish North Sea(Figure 65), in which some fault planes seal (A), whereas other fault planes (B and C) do not (Williams et al., 1975; Maher et al.,1992). Fault-dominant traps are sub-divided into three categories: normal-, reverse-, and strike-slip fault-dominated traps.

Normal faults

Normal faults are extensional in genesis and often occur in subsiding basins. Normal faults represent a regular feature of many sedimentary basins and are part of the basin-forming process. Most of these faults are syn- to post-depositional, listric faults that dip towards the basin. If the fault plane dips in the same direction as the regional dip, the faults are synthetic, or 慸own the basin faults? (Figure 66). Synthetic faults are also growth faults, caused by the flexing of lithosphere due to sediment loading. Faults cross-cutting the regional dip, or cutting homoclinal sequences, are antithetic.Synthetic and/or antithetic faults are often responsible for the placement of impermeable rocks against reservoir rocks and represent true fault traps. The Hibernia field, offshore Newfoundland (Arthur et al.,1982), contains both synthetic and antithetic sealing faults.

Figure 64. A schematic cross section showing the formation of a compactional drape (area within red oval) over a faulted basement.

Figure 65. Cross-section through the Piper field of the North Sea, showing sealing(A) and non-sealing (B and C) fault planes (after Maher et al., 1992).

Figure 66. Synthetic and antithetic faults in the Hibernia field, offshore Newfoundland (from Arthur et al., 1982).



50

Figure 68. A three-dimensional visualization of the structural contours overlying salt diapir and wall structures. All structures have discordordant contacts. Guglielmo et al.(1997) refer to deep elongated diapirs as 憌alls,? they also differentiate between low salt walls overlain by symmetrical half grabens termed 憇alt ridges? and low salt walls overlain by asymmetric half grabens that are called 憇alt rollers.? The mean trend of the salt walls and rollers is approximately perpendicular to the direction of extension (from Guglielmo et al., 1997).

Domes and piercement structures

Piercement structures

These regionally large structures represent the folding of overlying rock through the buoyant, upward movement of low density material (e.g., salt) that disturbs and disrupts overlying strata, often creating a variety of traps (Figure 67). Salt domes and diapirs are, therefore, generally considered prospective areas of interest for petroleum exploration since salt has the potential to create a number of structural traps (Halbouty, 1967; Harding and Lowell, 1979). Salt has a density approximately equal to that of recently deposited sand and clay, however in response to compaction the density of clay and sand increases, whereas the density of salt does not. At some depth, (between 800 to 1200 m) the density difference between surrounding lithologies and the salt is great enough to initiate the (upward) movement of salt, known as halokinesis. This ductile, halokinetic movement causes the salt to form swells, domes, pillows, and eventually piercement structures (e.g., diapirs, walls) that often have the appearance of a dome or plug, although in 3-D the shapes are more convolute, sometimes appearing as a 憌all? (Figure 68). If the salt rises gently without piercement, the structure is a salt dome; if the salt intrudes overlying sedimentary layers it is a piercement structure, known as a diapir and/or ridge. Such structures are recognized as being typically associated with a variety of traps and trapping mechanisms, as shown in Figure 67; in which (1) is a simple domal trap draped over the salt, (2) graben fault trap over the dome, (3) porous cap rock, (4) flank 憄inch-out? sediments and sand lens, (5) trap beneath overhang, (6) trap uplifted and buttressed against salt plug, (7) unconformity, (8) fault trap downthrown away from the salt, (9) fault trap downthrown toward the salt.

Figure 67. Generalized salt diapir and potential traps showing the common possible types of hydrocarbon trap associated with salt domes and diapirs: [1] simple domal trap draped over the salt, [2] graben fault trap over the dome, [3] porous cap rock, [4] flank 憄inch-out? sediments and sand lens, [5] trap beneath overhang, [6] trap uplifted and buttressed against salt plug, [7] unconformity, [8] fault trap downthrown away from the salt, [9] fault trap downthrown toward the salt (after Halbouty, 1967, with kind permission of Gulf Publishing Co).



51

Numerous examples of dome and piercement structures occur within the Gabon Basin (West Africa), Scotian Shelf (Canada), Ekofisk and Cod fields in the North Sea, and the Texas Gulf Coast Basin (for example see Halbouty, 1979).

Domes and piercement structures are often readily recognizable in seismic, as shown by the structures in the Kraka and Dan fields of the Danish North Sea (Jorgensen, 1992), where Paleocene strata overlies Permian Salt (Figure 69).

Domal structures have the potential to create a number of trap types and consequently remain structures of significant exploration interest, because uplift may create abundant radial faults in the overlying strata, as exemplified by many of the domal structures of the Texas Gulf Coast Basin (King and Lee, 1976).

There are many large fields in which domal and piercement structures play a significant part. However, there are also smaller fields that have produced steadily since discovery. For example, the Barbers Hill Dome, Texas, U.S.A., (Figure 70) was discovered in April 1916 and had produced nearly 130 million barrels by the end of 1984 when production ceased (Handbook of Texas Online, 2005).

Figure 69. Domal structure in the Kraka and Dan fields of the Danish North Sea, (left) structural map (top of chalk) and (right) an interpreted seismic line (from Jorgensen, 1992).

Figure 70. The Barbers Hill Dome, Texas, U.S.A., in section showing thelocation of known traps. Note the scale bar (from Halbouty, 1967,reprinted with kind permission of Gulf Publishing Co.).



52

Stratigraphic Traps

Trap types The existence of nonstructural traps has been recognized since the early part of the twentieth century, although it was Levorsen (1936) who proposed the term stratigraphic trap for a type of trap 搮 in which the chief trap-making element is some variation in the stratigraphy or lithology, or both, of the reservoir rock”(Levorsen, 1936, p. 237). Rittenhouse (1972) also adopted a broad understanding of the term stratigraphy and hence stratigraphic trap, which he considered to include paleogeomorphic traps. In the Treatise of Petroleum Geology (Stratigraphic Traps III), Foster and Beaumont (1992) consider a stratigraphic trap to be the sole result of stratigraphic elements, such as variations in porosity and/or permeability due to changes in facies, diagenetic alteration (e.g., dolomitization), or due to the erosion of material. More recently, Biddle and Wielchowsky (1994), following the lead of North (1985), define a stratigraphic trap 搮 as one in which the requisite geometry and reservoir-seal(s) combination were formed by any variation in the stratigraphy that is independent of structural deformation, except for regional tilting? (Biddle and Wielchowsky, 1994, p. 226). Pulling all of these various elements and views together, it is clear that stratigraphic traps are formed principally by depositional and sedimentary processes.

Unlike structural traps, stratigraphic traps can be created at any time during the deposition and formation of sedimentary rocks, due to the possible influence of erosional, depositional, and diagenetic factors. Stratigraphic traps can, therefore, be considered as pre-, syn-, or post-depositional.3

Stratigraphic traps are often harder to locate using seismic techniques and typically require good well control to determine the principle trap style. While examples of stratigraphic traps occur worldwide, it is not surprising that the greatest number of known and described stratigraphic traps occur within North America, particularly the United States, where basins have been penetrated by more wells than basins outside of North America. Drilling density has traditionally had great bearing upon the successful designation of a trap, although the recent increased usage of 3-D seismic has also had significant impact (Figure 71). It is because stratigraphic traps have traditionally seemed 憃bscure? and the most difficult to find that Michel T. Halbouty termed them the 憇ubtle trap?(Halbouty, 1982).

Rittenhouse (1972) published a detailed classification of stratigraphic traps that contained four orders of subdivision, in part due to the considerable variability that exists among stratigraphic traps. Many subsequent schemes generally follow the broad principals laid out by Rittenhouse. However, rather than present a catalogue of numerous subcategories of traps, only the broad subdivisions of Rittenhouse (Figure 72) will be used here, accompanied by various examples of each. It is interesting to note that trap types unassociated with unconformities are, broadly speaking, traps that occur within (seismic) sequences whereas traps associated with unconformities occur at sequence boundaries (Jenyon, 1990).

Traps unassociated with unconformities Depositional traps

Depositional traps are those traps in which the depositional environment had the greatest influence; in other words, they were created by changes in contemporaneous deposition (Biddle and Wielchowsky, 1994). Depositional traps can be created by the formation of depositional pinchouts, by changes in facies, and by burial depositional relief.

3

Pre (before), syn (during), and post (after).

Figure 72. A broad subdivision of stratigraphic trap types (based on Rittenhouse, 1972).

Figure 71. A 3-D seismic section (in plan view) over a prospect area showing the presence of a meandering channel in blue (used by permission of Sunoco, Inc.).



53

Examples of traps due to changes in facies include Channel traps and Barrier Bar traps, while examples of traps created by burial depositional relief include Carbonate buildups and Eolian dunes.

Depositional pinchout traps

Also known as wedge-out and feather-edge traps (Jenyon, 1990), pinchout traps may occur when ever there is a progressive lateral (i.e., updip) diminution of reservoir bed thickness (Figure 73). Interesting examples of pinchout traps occur within the oil basins of Eastern China, particularly the western Liaohe depression, where they are known as lithologic traps (Li et al., 1982).

The Chicontepec field, Tampico-Masantle Basin, Mexico, covers 3300 km3 (approx. 2000 mi2) and as of 1990, ultimate recoverable reserves were estimated to be 10.96 billion bbl of oil and 1.32 billion bbl of condensate (Busch, 1992). The field is large and the geology complex, mainly because the canyon fill consists of recycled sediments; although, the reservoir sediments consist of Eocene turbidite sandstones that were deposited in a deep water canyon that eroded into the floor of the Chicontepec Basin. These lenticular sand bodies have an extensive linear trend and all of them shale out up dip, therefore the pervasive trapping mechanism is considered to be the up dip shale-out along the axial trend of the Chicontepec canyon fill (Busch, 1992).

The Glenn Pool field, Northeast Oklahoma Platform, Oklahoma, U.S.A., covers approximately 43 miles2

and in 1992, had more than 750 producing wells with a cumulative yearly production of more than 1 MMB (Kuykendall and Matson, 1992). The Bartlesville Reservoir (Figures 52 and 74) ranges in thickness from 30 to 35 m and although there is evidence of secondary porosity it is considered to be a stratigraphic trap due to the up dip pinchout of thick, porous, multistoried, alluvial-deltaic/valley-fill sandstone, into laterally sealing siltstone and shale (Kuykendall and Matson, 1992).

The small Seminole, SE field, west Texas, U.S.A., is also an example of updip facies change and porosity pinchout, in which productive Middle Pennsylvanian Strawn Limestone passes laterally into lime mudstone-wackestone (Mazzullo, 1986).

Channel traps

Channels typically contain clastic particles ranging in size from sand to silt. This is because within a 'deltaic' or coastal setting (Figure 75), channels are sites of both fluvial sediment transport and deposition. The parts of a fluvial regime that are most likely to be preserved are:

Interdistributary channel deposits,

Braided section (longitudinal and transverse bars),

Meandering section (developing point bars).

Their common sedimentary aspect is a general fining-upward sequence, with cross-laminations. The sands are, in general, less well-sorted than marine sands and often contain carbonaceous debris. In cross section, channel deposits derived from braided and interdistributary streams have convex bases and flat

Figure 73. The difference between facies change (e.g., channel or bar) and a pinchout trap (after Biddle and Wielchowsky, 1994)

Figure 74. Cross section through the Glenn Pool showing the pinchout of the Bartlesville sandstone (from Wilson in: Kuykendall and Matson, 1992).

Figure 75. The Delta: after Frasier and Osanick (1969), Ferm (1975), Bend (1992), and others. Approximate scale is 1 km (0.6 mi) edge to edge.



54

upper surfaces, and fairly abrupt changes in lithology at their margins.

This is in contrast to deposits from a major meandering stream channel, in which the deposit may have an asymmetry, reflecting the formation of a point bar deposit, as shown in the example of the Bell Creek Oilfield, Montana (McGreggor and Biggs, 1970). Figure 76 shows the petrophysical log signature for a channel deposit associated with the Upper Muddy; note the pronounced SP deflection, high resistivity, good porosity and permeability for this channel deposit.

Barrier bar traps

Because barrier complexes produce long shoe-string like sands of high permeability and porosity, they are excellent exploration targets if bounded by a seal. Barrier complexes generally contain well-sorted sands, although variations in sedimentary structure, infauna, epifauna, and lithologic characteristics exist depending upon the subenvironment of deposition (Figure 77) as discussed by Walker (1984).

Barrier complexes are typically narrow, linear, elongate, sandy peninsulas or islands that trend parallel to the paleoshoreline and found primarily on passive continental margins. Depending upon whether or not there is progradation or not, there is the likelihood that such sands are covered by very fine-grained clastics, ensuring a porosity and permeability change. Most traps formed by barrier complexes are often relatively small, although in the case of the Bisti field in New Mexico (Sabins, 1963), the existence and occasional coalescence of three subparallel bars has significantly increased the size of this play.

Carbonate buildups (reefs and mounds)

Carbonate buildups represent another significant stratigraphic trap, primarily because they are detectable by seismic, appearing as domal and/or elongate bodies. Carbonate buildups and reefs are sediment complexes typically built entirely by the organisms growing within them; they are therefore self generated. The term reef has been used in a very loose sense (c.f., Dunham, 1970; Heckel, 1974; Tucker and Wright, 1990), so that the term buildup is now used in reference to a body of carbonate rock that possesses topographic relief above the surrounding environment. Reefs are considered to be laterally restricted, have significant relief, show evidence of biological influence during growth (Tucker and Wright, 1990) and to be wave resistant (Dunham, 1970).

Reefs often possess flanking clastic deposits of high porosity, a significant facies change over their crests, and post depositional 慸rape structures? in overlying post-reef strata. Reefs have a variable, but above average, primary porosity and are well sealed, sometimes by transgressive marine shale. A number of basic characteristics typically aid the detection of carbonate buildups using seismic, which includes size, shape, symmetry, and location within a basin (Figure 78). Furthermore, carbonate rocks generally have higher P-wave velocities than clastic rocks, creating a recognizable seismic reflection (Jenyon, 1990).

Contemporary organic reefs range in size, from the Great Barrier Reef of Australia to small isolated reef knolls. Most reefs are largely carbonate constructions, built in oxygen-rich water by framework builders. Contemporary in situ reef builders includes hermatype scleractinian corals, coralline algae, bryozoans, or sponges, although in the geological past they included stromatolites, stramatoporoids, archaeocyathids, crinoids, receptaculitids, rugose, and tabulate corals for example. Reefs composed of frame-building organisms form a broad general type of reef known as skeletal (frame-

Figure 77. Barrier complex subenvironments (from Walker, 1984, reprinted with permission from Geological Association of Canada).

Figure 76. Bell Creek Oilfield, Montana, U.S.A., showing the petrophysical log signature for a channel deposit, termed 慚 arsh Facies,? showing SP and resistivity curves, core log, porosity and permeability values (from McGreggor and Biggs, 1970).



55

built) reefs. Such reefs are the high-relief, wave-resistant walled reefs found in modern barrier reef complexes and smaller patch reefs. In contrast, reef mounds are buildups that lack a prominent in situ skeletal framework. They are either composed of bioclastic material or mud (Tucker and Wright, 1990).

Examples of carbonate buildups, as traps, include the Middle Silurian Pinnacle reefs, Belle River Mills Gas field, Michigan Basin, U.S.A. (Gill, 1986), the Miocene Pinnacle reefs of the Nido B Field, South China Sea (Longman, 1986), and the Middle Devonian reefs, Rainbow Area, Alberta, Canada (Barss et al., 1970; Qing and Mountjoy, 1989).Reefs of the Elk Point Group in northeastern British Columbia and northwestern Alberta, Canada (Figure 77), have initial established marketable gas reserves of more than 1000 106 m3 (35 BCF).4 The Rainbow sub-basin, covering an area of approximately 7,000 km3, contains more than 80 individual oil-producing carbonate buildups in which the Rainbow field alone is considered to contain more than 1.5 BBO5 of oil in place (Barss et al., 1970). Reefs within the Rainbow sub-basin have been penetrated by several wells and entire reef sections were cored throughout providing excellent information that have been used in several detailed studies. The reefs developed pinnacle and atoll forms (Barss et al., 1970) that vary from 0.6 to 21 km2 with thicknesses ranging up to a maximum of 250 m (Qing and Mountjoy, 1989). Recoverable reserves for individual reefs vary within the Rainbow area. Many contain around 10 to 50 MMB, while some contain in excess of 200 MMB of oil (Barss et al., 1970). The internal facies of each reef is complex (Figure 79), reflecting their genesis; while size and geometry is related to the initial size of the mounds upon which they grew, rate of basin subsidence, paleogeography of the sea floor, local bathymetry, and directional influence of climate (Barss et al., 1970). The effect of pervasive dolomitization has generally reduced original porosity but increased the permeability within individual reefs (Qing and Mountjoy, 1989).

4 Source: www.ags.gov.ab.ca/publications/.

5BBO = billion barrels of oil, MMB = million barrels of oil.

Figure 79. Two examples of Devonian reefs from the Rainbow area, Northern Alberta, Canada; left, Pinnacle reef (2 km wide), right Atoll reef (3+ km wide) (from Barss et al., 1970).

Figure 78. The shape classification of modern reefs, showing the shape of reefs and relative water depth. For example, fringing reefs are attached to the coastline, patch reefs are isolated reefs, barrier reefs are separated from the coast by a lagoon, an atoll is a ring-like structure situated in deeper water and the table reef lacks a central lagoon (modified and redrawn from Tucker and Wright, 1990; with permission of Blackwell Publishing and M. Tucker).



56

Diagenetic traps

Transition in porosity and permeability

Porosity/permeability traps occur when a lateral reduction in porosity has a significant effect upon capillary entry pressure, so that the movement of petroleum is arrested (Jenyon, 1990). Porosity variations can occur due to lateral changes in facies, reflecting variations in depositional environment, although in this trap type diagenesis and/or solution effects are the principal controlling processes.

The Frisco Formation, Oklahoma, U.S.A., is a middle Lower Devonian limestone that contains significant productive reservoirs. Syntaxial cementation coupled with mechanical and chemical compaction were considered reasons for a marked reduction in primary porosity; however, subaerial exposure and solution effects created zones of good secondary porosity (Morgan et al.,1982).

Quiriquire field, Eastern Venezuela Basin, Venezuela, is the largest oil field in eastern Venezuela and one of the world抯 giant oil fields with estimated recoverable oil reserves in excess of 1 BBO. The Pliocene-age Quiriquire Formation is composed of irregularly interbedded, unconsolidated to poorly consolidated, poorly sorted, medium- to coarse-grained sandstones and conglomerates with minor amounts of sandy claystone/lignite beds (Salvador and Leon, 1992). The porosity of Quiriquire Formation reservoir sandstones and conglomerates averages 20% with an average permeability of 400 to 550 mD. The reservoirs of the Quiriquire Field are homoclinally tilted and the oil is trapped where the coarse clastics pinchout due to the formation of a semi-solid, viscous, heavier-than-water asphaltic oil and tar mat (Figure 80). The produced oils are generally asphaltic and vary in gravity from heavy oil to 28o

API with an average pour point of -4o C.

Traps associated with unconformities The term unconformity refers to a geological surface of non-deposition possibly in combination with erosion, separating older from younger rocks and representing a gap in the geological record. Other terms are used to describe specific types of unconformity, for example an angular unconformity separates younger rocks from eroded, dipping older rocks, whereas a disconformity represents a period of non-deposition, and a non-conformity separates overlying younger rocks from eroded, older igneous or metamorphic rocks. The juxtaposition of an older, perhaps more indurated and denser rock sequence against a younger less indurated and less dense rock sequence, can produce a recognizable seismic demarcation line separating lower and higher seismic velocities; such as the Late Kimmerian Unconformity in the East Shetland Basin of the North Sea (Figure 81) in which the Late Kimmerian Unconformity represents the boundary between the overlying high-velocity Cretaceous shale and marls, and the low-velocity Upper Jurassic Kimmeridge Clay Formation (Skarpness et al., 1982).

Examples of different types of trap associated with unconformities are shown in Figure 82, in which the relative difference between traps that underlie (Figure 82A) or overlie (Figure 82B) an unconformity are shown. Excellent examples of traps formed in this way occur within the Mississippian of the northern part of the Williston Basin (Canada) associated with ultimate recoverable reserves of over a 1.5 million m3.

Figure 80. An north-south cross section through the Quiriquire Field showing the occurrence and distribution of APIo oil gravities. The heaviest oils are dark green, the lightest oils are red. The small inset map shows the outline of the Quiriquire Field and the orientation of the line of section.

Contour intervals are 2o API (from Salvador and Leon, 1992).

Figure 81. A generalized section from Statfjord to 34/10 Delta in the Norwegian North Sea showing the Late Kimmerian Unconformity (from Skarpness, 1982).



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Traps overlying unconformities

Onlap

Onlap traps occur when shallowly dipping or near-horizontal, younger strata progressively terminate against more steeply dipping, older strata (Figure 82B). According to the principles of sequence stratigraphy, onlapping strata are deposited during a marine transgression. Onlap should not be confused with downlap (Figure 83), recognized as a type of base-discordant relationship and a term used to describe the geometry of seismic reflections with a sequence of seismic data (Jenyon, 1990).

Examples of onlap traps include the Midway oil field, California, U.S.A., where petroleum-bearing Pliocene strata onlap strata of the Upper Miocene, and the Cutbank Pool, Montana, U.S.A.. The Sergnano Gas field, Po Basin, Italy, was initially thought to be an anticlinal structure and explored as such. However, subsequent analysis indicated the presence of Pliocene-age conglomerates unconformably overlying (onlap) Lower Miocene/Oligocene erosional relief. Gas reserves were estimated at 3.5 billion m3 (123.6 billion ft3). The conglomerates have an average porosity of 25% and an average permeability of 400 mD (Rocco and D扐gostino, 1972).

Channel/Incised valley

The South Glenrock Oil field, Wyoming, U.S.A., is interesting in that it demonstrates a change in thinking and exploration strategy within Wyoming during the middle of the 20th century, from structural- to stratigraphic-type plays. The lower Muddy Formation in the Glenrock field was interpreted as a meandering channel-fill deposit (Figure 84), with oil trapped within the point-bar sandstone (Curry and Curry, 1972).

The Midland Gas field, Western Kentucky, U.S.A., is noted as a combination trap consisting of channel-fill deposits that were localized by subsequent structural deformation. Gas is produced from the Bethel Channel Sandstone, formed by the downcutting of a deep (250 ft) channel into the underlying massive limestone (Figure 85). Subsequent channel infill by sands bounded by shales and reworked limestone deposits were overlain by the Lower Paint Creek Limestone (Reynolds and Vincent, 1972).

Figure 82. Example of traps associated with unconformities (A) beneath an unconformity and, (B) above an unconformity (after Biddle and Wielchowsky, 1994).

Figure 83. Schematic showing downlap and onlap (image ? Schlumberger, Ltd. used with permission).

Figure 84. Isopach map of lower Muddy interval, South Glenrock Oil field, Wyoming, showing two channel deposits and one meander belt. The oil is stratigraphically trapped within the point-bar sandstone of the channel fill (from Curry and Curry, 1972).



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Traps underlying unconformities

Truncation

The Bosc醤 field, Venezuela, was discovered in 1946 and is renowned for its heavy (10.3 癆PI) oil that has a sulfur content of 5.5% and a vanadium content of 1,200 ppm (Sutherland, 1972). Exploration in the area began in the early 1900s, encouraged by the presence of surface seepages of oil. Success was elusive until the 1940s when oil was found in upper Eocene sandstones, of which the 揢pper? Bosc醤 Sandstone is the most important. This unit thins from more than 120 m (400 ft) in the south to 0 m in the north due to post-Eocene erosion. The 揕ower? Bosc醤 sandstones are medium- to coarse-grained in the south, but become increasingly finer and impermeable towards the north. The NNE-SSW trending Bosc醤 Fault provides closure to the field (Sutherland, 1972).

The Silurian reservoirs of the Hunton Group, Mt. Everette, and Southwest Reeding fields Kingfisher County, Oklahoma, U.S.A., are also examples of a subunconformity truncation. Excellent production typically requires the truncation of the Clarita skeletal buildup, unconformably overlain by the Woodford Shales (Morgan et al., 1982).

Paleogeomorphic

The trap-creating capacity of an unconformity is sometimes due to the existence of an inherent structure, such as an undulating paleogeomorphic surface. Within the Ca玢o field, Espirito Santo Basin, Southeastern Brazil, the Barra Nova Formation submature fine- to coarse-grained feldspathic sandstone contains 50.4 MMB of oil, with an estimated recovery of 12.6 MMB (Lima and Aurich, 1992). The Barra Nova Formation is part of a paleogeomorphic high caused by submarine erosion of the Upper Cretaceous; the sealing surface consists of the unconformable shales of the Uracutuca Formation.

There are excellent examples of paleogeomorphic (i.e., buried-hill) traps in the Renqiu oil field, North China Basin. More than 40 paleogeomorphic oil and gas pools have been found in an area of 200,000 km2 (Guangming and Quanheng, 1982). The seal is typically Tertiary in age, which lies unconformably over Precambrian, Mesozoic, and Paleogene rocks (Figure 86), in which excellent production is obtained from reservoir rocks that range from karsted and non-karsted carbonate rocks (limestone, oolitic limestone, dolomite) to fractured or weathered igneous rocks (andesites and basalts).

The Middle Jurassic reservoirs of the Coulommes oil field, Paris Basin, France, are dedolomitized carbonate reservoirs that pass laterally into dense limestone over a paleohigh (Purser, 1986).

Figure 85. Block diagrams showing the history of the Bethel Sandstone channel, Midland Gas field, Western Kentucky; (A) the pre-Bethel erosional channel, (B) showing back-fill and channel-fill, (C) the deposition of the Lower Paint Creek Limestone (after Reynolds and Vincent, 1972).

Figure 86. Examples of paleogeomorphic (buried-hill) traps in the North China Basin (from Guangming and Quanheng, 1982).



59

Figure 89. The generalized effect of hydrodynamic flow and petroleum density upon trap effectiveness and capacity (from Biddle and Wielchowsky, 1994).

The Casablanca field, offshore Spain, is another example of a paleogeomorphic trap. Low sulfur, 33.7o API gravity oil is produced from weathered and fractured Jurassic carbonate that is unconformably overlain by the lower to middle Miocene Alcanar Group (Figure 87). The Casablanca trap consists of an elongate carbonate ridge that is bisected by two transverse valleys, which divide the ridge into three highs (Watson, 1982).

Hydrodynamic traps To varying degrees, reservoirs are typically water wet. It should also be remembered that as petroleum is withdrawn from a trap, water must be readmitted into the trap, refilling the pore spaces of the reservoir rock. Typically subsurface water flows within a basin along the potentiometric gradient from regions associated with a high water table to regions of low water table. Water within the 慺ree-water zone? (see Figure 57) may be static or moving creating two possible, general conditions within the trap (Figure 88); static water will remain in a hydrostatic condition whereas flowing water (i.e., 慼ydrodynamic? may tilt the oil-water contact within a trap (Figure 89A and 89B). This is not a new phenomenon (see Levorsen, 1954, 1967) and there are a number of producing fields (e.g., Bolivar Coastal field, Venezuela) in which hydrodynamic flow has had some impact upon the geometry of the oil-water contact. Under hydrodynamic conditions, the oil-water contact is tilted within the direction of water flow and the amount of tilt depends upon the hydraulic gradient and the density of the fluids (Hubbert, 1953). Generally, the angle of tilt will increase (Figure 89C) if either the flow increases or the density of the oil increases at constant flow (North, 1985; Biddle and Wielchowsky, 1994). Water moving downdip within a flexure (Figure 89D) will trap oil, whereas an updip hydrodynamic flow will not (Figure 86E). Similarly, the direction of flow through a convex trap will either increase the effective capacity of the trap (Figure 89F) or diminish it (Figure 89G).

Figure 87. (left) West-to-east seismic line through the Casablanca field, offshore Spain, upon which the Tertiary and Plio/Miocene unconformities are marked (left). The west-to-east structural section through the Casablanca field provides a simplified interpretation (right). The structural section runs parallel to the seismic section, but is 4 km to the north (from Watson, 1982).

Figure 88. Hydrostatic vs. hydrodynamic trap conditions.



60

Combination traps Levorson (1954, 1967) recognized that many traps cannot be easily differentiated as either structural or stratigraphic, because they combine elements of both trap type. Within a given oil field there may appear to be a single dominating trap type, or even a combination of two, as a result of interpretations based upon seismic, or interpretations limited by moderate well control. There are a number of possible reasons for this. Of all the known stratigraphically trapped pools in the world, 90% occur within the United States of America (North, 1985). It is difficult to believe that this distribution is genuine. Is it, as North (1985) contends, because the rest of world is looking for structural traps? Or is it more a reflection of the relatively high proportion of wells drilled within the United States that yields a higher degree of well (i.e., stratigraphic) control, hence an increased amount of data and a more refined interpretation of the subsurface?

True combination traps are the result of a complex, multistage geological history. For example an updip permeability pinchout (stratigraphic) could intersect with a fault (structural). If the effectiveness of the trap is controlled by the presence of a sealing fault and reduction in permeability (Figure 87) then the result is a combination trap (Levorsen, 1954). Within the Rodessa oilfield, Louisiana and northeast Texas, one of the pools within that field occurs where the Rodessa Fault cuts the oolitic limestone member of the Glen Rose Formation.

However, as Biddle and Wielchowsky (1994) note, the term combination trap is presently used in a much less rigorous way than Levorsen (1954) suggested. They also go on to note that strict adherence to definitions will not necessarily find petroleum, but early recognition of stratigraphic elements within a structural play or the interplay of structural influences upon a stratigraphic play will help eliminate surprises (Biddle and Wielchowsky, 1994), reduce risk, and lower uncertainty. These are wise words indeed!

Sedimentary Basins

Introduction

More than 700 sedimentary basins, of varying size, have been identified worldwide, many of which are depicted in the world map shown in Figure 90. Sedimentary basins are an integral part of the earth抯 crust, and remain the principle focus of exploration geologists in their ongoing search for petroleum, because of the increased certainty and reduction of risk due to the empirical association between economic accumulations of petroleum and sedimentary basins.

For many sedimentary basins, their genesis and prolongation, (as a sediment sink) is related to the tectonic regime in which the basin formed.

Figure 90. The global distribution of 592 giant oil fields summarized as regions on the Exxon tectonic map of the world according to Mann et al., (2001). The areas outlined in yellow indicate concentrations of giant oil fields; identified as (A) Alaska; (B) Rocky Mountain foreland; (C) Southern California; (D) Permian and Anadarko basins; (E) Gulf of Mexico; (F) Northern South America; (G) Brazil; (H) North Sea; (I) North Africa; (J) West Africa; (K) Arabian Peninsula/Persian Gulf; (L) Black Sea; (M) Caspian Sea; (N) Ural Mountains; (O) West Siberia; (P) Siberia; (Q) China; (R) Sunda; (S) Australia; and

(T) Bass strait/Australia/Tasmania (used with permission of World Oil).



61

Therefore, there have been ongoing attempts to establish a relationship between basin style and tectonics. Basins may initially be divided into intracontinental or intercontinental basins, with a further subdivision reflecting setting and tectonic style (Figure 91).

Fischer (1975) recognized four distinctive tectonic origins:

Basins formed due to crustal tension (e.g., rifting.

Basins formed at an active crustal margin, due to crustal compression (e.g., subduction).

Basins formed within an intracratonic hollow, perhaps due to changes in upper mantle heat flow.

Basins formed by sediment loading at the margin of the continents (e.g., delta).

However, as we shall see the formation of a basin is typically much more complex.

Classification of basins

There are many way of classifying sedimentary basins, depending upon purpose. Petroleum industrial classifications mainly focus upon the 慶ontainer? aspect of a given basin and seek to identify the processes of basin genesis and evolution. Here we will use a scheme initially proposed by Halbouty (1970) and subsequently developed by Klemme (1975, 1980a, 1980b, 1987) as shown in Figure 92; which is a system of basin differentiation, based upon the framework of plate tectonics and basin genesis. This not only creates a classification scheme that is both dynamic and inclusive of differences in pervasive trap style, but also provides a scheme that can account for variations in source rock characteristics and crustal heat flow.

The scheme of Klemme

Intracontinental basins Intracontinental basins are subcircular basins formed on continental (cratonic) crust. Faulting, which can include rifting, may be in evidence within the basement rocks. There are three basin subtypes known as Types 1, 2, and 3. In each type, geological facies, hydrocarbon potential, and trap type can be significantly different. It is also possible to create two sub-varieties for each subtype. This further subdivision is based more upon paleogeography and climate, than on tectonics, which can have a significant influence upon lithofacies, organofacies, and the hydrocarbon potential of source material!

Type 1 single-cycle

These are simple, circular to sub-circular single-cycle cratonic basins, associated with mostly Paleozoic rock, located within the central area of a craton, situated either upon or adjacent to Precambrian shield. Examples include the Williston Basin, and the Michigan and Illinois basins. Reasons for subsidence vary.

Figure 92. A summary of the classification scheme of Klemme (1975, 1980a, 1980b, 1987); (after Klemme 1980b; published with permission of Oil and Gas Science and Technology, Revue de l'IFP, and AAPG).

Figure 91. Examples of basin origin according to Fisher (1975); crustal tension (rifting) crustal compression (subduction), and intracratonic hollow or depression (after Fischer [1975] and others).



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Type 2 composite

Type 2 include intracontinental composite, multicycle cratonic basins, associated with a second cycle of sedimentation due to compressional tectonics, giving rise to an asymmetric basinal profile. Examples include the basins of the Volga region, Siberia Platform, and the Rocky Mountain basins. Type 2A complex, multicycle cratonic basins possess a more complex origin. Klemme notes (1980a) 50% of the world抯 gas reserves occurs in Type 2A complex basins. Examples include the basins of W. Siberia, the Erg Oriental (Algeria), and the Cooper-Eromanga Basin (Australia).

Type 3 rift basins

Type 3 rift basins are primarily Upper Paleozoic, Mesozoic and Tertiary in age, located on or near cratonic areas. Examples include the Dnieper ? Donetz Basin, the Mesozoic Basins of the North Sea, and the Suez (Cenozoic).Rifted basins such as the North Sea Basin are closely related to the existence of extensional tectonics, either active or failed. Rift basin sediments are typically non-marine at the onset, passing through a lacustrine phase, followed by a marine phase of sedimentation.

Intercontinental Basins Intercontinental basins (termed extracontinental by Klemme) form on the margin of continental crust and are analogous to foreland shelf basins. Again each basin type could be further subdivided depending upon the predominance of clastic or carbonate sedimentation. There are four types of Intercontinental basin identified by Klemme (1975, 1980a, 1987) and numbered Types 4 to 8.

Type 4 down-warp basins

These are depressions within small oceanic basins. According to Klemme, such basins are highly significant basins and contain more than 50% of the world抯 known oil reserves. Down-warp basins are subdivided into:

4a. Basins formed within deformed belts, for example the Persian Gulf and the Orinoco Basin.

4b. Troughs between deformed belts, such as the Upper Assam and Po Valley.

4c. Open basins bound on one side by continent, for example, within the Gulf Coast and Northern Alaska.

All are formed by the downwarping of crust, or by faulted depressions under crustal tension. Often such basins exhibit a stratigraphic zonation, with progressively younger beds seaward. The Gulf Coast is considered to be the example of this type of basin. The basement is overlain by salt, which is in turn succeeded by a series of prograding wedges. Each sediment wedge consists of fluvial sands (landward) thickening to deltaic sand and mud, becoming deep marine clays basinward. Sedimentation was rapid, hence the geothermal gradient is low and overpressuring is prevalent.

Type 5 pull-apart basins

Such basins form within the passive continental margin of divergent boundaries. Their genesis appears linked to an initial rifting stage and extensional tectonics. Examples occur off the coast of Gabon and the Scotian Shelf, Canada. This type appears to be an end member of the Type 3 basin when sea floor spreading is not aborted. Sediments typically are non-marine at the onset, subsequently giving way to marine sedimentation, younging upwards and seawards.



63

Type 6 subduction basins

They are small and can be fore-arc, back arc, or non-arc (i.e., transform), many occur as a cluster of basins (i.e., borderland festoon). Subdivided into Type 6A Fore-arc (i.e., oceanward side of the volcanic arc), Type 6B Back-arc (cratonic side of the volcanic arc) basins, and Type 6C Non-arc (i.e., destroyed island arc), their genesis is due to compressional tectonics along a convergent margin (Klemme, 1980a, 1980b). Examples are found in Talara, Peru (Type 6A), Sumatra and Cook Inlet (Type 6B), Baku and the Los Angeles Basin, California (Type 6C). Such basins tend to be young, narrow, and short lived! Hence, most of the (current) productive zones are Tertiary (or younger) in age. The range of lithological rock type varies greatly, as does trap type.

Type 7 median basins

Median basins are small, linear basins that occur between two, collisional, deformation belts and possess compressed and uplifted zones. Examples can be found within the Maracaibo Basin, Venezuela, and the Gippsland Basin, Australia. Such basins possess structural asymmetry; successive deformation on either side of the basin may mobilize either (or both) flank(s).

Type 8 delta basins

Mainly Tertiary in age and comprised predominantly of siliciclastic sediments, deltaic basins form along the continental margin due to the creation and existence of a long-living delta complex. Excellent examples include the Niger, Mackenzi, Mississippi, and Mahakam deltas. It is assumed such basins are self perpetuating, provided that there is sufficient sediment input to combat wave erosion and crustal down warping. The Niger delta is interesting in that its origin maybe related to basement tectonics. Magnetic anomalies suggest the presence of a suture that forms a point of juncture between oceanic and continental crust, which is also coincident with the topographic nadir of the basin (North, 1985). It would appear that the delta formed at the site of a triple junction, related to the opening of the Atlantic in the Late Jurassic (Tuttle et al., 1999). This suggests that this basin in particular has evolved throughout time.

The evolution of basins Klemme (1980a) notes that there is general agreement concerning the classification of three-quarters of all known basins and that the remainder are either poorly known or have a complicated architecture due changes in basin genesis through time (Figure 93).

In many ways, the designation of Basin Type is largely dependent upon the evolutionary stage of a given region, at any given moment in geologic time due to global tectonics. Therefore, the designation of Basin Type based upon the most recent pervasive geological setting may not accommodate the full history of a given basin. This concept is especially important when modeling the thermal history of a given basin or conducting a systems-approach to basin modeling, since Basin Type not only influences basin size, basin fill, and pervasive sedimentology, but trap types are also influenced by the tectonic framework of a given basin as is crustal heat flow and sediment thermal conductivity (Klemme, 1980a, 1980b, 1987). For example, Type 3 Rift basins may develop through sea floor spreading into a Type 5 pull-apart basin (example: the Grand Banks, Canadian east coast), or from a Type 3 basin through Type 5 pull-apart basin into a contemporaneous Type 8 Delta basin (e.g. Niger delta, Africa). Klemme (1980a) acknowledged the possible evolution of some basins in his portrayal of the evolutionary development of basins (Figure 93).



64

Figure 93. The evolution of basins. The genesis and relationships between basins, as envisioned by Klemme (1980a) (after Klemme,1980a; with permission of Blackwell Publishing).



65

Sedimentary basins and heat flow The role and importance of temperature, associated with burial depth and the transformation of kerogen to petroleum, has been previously discussed. What has not been discussed so far is the relationship between the sedimentary basin, tectonic regime, and crustal heat flow. Within a given basin, changing tectonics, basin evolution and variations in sediment conductivity will combine to create spatial and temporal variations in heat flow, often expressed as a geothermal gradient. Simply put, source rock maturation will take longer in a relatively cooler intracratonic basin (e.g., Michigan Basin, U.S.A.)than within an active rifted basin (e.g., Red Sea).

Heat flow The world average crustal heat flow is about 1.4 HFU6 (heat flow units) or 60 to 70 mW m2 (Robert, 1985). Heat flow is greatest over oceanic ridges and lowest over oceanic trenches (Figure 94). Geothermal gradients are more commonly understood by petroleum geologists, which are expressions of the rate of temperature increase with increasing depth, with values that range from 15 to 30 km2.Many recognize that geothermal gradients are not static or constant through geological time, but will vary if the basin undergoes some form of evolution, as previously discussed.

For example, a basin that begins as a Klemme Type 3, developing through a Type 5, and ending as Type 8 (e.g., Niger Delta) may have a high initial heat flow that is 25% greater than the global average, eventually cooling to below global average as the tectonic regime changes through time. Such a concept becomes highly significant within the context of Basin Modeling and Petroleum Systems analysis; both related approaches seek to examine the occurrence of petroleum within the context of a dynamic and evolving basinal system. For further discussion on this topic please see Magoon and Dow (1994).

Basins and hydrocarbon potential Let us now examine the global distribution of hydrocarbons for the various basin Types in Klemme抯 (1975, 1980a, 1980b) classification scheme (Figure 95). It is interesting to note that the presence of a single giant basin (Arabian Gulf) dominates the distribution of specific types of basin and their tectonic origin. It is perhaps for this reason that many exploration geologists consider the large structural play within a foreland basin setting to be the optimum for the creation of giant fields, and consequently they are pessimistic concerning future exploration prospects and the possibility of discovering another giant, like the Ghawar field in Saudi Arabia. It is also worth noting that more than 85% of world oil reserves occur within Klemme Types 2, 3, and 4 basin designations (Figure 95). Some of the most intensely explored regions of the world, the single cycle, intracontinental basins (i.e., Type 1; example U.S.A.) account for almost 20% of the world抯 total basinal area and yet contain less than 2.5% of the world抯 reserves.

6 1 HFU = 10-2 cal cm2 s-1 or 42 mW m2.

Figure 94. A summary of the typical heat flow associated with various types of sedimentary basins (from Allen and Allen, 2005; reprinted with permission of Blackwell Publishing).

Figure 95. A comparison of the surface area of different types of sedimentary basins and their known petroleum reserves (data from Klemme, 1980a).

47%



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Longman, M. W., 1980, Carbonate diagenetic textures from near surface diagenetic environments: AAPG Bulletin, v. 64, p. 461-487.

Longman, M. W., 1986, Fracture porosity in reef talus of a Miocene Pinnacle-reef reservoir, Nido B Field, The Philippines in Carbonate petroleum reservoirs (P. O. Roehl and P. W. Choquette, eds.): Springer Verlag, New York, Berlin, Heidelberg, Tokyo, p. 547-560

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McBride, E. F., 1984, Compaction in sandstones-influence on reservoir quality: AAPG Bulletin, v. 68, p. 505.

McDonald, D. A., and R. C. Surdam, 1984, Clastic diagenesis: AAPG Memoir 37, 434 p.

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Pittman, E. D., 1979, Porosity, diagenesis and productive capability of sandstone reservoirs in Aspects of Diagenesis (P. A. Scholle and P. R. Schluger, eds.): Society of Economic Paleontologists and Mineralogists Special Publication 26, p. 159-173.

Pryor, W. A., 1973, Permeability-porosity patterns and variations in some Holocene sand bodies: AAPG Bulletin, v. 57, no. 1, p. 162-189.

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Walker, R. G., 1984, Facies Models, 2nd Ed., Geoscience Canada Reprint Series 1: Geological Association of Canada, Toronto, 417 p.

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Chapter 5—Water, Pressure, and Temperature

71

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Oilfield water

Introduction 慜ilfield water,? or water associated with petroleum reservoirs, has a composition very different from the potable water that typifies an aquifer. Oilfield waters have a high proportion of total dissolved solids (TDS) and as such are brines; that is they are 憇alty.? Why they are brines is not fully resolved; they may be the 慺ossil? remnants of ancient sea water trapped within the sediments during deposition or contain material that is dissolved from host rocks. Subsurface brines do not have a single uniform composition; subtle and sometimes less-than-subtle variations in composition exist between subsurface brines from different formations, a characteristic that can become highly significant if there is water disposal to consider or a reservoir waterflood program to develop for a given oilfield. Because adding oxygenated 慺resh water? to a producing reservoir can lead to the severe degradation of reservoired oil (Connan, 1984; Palmer, 1991; Walther, 2005), a thorough knowledge of the composition of oilfield water is therefore essential.

Types of subsurface water Meteoric water is subsurface water that has hydraulic continuity with an area of recharge and is therefore an active part of the hydrological cycle. The infiltration and percolation of water from the surface generates water that is typically characterized as having a low concentration of TDS (hence, very low salinity), high amounts of HCO3? and is oxidizing (Collins, 1975). Connate water is water that may have been buried within a closed hydraulic system and therefore does not form part of the hydrological cycle. Connate waters are brines, containing between 20,000 and 300,000 mg/L TDS, they are also neutral to alkaline, reducing, and maybe high in Cl-, Na+, K+, Ca2+, and/or Mg2+.Thought as having originated from sediment entrapped seawater, connate water however, differs from sea water in both concentration and chemistry. Juvenile water is subsurface water that is considered to be 慼ydrothermal water? of magmatic origin.

Chemistry of oilfield water

Eh and pHA summary of the Eh and pH for various subsurface fluids, compared to seawater and rainwater, is given in Figure 96, which is also known as a Pourbaix diagram. Rainwater is both acidic (i.e., low pH) and oxidizing (i.e., high Eh). Upon contact, rainwater oxidizes organic matter (i.e., humic acids) and is in turn reduced (lower Eh). Aerobic bacteria feed upon organic matter, deriving energy through the oxidation of carbon. In the presence of oxygen, the 慹lectron sink? is the reduction of oxygen, which in turn lowers the Eh. Anaerobic bacteria utilize the sulfate ion, which is reduced to sulfite and finally sulfide, in doing so the Eh decreases to -0.6 V (Collins, 1975; Walther, 2005). The percolating water will also acquire dissolved solids, which changes the pH from 慳cidic? to neutral/slightly alkaline. However, as a general rules the pH of oilfield water is typically controlled by the carbon dioxide-bicarbonate system (Collins, 1975).

Connate waters show a broad range of Eh and pH values (Figure 96) due to their variation in composition from basin to basin and formation to formation, although, in general, oilfield brines tend to be both alkaline and strongly reducing.

Figure 96. Eh-pH plot (Pourbaix diagram) showing the stability of water at STP. Also shown are the generalized Eh-pHcharacteristics of rainwater, meteoric water, modern sea water, connate water and the stability limits of water (after Pourbaix, 1966; Collins, 1975; Walther, 2005; and others).



72

Chemical composition There are a number of reasons for analyzing the composition and hydrochemistry of oilfield water. It has been stated that within the U.S.A., 7 bbl of water is produced for every 1 bbl of oil3. Therefore, understanding the characteristics of produced (i.e., oilfield) water can help operators increase production and facilitate water disposal, as well as identify potential well-bore or reservoir problem areas (Breit e. al., 2000, 2001). Knowledge of the TDS content can help define pay zones when coupled with conductivity and or resistivity measurements (Breit et al., 2000). Furthermore, temperature and pH influence the solubility of organic compounds (Collins, 1975; Price, 1976; McFarlane et. al., 2002; Walther, 2005) with the result that oilfield water may contain organic acids, polycyclic aromatic hydrocarbons (PAH), phenols, and dissolved light hydrocarbons.

The hydrochemistry of water is typically defined using a suite of ions in solution (e.g., HCO3? SO42-, Cl-, Na+, K+,

Ca2+ and Mg2+), augmented by other analyses, such as the redox potential (Eh) and pH (-log[H+]), or the assessment of electrical conductivity (S- m-1) to identify the specific origin for a given water. The acid-neutralizing capacity of a water sample is expressed by total alkalinity (mg/L CaCO3). The analysis of oilfield water may also include an analysis of organic constituents, such as humic acids, fulvic acids, carbohydrates and hydrocarbons. However, the most routine analysis generally involves the analysis of the TDS. Consequently subsurface waters have been 慸escribed? using such characteristics.

Classification慛ormal? seawater contains approximately 35,000 ppm (3.5%) total dissolved solids (TDS), mostly as NaCl. In contrast, most connate waters contain up to 300,000 ppm TDS. Subsurface water containing more than 100,000 ppm TDS is considered a brine. The most concentrated brines occur in undisturbed deep basins, although brine can become more concentrated if the stratigraphic sequence includes evaporites. Meteoric waters tend to have higher concentrations of HCO3¯and SO4

2-, and relatively low amounts of Ca2+ and Mg2+. In contrast, connate waters differ from seawater because they contain lower concentrations of SO4

2-, Ca2+ and Mg2+, and higher proportions of Cl-, Na+, and K+. Therefore, most classification schemes reflect the dominant mineral ion, or ions, in solution, e.g., Cl-, SO4

2-, HCO3? Ca2+, Mg2+, and Na+.

Sulin scheme

Proposed by the Russian hydrologist V.A. Sulin (1946), the Sulin classification (Figure 97) recognizes four hydrochemical water classes or types based upon the relative dominant anion (e.g., HCO3? ), and cation (e.g., Ca2+). These are: a) Sulfate - sodium waters

b) Bicarbonate - sodium waters

c) Chloride - magnesium waters

d) Chloride - calcium waters

Most oilfield waters are Chloride - calcium watersbecause they typically contain almost no SO4

2- or HCO3

-, water associated with evaporitic sequences are characterized as Chloride - magnesium waters,whereas meteoric waters are typically Sulfate ? sodiumand Bicarbonate - sodium waters. Data for a given water analysis can be plotted graphically (Figure 97) on a diagram consisting of two axes comprised of the ion pairs, Cl- and Na+, and SO4

2- and Mg2+. Ion concentrations in milligrams per liter (mg/L) are converted to millequivalents per liter (meq/L) and plotted using the appropriate axis. Regions within the diagram correspond to the four hydrochemical water types.

3 Source http://www.energy.gov/

Figure 98. Stiff (1951) diagrams, showing the plotting axes and example plots (after Stiff, 1951; Collins, 1975; and others).

Figure 97. Sulin (1946) classification plot. Values are in milliequivalent percent (meq/L %) and regions for the four hydrochemical water classes or types are indicted (after Sulin, 1946; Collins, 1975; Walther, 2005; and others).



73

Stiff diagrams

Stiff diagrams (Figure 98) are another visual method to compare and contrast the relative proportions of ions in water (Stiff, 1951). Like the Sulin diagram, ion concentrations are plotted in millequivalents per liter (meq/L), in which cations (e.g., Na+, Ca2+, Mg2+, and Fe2+) are plotted on the left and anions (e.g. Cl-, SO4

2-, HCO3-, and CO3) on the right

(Figure 98). The shape of each Stiff plot visually conveys the relative abundance and dominance of specific ions in a given water, since the distance of each vertex from the medial line is proportional to ionic content and abundance. Stiff plots are somewhat flexible, in that different ion combinations can be plotted depending on aqueous geochemistry. For example, plots could incorporate sodium plus potassium (Na++K+), calcium (Ca2+), and magnesium (Mg2+) on the left, with chloride (Cl-), bicarbonate plus carbonate (HCO3? + CO3), and sulfate (SO4

2-) on the right.

Piper diagrams

The Piper diagram, also known as a Trilinear diagram (Piper, 1944), is a plot of the major ions as percentages of milli-equivalents in two base triangles, in which cations plot on the left plot and anions on the right (Figure 99). For each triangular plot the values to be plotted are derived by taking the value for each ion and dividing that value by the sum of all three values, to produce a percentage.

For example, if Ca2+ = 0.26 meq, Mg2+ = 0.89 meq and Na+ + K+ = 0.80 meq, then Ca2+ = 13%, Mg2+ = 45%, and (Na+ + K+) = 40%.

The data points in the central (diamond-shaped) field represent points of intersection, located by projecting points from each of the two lower triangular plots to a point of intersection in the center field. The main purpose of the Piper diagram is to show the clustering of data points to identify and indicate water samples that have similar compositions.

Isotopes

Isotopes are increasingly used in the analysis of oilfield water and ground water in general. Isotope analysis is based on the concept that the relative mass abundance of light to heavy isotopes is large and that some natural process modifies the relative abundance of a given isotope within a system (Turan, 1982). The most commonly used isotopes include the stable isotopes deuterium (an isotope of hydrogen), oxygen, sulfur, and carbon (D, 18O, 34S, and 13C respectively), and the radiogenic isotopes chlorine (36Cl), carbon (14C), and strontium (Sr87) (Chaudhuri, 1978; Connolly et al., 1990).

For stable isotopes, usually one isotope (e.g., oxygen 16O, 18O) has a greater relative abundance, and differences due to fractionation are often small, isotopic abundance is therefore calculated as a ratio and expressed as positive or negative deviations from a standard (Fritz and Fontes, 1980).

For example, the relative abundance of 18O/16O within a sample is compared to the 18O/16O of VSMOW (Vienna Standard Mean Ocean Water as established by the International Atomic Energy Agency). Relative abundance is therefore represented by the formula:

where: represents the deviation from the standard, reported as per mil ( ) and

R is the isotopic ratio: e.g. (18O/16O).

The isotopic abundance of D or 34S is defined in a similar way, although both 18O and D are compared to SMOW, whereas 34S is compared to the Canyon Diablo meteorite (Nielson, 1979).

Radioactive isotopes are reported in different ways. Measurements of 36Cl are reported as a ratio of 36Cl/Cl, whereas 87Sr is given as a normalized ratio, checked against a standard (e.g., SRM-987). Analyses of 87Sr/86Sr isotopic ratios, in conjunction with stable isotopes, can help determine the extent of water/mineral interactions and water mixing, and help identify migration pathways (e.g., Chaudhuri, 1978; Stueber et al., 1987). Oxygen and deuterium values are useful

(5)

Figure 99. Piper diagram (Trilinear diagram) for the Great Plains and Cedar Hills Aquifers in Central Kansas, U.S.A. (from Macfarlane et al.,1988, Open-file Report 88-39).



74

indicators of water origin, whereas strontium can provide information concerning the chemical evolution of water (Chaudhuri, 1978).

Subsurface pressure

Introduction As discussed previously, the pore space within sediment and rock alike is filled with fluid, typically water, which at any given depth, is under pressure. Sedimentary basins are also not homogeneous entities; variations exist, for example, in lithology, porosity, permeability, structure, water composition, petroleum generative potential, and the presence or absence of seals. Such variations will give rise to differences in subsurface pressure. Assessing and understanding subsurface pressure is of importance not only to the engineer, but also to the geologist, especially since the optimal recovery of trapped petroleum without incident is the ultimate goal.

There are a number of different ways of expressing pressure in the subsurface. Subsurface pressures may be expressed as equivalent (reservoir) fluid pressures in pounds per square inch (psi) mega pascals or kilo pascals (MPa or kPa respectively), as a pressure gradient in either psi ft, MPa/km or kPa/m, or equivalent fluid density such as pounds per gallon (ppg) or kg cm-1 m-1. In the U.S.A. pressure gradients are often expressed in psi/ft, elsewhere as MPa/km (or kPa/m) or kg cm-1 m-1.

Pressure regimes

Hydrostatic pressure Hydrostatic pressure is both (a) the pressure exerted (per unit area) in a column of fluid by the density of fluid (i.e., liquid plus solids) and (b) the normal predicted pressure for a given depth exerted by a static column of water due to the density of the liquid (and dissolved solids) plus any pressure acting on the surface of the liquid. Case (a) uses a straightforward approach that we will adopt when describing a bore hole filled with drilling fluid, whereas (b) is more geologically oriented. However, in both cases the size and shape of the fluid column (Figure 100) has no effect on the magnitude of the pressure at any depth, it is liquid density and vertical distance that fundamentally control hydrostatic pressure (Fertle etal., 1976).

However, differences in fluid density and the presence of temperature gradients do affect hydrostatic pressure and hydrostatic pressure gradients. For example, an increase in the concentration of TDS will lead to an increase in the hydrostatic pressure gradient, whereas the presence of gas will decrease the gradient. Similarly, an increase in temperature will lead to a decrease in density and also lower the gradient. Hydrostatic pressure (Phy) at a given depth can be approximated using the average fluid density, multiplied by depth and a gravity constant. However, for oil field purposes hydrostatic pressure is often calculated using the following (or derivative):

Phy = 0.0519 * W * D (imperial units) or (6)

Phy = 0.0098 * W * D (metric units)

where: Phy = hydrostatic pressure (psi or kPa)

W = fluid density, expressed as a weight (lb/gal or kg/m3)

D = the vertical height of the column (feet, SI, or meters) and

0.0519 and 0.0098 are oilfield conversion constants (imperial and metric units respectively)

All oil field measurements are related to the rotary kelly bushing (RKB).

Figure 100. Hydrostatic pressure (Phy), showing that shape is irrelevant. In all cases the vertical height is 3,000 m (9,842 ft), the mud weight density is 1,437 kg m3 (12 lb gal or 0.623 psi ft); in all cases (a to e) the Phy is 21,470 kPa or 3114 psi at the base of each column.



75

Overburden pressure Overburden pressure (Po ) is the sum of rock (i.e., mineral) density, fluid density, and vertical height (Fertle et al.,1976). Since this pressure is due to the combined weight of the rock/sediment matrix and pore fluids, overburden pressure generally increases with depth and has been expressed as:

where: Po = overburden pressure D = vertical height of the geological column (feet or meters)

= porosity (as a fraction) pma = rock matrix density in lb/ft3 or kg/dm3 andpf l = fluid density in lb/ft3 or kg/dm3.

The force exerted due to the combined weight of the rock/sediment matrix and pore fluids creates an overburden pressure gradient, expressed in psi/ft or kg cm-1 m-1. In contrast the pressure gradients exerted by rock matrix (i.e., lithostatic) or pore fluid (i.e., hydrostatic) alone will be less than the overburden pressure (Figure 101). Overburden pressure gradients vary from basin to basin and even within a basin.

Formation pressureFormation pressure (Pf ) is the pressure acting upon formation fluids (gas, oil, water) held within the pore space of rock/sediment. If hydraulic continuity exists between the surface and the subsurface, the pressure will equal the hydrostatic head (hydrostatic pressure, Figure 101).

However, as already discussed, hydrostatic pressure is dependent upon the density of the pore fluid. For example, within the Rocky Mountains (U.S.A.) where meteoric water predominates, the normal pressure gradient is 9.8 kPa/m or 0.434 psi/ft; in contrast, within the Gulf of Mexico formation water is dense and saline (i.e., connate water), and associated with a normal pressure gradient of 11.3 to 12.4 kPa/m or 0.5 to 0.55 psi/ft (Chillingar et al., 2002).

Normal and abnormal formation pressures It is often assumed that for normally compacted formations in which pressure is transmitted through a continuous column of water from surface down to a given depth, the pressure gradient will increase uniformly (linearly) with depth (Figure 102A). However, many basins of the world exhibit markedly nonuniform or nonlinear pressure gradients, where there is a lack of hydraulic continuity between the surface and a formation of interest, perhaps due to the presence of a sealing surface. If the pressure below the seal is greater than the normal (i.e., hydrostatic) pressure gradient, the pressure is termed overpressure (Figure 102B), if the pressure below the seal is less, then the pressure is termed underpressure or subpressure (Fertle et al., 1976).

Figure 102. (a) Normal pressure gradient in which all successively deeper reservoirs [A, B, and C] are in hydraulic continuity with the surface; (b) an abnormal pressure gradient in which a sealing surface isolates reservoir [C] resulting in overpressure [C1] or underpressure [C].

(7)

Figure 101. Subsurface pressure concepts (after Fertle et. al., 1976; Chillingar et al.,2002; Swarbrick et al., 2002; and others).

Figure 102. (a) Normal pressure gradient in which all successively deeper reservoirs [A, B, and C] are in hydraulic continuity with the surface; (b) an abnormal pressure gradient in which a sealing surface isolates reservoir [C] resulting in overpressure [C1] or underpressure [C].



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Therefore, a normal pressure gradient can be visualized as a hydraulic 憃pen system? in which hydrostatic conditions exist (Figure 102A). In contrast, abnormal pressure gradients are essentially 慶losed systems,? in which fluid communication is restricted or prevented (Fertle et al.,1976). In a normally pressured basin, the rock matrix (i.e., mineral grains) supports the overburden load by grain-to-grain contact. If the pressure gradient is high (i.e., overpressured) then the overburden pressure is, in part, supported by formation fluid within the pore space Figure 103).

Overburden pressure gradients vary from basin to basin (Figure 104) and there are many causes of abnormal pressure gradients. For example, variations in fluid and rock density, compaction rates, the permeability evolution of sediment, transformation of kerogen to petroleum and the diagenesis of minerals can all influence the pressure regime of a basin (Fertle et al., 1976; Swarbrick et al., 2002).

Examples of subnormal pressured gradients exist and include, for example, the Permian, Pennsylvanian, Mississippian, and Devonian age formations in parts of the Anadarko Basin, Oklahoma, U.S.A., areas of the Texas Panhandle, U.S.A., with gradients ranging from 0.083 kg cm-2

(0.36 psi/ft) to 0.09 kg cm-2 (0.39 psi/ft), oil and gas reservoirs of Tertiary age and Middle Miocene age in Russia, and the Viking Formation, Alberta, Canada (Fertle et al., 1976). Possible causes for underpressure or subnormal pressured gradients include the presence of abnormally low water tables (e.g., Middle East) or the lowering of the water table by excessive subsurface fluid withdrawal (Swarbrick et al.,2002).

Some factors responsible for overpressure

There are a number of possible reasons for overpressure and only some are presented here. For a contemporary review see Swarbrick et al.,(2002) and Chillingar et al., (2002).

Disequilibrium compaction During sediment burial, an increase in vertical stress, coupled with a marked reduction in permeability, may lead to incomplete sediment dewatering (Figure 103) and fluid retention. The depth at which this phenomenon occurs is known as the fluid retention depth (FRD). The FRD occurs at a shallower depth for 憁ud rocks? of low permeability compared to less compressible and more permeable rocks, such as siltstone and sandstone (Swarbrick et al., 2002). This general phenomenon is commonly termed disequilibrium compaction.

Fluid expansion Fluid expansion can occur due to aquathermal expansion of pore fluids, smectite dehydration, and kerogen transformation/petroleum generation. The aquathermal expansion of pore fluids has been cited as a possible mechanism responsible for abnormal formation pressures (Chillingar etal., 2002). For example, an increase of 40oC will generate a volumetric expansion of pore fluid of 1.65% (Swarbrick et al., 2002). Although this degree of expansion can lead to an increase in pore pressure, aquathermal expansion is not considered capable of generating the high-magnitude overpressures associated with some basins (e.g., Northwest Shelf, Australia).

Smectite dehydration involves three stages of dewatering, with an estimated increase in volume of 4%; whereas the transformation of smectite to illite can generate either a volumetric increase of 4.1% or a decrease of 8.4%, although estimates using a higher geothermal gradient (40 篊 km) yield an estimated increase in overpressure of 0.8 MPa (112 psi) (Swarbrick et al., 2002).

When kerogen is thermally transformed into petroleum there is a volumetric increase, depending upon kerogen Type and the molecular weight and density of the petroleum products. Volumetric increases of 25 vol% are considered

Figure 103. Overpressure. When sediment burial israpid and permeability poor, pore fluid cannotescape and supports the ever-increasingoverburden stress (left). Permeable lithologiesundergo 慸ewatering? (right). Povb = overburdenpressure (psi); Ppore = pore pressure (psi) (image ? 2007 Schlumberger, Ltd. Used with permission).

Figure 104. Generalized example overburden pressure gradients (after Rehm, 1972; Lepine and White, 1973; Fertle et al., 1976; Eaton, 1999; and others).



77

possible during the generation of oil from a Type II kerogen (Meissner, 1978) with estimates ranging from 75 to 140 vol% during the generation of gas at high levels of thermal maturity. The generation of gas can create potential overpressures of 0.5 to 41 MPa (70 to 6000 psi) (Swarbrick et al., 2002).

Overpressure: The concern

There are many reasons abnormal pressure is a concern, especially during the drilling of a well, which include the following (Figure 105):

The ingress of formation fluid into the wellbore, known as a 慿ick? (Figure 105:1). An uncontrolled kick that either flows to the surface or invades another formation is termed a 慴lowout.?

Increasing the drilling fluid density to counter a kick (Figure 105:2) can cause the loss of drilling fluid, known as 憀ost circulation,? into a porous underpressured or normally pressured formation (Figure 105:4). Large scale losses will lower the hydrostatic head of the drilling fluid, creating other problems.

The differential sticking of drill pipe to the wall of the borehole, known as 憇tuck pipe? (Figure 105:3).

A high pore pressure in low permeability rocks (e.g., mudrocks) can cause those rocks to 慶ave? (swell and slough) into the borehole, creating a drilling hazard or complicating the geological interpretation of drilled lithologies.

For these and many other reasons, drillers and engineers alike are constantly seeking and refining means of predicting abnormal pressure regimes ahead of the drill bit. Various approaches have proven useful throughout the last 40 years, especially in clastic-dominated basins, and include the observation of shale cuttings density and shape, the use of d-exponents, wireline data and more recently measurement-while-drillingdevices (MWD).

For a succinct overview of pressure detection methods see Pilkington (1999) and Fertle et al., (2002)

Temperature

Geothermal gradient The subsurface temperature generally increases with depth of burial due to the outward transfer of heat from Earth抯 interior to the surface. A depth-related plot of subsurface temperature creates a temperature profile, generally known as the geothermal gradient. Geothermal gradients range from 18 oC km-1 to more than 55 oC km-1, with a global average of

25 to 30 oC km-1 [or ~15 oF 1000 ft-1]4. Areas of high geothermal gradient, typified by mid-oceanic ridges and rift valleys, have a temperature profile that increases quickly with depth, due to rising hot magma beneath the Earth抯 crust. In contrast, a low geothermal gradient, such as those experienced along a subduction zone, generally have a temperature profile that increases slowly with depth, due to the subduction of relatively cool sea floor, oceanic crust sediments, and fluids. Areas characterized as having an average geothermal gradient include continental areas that do not have tectonically active zones.

Regional and local variations in heat flow also modify the geothermal gradient of an area (Figure 106) due to differences in: lithology, sediment conductivity, sediment compaction, local variations in structure (i.e., presence of

faults), the possible addition of heat from the decay of radioactive isotopes (e.g., 40K, 232Th, 235U, and 238U) (Prensky, 1992), and the intrusion of igneous material.

Thermal conductivity There is no such thing as a linear (i.e., uniform) geothermal gradient with increasing depth for reasons outlined above. Within a given basin, variations in the thermal conductivity of sediment and rock appear to have the most pronounced influence (Figure 106) (Robert, 1988). Thermal conductivity involves the transfer of heat within a geological sequence. 4 The conversion of Celsius to Fahrenheit uses the formula: oF = 32 + 1.8 oC

Figure 105. A representation of some potential hazards and problems associated with overpressured zones during drilling, (1) Ingress of formation fluid(s), (2) increase in mud weight density, (3) differential sticking, and (4) lost circulation (drillstring image of courtesy of Smith International).



78

The transfer of heat is measured in units of heat flow (milliwatt per meter2 or microcalories per cm2), whereas conductivity is the quantity of heat transmitted along a unit of distance (Wm-1 oC-1 or cal cm-1 sec-1 C-1). The average heat flow on Earth is approximately 60 Wm-2 and example thermal conductivities include:

Halite 8 to 11 Wm-1 oC-1 Anhydrite 5.0 Wm-1 o

C-1

Dolomite 5.0 Wm-1 oC-1 Limestone 2.8 to 3.5 Wm-1 oC-1

Sandstone 2.6 to 4.0 Wm-1 oC-1 Shale 1.5 to 2.0 Wm-1 oC-1

Coal 0.3 to 0.6 Wm-1 oC-1.

Variations in thermal conductivity reflect differences in bulk density (notably mineralogy and porosity), variations in water chemistry, and the presence or absence of hydrocarbons. Lithologies that have high thermal conductivities (e.g., halite) dissipate or transfer heat more quickly than lithologies of low thermal conductivity (e.g., coal), therefore, the temperature within lithologies of low thermal conductivity (e.g., shale) will rise (Figure 106). Local and regional variations in thermal conductivity, heat flow, and geothermal gradient have important implications for prospect evaluation, hydrocarbon generation and basin modeling (e.g., Waples, 1984).

Derivation of formation temperature The temperature of a formation is typically obtained as maximum-reading values from the bottom of the wellbore (known as bottom hole temperature or BHT) during petrophysical logging runs. The BHT is obtained by suspending the circulation of drilling fluid for a period of time and allowing the temperature of the drilling fluid, within the bottom of the hole, to equilibrate with the temperature of the adjacent formation (Figure 107). However, the 搕hermal recovery time? for a borehole may range from a few days to several months for deep mud-drilled wells (Prensky, 1992), and because of time constraints, this typically does not happen. Therefore, temperature data must be extrapolated to static conditions using algorithms first suggested by Bullard (1947) and Lachenbruch and Brewer (1959), or using a graphical method known as a 揌orner plot.? Because a similarity exists between the transient response of pressure and temperature build-up, it was suggested (Timko and Fertl, 1972) that the Horner (1951) method be used for the prediction of formation temperature from bottom-hole temperature surveys. The use of the Horner plot approach, in which temperature vs. (t + t)/ t (Figure 108), requires the following data: measured bottom hole temperature, the number of hours since circulation (t), and the duration of circulation ( t). One drawback is that the duration of circulation or time since circulation is not always recorded. Consequently, many extrapolations of formation temperature are derived using a graphical solution for temperature, corrected for differences in surface temperature when BHT data exists for two depths (e.g., Schlumberger, Gen-6). A linear relationship is assumed between the ambient surface temperature and BHT temperatures at all depths.

Figure 108. A temperature vs. (t + t)/ t plot, also known as a 揌 orner type plot,? see text for details (data from Kutasov and Eppelbaum, 2005).

Figure 107. The thermal recovery of bottom hole temperature (BHT) and true (equilibrated) formation temperature (A) for a number of log runs at a given depth. Note: BHT temperatures are obtained during each petrophysical log run, note also that the difference in temperature between actual temperature and the recorded BHT diminishes for each successive log run and that the acquisition of an equilibrated temperature (A) may require a prohibitively long period of time.

Figure 106. A variation in geothermal gradient in response to differences in thermal conductivity; where shale units 1, 2 and 3 have the lowest thermal conductivity (high geothermal gradient), sandstone units 1 and 2 have the highest thermal conductivities (low geothermal gradient) and siltstone units 1 and 2 are intermediate.



79

References

Breit, G. N., Y. K. Kharaka, and C. A. Rice, 2000, National database on the chemical composition of formation water from petroleum wells in Environmental issues and solutions in petroleum exploration, production and refining (K. L. Sublette, ed.): Proceedings of the 7th IPEC meeting, Albuquerque, New Mexico, U.S.A., Nov. 7-10, University of Tulsa, p. 920-943 (CD-ROM format).

Breit, G.N., Y. K. Kharaka, C. A. Rice, 2001, National database on the chemical composition of formation water from petroleum wells in Sublette, K.L., ed., Environmental Issues and Solutions in Petroleum Exploration, Production and Refining (L. L. Sublette, ed.): Proceedings 7th IPEC meeting, November, 2000, CD-ROM format, 20 p.

Bullard, E. C., 1947, The time taken for a borehole to attain temperature equilibrium: Monthly Notices of the Royal Astronomical Survey, Geophysical Supplement, v. 5, p. 127-130.

Chaudhuri, S., 1978, Strontium isotopic composition of several oilfield brines from Kansas and Colorado: Geochim. Cosmichim. Acta, v. 42, p. 329-331.

Chillingar, G. V., J. O. Robertson Jr., and H. H. Rieke III, 2002, Origin of abnormal formation pressures in Origin and prediction of abnormal formation pressures, (G. V. Chillingar, V. A. Serebryakov, and J. O. Robertson Jr., eds.): Developments in Petroleum Science, 50, Elsevier, Amsterdam, p. 21-68.

Collins, A. G., 1975, Geochemistry of oil field waters: New York, Elsevier Scientific Pub. Co., 496 p.

Connan, J., 1984, Biodegradation of crude oils in reservoirs in Advances in Petroleum Geochemistry, v. I, (J. Brooks and D. H. Welte, eds.): Academic Press, London, p. 229-335.

Connolly, C. A., L. M. Walter, H. Baadsgaard, and F. J. Longstaffe, 1990, Origin and evolution of formation waters, Alberta Basin, Western Canada Sedimentary Basin. II. Isotope systematics and water mixing: Applied Geochemistry, v. 5, p. 97-413.

Eaton, B.A., 1999, Fracture gradient prediction and its application in oilfield applications in Pore pressure and fracture gradients, (Society of Petroleum Engineers Staff, eds.): SPE Reprint Series no. 49, Richardson, Texas, U.S.A., p. 88-95.

Fertle, W. H., G. V. Chilingarian and H. H. Rieke, III, 1976, Abnormal Formation Pressures, Developments in Petroleum Science, 2, Elsevier Scientific, Amsterdam, Oxford, New York, 382 p.

Fertle, W. H., G. V. Chilingar, and J. G. Robertson, 2002, Drilling parameters in Origin and prediction of abnormal formation pressures, (G. V. Chillingar, V. A. Serebryakov, and J. O. Robertson Jr., eds.): Developments in Petroleum Science, 50, Elsevier, Amsterdam, p. 151-167.

Fritz, P., and J. C. Fontes, 1980, Introduction in Handbook of Environmental Isotope Geochemistry, v.1., (P. Fritz and J. C. Fontes, eds.): Elsevier, Amsterdam, p. 1-19.

Horner, D. R., 1951, Pressure buildup in wells: Proceedings of the World Petroleum Congress, v. 3rd (2), p. 503-521.

Kutasov, I. M., and L. V. Eppelbaum, 2005, Determination of formation temperature from bottom-hole temperature logs-a generalized Horner method: J. Geophys. Eng. v. 2, p. 90? 6.

Lachenbruch, A. H., and M. C. Brewer, 1959, Dissipation of the thermal effect of drilling a well in arctic Alaska: U.S. Geological Survey Bulletin 1083-C, p. 73-109.

Lepine, F. H., and J. A. W. White, 1973, Drilling in overpressured formations in Australia and Papua New Guinea: APEA Journal, v. 13, no. 1, p. 157-161.

Macfarlane, P. A., M. A. Townsend, D. O. Whittemore, J. Doveton, and M. Staton, 1988, Hydrogeology and water chemistry of the Great Plains (Dakota, Kiowa, and Cheyenne) and Cedar Hills Aquifers in Central Kansas: Kansas Geological Survey, Open-file Report, p. 88-39.

McFarlane, J., D. T. Bostick, and H. Luo, 2002, Characterization and Modeling of Produced Water: presented at the 2002 Ground Water Protection Council Produced Water Conference, Colorado Springs, CO, Oct. 16-17, (available at: http://www.gwpc.org/GWPC_Meetings/Information/PW2002/Papers/Joanna_McFarlane_PWC2002.pdf).

Meissner, F. F., 1978, Petroleum geology of the Bakken Formation, Williston Basin, North Dakota and Montana in24th annual conference, Williston Basin symposium: Montana Geological Society, p. 207-227.

Nielson, H., 1979, Sulfur Isotopes in Lectures in Isotope Geology, (E. Jager and J. C. Hunziker, eds.): New York, Springer-Verlag, p.283-312.

Palmer, S. A., 1991, Effects of biodegradation and water washing on crude oil composition in Source and migration processes and evaluation techniques (R. K. Merrill, ed.): AAPG Treatise of Petroleum Geology, p. 47-54.



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Pilkington, P. E., 1999, Uses of pressure and temperature data in exploration and new developments in overpressure detection in Pore pressure and fracture gradients (Society of Petroleum Engineers Staff, eds.): SPE Reprint Series, no. 49, Society of Petroleum Engineers, Richardson, Texas, p. 64-70.

Piper, A. M., 1944, A graphic procedure in the geochemical interpretation of water analyses: Am. Geophys. Union Trans., v. 25, p. 914-923.

Prensky, S., 1992, Temperature Measurements in Boreholes: An Overview of Engineering and Scientific Application: The Log Analyst, v. 33, no. 3, p. 313-333.

Price, L. C., 1976, Aqueous solubility of petroleum as applied to its origins and primary migration: AAPG Bulletin, v.60, p. 231-244.

Pourbaix, M., 1966, Atlas of Electrochemical Equilibria in Aqueous Solutions: Pergamon, New York, 644 p.

Rehm, B., 1972, Worldwide occurrence of abnormal formation pressures, II: Abnormal Subsurface Pressure Symposium, 15-16 May, Baton Rouge, Louisiana, SPE, http://www.spe.org/elibrary/app/search.do.

Robert, P., 1988, Organic metamorphism and geothermal history: Elf-Aquitaine and D. Reidel Publishing Company (Kluwer), Dordrecht, Boston, Lancaster, Tokyo, 311 p.

Schlumberger, 2007, On-line glossary: http://www.glossary.oilfield.slb.com/

Stiff, H. A., Jr., 1951, The Interpretation of Chemical Water Analysis by Means of Patterns: Journal of Petroleum Technology, v. 3, no. 10, p. 15-17.

Stueber, A. M., P. Pushkar, and E. A. Hetherington, 1987, A strontium isotopic study of formation waters from the Illinois Basin, U.S.A.: Applied Geochem., v. 2, p. 477-494.

Sulin, V. A., 1946, Waters of petroleum formations in the system of nature waters: Gostoptekhizdat, Moscow, (in Russian), 96 p.

Swarbrick, R. E., M. J. Osborne, and G. S. Yardley, 2002, Comparison of overpressure magnitude resulting from the main generating mechanisms in Pressure regimes in sedimentary basins and their prediction, (A. Huffman and G. Bowers, eds.): AAPG Memoir 76, p. 1-12.

Timko, D. J., and W. H. Fertl, 1972, How downhole temperatures and pressures affect drilling: World Oil, v.175, p. 73? 0.

Turan, L., 1982, Isotopes in ground-water investigations: Ground Water, v. 20, no. 6, p. 740-745.

Walther, J. V., 2005, Essentials of geochemistry: Jones and Bartlett Publishers, Sudbury, Massachusetts, 704 p.

Waples, D. W., 1984, Thermal models for oil generation in Advances in Petroleum Geochemistry, vol. I., (J. Brooks and D. H. Welte, eds.): Academic Press, London, p. 7-67.


Chapter 6—Exploration

81

EEExxxppplllooorrraaattt iiiooonnn

Land acquisition

The petroleum landman

Role and function The private ownership of land is permitted in many countries of the world. Some countries (e.g., U.S.A., UK, and Canada), allow the private ownership of oil and gas interests or 憆ights.? Typically, such rights predate an act of union (e.g., U.S.A.) or act of parliament. Invariably, governments control the leasing of most oil and gas interests on the continent (i.e., on-shore) and all of the interests off-shore. Therefore, an exploration company seeking both access to land and the right to explore/produce oil and/or gas must determine who holds the 憆ights? and the steps necessary to acquire and maintain that lease. In North America, that person is the 慙andman.? The role and function of the Landman may vary from company to company; however, all successful Landmen share the same professional attributes; they are knowledgeable and skillful negotiators.

The Petroleum Landman may be involved in any one or all of the following activities (Tinkler, 1992): the acquisition of leases and drilling rights, the maintenance of leases, agreements, contracts and legal obligations, and ultimately the disposition of leases and termination of contracts.

AcquisitionThe acquisition of leases begins with the examination of public records to determine who holds oil and gas rights in a given area of interest. A review of previous lease sales in the area or adjoining area will be undertaken and perhaps the past and present activity of other companies will be researched. The Landman must also determine the necessary terms to obtain a lease if privately owned, or the value of the lease, if the lease is awarded on the basis of a sealed bid. If leases are awarded on a first-come-first-served basis, then appropriate steps must be undertaken.

Fundamentally, the Landman must obtain the rights to explore and produce oil/gas. In addition to the acquisition of the oil and gas lease, there maybe permits to acquire and contracts (such as Farm-outs or Joint Operative Ventures) to negotiate and asset trades to deal with.

MaintenanceOnce a lease or an agreement has been attained there then follows a period of maintenance during which the administration of the lease must be maintained. For example, during this time the processing of payments or royalties must be maintained, land titles and leases may require curative work or maintenance and there will be a need to keep track of all lease and contractual obligations. It may also be necessary to enter into contractual negotiations with investors or outside parties who have an ongoing interest, or who have developed an interest, in the associated venture. This may lead to 慺arm-outs? and 慺arm-in? agreements, seismic options, bottom-hole contributions, etc.

Disposition

Ultimately a decision will be made to trade, release, or surrender the lease, and terminate contracts, or to permit them to expire. Therefore, the Landman will be involved in the possible Farm-out, sale, or disposal of oil and gas interests. Whatever transpires, company records must be maintained and the filing of all necessary documents with the appropriate government department or agency should be done in a timely manner.

Farm-out and Farm-in: If an oil and gas company holding a lease (hence known as the Farmor) agrees to assign a portion of that lease (called the farm-out-area) to another company (the Farmee), in consideration of the Farmee drilling a specified number of wells on that Farmed-out-area, then the Farmor has made a Farm-out and Farmee has made a Farm-in.

Joint Operating Agreements (JOA): A JOA, or operating agreement, occurs when two or more companies who share a working interest share the risk of drilling, developing, and operating an oil or gas venture. Typically one of the companies acts as the operator for all the companies bound by the JOA. The JOA also specifies how the costs and revenue will be shared and how leases will be acquired, maintained, and disposed of (Tinkler, 1992)



82

Land description and land maps

Subdivision of land Legal property descriptions and oil and gas maps are the means through which a well is physically located and the subsurface geology portrayed. Geologists are familiar with various types of map, such as topographic maps, solid-geology maps, isopach maps, structural maps, etc., but 搇and? maps are planimetric maps that show the subdivision of land without reference to variations in ground elevation.

Land maps consist of a grid system where land is divided into blocks that may be subsequently subdivided into smaller blocks. The grid systems of many land maps are typically tied to the major trending lines of latitude and longitude. The legal description of property and well location is only one aspect of a land map; land maps also typically include (Tinkler, 1992):

The legal description of the well/property by township, range, section, block, survey, or LSD1

The names of operators and/or leases

Surface land ownership, and

Mineral ownership (if different from the surface land owner)

Lease status

Pertinent well data, such as well name, well status, total depth, etc.

The names of significant land marks, such as roads, streams, lakes.

Legal property descriptions The inaccurate description of property or a well is the most common reason why land titles fail. In the United States the subdivision of land typically follows the Rectangular System of Surveys, or more commonly known as the Public Lands Survey, which was adopted by the U.S. Government for Alabama, Florida, Mississippi, all lands west of the Mississippi (except Texas) and all states north of the Ohio River (Figure 109). Those states not included in this system use a sectionalized system developed within each state. Through a system of land subdivision based on east-west and north-south lines, land subdivided according to the Public Lands Survey is divided into squares called townships, ranges, and sections. All surveys have a reference point or Point of Beginning. This reference point is the intersection of an east-west 揵aseline? and a north-south 搈 eridian.? For example, in Kansas this point is known as the Initial Point for the Sixth Principal Meridian.

The Public Lands Survey divides the land into 搕ownships,? which are square parcels of land that are six miles on each side. The location of a given Township is by reference to the number of townships north or south of the baseline, and the number of Ranges, east or west of the reference meridian. Each township is further divided into 36 parts called

1 LSD: (Legal subdivision) a legally defined subdivision of land or territory: an area composed of subdivided lots

Figure 109. A representation of the Public Lands Survey system of land subdivision used by many states in the United States of America. For example, the legal description for well 慪? shown in the 40-acre subdivision above (D) would be Township 2 North,Range 2 West, nth Principle Meridian (T-2-N, R-2W, nthPM), Section nineteen (19), southwest quarter (SW/4) of the northwest quarter (NW/4), southeast corner (SE Cor.). Putting that together we would have: SE Cor., SW NW, Sec 19, T-2-N, R-2W, nthPM.



83

搒ections.? Each section contains 640 acres or one square mile. Because of the Earth抯 curvature, corrections must be made every 30 miles, which is every 5th Township line.

The subdivision of land in the Provinces of Alberta, Manitoba, and Saskatchewan within Canada is similar, in that it uses imperial units of measurement, and is based upon a Township and Range planimetric grid system. However, because this system is based on the Torren System, the numbering of sections differs from that used within the Public Lands System of the U.S.A., and note also that the subdivision of each section uses a grid of 16 40-acre blocks. The subdivision of land is represented in Figure 110.Adjacent to the western side of a meridian the subdivisions are of 憇tandard? proportions, consisting of full quarters. To compensate for the curvature of the Earth, subdivisions are often irregular, consisting of partial or make-up 憅uarters?close to Provincial borders and along the eastern side of each meridian. The minimum spacing for a conventional well is 40 acres, and for a gas well is 80 acres. Wells are located by the further subdivision of each LSD, and then using Lat. and Long.

Offshore descriptions and subdivision In the United States, offshore areas that are subject to state control use the same system that was devised for land. However, areas of Federal interest utilize the Outer Continental Shelf Leasing Maps designated by the Mineral Management Services (1984). Such maps are subdivided into blocks that are 5760-acre blocks, except offshore Louisiana, which uses 5000-acre blocks.

On the East Coast of Canada, such as the Scotian Shelf, a hierarchical system has been devised based upon regular subdivisions of longitude and latitude. The largest subdivisions are Grids, which in turn are subdivided into Sections and subsequently into Units (Figure 111). Further refinement is possible by subdividing each Unit into four 200 m2 quadrants known as Targets.

The United Kingdom uses a well-registration numbering system that permits the identification of Country, the number, or letter of the quadrant in which the well is drilled, and pertinent drilling information. UK quadrants are areas enclosed by one degree of latitude and longitude, and each UK Quadrant is divided into 30 blocks measuring 12 minutes of longitude by 10 minutes of latitude (Figure 112). The well-registration numbering system includes both Quadrant, the number of the block within the quadrant, and a block-suffix, if the block is subdivided.

Figure 111. The Grid, Section, and Unit system that is utilized off shore Nova Scotia, Canada.

Figure 110. A representation of the Torren Survey system of land subdivision used by some of the Provinces of Canada. For example, the well in the 40-acre LSD above (indicated by a ? ? is in Township 2, Range 2West of the X Meridian, Section thirty (30), LSD 13. Putting this all together we would have: 6-13, T2, R2WX.



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Figure 112. The Quadrant system of the United Kingdom (offshore). The planimetric grid that subdivides offshore England and Scotland into numbered Quadrants is based upon lines of longitude and latitude. The inset diagram (blue border) illustrates the numbering and subdivision of each Quadrant. England and Scotland are shown in solid grey (modified from the UK Department of Trade and Industry, PON12, 2005; ? Crown copyright material is reproduced with the permission of the Controller of HMSO and Queen's Printer for Scotland ).



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Surface prospecting and remote sensing

Seeps (oil and gas)

IntroductionA visible oil or gas seep may be an important phenomenon in oil exploration; their presence is an indication of petroleum and/or source rocks within the subsurface, since many seeps represent the tertiary migration of petroleum. Many oil fields have been discovered through the associated presence of an oil seep, including Baku (Russia), many fields within California, Oil creek (Pennsylvania), Golden lane (Mexico), Masjid-I-Sulaimin field (Iran) and the Hombre Pintado field (Venezuela), to name but a few. However, the concept of using seeps and other remote sensing techniques, as a prospecting tool, has fallen out of favor with many exploration companies, but not all! The existence of a surface seep is hard to ignore. But rather than simply indicate the presence of hydrocarbons within the subsurface, the presence of a surface seep may indicate something else, such as a deficient trap

Weathering and transformation of seeps Hydrocarbons associated with seeps do not remain in pristine condition for long. A transformation readily occurs depending upon: oxygen availability, temperature, the presence or absence of water, and the presence or absence of bacteria. Changes initially involve a lowering of 癆PI gravity followed by pronounced changes in molecular composition, viscosity, and solubility; the end product is a solid-like material known as pyrobitumen (Figure 113).

Classification of seeps Upon encountering a surface seep, the first step would be to characterize the seep material and determine if the seep is: active (i.e., live), inactive (often manifest by the presence of solid bitumen impsonite or grahamite), or a false seep such as those associated with landfill sites. Link (1952) offered a simple classification of seeps that was related to their geological mode of occurrence. Most seeps occur at basin margins and in sediments that have been either folded or faulted and eroded. The classification of Link (1952) is straightforward and relatively uncomplicated, consisting of:

1. Seeps emerging from homoclinal beds, the ends of which are exposed and the beds outcrop at the surface (e.g., Trenton Limestone, Canada).

2. Seeps associated with source rocks that have become fractured or exposed to the Earth抯 surface (e.g., Green River Fm, Uinta Basin, U.S.A.).

3. Seeps from large hydrocarbon accumulations that have been exposed by the erosion of faulted or folded reservoir rock (e.g., Masjid-I-Sulaimin field, Iran, or the Hombre Pintado field, Venezuela).

4. Seeps along the outcropping of an unconformity (e.g., Athabasca oil sands, Canada).

5. Seeps associated with igneous intrusions, salt diapirs, or other local sources of extraneous heat that may 憁obilize?a small portion of a reservoir (e.g., Golden lane, Mexico).

Gas or condensate seeps and geochemical prospecting

Terrestrial seeps

Gas and condensate are difficult to detect as seeps, unless under water. Light hydrocarbons typically evaporate or are easily dissipated at the Earth抯 surface and, therefore, cannot be detected directly. However, gas and condensate seeps have been detected, for example, in Louisiana, Texas, and the Gulf of Mexico, indirectly through the occurrence and

Figure 113. The sequential transformation of crude oil due to weathering. Physical and chemical changes are summarized (above) and the end product, a sample of Pyrobitumen from Western Canada, is shown right. The Pyrobitumen displays a characteristic optical texture (indicated by the arrows) due to an increase in molecular order when examined in cross

polarized reflected white light. The image is approximately 150 m across (image courtesy of L. Stasiuk).



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association of 憄araffin dirt.? Paraffin dirt is typically yellow, behaves elastically, and resembles natural gums and resins in appearance. However, paraffin dirt does not contain hydrocarbons of thermogenic origin. It is composed almost entirely of microbial cells and bacteria (including methane-, ethane-, propane-, and butane-metabolizing bacteria), and metabolic by-products.

Underwater seeps Live or active seeps have been found on the continental shelf off the coast of California, such as those associated with the Ventura field, California. Underwater oil seeps have been identified visually, since gas bubbles are amenable to visual detection. The unambiguous detection of a thermogenic gas seep requires the use of sophisticated 慻as sniffers.? Such devices are sensitive detectors with claimed detection limits of 0.5 ppb. However, like all techniques, the user must be aware of certain limitations. It must be determined if the gas is biogenic or thermogenic, the latter implies the presence of an active source rock and migration system. Whereas biogenic gas is the by-product of the microbial decay of buried organic matter and may not be linked to an economic accumulation of petroleum! The presence of propane and ethane (plus others) is often taken as an indicator of thermogenic gas, but should be confirmed by isotope analysis.

Offshore gas sniffing is also difficult to interpret in areas frequently used by shipping, or in coastal areas adjacent to cities or industrial centers. Surface prospecting techniques, such as all exploration (i.e., 憄rospecting? techniques may or may not work with equal success in all areas. Each area must be evaluated on its own merit!

Geophysical exploration

Introduction

With costs rising, no one would seriously consider drilling a well using any of the reconnaissance techniques prevalent in the nineteenth century. Business decisions require data and a detailed prognosis of the play to be explored. Acquiring subsurface data by drilling a borehole is expensive and while it provides a great deal of geological data, the reliability of that data, beyond the confines of the borehole is unknown. Fortunately, there are techniques that can be used to provide information of an area of interest and/or help relate one borehole to another.

Analysis of outcrop and surface topography give vital clues to the geological style of an area or basin (Video 7) that can supplement the information provided by geophysical surveys (Video 8). Geophysical surveys provide a cost-effect means of acquiring geological information of an area of interest; information that can help reduce exploration risk. There are three types of geophysical survey frequently used in the petroleum industry:

magnetic anomaly surveys

gravity surveys

seismic surveying

Both magnetic and gravity survey techniques are reconnaissance-type surveys, often conducted from the air to facilitate speed and permit the surveying of large tracts of the Earth抯 crust. In contrast, seismic surveys provide a greater degree of subsurface detail, but require physical contact with the ground.

Video 8. Geophysical techniques, from 揟 he Making of Oil? (? 1996 Schlumberger, Ltd. used with permission).

Video 7. Surface techniques, from 揟 he Making of Oil? (? 1996 Schlumberger, Ltd. used with permission).



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Magnetic anomaly surveys

Magnetic surveying investigates anomalies in the Earth抯 magnetic field due to the magnetic properties of rocks within the subsurface (Figure 114). Magnetic surveys can be conducted from the air, over land or water as an airborne survey. Such surveys typically cost 40% less than ground-based surveys and can be conducted over relatively inaccessible terrain. Aeromagnetic surveys usually have the sensor suspended or towed from an aircraft, whereas marine surveys can be conducted from a sensor towed some distance behind a ship. Therefore, magnetic surveys are well suited as a reconnaissance tool, providing geological information over a very large and extensive region, such as a continental shelf (Keary and Brooks, 1991). In the absence of magnetic minerals within rocks of a sedimentary basin, a magnetic survey can provide information on structures and the composition of the underlying crystalline basement. Magnetic surveys provide an overall assessment or geological impression of basement topography, possibly indicating the basin depocenter (Figure 114). In areas where it is believed that overlying sediments are controlled by the crystalline basement, magnetic surveys can be used to help delineate areas of exploration potential. Therefore, a magnetic survey is primarily regarded by the oil industry as a reconnaissance tool! However, they are incapable of locating small structures, such as reefs. Many national geological surveys conduct magnetic surveys as a matter of course. However, more companies are running their own high-resolution magnetic surveys, recognizing that lineaments, faults, and basement highs typically leave a geological imprint on the overlying strata with the potential to influence migration fairways and plays.

Gravity surveying

The gravity method is also used as a reconnaissance tool. However, gravity surveys are capable of suggesting the presence of small-scale structures, such as salt domes and reefs. Gravity surveys are feasible because global and regional variations in gravity exist due to crustal heterogeneity and differences in rock density. The unit of gravity measurement is the Gal, named in honor of Galileo, which is divisible into mGal and Gal. 1.0 Gal is equal to 1 cm sec2. Generally gravity decreases with increasing distance from the center of the Earth; either as a function of the Earth抯 shape (as an oblate spheroid) or due to changes in elevation or with changes in mass! The presence of a rock unit of differing density from the surrounding rocks will cause a local perturbation in the Earth抯 gravitational field, generating what is commonly known as a gravity anomaly. Once corrections for surface effects, latitude, elevation, tide and instrument drift have been made, the presence of bodies of varying mass result in variations in gravity, or 慳nomalies? (Figure 115). A gravity anomaly can be expressed by differences in rock density:

p = P1 - P2 (8)

where, P1 is the density of a body of rock, surrounded by rock of density (P2) and

p represents the difference in density.

Figure 114. Two imaginary transects, depicting a simplified geology and their respective gravity (G) and magnetic (M) responses.

Figure 115. This illustration shows the relative effect of a small body of high mass and a larger body of lower mass against corrected 慴ackground? gravity;note that ground elevation has no effect upon the gravity survey device.



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Video 9. A short movie featuring a Vibrator truck,from 揟 he Making of Oil? (? 1996 Schlumberger, Ltd. used with permission).

Table 9. Compressional wave velocities (Vp) for selected geological materials.

Material Vp (km s-1)

Sand (wet) 1.5 ? 2.0 Clay 1.0 ? 2.5 Sandstone Tertiary 2.0 ? 2.5 Carboniferous 4.0 ? 4.5 Limestone Cret. chalk 2.0 ? 2.5

Carbonif. lms 3.0 ? 4.0 Dolomite 2.5 ? 6.0 Salt 4.5 ? 5.0 Anhydrite 4.5 ? 6.5

If the density difference is negative then the gravity anomaly will be negative. The principal reason for variations in rock density in sedimentary rock is rock porosity; hence, densities increase within rocks of low porosity or increasing depth. Some example densities are given in Table 8 for common sedimentary rocks. Gravity anomalies range from the small scale, such as a buried valley or reef, to larger anomalies, such as a salt dome and regionally extensive anomalies, typical of igneous plutons. However, it is generally recognized that it is difficult to distinguish between small bodies of high mass and large bodies of low mass. Bouguer anomaly maps can help delineate areas of differing density; low-density sediment appear as negative anomalies, and rocks of relatively higher density appear as positive anomalies.

Seismic surveying

Introduction Seismic waves are 憄arcels? of elastic strain energy that propagate outwards from a seismic source (e.g., explosion). The velocity of a seismic wave is determined by the physical properties of the rock(s) transmitting the wave. If the rock properties are homogeneous (i.e., isotropic) then the wave front travels at the same speed in all directions and the locus of the wave front would define a sphere, rather like ripples on water (Figure 116). Physical properties, such as mineral composition; grain size, shape, and sorting; porosity; and pore fluids type combine to determine the density and elastic modulus for a given rock unit, and, therefore, seismic velocity. Compressional wave velocities (Vp) vary from 0.5 to 1.0 km s-1 for dry sand up to 2.0 to 6.5 km s-1 for anhydrite (Table 9). In general Vp increases with depth of burial, due to the combined effects of increased confining pressure, compaction, and cementation, although frequency decreases. The presence of gas also reduces shear wave velocity (Vs) (Keary and Brooks, 1991).

Energy sources

Land: Vibroseis or Vibrator truck has rapidly become the most common non-explosive method utilized on land. These truck-mounted pad vibrators (Figure 117; Video 9) are capable of creating a sweep signal from 10 to 80 Hz for extended periods of time. Vibroseis units can also be used as linked units by phase-linking each unit, thereby permitting deep seismic penetration of the crust. Because such units require good contact between pad and ground they work best on firm ground; and unlike dynamite they are urban environment friendly. Land-based recording devices are called geophones (Short, 1992).

Figure 117. A seismic energy source; the vibrator truck.

Table 8. Ranges in rock density for common sedimentary rocks (after Keary and Brooks, 1991)

Lithology Density (Mg m-3)

Clay 1.63 ? 2.60 Shale 2.06 ? 2.66 Sandstone (Cretaceous) 2.05 ? 2.35 Sandstone (Tertiary) 2.25 ? 2.30 Sandstone (Carboniferous) 2.35 ? 2.55 Chalk 1.90 ? 2.90 Limestone 2.60 ? 2.88 Dolomite 2.28 ? 2.90 Halite 2.10 ? 2.40

Figure 116. The relationship between a ray path to an associated wave front in an homogeneous rock unit (after Keary and Brooks, 1991; with permission of Blackwell Publishing).



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Marine: There are many seismic source options for use offshore that are typically chosen for a specific depth of penetration and resolution. The most commonly used include the air gun, water gun, sparkers, pingers, and boomers.Air guns (Video 10) are capable of deep penetration whereas water guns can achieve high resolution because there is no 慴ounce back,? a phenomenon associated with pneumatic devices. Sparkers are electrical devices that can achieve high resolution but are best suited to shallow depths. Marine recording devices (Video 11) are called hydrophones (Dessler, 1992).

Seismic wave paths

As mentioned above, reflection seismic surveying utilizes the reflection and refraction of compressional waves that travel from a seismic source back to the surface (Video 11), permitting us to interpret the subsurface. Since wave properties are predominantly a function of the elastic modulus and density of the transmitting and propagating media (i.e., rock plus pore fluids) when seismic waves (wavelets) pass from one lithology to another, those wavelets undergo a change in velocity, amplitude, and direction. To help explain the complex behavior of seismic waves it is useful to introduce their behavior as analogous to light waves, because compressional waves have amplitude, wavelength, and frequency, rather like light (Figure 118). The interface between two lithologies of differing density is known as a velocity interface. The analogy of the light ray is useful because it illustrates that the transmission of seismic waves, through strata of differing density, results in both reflection and refraction at each velocity interface, according to Snell抯 law2. Since we are primarily concerned with reflection seismology, the arrival time of reflected wavelets to a given geophone/hydrophone is given as a two-way travel time. However, in reality seismic waves are not simple vectors, but travel as spherical wave fronts (Figure 119) that radiate from the energy source. Because multiple geophones are used during a seismic survey (e.g., 12 to 1064 arranged as an array), two-way travel times for reflected seismic waves increase with increasing distance from the mid-point or source (Figure 120) which creates a velocity hyperbola, known as diffraction. Raw, unprocessed seismic data is of little use for geological interpretation. Processing raw data involves a number of possible steps, such as stepout correction, stacking, seismic migration, convolution, and deconvolution.

2 Which relates the angle of incidence and refraction to the propagation velocity within the two media.

Figure 118. A seismic ray as analogous to a light ray. In this example, the seismic wave travels through lithology 1 with uniform velocity, amplitude and frequency. When the seismic wave encounters a change in lithology with differing density, noted by the velocity interface, the seismic wave is both reflected and refracted where:

v1 = velocity of lithology 1 v2 = velocity of lithology 2 v2 = velocity of lithology 2

and (a) = Reflected wave

(b) = Refracted wave

Video 11. An animation of the seismic wave propagation process in a marine setting, from 揟 he Making of Oil?(? 1996 Schlumberger, Ltd. used with permission).

Video 10. Seismic and data acquisition, from 揟 he Making of Oil? (? 1996 Schlumberger, Ltd. used with permission).



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Figure 119. A graphical representation of 憇eismic wave offset,? in which a planar surface generates an apparent surface of curvature (velocity hyperbola).

Seismic data processing

Stepout and stacking The horizontal distance from the seismic source to receiver (e.g., geophone) is termed offset. When using multiple geophones, two-way travel times between the surface and a given velocity interface increase as the distance between shot point and each geophone (i.e., offset) increases. This creates a delay, known as moveout, in the arrival time of reflected waves creating a velocity hyperbola (Figure 119). Stepout correction involves correcting for seismic moveout (vertical wave offset), otherwise planar surfaces will not appear planar. Moveout correction for horizontal and planar surfaces is known as normal moveout correction (NMO); dip moveout correction (DMO) is a correction applied to dipping reflectors (Keary and Brooks, 1991; Duncan,1992). When using multiple energy sources, and several arrays of geophone/hydrophone, velocity hyperbola are combined, or stacked to eliminate random background noise and create continuous seismic sections; typically represented as a wiggle trace in conventional seismic sections.

CMP, CDP, and migration The common midpoint (CMP) is the midpoint, at the Earth抯 surface, between source and receiver (Figures 120a and 120b). If the reflector is a horizontal plane, the common midpoint lies vertically (Figure 120a) above the common depth point (CDP), which is also the common reflection point (Keary and Brooks, 1991; Larner and Hale, 1992). Common depth point profiling has become the standard method used in two-dimensional (2-D) multi-channel seismic surveying because traces from different source-receiver pairs that share a common midpoint can be corrected to remove the effects of different source-receiver offsets, and stacked to improve the signal-to-noise ratio (Keary and Brooks, 1991; Larner and Hale, 1992).

However, sediments and sedimentary rocks are not always horizontal layers. Dipping reflectors do not have a common depth point because the reflection point for each successive source-receiver pair will be displaced updip (Figure 120b). Migration is a form of seismic processing that repositions reflection events (e.g., the dipping surface in Figure 120b) to their correct surface locations and at a corrected vertical reflection time (Keary and Brooks, 1991).

Figure 120. Common depth point (CDP) reflection profiling. (a) The seismic reflector is a horizontal surface. The common midpoint (CMP) directly overlies a common depth point (CDP), which is common to all source-detector pairs (S1 to S3; D1 toD3 respectively); (b) For a sloping reflector there is no common depth point and the reflection point differs for ray pairs S1-D1, S2-D2 and S3-D3 (after Duncan, 1992).



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If the survey line is at some angle to the dip of the reflector (e.g., along the strike) in a 2-D seismic survey, the reflection point is displaced out of the plane of section, i.e., cross-dip (Keary and Brooks, 1991). Cross-dip cannot easily be resolved with two-dimensional (2-D) seismic surveys and represents a problem and limitation regarding 2-D seismic data. However, the problem is easily resolved using three-dimensional (3-D) seismic surveys, since reflection points can be migrated in any azimuthal direction.

Convolution and deconvolution During the seismic reflection process, seismic energy is naturally filtered by the Earth. Wavelets change as they propagate through layers of differing sediment. As stated above, the interface between two lithologies of differing density is known as a velocity interface; as wavelets encounter a velocity interface, each reflecting velocity interface reflects the whole wavelet but a reduced amount of the original energy. Convolution is a process of filtering the propagation of seismic energy within the Earth and is a natural filtering process. Convolution can be used to model the filtering of seismic energy by the various rock layers in the Earth.

Deconvolution is used in seismic processing to counteract the adverse affects of filtering, or convolution that occurs naturally as seismic energy is naturally filtered by the Earth, or the removal of the frequency-dependent response of the seismic source and recording device and instrument (Duncan, 1992). Examples of seismic trace processing are given in Figures 121 and 122.

Figure 121. Example seismic traces showing the result of various types of seismic processing. (a) The shot-to-receiver offset is zero at the center and increases to 2000 m at either end. Note the presence of offset-related hyberbola due to normal moveout. (b) After theapplication of normal moveout correction (NMO) the horizons are flat. (c) A seismic section is produced by combining and stacking six adjacent shots (from Duncan, 1992; images courtesy of Landmark Graphics Corporation).

(a) (b) (c)

Figure 122. Seismic data from the Santa Barbara Channel, offshore California, U.S.A.. (a) A CMP stacked data showing multiple crossing reflections; (b) correcting for the mispositioning of dipping reflectors and 揷ollapsing? diffraction curves, migration reveals a series of tightly folded anticlines and synclines (from Larner and Hale, 1992).



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Bright spot seismicity Bright spot seismicity is the recognition of hydrocarbon- (i.e., gas- charged reservoirs). This is due to significant changes in density between water saturated rocks over- and underlying a porous rock (e.g., sandstone) that is relatively depleted in water due to the high saturation of gas (e.g., Sw less than 20%). As seismic waves encounter a velocity interface, reflection and refraction occurs; where significant changes in density occur, reflectors will be prominent. Therefore, the reflector associated with the gas-charged reservoir will appear as a strong reflector on the wiggle trace, due to the enhanced amplitude of each 憌iggle? (Keary and Brooks, 1991). Notice in Figure 123 that in this example the enhancement of amplitude is greatest at the base of the gas-charged reservoir; this is due to the migration of some gas into the overlying shale (or as an alternative interpretation the downward migration of gas). As discussed above, this will generate a bright spot on the seismic trace (Figure 123).

3-D and 4-D Seismic Geologists are comfortable working with cross sections and so are comfortable with 2-D seismic sections. However, for reasons outlined above, 2-D seismic does have some limitations particularly relating to the optimal orientation of the section and during signal processing (e.g., migration). Furthermore, since traps are three dimensional entities a two-dimensional seismic line may not present the optimal subsurface image (Hart, 2000). 3-D seismic surveying overcomes many of those concerns. Marine 3-D seismic surveys utilize a series of closely spaced parallel lines (line shooting) whereas on land receiver lines are arranged parallel to one another with the shot points positioned in a perpendicular direction (swath shooting) (Yilmaz, 1992; Hart, 2000). The distance between lines in 3-D seismic surveying is typically 50 m or less, compared to 2-D seismic surveying which may be 1 km or more. As a consequence hundreds of thousand to hundreds of millions of traces are collected during a 3-D seismic survey, generating gigabytes and terabytes of data. 3-D seismic data is available as vertical sections along the in-line or cross-line orientation (Figure 124a) and as horizontal sections (time slices) (Figure 124b). Multilayer time slices permit the generation of contour maps (e.g., isochron) or the identification of subtle types of trap, such as a meandering stream that otherwise would be problematic with a 2-D survey (Brown, 1988).

Time lapse seismic surveying (Video 12), often referred to as 4-D seismic, is the sequential surveying of a producing reservoir throughout a set period of time. Time lapse seismic surveying seeks to ascertain changes within a reservoir due to the withdrawal of petroleum, in which areas within the reservoir containing untapped oil will show little to no change. Time lapse seismic surveying has been used with great success in many producing fields in the North Sea.

Figure 123. A seismic line for Shell's Mars play, Gulf of Mexico, a "bright spot" play that became a 700-million barrel discovery (from Forest, 2000).

Figure 124. Examples of 3-D seismic showing (a) data volume around a salt diapir depicting vertical sections in both in-line andcross-line orientation, and as time slices (image courtesy of Hunt Oil Company); (b) a time slice showing a meandering stream (used by permission of Sunoco, Inc.).



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Cross sections and subsurface maps

Introduction

Geological maps and cross sections are created to help resolve complexities in subsurface data, to provide a visual synthesis of geological features, and to communicate our geological interpretations to others. They are both versatile and an indispensable tool.

Even with the increased usage of 3-D seismic, the geologist still has need for cross sections. For example, they permit the geologist to extrapolate stratigraphic equivalence between units, using seismic data, wire-line data and or lithostratigraphic information between wells or proposed wells. Cross sections also permit a synthesis of structural attitudes of strata in relation to sea level or some other datum with data derived from seismic, or borehole data.

The petroleum geologist will also construct many different types of maps, including maps of the subsurface, topographic location maps, and land usage maps (Weissenburger, 1992). For a given area and or zone of interest, it maybe necessary to construct a suite of maps. In this section, our examination of maps will be restricted to subsurface maps, in particular maps that contour a subsurface feature (e.g., isopach, isochore, isochron, net pay) or depict relationships, e.g., fault planes, facies change, or changes in porosity (Figures 125 and 126).

Figure 125. Example subsurface map (after Weissenburger, 1992).

Figure 126. Isopach map of the South Glenrock oil field, U.S.A., showing an ancient (i.e., buried) meander belt (from Curry and Curry, 1972).

Video 12. An animation showing the use and possible sequence of events when conducting time-lapse seismic, from 揟 he Making of Oil? (? 1996 Schlumberger, Ltd. used with permission).



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Cross sections

Cross sections are graphical representations of slices through the Earth抯 crust that are commonly used by the petroleum geologist to clarify or help interpret geological relationships (Boak, 1992). There are three basic types of cross sections: correlation, structural, and stratigraphic.

Correlation cross sections Such cross sections may be the first to be drawn and are often based upon seismic data. Such sections also evolve, modified, updated, and refined as data becomes available. Correlation cross sections are often large scale and do not permit the extrapolation of high-resolution stratigraphic equivalence between wells or proposed wells, although it was in dealing with seismic data and the construction of cross sections that prompted Vail et al., (1977) to devise the concept of sequence stratigraphy.

Structural cross sections The structural attitude of strata, or any geological feature of interest, is typically drawn from seismic, or using seismic and borehole data (Figure 127). Such cross sections are drawn in relation to sea level, or some other datum. Structural cross sections are particularly effective when interpreting the location and nature of faults.

Stratigraphic cross sections The detailed correlation of strata between wells is typically performed via the construction of stratigraphic cross sections in which a given stratum is selected as the datum horizon, and all others 慼ung? from that horizon. The data is often derived from wire-line data or from a composite log consisting of wire-line data and drill cuttings, core, or paleontological data.

Such sections may reveal features or used to identify subsurface sequence boundaries (Vailet al., 1977); typically deduced from wireline log responses, supplemented by core and/or drill cuttings. Cross sections are a powerful visual, interpretative tool; even more so if combined with a base map as a fence diagram (Figure 128). A fence diagram or panel diagram accommodates a number of interlinked cross sections within a single three-dimensional diagram. Using a perspective view, each panel or fence is projected below a surface grid (the datum) and linked to one another. They can be an effective means of deriving a solution when data is limited.

Maps

Basic requirements of a map Whatever map is used it must be as accurate as possible. Errors and inaccuracy on a subsurface map may be more misleading, since the map represents a visual summation of data and is mostly responsible for molding our interpretations of a given data set or subsurface feature and the basis upon which exploration decisions hinge (Weissenburger, 1992). There is also trade-off between the inclusion of complex data and simplicity, and because each of us has individual thresholds of comprehension and confusion, the usefulness of a map should be gauged by the ease by which others can comprehend the data, or interpretation. Furthermore, all maps for a given basin, field, or play should conform to one another; not only in scale, but also in style, concept, and possibly interpretation. This is often

Figure 128. A partially completed fence diagram (panel diagram) with a 慴ase-map?projection.

Figure 127. A simplified structural cross-section through Hibernia, east coast Canada (from Arthur et al., 1982).



95

difficult, or impossible, when a basin straddles a political boundary where differences in nomenclature, units, or geological resolution may occur. However, resolving differences or anomalies may yield insight.

Contouring There is an increasing reliance upon computers to construct a subsurface map. However, it should always be remembered that subsurface maps, more than topographic maps, require interpretative skills and that an interpretation is controlled by a variety of factors of which the relative abundance of data and well control is perhaps the most critical. The creation of 慴ulls eye? contouring by computer should always be questioned, since mapping software still lacks the ability to apply geological 慽ntuition.? When dealing with a limited data set, contour in keeping with the structural style of the region; for example, don抰 invoke block faulting if simple folding is thought to dominate the structural style of a region. With a limited data set, remember a number of interpretations are possible, increasing the data set will eventually narrow the options and number of interpretations.

Isopach maps Isopach maps record the thickness of a given formation. Such maps can be local or regional. Note that with such maps, formation thickness does not always coincide with basin subsidence: carbonates or sand bodies are often thickest on the margins of basins, and local or regional truncation may result in formation thickness! An Isochore map is a specific type of isopach, depicting the thickness of an interval between the oil-water contact and the cap rock. Similarly, net pay can be depicted using a ratio of gross pay to net pay within a reservoir.

Structural contour maps This type of map is often the simplest and perhaps the most important subsurface map (Figure 129). This map is a representation of contours for any subsurface horizon with respect to some stated datum, which could be sea level, RKB3 or some other subsurface horizon. Subsurface structural maps can also be local or regional. The information used could be based upon seismic, well control, or preferentially both. Structural maps delineate traps and are essential for reserve calculations. Most structural maps utilize sea level with all deep horizons below sea level, and larger contour values are negative and therefore represent greater depths. The contour intervals should be clear; the map must have a scale and legend, and faults clearly marked.

Reserve Calculations

Estimates

Estimates of recoverable reserves must be made when conducting an appraisal of a reservoir, pool, or field and updated whenever new data or information becomes available. There are several parameters that should be known, calculated, or estimated including, for example, reservoir volume, reservoir porosity, water saturation (Sw), a recovery factor, and an estimation of the formation volume factor (i.e., stock-tank shrinkage). The estimation of reserves may also include other assumptions; such as the presence/absence of a gas cap, the geometry of the oil/water interface, and that the reservoir is regular and divisible into units to facilitate volumetric calculations. Calculated figures should never be regarded as absolute; they are estimations because our knowledge of the reservoir is not perfect and is always subject to change or revision. However, even as estimations, those calculations should be as accurate as possible since they form the basis for a number of business decisions regarding the possible outcome of a reservoir, pool, or field.

Rough estimate: Roil = Vb f (9)

where: Roil = the amount of recoverable oil (in bbl or m3)Vb = bulk volume of the reservoir rock

3

RKB: the rotary kelly bushing, depth measurements are commonly referenced to the kelly bushing.

Figure 129. Structural contour map (from Jorgensen, 1992).



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f = recoverable oil

This method has some assumptions, the method uses 憈ypical recovery values? and porosity estimates (e.g., 30% for sandstone, 10 to 20% for carbonates).

Reservoir volume There are various other formulae by which it is possible to estimate recoverable reserves using actual data. Most however, utilize a formula that calculates a tabular volume, such as the area of a pyramid or a hemisphere (Dahlberg, 1979).

An isopach map is often the starting point for most reservoir volumetric calculations (Figure 130). The basal area for each contour interval is then derived using a planimeter, or by dividing the area into a square grid or by using some other means of measuring area.

The cumulative area occupied by the reservoir is derived using the contour interval (h) plus values for the base of each area, using the following formula (Dahlberg, 1979):

V = ? (A0+A1) + ? A1+A2)...+ residual above the last plane (10)

Or

where: V = rock unit volume h = the contour interval of the isopach map (i.e., height) A0 = the basal area above the oil/water contact A1 = the basal area of the first contour A2 = the basal area of the second contour An etc = the basal area of the nth contour

Recoverable oil Only a small volume of the area calculated is actual pore volume; therefore, V must be reduced to accurately represent the pore volume of the reservoir. This is achieved by multiplying the calculated volume by a porosity value in decimal form (e.g., 0.17). Porosity is typically derived from core analysis or estimated from petrophysical logs. Furthermore, the volume of the reservoir that holds oil or gas must be further reduced because of varying amounts of water and oil. The amount of water present within a reservoir is expressed as the water saturation (Sw) and, therefore, must be factored into such calculations, e.g., V = [1.0 - Sw]. Furthermore, the amount of hydrocarbon that can be produced from a reservoir may be less than 100% due to the volumetric shrinkage of oil, because dissolved gas will come out of solution, leading to an effective volumetric shrinkage in oil. The shrinkage factor is calculated from the temperature, pressure, and GOR (gas-to-oil ratio) of the oil and can be as much as 10 to 30 percent. Therefore, the formation volume factor (FVF) will range from 1.1 for gas-free oil to 2.0 for a high gas-oil. Hence, the equation for estimating recoverable oil is (Dahlberg, 1979):

Recoverable oil = V (1 - Sw) R (12)

FVF

where: V = reservoir volume (in cubic meters, barrels, or cubic feet)

= average porosity (as a decimal) Sw = average water saturation R = estimated recovery factor, as a decimal equivalent FVF = formation volume factor

Figure 130. A simplified isopach map and cross section illustrating the basis for estimating volume.

(11)



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If it is required to express the results as barrels of oil, the reserves should be converted from cubic meters by dividing V by 0.159, or dividing V by 5.615 when working in cubic feet.

Utilizing the pore volume equation

(STB) = V N/G Shc R 6.29 (13)

FVF

where: V = reservoir volume N/G = net or gross ratio of the reservoir rock body making up V

6.29 = oil field conversion factor (m3 to bbl)

= average porosity Shc = average hydrocarbon sat. R = estimated recovery factor FVF = formation volume factor

STB = Stock tank barrels, bbl of oil at 60 F and 14.7 psi.

Shortcuts Spherical or ellipsoidal reservoir Many shortcuts and 憅uick-look? methods exist, depending upon the approximate geometry of the trap; we will examine one method that assumes a hemispherical (dome) shape. The volume of the top of a sphere can be approximated by the following quick method.

area of the base ? max. thickness (i.e., height of reservoir) (14)

For a hemispherical or near hemispherical reservoir this approximation will be within 6%. The error will increase, as the shape becomes more ellipsoidal, such as a fault-bounded trap. The volume can be approximated by determining the area corresponding to the mid-distance between the reservoir base and top.

Reference

Arthur, K. R., D. R. Cole, G. G. L. Henderson, and D.W. Kushnir, 1982, Geology of the Hibernia discovery in The deliberate search for the subtle trap (M. T. Halbouty, ed.): AAPG Memoir 32, Geologists, Tulsa, p. 181-195.

Brown, A. R., 1988, Interpretation of three-dimensional seismic data, Second edition: AAPG Memoir 42, 253 p.

Boak, J. M., 1992, Geological cross sections in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 300-302.

Dahlberg, E. C., 1979, Geological Note: Hydrocarbon reserves estimation from contour maps: A do-it-yourself exercise: Bull Can Petrol Geol, v. 27, no 1, March, p. 94-99.

Curry, W. H., and A. H. Curry III, 1972, South Glenrock oil field, Wyoming: prediscovery thinking and postdiscovery description in Stratigraphic oil and gas fields-classification, exploration methods and case histories (R. E. King, ed.): AAPG Memoir 16, p. 415-427.

Department of Trade and Industry, 2005, Department of Trade and Industry well numbering system, Petroleum Operational Notice 12: Department of Trade and Industry, HM Government, UK, http://www.og.dti.gov.uk/regulation/pons/pon_12.htm.

Dessler, J. F., 1992, Marine seismic data acquisition in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 361-363.

Duncan, P. M., 1992, Basic seismic processing in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 364-371.

Forest, M., 2000, Bright investment pays off: AAPG Explorer, July, p. 13-14.

Hart, B., 2000, 3-D Seismic interpretations: a primer for geologists: SEPM Short Course No. 48, 123 p.

Jorgensen, L. N., 1992, Dan Field-Denmark in Structural Traps VI, Treatise of petroleum geology, atlas of oil and gas fields, (N. H. Foster and E. A. Beaumont, eds.): AAPG Treatise of Petroleum Geology, p. 199-218.



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Keary, P., and M. Brooks, 1991, An introduction to geophysical exploration, 2nd Edition: Blackwell Science Ltd, Oxford, 254 p.

Larner, K., and D. Hale, 1992, Seismic migration in Development geology reference manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 372-376.

Link, W. K., 1952, Significance of oil and gas seeps in world oil exploration: AAPG Bulletin, v. 36, p. 1505-1540.

Mineral Management Services, 1984, Oil and gas leasing procedures guidelines, Gulf of Mexico Region: MMS, Department of the Interior, U.S. Government, 188 p.

Schlumberger, 1996, The Making of Oil: Schlumberger Wireline and Testing, Sugarland, Texas.

Short, D. M., 1992, Seismic data acquisition on land in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 358-360.

Tinkler, J. C., 1992, Part 1. Land and Leasing in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 1-20.

Vail, P. R., R. M. Mitchum Jr, R. G. Todd, J. M. Widmier, S. Thompson, J. B. Sangree, J. N. Bubb, and W. G. Hatlelid, 1977, Seismic stratigraphy and global changes of sea level in Seismic Stratigraphy-Applications to Hydrocarbon Exploration, (C. E. Payton, ed.): Memoir 26, p. 49-205.

Weissenburger, K. W., 1992, Subsurface maps in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 294-299.

Yilmaz, 謟 . 1992, Three-dimensional seismic method in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 385-387.


Chapter 7桪 rilling the Well

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Pre-rotary drilling From pits to cable Oil seeps, shallow pits, mine shafts, strip mines spring poles, and cable tool drilling rigs have all been used at some point in time, when exploring for oil in the historical past (Figure 131a, b). Each new technology was supplanted by the next, although by the late 19th century the cable-tool drilling rig represented the state of the art. Developed in Europe for the drilling of water wells, it was readily adapted for petroleum exploration by North America drillers (Brantly, 1971). Both the spring pole and the cable-tool drilling rig were essentially percussive techniques, with the motive power provided by either muscle (human or animal) or an engine (e.g., steam). The rate of progress was slow, measurable in meters per day, not meters per minute! Limited by their technology, drillers could not drill very deep wells. Because cable-tool drilling was also an 憃pen hole? technique the ability to combat a 慿ick? was very limited, hence, the common occurrence of 慻ushers.? Drillers needed a better drilling technology (Figure 131b).

Rotary drilling

Introduction

Rotary drilling (Figure 132) superseded cable-tool drilling because it was possible to drill wells with greater rates of penetration, and with an enhanced degree of safety. Some aspects of rotary drilling have not changed since the early 1900s. However, many notable developments occurred during the middle of the twentieth century that enabled deeper wells to be drilled in areas unthinkable in 1900, such as the development of the tri-cone bit, non-rotating polycrystalline diamond bits, electric drawworks, the development of down-hole motors, the development of hydraulic blow-out-preventers, the development of polymer drilling fluids, the development of the riser, and the initial invention and subsequent refinement of petrophysical-logging tools.

More recently, the industry has seen the development of flexible drillpipe, top-drive motive units, the widespread application of horizontal drilling, the widespread use of mud telemetry and measurement whilst drilling (MWD) tools, and the ubiquitous use of computers and the remote monitoring of operations.

Figure 132. Conventional on-shore rig schematic (reprinted courtesy of California Department of Conservation).

Figure 131. A Fifteenth century Chinese drilling tool (a), and Patent drawings for an early 揜 oss? drilling rig and equipment of 1891 (b) (from Brantly, 1971; reprinted with permission of Gulf Publishing Co.).



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Figure 133. Nabors #9 on location in western Canada.

Drilling terminology and equipment

Land rigs There are numerous types of landrigs, ranging in size from the large 慶onventional?triple, through light-weight helli-rigs, to the small portable coiled-tubing rig. Variations in size reflect differences in function and the load-bearing limit of the drawworks, derrick, and traveling block (Figure 132). Large land rigs must be broken down into transportable units. Where roads or bridges pose weight limits, the helli-rig can be flown into a remote location piece-by-piece and assembled at the drillsite. Full-size conventional rigs are typically large triples (Figure 133), equipped with substantial masts that are capable of handling the heavy drill-strings required when drilling a deep (vertical) well, unlike the lightweight mobile rigs designed for horizontal wells (small doubles, mobile rig), which typically cannot handle heavy strings of drill pipe.

Offshore rigs Barges: These are essentially 憀and rigs? built upon a shallow hull designed for water depths of 3 to 7 m. The rig is towed to the drillsite and the hull is flooded so that the broad bottom of the barge sits on the seabed or lakebed.

Islands: Seasonal ice and a very short drilling season typify the Arctic. The solution is to build an island upon which a winterized land rig can be placed. The island permits year-round drilling on the continental shelf, instead of being limited to ice-free months during the summer. The island prevents ice from crushing the rig, which is a hazard for floating rigs.

Jack-ups: This type of offshore rig is designed to work in shallow water within the confines of the continental shelf and in water depths of approximately 50 to 80 m. This type of rig has a hull and three or more legs that provide support for the rig. The jack-up rig is towed or carried to the drill site by boat with the legs fully raised. Once at the drilling location, the support legs are lowered and the rig platform 慾acked-up? so the legs are in contact with the seabed and the platform is clear of maximum peak wave height (Figure 134). The derrick is typically 憇kidded? over the rear during drilling. Because the jack-up rig is fixed to the seabed, the hull of the rig and drill floor do not experience vertical motion due to tides or wave action. Therefore, the 憆iser? is fixed and a motion-compensation system is not required on this type of rig. Some jack-up rigs are often equipped with blowout preventers under the drill floor.

Semi-submersibles: This is a floating type of drilling rig, designed for medium and deep water (Figures 135 and 136). The semi-submersible rig, known as a 憇emi-sub,?has either large pads or pontoons at the base of each leg which provide buoyancy while traveling to the drill site, but are subsequently partially flooded during drilling to give the rig the required drilling draft. The pontoons are ideally below wavebase to reduce the motion of the rig, but they also add a degree of stability when handling large amounts of drill pipe during drilling by lowering the semi-sub抯 center of gravity. At the drill site, semi-subs are either anchored in place or use dynamic positioning, comprised of thrusters fore and aft that help maintain the rig抯 position over the wellhead. Because semi-subs are floating rigs, they are subject to the influence of tides and wave motion. They are therefore equipped with a 憁otion compensating system? which is attached to the 憆iser? and the drillstring traveling system. The riser (Figure 137a, b) is a large diameter telescopic tube that connects the drill

Figure 134. A jack-up rig.

Figure 135. A modern dynamically positioned twin-hulled semi-submersible rig.



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Figure 136. A semi-submersible rig in Galveston.

floor to the borehole via the blowout preventers.

The riser is an extension of the borehole through the water column that enables the return of drilling fluid within the annulus from the borehole to the rig. The lower part of the riser (Figure 137a [#2] and Figure 137b [#4]) is attached to the blowout preventers on the seabed, which in turn is attached to the casing that lines and protects the borehole. The upper sleeve (Figure 137b [#5]) is attached to the floating rig. As the rig moves vertically in response to tidal and wave motion, the upper sleeve moves up and down inside the lower sleeve through the slip joint. Note that steel cables (Figure 136b) support both the upper and lower sleeves. The cables are a key element of the motion compensation system and are constantly tensioned (Figure 137c [#8]) by lengthening and shortening the wire suspension system in synchrony with the vertical rise and fall of the rig. The motion compensator system is also linked to the traveling block (Figure 137c [#9]) ensuring that the drillstring is also in synchrony with the vertical rise and fall of the rig.

The opening and closing of any ram within the blowout preventer system is controlled from the rig via hydraulic lines (Figure 136b [#7]). Think of the riser as a mechanical extension of the borehole, with the drillstring in the center of the riser/borehole and drill cuttings etc., returning up the annulus. Without the motion compensation system, it would be impossible to drill in deep water. The development of the motion compensating system ensures that the bit maintains constant torque and does not bounce up and down in the borehole as the rig moves up and down in response to tidal or wave motion. Both the riser and the blowout preventer system permit the safe exploration of very deep water plays, with depths of 3,200 m (10,011 ft) and storm wave height of 30 m within range of the largest and newest rigs.

Drill ships: Designed for medium and deep water, these mobile, self contained, and self-powered rigs are unmistakably 慺loaters? (Figures 138, 139). Unlike the semi-sub, these rigs do not need anchors to maintain their position over the well head; using computer controlled dynamic positioning and thruster system these rigs can position themselves over the wellhead in the deepest of water. The derrick is located centrally, over a 憁oon pool? a purpose built opening through which the riser is run. Like the semi-submersible, drillships also utilize motion compensation apparatus, however, unlike 'semi-subs', drill ships often have the ability to store supplies, drill pipe, casing, etc., in the hull of the ship to lower the center of gravity and increase stability.

Figure 137. Images showing various aspects of the motion compensating system on a semi-submersible drilling rig. (a) A scale model of a semi-sub showing (1) sea level (drilling draft), (2) the riser, and (3) the location of the blowout preventers as a subsea stack; (b) a view of the riser showing (4) the lower sleeve of the riser that is physically attached to the blowout preventers (BOP), (5) the slip joint that permits vertical movement by the drilling rig due to tides and waves, (6) wire suspension system, (7) BOP hydraulic control line; (c) (8) pneumatic tensioners, (9) the traveling block system.



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Platforms: These are fixed structures that are typically anchored to the sea floor via a steel or concrete support structure (Figure 140). The super-structure contains the drilling rig, living quarters, and production equipment and is purpose built to serve a given oil field for several decades. The production platform signifies an important part in the life cycle of an offshore oil field, because it moves the oilfield from the exploration and appraisal stage to the production phase. Offshore production is very rarely conducted through an exploration well.

The optimal recovery of petroleum from a reservoir or several reservoirs off shore requires the drilling of numerous wells, some of which are used to produce oil/gas, whereas others are used to enhance the recovery as injector wells, via water or miscible fluid flood. Because a platform services a number of wells (Figure 141), the derrick can be repositioned over a given wellhead on skid beams. Some of the largest offshore structures ever built are platforms. Structures built on steel legs are called 憄latforms,? if the structure utilizes a concrete support it is known as a 慶aisson.?

Figure 141. Subsurface perspective view of the production wells drilled in the Piper field, North Sea, from a single production platform (from Maher et. al.,1992).

Figure 140. The Piper field production platform (from Maher et. al., 1992).

Figure 139. The derrick of the Discoverer II.

Figure 138. A dynamically positioned drill ship.



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Drilling techniques, problems and solutions

Conventional drilling

The drill string The rotating system consists of the drill string, swivel, kelly, kelly-saversub, and the rotary table. The drill string is comprised of drill pipe, drill collars, subs/joints, stabilizers, and drill bit. Rotary power is transferred from the rotary table, through the rotary bushing (Figure 142) to the kelly, which in turn is connected to the drill string. The drill string is divisible into 慸rill pipe? and the 慴ottom hole assembly? (BHA). In a conventional system the drill string transfers torque and rotary power to the bit, provides a conduit for the circulation of drilling fluid, and provides both support and compressive weight to the drill bit via the BHA.

Drill pipe Drill pipe is not complicated. Drill pipe is made in 31 ft (9.4 m) lengths, known as a 憇ingle? with a nominal tube outside diameter (OD) of either 4.5 or 5.0 inch (114 or 127 mm) and tool joint tube OD diameter of either 6.25 or 6.5 inch (159 or 165 mm), respectively (Smith International, 1992). The nominal inside diameter (ID) dimensions for the two types of pipe are 2.75 and 3 inch (70 or 76 mm) respectively. Typical weight for a single length of drill pipe is 16.6 lbs ft (24.6 kg m). The drill pipe runs from the kelly saver sub, extending down into the borehole, to the top of the BHA. As the depth of the borehole increases more drill pipe is added.

The BHA The composition of the BHA (Figure 143) has great bearing on the drilling behavior and characteristics of a given drill string. Unlike drill pipe, the BHA can be complex. After the bit, perhaps the two most important components of the BHA are the drill collars and stabilizers. Drill collars are thick-walled, heavy lengths of pipe finished with either a smooth surface or helical ribs (Figure 144). The maximum permissible outside diameter of drill collar is determined by the cutting diameter of the drill bit. For example, an 11 inch (279.4 mm) OD drill collar could be used in conjunction with a 12? inch (311 mm) or larger bit, whereas smaller diameter drill collars would be used with a smaller bit. Engineers want to run the largest diameter drill collar possible because drill collar stiffness increases by the fourth power of the diameter (e.g., 9 inch drill collars are four times stiffer than 7 inch, but only two times stiffer than 8 inch drill collars). Another reason for selecting maximum diameter drill collar is weight. A 31 ft. (9.4 m) length of 11 inch (279.4 mm) drill collar weighs approximately 9,498 lbs (4286 kg); that抯 about 306 lb per ft (Smith International, 1992). The BHA provides weight onto the bit and maintains tension within the drill (i.e., to avoid buckling). To control pipe flexure and buckling, the BHA typically contains stabilizers. Stabilizers are used to control drill angle, prevent

dog-legs, key seats, and reduce the potential for 慸ifferential sticking?(discussed below). There are three types of stabilizer; rotating blade,non-rotating sleeve and the roller cutter reamer. Stabilizers are designed to make contact with the wall of the hole. The type and number of stabilizer used will impact upon the geologists? work by adding caved material to the drill cuttings. Rotating blade stabilizers (Figure 145) have a 憇piral appearance,? they turn with the drill string and will, therefore, dislodge geologic material from the wall of the borehole. Non-rotating stabilizers (Figure 143a) behave like a 憆udder? as the drill string rotates within the sleeve of the stabilizer. Stabilizers act as 憄ressure points? and as a means of keeping the drill string in the center of the borehole. Figure 143 perhaps shows two extremes. The upper BHA (Figure 143a) is a packed BHA, because there is a high proportion of stabilizer [i.e., 1 and 3] relative to drill collars [2] or other components, such as jars, subs, or shock-subs [4]. What the packed BHA achieves is a straighter borehole trajectory because pressure (i.e. weight-on-bit: WOB) is distributed evenly across the cutting-surface of the bit. This is not the case when stabilizers are omitted from the BHA (Figure 143b), where increased WOB causes the pipe to buckle producing an unequal distribution of pressure across the cutting-surface of the bit. This latter configuration can initiate a deviated borehole.

Figure 142. Rotary table and kelly bushing (image ? Schlumberger, Ltd. used with permission).

Figure 143. BHA (Smith International, 1992; used with permission).

Figure 144. The rig floor of the Discover II during a trip.



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Making a 慶onnection?and 憈rips?The entire drill string is supported by the traveling block and swivel (Figure 132). Rotary power is traditionally transferred from the kelly bushing to the drill string via the kelly, which has a hexagonal cross-sectional shape. The kelly can move freely up and down through the kelly bushing. As the depth increases the kelly passes through the kelly bushing. Once the kelly reaches it's lowest point, the kelly is raised through the kelly bushing, unscrewed from the drill string and a new length of drill pipe added. The kelly is then reattached, drilling re-continues until the kelly has been worked through the rotary bushing, the kelly is then once again unscrewed, new pipe added and so on. The business of adding new lengths of drill pipe is called 憁aking a connection? and is often a manual operation (Figure 146). Changing the drill bit requires the complete removal of the drill string in 27 m (90 ft) lengths, known as 憇tands.? Changing the bit is known as tripping the bit or simply tripping (Figures 144, 145, 146). Short trips or wiper trips are periodically run to ensure the drill string does not get stuck. In this case the bit and BHA are not retrieved and broken down into 27 m lengths, but worked like a (slow) piston to condition the borehole.

Drill bits

The role of the drill bit The drill bit does the work of cutting, chipping, grinding, or gouging the formation and deepens the borehole. The actual cutting characteristics of a given bit are matched to the lithological characteristics (e.g., hardness, abrasiveness) of the formation to be drilled and specific drilling objectives. Tri-cone roller-bits (Figure 147) fitted with carbide insert teeth or milled-steel teeth are the most common varieties currently in use in land-based drilling operations. However, 憉nconventional? bits that have non-moving parts (e.g., PDC, see below) are becoming increasingly common on deep or technical wells, especially off shore. One reason is cost. The other is the relative cost of a given drill bit compared to the daily cost of drilling a well. When daily costs are high, the PDC drill bits with very high cutting efficiencies and longer wear rates are desirable irrespective of their cost.

Roller bits Modern roller bits are typically comprised of three rotating cones (Figure 147). The length of the teeth, the degree of ?cone offset,? type of bearings, and tooth construction (e.g., milled steel or tungsten carbide insert) govern the allowable weight and rotational speed limits of a drill bit. Specific types of drill bit are constructed to match specific types of formation, such as ultra soft (e.g., unconsolidated sands), medium (e.g., shale), to very hard (e.g. abrasive and well cemented sandstones). Soft formations are optimally drilled by 慻ouging? the formation with long teeth, rather than chipping or fracturing as in the case of the short 慴utton bit,? which is designed for highly indurated and abrasive formations. 慓ouging? is achieved by increasing the degree of cone 憃ffset.? The yellow lines in Figure 147b show that the apices of the three cones do not come to a single point in the center of the bit face, each apex is 憃ffset? from the true center. The greater the 憃ffset,? the more the teeth twist and gouge the formation. Hard formation drill bits have no offset, whereas tri-cone bits, optimized for ultra-soft formations, have the greatest offset! Geologists who regularly have to examine and describe drill cuttings (e.g., wellsite geologist) would be well advised to acquaint themselves with the characteristics of the specific drill bit used and BHA configuration because of the impact these tools have on drill cutting characteristics and the possible presence of caved material. Long tooth bits gouge, medium tooth bits cut, whereas short insert teeth chip and fracture the formation during drilling. In this way the shape and size of drill cuttings is largely determined by the type of bit used. Cavings are often derived from stabilizers or centralizers as drill collars or drill pipe contact the wall of the borehole.

Figure 145. The rig floor of the Discover II during a trip.Note the stabilizer.

Figure 146. Adding pipe.

Figure 147. The side view of atri-cone roller bit (a); and thebit face (b), illustrating cone憃ffset? click on each image toactivate the QuickTime VR(courtesy of OneEarth Virtuals).



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Figure 148. PDC bit (Image ? Halliburton Company, used with permission).

Fixed cutter bits Fixed cutter bits (Figure 148) have no moving parts. The cutting surfaces, which are typically made out of polycrystalline diamond (PDC), are aligned as blades. Fixed cutter bits are designed to handle high RPMs (e.g., 160 rpm) and are specifically designed to work with down-hole motors or top-drive units. A downhole motor is typically a hydraulic motive unit that is part of the BHA behind the bit. Bit rotation is provided by the downhole motor and not via the rotary table-kelly-drillstring system. Topdrive units permit the use of longer lengths of drillstring, however, the drillstring does rotate.

Drilling fluid

FunctionDrilling fluid, commonly referred to as 憁ud,? has several functions (Videos 13 to 15). It cools the bit, keeps the cutting face of the drill bit clear of cuttings, exerts hydraulic impact on the formation, provides a telemetry medium, prevents the ingress of formation fluids during drilling or tripping, lines the borehole with a 憁udcake,? (Video 15) and last but not least, it transports cuttings and formation gas to the surface for analysis. There are a variety of drilling fluids, including water-based, oil-based, and non-fluid drilling fluids; the selection of which depends upon cost and the need to avoid engineering and/or geological problems.

Water-based systems This includes salt water-based and fresh water-calcium-based systems that typically incorporate bentonite or barite as the basic solid material. Fresh water weighs 1.000028 kg per liter or 8.3 lb per gallon, seawater has a weight of 1.02198 kg per liter or approximately 8.8 lb per gallon. Formation pressure increases with increasing depth; therefore, to counter the ingress of formation fluid the density (i.e., weight) of the drilling fluid must increase as depth increases. This is typically achieved by adding solids; either in the form of bentonite, barite, or potassium-chloride (KCl) polymers. KCl fluid systems should not really be called 憁ud? since they do not incorporate bentonite. The choice of freshwater or seawater is often decided by geography, the character of formation water, and the general type of formation to be drilled.

Oil-based fluid systems Originally designed to prevent the dissolution of salts or anhydrite formations or the swelling of hydrophillic‡ shales (e.g., smectite) if present. From the geologist抯 perspective oil-based fluid systems can be difficult to work with, but for the engineer, they prevent the differential sticking of the drillstring, reduce the tendency of hydroscopic shales to slough, possess a high degree of thermal stability, and resist chemical contamination. But oil-based fluid systems require high maintenance, are expensive, have a high environmental cost, and mask or prevent certain formation evaluation techniques from being utilized.

Non-fluid systems Some wells have been drilled using the circulation of compressed air or nitrogen foam to cool the bit and lift cuttings to the surface. This type of system is possible only on very shallow wells because non-fluid systems cannot counter the ingress of formation fluids.

Cleaning drilling fluid Fluid based systems are cleaned of drill cuttings using a de-sander, de-silter, and 憇hale shakers.? Shale shakers are large vibrating screens that remove drill cuttings from the drilling fluid. The 'mud' passes through the screens, the cuttings fall off the front edge of the screen and are collected for examination by the geologist.

‡ Hydrophyllic: a material (e.g., clay) whose surface has an attraction for water. Oleophillic: attraction for oil.

Video 14. Drilling fluid properties, from揟 he Making of Oil? (? 1997Schlumberger, Ltd. used withpermission).

Video 13. Drilling fluid, from 揟 he Making of Oil? (? 1997 Schlumberger, Ltd. used with permission).

Video 15. Mudcake in the borehole, from 揟 he Making of Oil? (? 1997 Schlumberger, Ltd. used with permission).



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Wellsite appraisal

The Wellsite Geologist (Figure 149) is responsible for acquiring a complete and accurate evaluation of geological data, including the description of lithologies and the initial evaluation of 憄ay? (i.e., oil or gas). The wellsite geologist should also keep other drilling personnel appraised with the necessary information to ensure a safe and efficient drilling operation. Depending upon the scale of the drilling program, the wellsite geologist may have additional responsibilities; for example, the monitoring and supervision of mud logging operations, monitoring and supervision of coring operation, the identification of core-point, core description, or the monitoring and supervision of the petrophysical logging operation.

Petrophysical logging

Petrophysical logs are an important data source. They are used to evaluate the economic potential of a well, interpret lithologies, elucidate bedding and geological structure, correlate between wells and even help directional drillers track target lithologies. There is a successive chapter that deals with petrophysical logging in great detail. However, there are aspects to introduce at this point.

The type of logging tools to be run (as a suite of tools) and the depths to be run is an integral part of the drilling prognosis. If a well is an exploration or an appraisal well the log suite to be run will typically be comprehensive and the logging budget may constitute approximately 5% (or more) of the total exploration budget. If the well is developmental, the number of logs to be run maybe reduced. Typically log suites are run prior to setting casing in the open hole section and can take typically one or two days to complete. The datum for all recorded data is the kelly bushing elevation. The elevation of the kelly bushing above sea floor is recorded on each log header. Corrections for true vertical depth and formation thickness are also given. Once drilling has ceased, the well is 慶onditioned? by circulating drilling fluid for a number of hours, followed by removing the drill string from the well (trip). The logging sondes (Figure 150 慡? are lowered into the well suspended by an insulated cable attached to a winch unit (Figure 151). Once the logging depth is reached the sonde is turned on and spooled upward at 600 m per hour. Depending upon the type of tool run, the signal may be transmitted via the cable or collected by a surface detector and recorded in the logging unit at the surface (Figures 150 to 152). There are some essential parameters that must be determined for a successful logging run. The first one is an accurate determination of mud filtrate and mud filter cake resistivity. The time since mud circulation ceased must also be recorded. If the drilling prognosis calls for an extensive suite of logs to be run, the on-site engineer may wish to run the drill string back into the borehole, to recondition the borehole. The mud filtrate and mud cake resistivity should be checked for subtle changes that may affect final results. There is a wide array of logging sondes available, which are discussed in detail in a later chapter devoted to petrophysical logging.

Figure 149. The wellsite geologist.

Figure 150. Exterior rear view of a logging truck, with sonic sonde (S) (courtesy of OneEarth Virtuals).

Figure 151. The rear of a logging truck, showing the winch unit (courtesy of OneEarth Virtuals).

Figure 152. Logging truck interior, 慦 ? winch control, 慍? computer workstation, 慠?data and record unit (courtesy of OneEarth Virtuals).



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Deviations, dog-legs, and key seats

Deviated borehole Wells are drilled to reach specific targets (i.e., a prospective reservoir), but must be drilled within the specified lease and according to an approved drilling prognosis. Therefore, the trajectory of the borehole must be controlled. Subsurface geology is rarely homogenous or arranged like flat-lying layers. Dipping strata, alternations of 憇oft? and indurated lithologies, and inclined fault planes can cause a borehole to deviate from a prognosed trajectory. There are also many instances when it is necessary to drill a controlled deviated borehole. 慏esigner? wells are highly deviated wells that have a high degree of curvature and/or horizontal component to them. A 憇traight? wellbore is one that is often regarded as having a total deviation of no more than 5o from vertical. However, as can be shown in Figure 153 problems can still arise due to the rate of change in borehole angle. Changes in borehole angle of 1? or more per 100 m will generate a 慸og-leg;? which is undesirable because it can lead to drilling problems, such as the creation of key seats and possibly stuck pipe.

Dog-leg and key seat A dog-leg is a sudden change in borehole angle, often caused by a change in lithology or structure, or due to changes in BHA configuration. If the drillstring is rotated by the rotary table, then the rotating pipe can initiate a notch where the drill pipe makes contact with the borehole, i.e., in the shoulder of the dog-leg (Figure 154). This notch is often the size of the drill pipe and is called a key seat. Wider diameter drill collars cannot be pulled through a key seat which can lead to stuck pipe and eventually pipe fatigue through jarring. Key seats are undesirable.

Whipstocks and controlling angle Borehole angle can be controlled or corrected, with some modicum of control, by careful configuration of the BHA. The strategic location of stabilizers combined with a judicious choice of WOB (weight-on-bit) and the effects of gravity, will allow the BHA to either build angle (via a fulcrum effect) or decrease angle (via a pendulum effect). When the stabilizer is located behind the bit and the WOB increased, the stabilizer acts as a fulcrum driving the bit into the side of the borehole. Conversely, if a stabilizer is positioned at some distance from the bit and the WOB is decreased, then gravity pulls the bit towards the vertical. Greater control of borehole angle can be achieved by using a steering tool or a whipstock. Devised in the 1930s, this effective device (Figure 155; Video 16) remains one of the simplest ways of initiating a deviated borehole or creating a 慿icking-off point? for either 憇idetracks,? re-entry wells, or initiating a horizontal borehole with a high degree of precision. The whipstock is run into the borehole to the desired depth and set in place. Once rotation of the milling assembly is begun the WOB is backed-off until the carbide blades of the mill contact the casing or borehole wall. A 憌indow? is then milled through the casing that initiates the 慿ick-off point? (Video 16), followed by cleaning and reaming to ensure that subsequent BHA will not get stuck on the window. Well deviations drilled in the Prudhoe Bay of Alaska, using whipstocks, between 1991 and 1993 ranged from 2? to 67? with an average of 35.2?

Figure 154. The formation of a key seat (? Schlumberger, Ltd. used with permission).

Figure 153. Although this borehole is within the 5o target window, it has a total deviation of 6o and a dog-leg.

Figure 155. Some of the steps involved in 慶utting a window? and kicking-off a sidetrack well (image ? Schlumberger, Ltd. used with permission).

Video 16. The whipstock and 慶utting a window? from 揟 he Making of Oil?(? 1997 Schlumberger, Ltd. used with permission).



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Casing

Overview Casing is large-diameter threaded pipe that is run into open hole and cemented into position to provide support and protection to the borehole. Casing isolates and protects sensitive, economic, or potentially dangerous zones, such as fresh-water bearing formations, pay (i.e., reservoir), or formations with different pressure gradients. The lower most component of the casing string is the casing shoe, which is typically set within a formation of relatively low porosity and/or high tensile strength (i.e., high fracture pressure). Casing is always run from the BOP to the casing shoe depth. Successive, smaller diameter strings of casing are run inside previous (wider) casing strings, ensuring that the formations most susceptible to damage (i.e., upper part of the well) are protected (Figure 156).

Why run casing? At the most simple level, casing provides added protection against the sudden and uncontrolled ingress of formation fluids into the wellbore. Casing protects the borehole from damage (慽nvasion? , caving, and uncontrolled fracturing. Formation pressure increases with increasing depth. However, that increase is never linear because of the existence of pressure gradients; that is the marked increase in pressure across discontinuities such as seals, unconformities, faults, and lithology breaks. Typically, an increase in formation pressure gradient (Figure 157) can be matched by the hydrostatic pressure of the drilling fluid within the wellbore. The hydraulic head of pressure thus created is the most effective blowout preventer during drilling. As you will recall, if the formation pressure, at any depth, becomes greater than the hydostatic pressure of the drilling fluid, formation fluid will flow into the wellbore (a kick). Figure 157 illustrates the need for casing. Increasing the mud weight density to combat problems at depth can cause additional problems higher up the borehole, such as fracturing the formation and lost circulation. Both are additional hazards and should be avoided if possible. Therefore, casing provides an effective permanent means of dealing with increases in formation pressure. Typically the engineer needs to know an estimate of formation tensile strength (i.e., formation fracture pressure), depths of expected unconformities or faults, the presence of unusual formations (e.g., overpressured or underpressured formations), and the depth of a suitable formation for the casing shoe.

Conversion for mass

Figure 157. A hypothetical pressure gradient for an offshore Gulf Coast well illustrating the need for casing. The diagram shows a generalized pressure gradient (red line) and mud weight density (blue line), the formation tensile strength is also given as a generalized line. Note that the upper 2,000 m is drilled with no change in mud weight density. However, where the formation pressure gradient exceeds the mud weight density a kick may occur. If the mud weight density is increased to more than 1.25 gm cc (10.6 lb gal) and the borehole was not previously cased, the tensile strength of the rock will be exceeded and fractures will form in weaker formations at relatively shallow depth, with the possible loss of drilling fluid to the formation. Note also the significant and sudden increase in formation pressure below depth 慩 .? If casing is not set close to and above this point, the high mud weight density required below this depth to prevent a kick, would most certainly cause problems higher in the borehole. Problems such as the loss of drilling fluid to a formation of lower tensile strength and/or the fracturing of a weaker formation.

Figure 156. Generalized casing arrangement for a producing well (image ? Schlumberger, Ltd. used with permission).



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Directional drilling

An overview

Directional drilling and many re-entry wells have become an essential component in many exploration strategies in areas that require a cost-effective means of enhancing production, the drilling of multiple targets from a single rig/platform, drilling around obstacles, or the revitalization of marginally to sub-economic fields (Videos 17 to 18).

Horizontal and 慹xtended reach? wells perhaps represent the ultimate examples of deviated well drilling. Throughout the last ten years, the lateral reach (known as horizontal displacement) of such wells has increased substantially.

An 慹xtended reach? well drilled from the Wytch Farm development (England) attained a horizontal displacement of 10,114 m (33,182 ft), horizontal displacements of 8,060 m (26,446 ft) and 7,852 m (25,764 ft) have been achieved in the South China Sea and North Sea respectively (Allen et al., 1997). Other example extended reach wells, drilled from land, include those off the south coast of Argentina, the north coast of Germany, and the east coast of Sakhalin Island, Russia.

Horizontal wells are typically drilled using a significantly different drilling procedure from that of the vertical (conventional) wells and require specialized equipment, such as a flexible drill string, a steering tool, and some form of 憆eal-time? downhole monitoring device (e.g., measurements-whilst-drilling device or MWD).

The majority of horizontal wells are 慿icked-off? from a 憊ertical? well, often using a whipstock (discussed above) or from an existing leg of a deviated well as a 憆e-entry? well (Video 18). Once the initial window is cut through the casing the drill string is typically completely reconfigured with a downhole motor, bent-sub, a MWD tool, flexible joint(s), flexible pipe (or coiled tubing) an orientation tool steering tool or directional tool (Figures 158, 159). Because

Figure 158. Generalized BHA used in drilling deviated wells; (a) short radius, (b) medium radius, and (c) long radius (image ? Halliburton Company, used with permission).

Figure 159. Orientation (steering) tools and down hole motor. (a) Down hole motor (lower) and angle selection joint. The yellow line is a non-perpendicular rotational surface. Rotating one end of the tool along that plane and to the desired angles bends the tool

Video 17. Extending the life of a reservoir, from 揟 he Making of Oil? (? 1997 Schlumberger, Ltd. used with permission).

Video 18. Extending the reach and increasing production, from 揟 he Making of Oil? (? 1997 Schlumberger, Ltd. used with permission).

Video 20. Directional and horizontal drilling.Courtesy of the American Petroleum Institute, copyright API 2007.

Figure 159. Orientation (steering) tools and down hole motor. (a) Down hole motor (lower) and angle selection joint. The yellow line is a non-perpendicular rotational surface. Rotating one end of the tool along that plane and to the desired angles bends the tool.



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highly deviated wells, of which horizontal wells are but an example, have complex trajectories it is necessary to know where the drill bit is. This is achieved using a measurements-whilst-drilling device (MWD).

MWD tools can be configured in a number of ways, with available modules that can provide geological, engineering, and direction information. A magnetometer unit enables the directional driller to determine the location of the unit within the subsurface; which is important information if several targets are to be intersected with the same well (i.e., drilling 慸esigner wells? . The configuration of the drill string is determined by the desired build angle or radius of curvature (Figure 158). Generally wells can be drilled in a long, medium, or short radius (Figure 158; Video 19). Long radius wells often involve build angles of 2 to 6? per 30 m (100 ft) with horizontal legs of 1,250 m+, or 2 to 4? per 30 m (100 ft) in the North Sea, with horizontal legs of 400 m+. Medium radius in the continental U.S.A. involve build angles of 16 to 23? per 30 m (100 ft) with horizontal legs of 160 m, or 11 to 14? per 30 m (100 ft) in the Middle East (offshore) with horizontal legs of 350 m. Short radius wells, for example, have build angles of 1 to 3? per 30 cm (1 ft) in the Middle East (on-shore) with horizontal legs of 160 m.

Figure 160 shows, in plan view, the well courses for production wells of the Piper field, North Sea. Each well is drilled directionally from the platform, which supported two derricks (Maher et al., 1992). A perspective view of this field and the wells is given in Figure 141.

Why run highly deviated and horizontal wells?

There are a number of reasons for running 慼orizontal wells? and re-entry wells, which including:

Increased contact with the reservoir.

Linear drainage of the reservoir along the borehole.

Reduced pressure gradient at the well.

Reduced number of wells required to maximize drainage.

Penetration of natural fractures or permeability conduits.

More effective drainage of laterally continuous thin reservoirs.

Cost effectiveness.

However, not all formations are good candidates for horizontal or reentry wells. Costs can increase rapidly, especially if there are potential technical and engineering problems that could lead to the loss of the well.

However, it is in the area of off-shore production that the drilling of deviated wells has been perfected. The ability to tap into the reservoir from a single production platform enhances the viability of many fields and makes effective use of expensive centralized infrastructure.

References

Allen, F., P. Toons, G. Conran, and W. Lesso, 1997, Extended-reach drilling: breaking the 10-km barrier: Oilfield Review, Schlumberger, Sugarland, Texas, p. 32-47.

Brantly, J. E., 1971, History of oil well drilling, Gulf Publishing Co., Houston, Texas, 1525 p.

Maher, C. E., H. R. H. Schmitt, and S. C. H. Green, 1992, Piper Field-UK in Structural Traps VI, Treatise of petroleum geology, atlas of oil and gas fields, (N. H. Foster and E. A. Beaumont, eds.): AAPG Treatise of Petroleum Geology, p. 85-111.

Schlumberger, 1997, The Making of Oil: Schlumberger Wireline and Testing, Sugarland, Texas.

Smith International, 1992, Drilco drilling assembly handbook: Smith International, Houston, Texas, 159 p.

Figure 160. A plan view of the Piper Field well courses (from Maher et. al., 1992).

Video 19. Short vs. Medium radius, drilling from 揟 he Making of Oil? (? 1997 Schlumberger, Ltd. used with permission)

Video 19. Short vs. Medium radius, drilling from 揟 he Making of Oil? (? 1997 Schlumberger, Ltd. used with permission).


Chapter 8—Production and Recovery

112

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Evaluation and appraisal

Introduction

At this point in the quest for petroleum, the exploration well would have been drilled to total depth (TD) and probably the primary, secondary, and ancillary targets reached and evaluated by geologic and petrophysical means. If an oil show was encountered, the core analysis results were good, and the petrophysical log analysis encouraging, the decision to proceed with a test (e.g., DST) would seem to be the next logical step towards evaluating reservoir potential (Figure 161). However, it is worthwhile reviewing some of the factors that should be considered at this time.

Perhaps the most fundamental objective of any appraisal activity is the reduction in uncertainty concerning the description of the hydrocarbon reservoir and the provision of sufficient information with which to make subsequent decisions. Such decisions may be to conduct further data gathering and extend the appraisal, to cease activities altogether and abandon, or farm-in, farm-out, or hasten 慺irst oil.?However, it is reasonable to state that not every well drilled is tested. Why? Some reasons are obvious! The absence of an oil or gas 憇how,? the absence of detectable hydrocarbons through log analysis and/or due to discouraging geological analysis of primary and ancillary targets. Other factors include cost and safety. To run a drill stem test or production test has a cost factor, which may be 10% of the total exploration budget. For a deep well and/or an off-shore well those costs will be greater. In general, exploration activity costs increase with increasing depth by a factor of two for on-shore exploration activities. Some of the deepest on-shore wells drilled in N. America (e.g., Anadarko Basin) cost approximately $5,000,000 to $6,000,000 each to complete, in contrast to the shallower wells in the Williston Basin (approx. $1,500,000). Testing wells is potentially dangerous, since the formation to be tested is encouraged to flow, consequently the potential for a blow-out exists and preventative precautions must be taken in advance.

Drill stem testing

Introduction A drill stem test (DST) is a method of determining the potential of a well to produce oil and/or gas (Borah, 1992; Lancaster, 1992). The formation to be tested is sealed from the rest of bore hole by inflatable packers (Figure 162) and indigenous formation fluids are encouraged to flow by exposing the formation to reduced pressure or atmospheric pressure. There are two general types of DST; non-flowing and flowing. Flowing DSTs permit the flow of fluids to the surface and are analogous to production tests. The data from a DST can include samples of fluid, reservoir pressures (P*), formation properties such as permeability (k), skin (S), and radius of investigation (radius of depletion), and estimations of flow rate. DSTs can be run in either open hole or in perforated cased hole, although the optimal time to run a DST is just after drilling into a potential reservoir when the formation is relatively undamaged. An important consideration in planning a DST is the location of the 憄acker seats,? which should be a competent formation with low porosity, low permeability and adjacent to the test zone.

Figure 161. A 24-hr production test on the NW Dome, Qatar.

Figure 162. (a and b) Bottom Hole Tool: (a) packers uninflated; (b) packers inflated and tool open. (c) Straddle Test Tool: packer inflated and tool open.



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Test tools

The test tool consists of packers, a downhole shut-in valve, a safety joint, pressure recorder, and gauges (Borah, 1992). The testing tool is lowered into the bore hole, on the end of the drill string. Once at the desired depth, the hydraulic check valve is closed to prevent fluids from working up the drill pipe; the opening/closing of various check valves is achieved by a set number of drill string rotations. The packer is inflated against the walls of the bore hole (Figure 162). Once expanded, the packers support the hydrostatic pressure of the drilling fluid within the annulus. Formation fluids, either below the packer (Bottom Hole Tool) or between the packers (Straddle Test Tool), are allowed to produce when the hydraulic check valve is opened. The amount of fluid that flows into the drill pipe is a measure of the reservoir's potential to produce fluids. After a short period of time, the tool is shut-in and the formation pressure recorded. The shut-in valve can be opened and closed 3 times, if required. Once complete, the hydraulic valve is closed and the pressure equalized for packer unseating. Formation fluids are then reverse circulated out of the hole and fluids recovered. The recorded pressure provides information regarding formation pressures, and the permeability and recharge capacity of the reservoir. In general terms, the permeability can be 慹yeballed? by looking at the radius of curvature of the shut-in pressure curve; however, the viscosity of the fluids also influences the curve (Borah, 1992).

DST charts Please refer to Figure 163. The DST tool is run into the borehole (RIH), during which the steady increase in hydrostatic pressure is recorded by the tool. (1 to 2) The packers are set and the formation is allowed to 憄re-flow,?clearing the pores of mud cake and filtrate. (2 to 3) The tool is then shut-in and the formation pressure recorded, the height of the curve reflects pressure while the slope reflects rock permeability. (3 to 4) The shut-in valve is opened, the pressure drops and (4 to 5) the formation allowed to flow for a period of time. (5 to 6) The shut-in valve is closed again and the formation pressure recorded, any change in height or slope compared to the slope for the initial shut-in period (2 to 3) may signify low formation transmissibility. At the end of the test, the tool is opened (6 to 7), the packers released, and the tool pulled out of the hole (POOH). The analysis of data is conducted using algorithms and a Horner type plot to determine static reservoir pressure (Borah, 1992). Some example DSTs and relevant data are given below and in Figure 164.

Figure 163. Example DST chart. The numbering is also used on subsequent charts: (1) Initial hydrostatic, (2) Preflow, (3) Initial shut-in pressure, (4) Initial flow pressure, (5) Final flow pressure, (6) Final shut-in pressure, (7) Final hydrostatic (after Lynes, 1981; Borah, 1992; and others).

Figure 164. Two example DST charts and data for the Sparky

態? Manville Fm., Saskatchewan.

DST Number 1 High permeability formation

Sparky 態?

Depth (m) 677 Pressures (Mpa) PF = 0.903 1, ISI = 3.350 5, IF = 1.041 0, FF = 2.137 1, FSI 3.000 7 Times (min) PF = 5, ISI = 60, FF = 60, FSI = 90, PF = fair IP V good air blow decreasing to fair steady throughout Recovery 207 m heavy gassy oil

R k H d il

DST Number 2 High permeability formation

Sparky 態?

Depth (m) 623 to 627 Pressures (Mpa) PF = 0.648 0, ISI = 5.377 3, IF = 0.978 9, FF = 1.323 6, FSI 5.156 7 Times (min) PF = 5, ISI = 60, FF = 60, FSI = 90, PF = fair to strong Strong decreasing to dead in 45 min Recovery 112 m heavy crude oil, 4.6 m mud cut oil Remarks Heavy viscous oil



114

Completion and production

Open hole completion

If the decision is to go ahead and complete the well and produce, there are a variety of options that can be pursued, depending upon cost, reservoir characteristics, local regulations, nature of the producing fluids, potential hazards and environmental concerns (Holditch, 1992).

Several decades ago, typical completions were of the so-called 憃pen hole?type (Figure 165a). That is, production was from the open, unprotected hole without packers isolating the zone of interest. When the producing formation was penetrated and petroleum began to flow, drilling was stopped and the well was produced from the open (i.e., bottom) hole. Well stimulation was even sometimes achieved using nitroglycerin!

Liner completion

This is a variation of the open hole completion technique, except that steel tubing, known as a liner, is hung from inside the casing. That is, if the 339 mm (133/8 inch) casing shoe was set at 3,000 meters and TD was 3,200 meters, then a liner would be hung from 339 mm (133/8 inch) casing to TD. Therefore, the casing must be in place before the liner can be set and prior to production. The liner has numerous 慼oles? through which fluids can enter the well bore; which includes the slotted liner, screen and liner, or a cemented liner.

Slotted liners (Figure 165), although cheap this type gives very little protection. Screen and liner types are sometimes used when producing from an unconsolidated formation, the difference being the addition of aggregate (e.g., gravel) behind the screen (Holditch, 1992). They are also inexpensive and provide limited protection.

Cemented liner. This type is used when there is a need to isolate and or protect zones of interest. Advantages of the Cemented liner include (1) cost effectiveness, (2) can selectively perforate and produce from a portion of the reservoir, and (3) a higher degree of formation integrity is maintained. Unfortunately this type of completion is dependent upon the integrity of the cement job (Holditch, 1992).

Perforated casing completion

A perforated casing completion is commonly used in vertical wells or where multiple producing zones are encountered (Figures 166 and 167). The casing is cemented back to the shoe (if possible) and the casing subsequently perforated.

Casing has a higher bursting pressure than a liner and it is easier to obtain a superior cement job with casing. This approach is also much more straightforward, relatively low cost, and typically associated with fewer operational problems (Holditch, 1992). There are a number of completion options, known as single, multiple, and alternate completions (Figures 166, 167).

Single perforated casing completion

This is the simplest completion approach, because production involves only one interval; this type of completion is also more common on land-based operations where drilling costs are less. This technique has also been used in some of the deepest wells drilled within the Anadarko Basin, U.S.A. (Holditch, 1992).

Figure 165. (a) Slotted Liner and (b) Screenand line completion. Producing zone in black(from Holditch, 1992).

Figure 166. Variation of perforated casingcompletions with tubing; (from Holditch,1992)

Figure 167. Conventional triple tubing, multiple perforation completion (from Holditch, 1992).

Figure 166. Variation of perforated casing completions with tubing; (from Holditch, 1992).



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Multiple perforated casing completion This type of completion is much more complex and allows for the simultaneous production from two or more zones (Figure 167). Multiple completions are often used off shore, in high cost areas, or where the characteristics of the produced fluids are distinct or the formation pressures are markedly different. The differences are the number of isolated zones that are completed simultaneously and the concomitant number of tubing strings (Figure 166a, b; Figure 167) Each zone of interest must be perforated before the tubing is run and the packer set. This approach allows for the simultaneous production from two or more reservoirs, but because production takes place through casing and through continuous tubing there is a higher degree of protection for producing and non-producing zones alike; individual zones can be isolated, fragile formations are protected, and the tubing can be replaced if necessary; although, the more complex the completion, the greater the opportunity for a technical problem to arise (Holditch, 1992).

Perforating

The main purpose of perforating is to provide conduits through the wall of the borehole that allow the effective flow of fluids from the reservoir. Holes are shot through the casing and cement into the formation (Figures 168, 169). The perforating gun is a 憌ireline? device comprised of an array of explosive devices, developed from early armor piercing weapons! Upon ignition, a 慾et?of burning charge plus a cone shaped liner generates a velocity of 20,000 ft sec-1 and a pressure of 5 106 psi, capable of punching a small diameter hole through casing, cement and into the formation (Figure 170). The main types of perforating gun include the expendable gun, the semi-expendable gun in which only part of the gun disintegrates and the retrievable hollow carrier gun which is the most widely used gun. It is rugged, strong, and reliable, it leaves no debris, creates little casing damage, has the highest performance and largest charges. All are available as casing guns or tubing guns (Holditch, 1992).

Producing from horizontal and re-entry wells

Production from highly deviated wells, was previously touched upon, but deserves special consideration due to the technical nature of such wells. Three completion options are shown in Figure 171, the selection of which is based upon the geological characteristics of the reservoir, the length of producing interval and radius of curvature.

Figure 171. Types of horizontal well completion. (a) bare foot (i.e., no liner); (b) slotted liner and (c) a cemented liner (Jahn et al., 1998, reprinted with permission from Elsevier).

(a) (b) (c)

Figure 168. Perforation patterns (plan view) using: (a) symmetric casing gun and (b) an asymmetrically position tubing gun (from Holditch, 1992).

Figure 170. A perforating 慻un? and blast (from Holditch, 1992).

Figure 169. (a) Casing perforating gun, (b) tubing perforation gun (from Holditch, 1992).



116

Bare foot The simplest and cheapest completion is the bare foot (Figure 171a). This is an open hole type completion and is only suitable for consolidated formations with a low collapse potential. Open hole completions are still used, for example in the Austin Chalk (Texas), because it is the easiest solution for short to medium radius horizontal wells. Disadvantages include lack of well control, a reduced ability to control the injection profile and the possible disintegration of the producing formation!

Slotted line The slotted liner (Figure 171b) is a non-cemented section of casing with slots cut into it, as discussed above. This type of liner provides some support, whilst permitting the formation to produce fluids, but because the slotted liner is slotted along its length there is often little control as to which part of the reservoir will or will not produce.

Cemented liner The cemented liner (Figure 171c) involves a cased and cemented bore hole within which the producing intervals are perforated, similar to a conventional well although because of the technical complexity of this type of completion, it is considerably more expensive. However, none of the examples given above are suited for production in unconsolidated to poorly consolidated sands. To complete such formations, gravel packs or 憈ailor made? completions would be required (Jahn et al., 1998).

Offshore production

Producing oil and or gas from an offshore field is typically more complex than on land. Because production must be accomplished by self-contained facilities, often out of sight of land, production is typically facilitated via an oil platform, which unlike drilling rigs and drill ships, are traditionally attached or anchored directly onto the ocean floor. Production platforms are generally self-sufficient industrial units that support a deck with space for a derrick (or two). Production platforms (Figure 172) can accommodate the crew, generate their own electrical power, process water, and the have the equipment required to process oil and gas for onshore delivery via pipeline or tanker. Such platforms are, because of their immobility, designed for very long term use.

There are numerous challenges that must be met when developing an offshore oil and/or gas field. Environments, such as the North Sea, Canada抯 East Coast, the Gulf of Mexico, and South China Sea for example, are often hostile environments in which severe storms are a regular occurrence. This aside, water depth alone presents a formidable challenge. Modern offshore drilling rigs have enabled exploration in water depths that was unthinkable 40 years ago. In contrast, the water depth capability of the production platform has always lagged behind the exploration rig, as technology 慶atches up?(Figure 173).

For many years, fixed platforms were the most common type of production facility. Fixed platforms are attached to concrete and/or steel legs that are anchored into the seabed. Fixed platforms are feasible in water depths up to approximately 500 m (1,500 ft). Many of the original production facilities in the North Sea (e.g., Piper Platform, Troll West), Gulf of Mexico (e.g., Baldpate platform), Santa Clara field, U.S.A., (e.g., Platform Gail), South China Sea (e.g., Malampaya platform), Bass Strait, Australia (e.g., Barracouta platform) are of this type.

Figure 172. A production platform topsides awaitingdeployment in the Gulf of Mexico.

Figure 173. Plots of water depth for off-shore explorationand production facilities showing a technological lagbetween the two (data from Veldmann and Lagers, 1997;MMS, 2004).



117

The Troll platform (Norwegian North Sea) operates in 305 m of water, which is generally acknowledged to be the limit for this type of platform because of the stresses placed upon such structures during storm conditions. Therefore, in water depth greater than 300 m different structures are required; the industry has begun to use compliant (i.e., not rigid) structures and subsea production systems (Figure 174). Floating production systems, tension-leg platforms, subsea systems, and SPAR platforms are all considered suitable in water depths up to 1,650 m (6,000 ft), 1,900 m (7,000 ft), 1,900 m (7,000 ft), and 2,700 m (10,000 ft) respectively (MMS, 2004).

Floating production systems (Figure 174) can be either semi-submersible drilling rigs or ships anchored to a location for a long period of time and equipped with processing facilities. There are three main types of floating production systems, known as: (1) floating production, storage, and offloading system (FPSO), (2) a floating storage and offloading system (FSO), and (3) the floating storage unit (FSU). The Shell and BP Na Kika floating production system, within the Gulf of Mexico, operates in 1,736 m (6,350 ft) of water.

Tension-leg platforms (Figure 174) consist of a tightly tethered floating rig system that allows side-to-side movement but effectively eliminates vertical movement. Tension-leg platforms are used in water depths up to about 2,000 m (~7,000 feet).

Subsea systems are designed to operate in water depths of 2,000 m (~7,000 feet) or more but do not have the ability to drill, only extract and produce oil and/or gas. Subsea systems are either linked to an existing production platform or a subsea pipeline. The Camden Hills subsea production facility, in the Gulf of Mexico, was set in 1,971 m (7,209 ft) in 2002.

Similar to the tension-leg platform, SPAR platforms are tethered using conventional mooring lines. The large hull (Figure 175a, 175b), which is typically more than 190 m (700 ft) long, supports the production facility (Figure 175c). The hull acts like a counterweight, giving the whole structure a greater degree of stability than the tension-leg platform. SPAR platforms currently operate in some of the world抯 deepest water. Dominion Oil's Devil's Tower is located in 1,710 m (5,610 feet) of water, in the Gulf of Mexico, and Kerr-McGee's Red Hawk is the first deep-water cell spar.

Figure 174. A comparison of various off-shore production facilities ranging from those suited to in-shore and shallow water (i.e.,Mono-pod and Jack-up), through the fixed platform types (includes the concrete gravity-based platform/caisson) that operate inwater depths up to approximately 300 m, and more recent deep-water facilities (floating platform systems, tension leg platform, sub-sea systems, and SPAR platforms). Water depth is not to scale.

Figure 175. (a) Lifting the hull of the Red Hawk cellspar, and (b) the Garrison spar platform in the Gulf ofMexico (images ? Anadarko Petroleum Corporation, allrights reserved, reprinted with permission).



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Reservoir drive mechanisms

Natural driving forces

Introduction The Field Appraisal aims at determining the revenue stream that will result from production. Production behavior is largely a function of reservoir characteristics, the type of fluids to be produced, and their behavior under the dynamic conditions of production. One key aspect is to determine what type of driving mechanism exists within a given reservoir and the optimal means of enhancing or maintaining production during the anticipated life span of the well or field.

Recovery efficiencies The efficient recovery of oil/gas from a pool or well is not only dependent upon the natural driving mechanism that causes fluids to be produced from the reservoir (i.e., drive mechanism) but upon a number of factors which include:

Reservoir quality (e.g., porosity, permeability) and continuity Duration allowed for production Type of fluid (e.g. methane, condensate, heavy oil) Well spacing The possible need to assist the natural drive mechanism.

The influence of well spacing alone can be determined by a simple examination of development costs versus the net revenue for the well, pool, or field. If well spacing is not determined by the local government, the optimization of well spacing will depend upon all of those factors. This is illustrated in Figure 176, in which 憄rofit? factors in: number of wells, cost of wells, recovery efficiency, porosity, K, Ko, or Kg, drive mechanism, time, inflation, flow rate, type and value of the oil or gas.

Primary production Reservoir fluids (gas, oil, and water) are under high pressure and elevated temperature; any drop in pressure (such as opening the borehole to near atmospheric pressure) will result in an increase in volume, producing flow. Removing a volume of fluid will also lead to drop in pressure. However, the amount of pressure drop depends upon the type of fluid. Gas is highly compressible, so removing a small volume of gas will not appreciably affect reservoir pressures. In contrast, oil is not very compressible, so removing oil will create a measurable drop in reservoir pressure, unless the volume removed is replenished by another fluid (e.g., water). The natural expansion of reservoir fluid is the primary energy source for initial production (Sills, 1992).

Types of drive mechanisms There are two basic types of primary drive mechanisms; water drive and gas drive. They have very different characteristics. If the reservoir pressure (and production) declines rapidly it is probably gas depletion drive, if the reservoir pressure declines, then levels off (and perhaps recovers), it is a water drive mechanism (Sills, 1992).

Gas drive

There are two types of gas drive mechanism: gas-cap and solution-gas (depletion) drive. Both mechanisms function through the expansion of gas and the volumetric displacement of oil, the difference between them is the presence or absence of an initial gas cap.

The gas-cap drive is a reservoir containing free-gas in the highest point of the trap, as a gas-cap. Reservoir pressure is maintained by expansion of the gas within the gas-cap.

The gas-solution (depletion) mechanism lacks an initial free-gas cap. A pressure drop, due to the initial withdrawal of oil from the reservoir, causes gas to come out of solution. The dissociation and expansion of gas drives the oil. The movement of the gas within the reservoir can be complex, but will generally be upwards towards the crest of the trap to form a gas cap, or towards the producing well (a local low pressure zone) under the influence of hydrodynamic flow. If a gas cap forms, then production switches to the gas-cap drive mechanism. Video 20 shows a simplified gas-solution (depletion) drive mechanism. The placement of production

Figure 176. A representation ofnet revenue (profit) versus oil wellspacing, showing the possiblerelationship between well spacingand net revenue.

Video 20. Gas-solution (depletion) drive.



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wells is of great importance. Wells drilled on the crest may remove some of the initial gas prior to the formation of a gas cap. This can be avoided by re-injecting the natural gas into the reservoir. For the gas depletion drive mechanism to work efficiently, as oil is removed the expansion of gas in the gas cap should exert pressure on the oil/gas contact.

Water drive

In contrast, the water drive mechanism requires a different well placement strategy. This is because the natural hydrodynamic flow into the structure maintains pressure beneath the pooled oil, driving the oil upwards. A natural water drive mechanism occurs when the underlying aquifer is large and capable of undergoing recharge. A common practice is to initially produce the reservoir using the natural depletion drive, subsequently switching to a water injection mechanism as an enhanced recovery method (discussed below).

Enhanced oil recovery

Introduction Enhanced oil recovery (EOR) techniques such as a water flood and gas injection have traditionally been regarded as secondary recovery techniques and other techniques (i.e., chemical flood, polymer flood, caustic flood, steam flood, steam drive, cyclic injection, in-situ combustion) were regarded as tertiary techniques. The current preferred term enhanced oil recovery encompasses all former (and future) secondary or tertiary recovery techniques. However, because water and gas injection techniques remain the most common techniques they will be discussed first and individually. Other EOR techniques are discussed according to category.

Water flood Water flooding (Figure 177) is used on a fairly regular basis in many pools to supplement the natural hydrodynamic flow of ground water as a means of maintaining reservoir pressure, driving oil to the production wells (Sam Sarem, 1992). The injected water should always be drawn from an aquifer, because of the oxidizing effect of meteoric water. The chemistry of the injected water must approximate the chemistry of the oil-field water within the producing formation to prevent the swelling of clays, prevent the in-situ degradation of oil within the reservoir (see Chapter 3 p. 32-32; Chapter 5 p. 72) and maintain similar levels of wetability to prevent channel-breakthrough and improve sweep efficiency (Figure 178).

Figure 177. 態y-passed' oil in a heterogeneous reservoir (Jahn et. al., 1998).

Figure 178. Oil, connate water and flood water (i.e., waterflood) moving through a laboratory scale reservoir. The 憆eservoir? is water wet (connate water), Sw >0.60, connate water occupies small and medium sized pores and surrounds the 憁 ineral grains? Within the pores oil and water are immiscible. However, the flood water, flowing left to right, has a different water chemistry and as a consequence there is interfacial tension between the connate water and the flood water, they do not readily mix (i.e., immiscible), hence the visible interface between the flood water and connate water. Consequently, the waterflood has formed a 憁 icro-channel? (blue arrow) and has bypassed the oil in the upper and lower pores. The scale bar is approximately 500 m. (after Dong et al., 2007, reprinted with kind permission).



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Water is injected via a separate injector well, or more typically via a number of wells arranged in a set pattern. Injector wells are always down dip from the producing wells. As oil is withdrawn the oil/water contact will rise. As producing wells 憌ater-out,? during production (Video 21), they would most likely be converted to an injector well (Sam Sarem, 1992; Jahn et al., 1998).

Of course in plan view, the pattern of injector wells should reflect the geometry of the trap, the porosity and permeability distribution throughout the reservoir, and known changes in facies, although typically producers use set injector patterns (Figure 179). Geologically inhomogeneous reservoirs are the norm, and a poorly designed injector pattern will produce less than ideal recovery, leaving behind by-passed oil (Figure 177), which can be difficult and expensive to recover. In the example given in Figure 177, injected water appears to have effectively swept oil from two high permeability zones and successfully produced oil. However, there are two low permeability zones, associated with a significant amount of oil remaining within those reservoir partitions as by-passed oil (Jahn et al.,1998). Any attempt to recover the by-passed oil by continued injection of water would be futile, since the injected water would preferentially travel through the more permeable zones (Figure 178). The geologist can contribute significantly in the optimization of production through the application of his/her knowledge and understanding of the reservoir rock, facies variation, type and depositional setting of the reservoir rock, trap geometry, variations in porosity and permeability and water saturation (i.e., Sw, Swirr) etc., all of which have great relevance when determining the optimum injector pattern.

Gas injection Producing oil wells can be assisted by injection of (compressed) solution gas back into the gas cap, in order to maintain pressure. Sometimes producing companies can inject unwanted gas back into the reservoir; this depends upon local regulations. Another option allows for the injection of gas into the annulus, with the aim of lowering the density of the produced oil and aiding production (Jahn et al., 1998).

Thermal techniquesThermal techniques are used to reduce the viscosity of oil within the reservoir in an attempt to increase mobility and displacement by reservoir drive mechanisms. Sources of heat include steam flood or hot water flood. The injection of a heat source may require separate injector wells or, the producing well may be used by cycling between production and injection. In-situ combustion is an extreme example of heat injection (Breit, 1992).

Chemical techniquesChemical techniques utilize reagents that change the physical properties of the produced fluid or the displacement fluid. There are two general sub-types, polymer flooding and alkali-surfactant flooding. Polymer flooding aims at increasing the viscosity of the displacing fluid (i.e., connate water) and increasing the sweeping efficiency of that fluid. Alkali-surfactant and surfactant flooding is used to reduce the amount of residual oil left in the pore space of the reservoir by reducing interfacial tension between water and oil. This is achieved by a reduction in oil droplet size, thereby permitting the oil to pass through smaller pore throats (Breit, 1992; Jahn et al., 1998). Emulsifiers can also be used in situations where oil to water ratios are unfavorable, or to assist with the production of heavy gravity crude oils, i.e., low API? gravity (Liu, 2006; Dong et al., 2007) (Video 22).

Figure 179. Water injector arrangement patterns. Shown here are the 4-Spot and the 5-Spot patterns. Single wells are typically associated with simpler patterns, whereas large pools demand complex patterns.

Video 21. The animation shows the sequential transformation of producing wells into water injector wells.

Video 22. Oil, connate water and alkali-surfactant flood moving through a laboratoryscale reservoir. The alkaline flood reducesthe interfacial tension between the floodwater and oil, increasing sweep efficiency.(after Dong et al., 2007, used with kindpermission).



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Miscible processesMiscible fluids are utilized to produce oil that could potentially become residual oil. This is achieved by injecting a fluid that mixes with the produced fluid. Typical miscible fluids are organic-based solvents, hydrocarbon gases, CO2

and N2 (Breit, 1992; Jahn et al.,1998)

Artificial lift systems Some wells will produce throughout most of their life without the need for EOR. However, most wells will require some form of recovery method to enable or accelerate production. Many wells require some form of artificial lift as reservoir pressures drop and production declines. Artificial lift is not an EOR technique, although it can augment the specific application of EOR. Artificial lift may also extend the life of a pool or field, or become the only means through which a well can become economic. Prior to the option of running horizontal legs, production from stripper wells (i.e., production less than 1.5 m3 p.d.) was only feasible by using a pump jack(beam pump) (Figure 180), the cost of which may represent one third of the total cost of drilling and developing some wells in N. America. In the case of off-shore ventures, the cost of production can easily exceed exploration costs.

When is the best time to install an artificial lift system? The obvious need is when production rates decline, or when the well is in danger of becoming sub-economic. However, probably the most intelligent time to install an artificial lift system is prior to first oil; because the cost of installation can be covered by the increased production rate throughout the life of the well, and the cost of installation can be written throughout over a longer period of time (if advantageous). Although, there may be cases when the optimal type of artificial lift changes during the life of a well or field. The types of artificial lift discussed here include: the pump jack (beam pump), the progressive cavity pump, the electric submersible pump, hydraulic reciprocating pump, hydraulic jet pump, continuous flow gas lift, and intermittent gas lift (Figure 181) (Smallwood, 1992; Jahn et al., 1998).

Gas lift Gas is injected into the producing fluid column, which decreases the hydrostatic pressure within the well bore, thereby stimulating natural flow (Figure 181a). In the continuous gas lift type, a constant stream of gas aids the production of fluid and the gas becomes dispersed within the produced fluid. However, in the intermittent gas lift variant the gas is injected as 憄ulses? generating a 憄iston-like? or pulse lift. The gas is removed from the produced fluid at the end of each 憄ulse.?

Lift capability (gross / BPD) 100 to 1,000 Hydraulic efficiency 2 to 30% Continuous gas lift

Lift capability (gross / BPD) 1 to 800 Hydraulic efficiency 2 to 10% Intermittent gas lift

Figure 180. A pump jack in the Midale field, Sask., Canada.

Figure 181. Examples of artificial lift systems. A gas lift, B hydraulic jet pump, C pump jack, D progressive cavity pump, and E electric submersible pump (after Jahn et al., 1998, reprinted with permission from Elsevier).



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1 23

Figure 182. A generalized three phase separator (redrawn and modified after Jahn et al., 1998).

Hydraulic jet pump A downhole hydraulic motor, driven by a hydraulic medium under pressure, achieves lift (Figure 181b). Energy for the motor is delivered via the hydraulic medium by a surface motor. There are no moving parts in the downhole hydraulic motor.

Lift capability (gross / BPD) 80 to 12,000 Hydraulic efficiency 10 to 30% Hydraulic Jet pump

Lift capability (gross / bpd) 80 to 10,000 Hydraulic efficiency 2 to 30% Hydr. reciprocating pump

Pump jack Also known as the beam pump and affectionately as a 憂odding donkey? (Figure 181c). Lift is achieved by a downhole plunger, which is connected to the counter-balanced reciprocating beam by sucker rods. A small motor drives the beam at the surface. Differing rates of production are achieved by varying the beam speed, the dimensions of the plunger, and stroke length, all of which should match the permeability characteristics of the reservoir and viscosity of the produced fluid.

Lift capability (gross / BPD) 1 to 5,000 Hydraulic efficiency 50 to 60%

Progressive cavity pump Based upon the Archimedes screw, the progressive cavity pump is a downhole motor driven by a small surface motor (Figure 181d). Variations in production rate can be achieved by changing the dimensions of the stator rotor and pump speed.


Electric submersible pump This is a centrifugal type of pump driven by a downhole motor powered by electricity (Figure 181e). Typical units consist of more than one pump, arranged as a series of pumps to aid lift.


Surface production facilities

Introduction

It is an exceptional oil-field fluid that can be produced from the reservoir ready to export. Typically the produced fluids will exist as a mixture of oil and gas, oil and water, oil plus gas and water or even condensate and hydrogen sulfide etc. Therefore, the produced fluids must be separated and the unwanted fluids or gases disposed. Separation is achieved at the surface in an oil and gas processing facility near or adjacent to the producing well and such facilities are tailored to the specifics of the producing well, pool, or field (Jennings, 1992; Jahn et al., 1998). Off-shore facilities may employ three separate fluid separators; consisting of a high pressure, medium pressure, and low pressure separators to remove gas and water. In comparison, land-based operations often use a single three phase separator (Figure 182).

Separators

The single three phase separator uses differences in density to remove gas, free-water and oil from the produced fluids (Figure 182). The inlet section [1] separates most of the liquid phase from the produced mixture. The dissolved gas comes out of solution and rises within the vessel as a gas phase. Because small amounts of liquid may exist as droplets within the gas phase, a demisting section[2] or device is utilized to remove any fluid phase. Demisting can be achieved by ether a centrifuge demister or an impingement demister.The centrifuge type utilizes high velocities to separate the phases whereas the impingement device is composed of either a screen or series of condensing plates upon which the fluid phase condenses. The fluid phases are separated at the base of the tank by a weir [3], which causes the liquid phases to 慴ack-up,? separation of oil and water is achieved by differences in density. Water-free oil spills over the weir and is collected as gas- and water-free oil.



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ReferencesBorah, I., 1992, Drill stem testing in Development Geology Reference Manual (M. Morton-Thompson and A. M.

Woods, eds.): AAPG Methods in Exploration 10, p. 131-139.

Breit, V. S., 1992, Enhanced recovery in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 527-530.

Dong, M., Q. Liu, and A. Li, 2007, Micromodel study of the displacement mechanisms of enhanced heavy oil recovery by alkaline flooding: SCA Annual Symposium, Calgary, Canada, September 9-13, in press.

Holditch, S. A., 1992, Well completions in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 457-541.

Jahn, F., M. Cook, and M. Graham, 1998, Hydrocarbon Exploration and Production Developments in Petroleum Science 46: Elsevier, New York, 384 p.

Jennings, J., 1992, Surface production equipment in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 482-484.

Liu, Q, 2006, Interfacial phenomenon in enhanced heavy oil recovery by alkaline flood, Ph.D. Thesis (unpub.): Faculty of Engineering, University of Regina, Canada, 234 p.

Lancaster, D. E., 1992, Production testing in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 474-476.

Lynes United Services Ltd, 1981, Drill Stem Test Analysis and Interpretation: Calgary, 62 p.

MMS, 2004, United States Department of the Interior Minerals Management Service, http://www.mms.gov/stats/PDFs/Milestones.pdf.

Sam Sarem, A. M., 1992, Waterflooding in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 523-526.

Sills, S. R., 1992, Drive mechanisms and recovery in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 518-522.

Smallwood, D. D., 1992, Artificial lift in Development Geology Reference Manual (M. Morton-Thompson and A. M. Woods, eds.): AAPG Methods in Exploration 10, p. 485-487.

Veldman, H., and G. Lagers, 1997, 50 years Offshore: Foundation for Offshore studies, Delft, 216 p.


Chapter 9—Petrophysical Logs

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Introduction

Log

Petrophysical logging, wireline logging, and borehole logging are used as synonyms to describe the same thing. In the same way, the word log is used as a noun, verb, or adjective; here we will limit the term to the act of either recording depth-related information over time (verb) or to the actual recorded hard copy (or digital display) of the depth-based measurement! Logs are used to conduct subsurface correlations, to assist with structure and isopach mapping, help define physical rock characteristics (lithology, porosity, pore geometry, and permeability), and identify production zone thickness and determine the type of formation fluids. There are two basic types of wireline logging tool. Those that are designed to work in an 憃pen? uncased hole and those that are able to work within 慶ased hole.? Open hole logs are recorded in the uncased section of the well, usually at some intermediary depth or total depth (TD), prior to running casing. This is because some logging tools do not work well in cased holes. For example, microresistivity logging devices cannot work through casing, unlike acoustic (or sonic) tools. A useful basis for subdividing open hole wireline logging tools is on the basis of 憈ype? or 慹nd-use?(Alberty, 1992), which will be used here (Table 10).

The Borehole and associated environment

Explanation of some symbols and terms When a borehole penetrates a formation, the character of the formation and the fluids within it are altered in the vicinity of the hole. The area immediately surrounding the borehole becomes contaminated with drilling fluid, with concomitant changes in resistivity. Such changes are constructively used to interpret the characteristics of both formation and the formation fluid(s).

dh hole diameter Borehole diameters may increase or decrease for a given well section due to: (a) formation wash out, (b) sloughing, or (c) build-up of filtercake on the walls of porous formations. A caliper tool measures and records the size (diameter) of the borehole through an interval of depth.

Rm drilling mud A pressure imbalance (i.e., overbalance) between the hydrostatic pressure of drilling fluid within the borehole and formation pressure will lead to the invasion of porous formational units by the drilling fluid. As invasion takes place, the solid material (e.g., gels or clay) from the drilling fluid infill the rock pore spaces and line the borehole wall with a gelatinous, sticky layer known as 慺iltercake,? the invading fluid (minus solids) is known as mud filtrate.

Water saturation Water saturation (Sw) is the percentage of pore volume (within a rock) occupied by formation water. Irreducible water saturation (Sw irr) is the proportion of formational water that is adsorbed (physisorbed or chemisorbed) on mineral surfaces, or held within micro pores by capillary pressure.

Conductivity Conductivity is the reciprocal of electrical resistance. Materials resist the flow of electricity differently in the reservoir,which is a function of porosity, fluid type, and rock type. For the basis of log interpretation, hydrocarbons and rock fabric act as insulators (non-conductive and highly resistive). In contrast, salt water is highly conductive.

Table 10. Basic open hole wireline tools by 憈ype?and 慹nd-use?(after Alberty, 1992).

慣ype?or 慹nd-use? Wireline tool

Correlation and lithology Spontaneous potential Gamma ray Photoelectric effect

Resistivity Induction Laterlog Microresistivity

Porosity and lithology Density Compensated Neutron Sonic Photoelectric effect

Auxiliary Caliper Dipmeter Formation tester Core plug

Borehole televiewer



125

Invaded zone This is the immediate zone around the borehole that is invaded by mud filtrate; consisting of a flushed zone (Rxo)within which mud filtrate has flushed formation water and/or hydrocarbons from the formation, and a transition zone (Ri) in which a mixture of filtrate and formation fluids exists.

Abbreviations and meaning The following diagram graphically sums, for a resistivity tool, the zones that typically exist within a porous and permeable formation. The abbreviations given in Figure 183 will be used throughout this review of petrophysical logs.

Correlation and lithology logs

Beyond the characterization of the reservoir and the fluids within it, there is a need to correlate between wells, define sequence boundaries, and identify common formations and marker zones. The logging devices in this category primarily serve that purpose.

Spontaneous Potential (SP) The SP log is used to identify impermeable (e.g., shale) and permeable zones (e.g., sand), and help determine Rw. This tool can only be used in the open hole containing a conductive drilling fluid (i.e., not oil-based mud). The SP log is a record of the DC voltage difference between the naturally occurring potential of a moveable electrode in the well bore and the potential of a fixed electrode located at the surface. Electric currents are generated between the conductive mud filtrate (Rmf ) and formation fluids (Rw) within permeable beds. Shale, due to its predominant clay content, acts as a cation membrane; that is it is permeable to cations (e.g., Na+) but not to anions (e.g., Cl-) due to the high negative charge on the lattice of clay minerals. The cations are able to move through the shale, that is from concentrated to dilute solutions (i.e., from salt to fresh) which creates a measurable potential within the borehole opposite the shale (by Na+). In contrast a negative potential is created within the borehole opposite a permeable formation. The presence of the Cl- anion generates a current, known as the SP current, which is measured in millivolts (mV). The overall effect is that the electrical potential is empirically related to formation permeability and the presence or absence of shale. The SP is influenced by bed thickness, bed resistivity, invasion, borehole diameter, shale content, and the ratio Rmf / Rw. TheSP device has a vertical resolution of 6 to 10 ft (5.5 to 9.3 m) (Alberty, 1992).

Shale baseline and the SP curve The SP log is recorded on the left of the log, track 1. For a given borehole, the SP response is relatively constant opposite all shale units, which enables the logging engineer to set the log to read zero opposite shale, which creates the shale baseline (Figure 184). Permeable zones are indicated wherever the SP deflects from the shale baseline and permeable bed boundaries are drawn at the point of inflection. In water-bearing zones the amount of SP reduction is

Figure 183. The borehole environment, notation and symbols (image ? 2005 Schlumberger, Ltd. used with permission).

dh hole diameter

di diameter of invaded zone (flushed zone)

Drj radius of invaded zone

dj diameter of invaded zone (invaded zone)

hmc thickness of filtercake ( mudcake)

Rm resistivity of the drilling fluid

Rmc resistivity of the filtercake

Rmf resistivity of the mud filtrate

Rs resistivity of shale

Rt resistivity of the uninvaded zone

Rw resistivity of formation water

Rxo resistivity of the flushed zone

Sw water saturation (uninvaded zone)

Sxo water saturation of the flushed zone



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proportional to the amount of shale present within the formation. The SP also usually has lower amplitude within hydrocarbon bearing zones. Deflection of the curve from the shale baseline can be used to demarcate sand, sandstone, or limestone in normal conditions, i.e., the salinity of the formation water is greater than that of the filtrate (Alberty, 1992; Asquith and Krygowski, 2004). In a general way, curvature to the left suggests permeability, whereas curvature to the right indicates no permeability, i.e., the presence of shale or clay.

Gamma ray log The gamma ray curve is also placed in track 1. The scale, is given in API units, typically ranges from 100 to 150. Tracks 2 and 3 often contain porosity logs or resistivity logs. The gamma ray log is affected by borehole dimension, but because the gamma ray tool detects the presence of natural radioactivity it can be used in cased hole. The resolution of the gamma ray device is 2 ft (~0.6 m) with a radius of investigation half that value (Alberty, 1992), the gamma ray tool is typically combined with other devices (Figure 185).

The gamma ray tool contains a scintillometer that detects the natural radioactivity (e.g., potassium) within a formation. Potassium (K40) is a common element within illite (but also occurs to a lesser extent within 憁ixed clays? , K-feldspar, mica, sylvite, carnallite, and glauconite. Thorium (Th232) occurs mainly in heavy minerals such as rutile, monzanite, and zircon, whereas uranium (U238) is often associated with phosphates or organic matter. Organic matter within shale may contain small amounts of highly radioactive elements, such as U and Th, the so-called 慼ot shales? within the North Sea are a known example of this phenomenon. Radioactivity can also be emitted from radioactive salts bound to the charged surfaces of clay minerals.

The gamma ray tool generates a log that is commonly used for correlative purposes between wells and the log is also used to estimate the proportion of shale/clay minerals within a formation. Because shale usually contains a high proportion of radioactive elements and clean quartz-rich sandstones contain none; the gamma ray log is used to differentiate between shale and shale-free lithologies. As the shale content increases, so the gamma ray curve deflects to the right; in contrast, clean sands are indicated by a deflection to the left. However, sandstone may produce a deflection to the right if it contains feldspars, micas, glauconite, zircon, and/or uranium-rich waters. The gamma ray log is also affected by borehole dimension, but because the gamma ray tool detects the presence of natural radioactivity, it can be used in cased hole.

Volume of shale calculation The gamma ray log can be used to calculate the volume percent shale within a given formation, known as the shale volume (Asquith and Krygowski, 2004). The derivation of shale volume (Vsh) begins with the calculation of the gamma ray index (IGR) using the following formula (Schlumberger, 1974):

where: IGR = gamma ray index GRlog = gamma ray reading from the log

GRmin = minimum gamma ray reading (i.e., clean sand) GR

max= maximum gamma ray reading (shale)

Once IGR has been calculated, there are two subsequent possible methods that can be used to derive Vshale; a linear and a nonlinear estimator (Alberty, 1992). The linear method is the most

Figure 184. Example SP deflections from the shale baseline. The mud filtrate resistivity (Rmf) is greater than that of the formation water (Rw)(from Asquith and Krygowski, 2004).

Figure 185. Microresistivity and gamma ray tool (click to activate).

(15)

Figure 186. Empirical correlations relating shale volume (Vsh) to gamma ray index (IGR) (after Larionov, 1969; Stieber, 1970; Clavier et al.,1971; Schlumberger, 1974; Western Atlas International, 1985; Bassiouni, 1994; and others).



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straightforward and can be used to derive a first order estimation of shale volume, where Vsh = IGR (Asquith and Krygowski, 2004). The nonlinear method applies an empirical correction (Figure 186), based upon clay content, formation age and geographic location, to derive Vsh (e.g., Larionov, 1969; Clavier et al., 1971). For further discussion please see Bassiouni (1994).

Worked example (volume of shale):

We will use the example log in Figure 187 and the procedure outlined above (Asquith, 1982; Alberty, 1992; Asquith and Krygowski, 2004).

where: GRlog

= 28 at 13,570'

GRmin = 15 at 13,590'

GRmax = 128 at 13,720'

IGR = (28 - 15)

(128 - 15)

IGR = 0.115

The calculated Vsh value is first located on the horizontal axis (Figure 186), ascending vertically and intercepting the appropriate curve, a 慶orrected?value of shale content (Vsh), depending upon geologic age and basin location, can be derived directly off the shale volume chart (Alberty, 1992; Asquith and Krygowski, 2004). A linear value of Vsh will be 11.5%, whereas 慶orrected?values will differ:

for example:

Vshale = 5.7% (pre-Tertiary)

or

Vshale = 2.8% (Tertiary)

Photoelectric log The Photoelectric effect (Pe) measures the ability of a formation to absorb gamma rays; an ability that varies from lithology to lithology. Because the tool requires contact with the borehole wall it is, therefore, a pad device (Alberty, 1992). The photoelectric index (Pe) records the absorption of low-energy gamma rays expressed in units of barns/electron (Doveton, 1994). The Photoelectric log is particularly useful in distinguishing between quartz sandstone, dolomite, and limestone, particularly in an alternating succession of sandstone and carbonate (Doveton, 1994). A cross-plot of Peand potassium concentration, derived from a Natural Gamma Ray Spectrometry log (Figure 188) provides clay mineralogy information.

Figure 188. A crossplot of Pe (photoelectric factor) and %KNGScor (Natural Gamma Ray Spectrometry Log), showing the general plot areas associated various clay minerals (? 2005 Schlumberger, Ltd. used with permission).

Figure 187. Example gamma ray log (track 1) and neutron-density log (track 2) (after Asquith and Krygowski, 2004).

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Resistivity

Introduction Resistivity tools are used for correlation and commonly to:

determine the water saturation (Sw) of a formation

determine hydrocarbon versus water-bearing zones

indicate permeable zones

determine Rt.

Resistivity and conductivity logging tools are connected to a source of power (i.e., generator), current is passed from the generator via tool electrodes though the borehole fluid into the formation and detected at the surface by a remote reference electrode. Because the rock fabric (i.e., minerals plus cement) is non-conductive, the ability to transmit an electric current is dependent up the formation fluid within the pores and capillaries (Video 23). Figure 189 and 190 show the resistivity profile for water-bearing and hydrocarbon-bearing formations, respectively. Note also the resistivity profiles for freshwater- or saltwater-based mud differ depending. Hydrocarbons are non-conductive (i.e., high resistivity) and saltwater is conductive. Therefore, in a water-bearing zone, where Rmf ~ Rw the resistivity response will be similar throughout each zone. In a hydrocarbon-bearing zone, where Rmf > Rw, Rt should increase.

Figure 190. A resistivity profile for transition-style invasion within a hydrocarbon-bearing formation (from Asquith and Krygowski, 2004).

Figure 189. A resistivity profile for transition-style invasion within a water-bearing formation (from Asquith and Krygowski, 2004).

Video 23. A resistivity log response, from 揟 he Making ofOil? (? 1997b Schlumberger, Ltd. used with permission).



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There are three basic types of resistivity tool currently in use:

induction

laterlog

microresitivity

InductionThis tool consists of one, or more, transmitting coils that emit high frequency AC creating a magnetic field within the formation, which in turn induces currents that are detected by the receiver. This tool enables the determination of resistivity without the requirement for a direct electrical connection between tool and formation and can, therefore, work with non-conductive drilling fluids (Alberty, 1992). The received signals are proportional to the conductivity within a given zone. Focusing coils within the tool minimize erroneous signals from the invaded zone, borehole and adjacent beds, thereby allowing the derivation of the resistivity of the uninvaded zone (Rt). Also the tool allows for differing degrees of vertical resolution and depth of investigation. The induction tool is better applied where resistivities are lower, rather than higher since it is a conductivity device. Induction devices have evolved since their inception, from a single induction measurement run in combination with the older short-normal measurement, to the dual induction and more recently the newer array tools. The new array tools have more receivers and use computer algorithms to improve signal response.

Induction electric log This was a single induction device run in combination with the short-normal measurement. The induction log was a single deep induction measurement (RIL) with a short normal measurement (RSN). Because the short-normal can measure the resistivity of the invaded zone it remains in service (Asquith and Krygowski, 2004).

Short-normal resistivity

This tool measures the resistivity within the invaded zone (Ri). When the resistivity of the short normal log is compared to that of the induction log, for example, invasion is detected by the separation of the two curves. The presence of invasion is significant because it suggests the presence of a permeable formation. The short normal resistivity device has an electrode spacing of 16 inch (~40 cm), and has a resolution of 4 ft (1.2 m) or more. In contrast, the induction tool has a transmitter/receiver spacing of 40 inch (~100 cm) and can resolve a bed thickness of 5 ft (1.3 m). Salt-water-based muds do not provide a suitable environment where Rmf ~ Rw.

Dual induction focused log This is the modern induction tool, capable of deep- (RILD), medium- (RILD) for Ri, and shallow-reading (Rxo). The three resistivity curves on the dual induction focused log are recorded on a four-cycle log scale (e.g., 0 to 2000 ohm/meters) and correspond to tracks 2 and 3. If it is suspected that deep invasion of the formation has occurred by the mud filtrate, by using the data from all three readings in conjunction with a tornado chart (Figure 191 and covered later) a true value for Rt can be derived (Asquith and Krygowski, 2004).

Induction tools may be run in air, oil, or foam filled boreholes since the induction system does not require the transmittance of electricity through the drilling fluid. Induction tools should be used in non-salt-saturated mud where Rmf > 3 Rw to obtain a more accurate value of true resistivity (Rt). Boreholes filled with a salt-saturated drilling mud (Rmf ~ Rw) require electric logs (e.g., Laterlog, or Dual Laterlog). The resolution of deep, medium, and shallow dual laterlog devices is 7 ft, 5 ft and 2.5 ft (1.8 m, 1.3 m and 0.6 m) respectively (Alberty, 1992).

Bed boundaries

Bed boundaries on a conductivity response occur half-way between the highest and lowest reading. For thin beds, the peak value represents the bed value. For thick beds with variable values, they are sometimes averaged. The short normal is another basic geological correlation tool and bed boundary are derived using the inflection point plus half the electrode spacing (8 inch or 20 cm)

Figure 191. Example Tornado chart (image ? 2005 Schlumberger, Ltd. used with permission).



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Figure 193. Pad configuration for a microresistivity tool showing current flow for: (a) microlog and (b) spherically focused log (from Asquith and Krygowski, 2004).

LaterlogsThis logging device requires electrical contact with the borehole wall, which is achieved via the drilling fluid within the annulus (Alberty, 1992). Laterlogs are therefore suited to water-based mud (i.e., not oil invert mud), and designed to measure true formation resistivity (Rt) where Rmf ~ Rw. The laterlog tool should not be run with fresh-water mud where Rmf > 3 Rw (Asquith and Krygowski, 2004). Focusing is achieved by location of electrodes along the device and, therefore, laterlogs are associated with good vertical resolution (e.g., 60 cm) with a radius of penetration of 0.5 m; although depth of penetration can be dependent upon the state of the filtercake and depth of invasion. Invasion effects are corrected using a 憈ornado chart? (Figure 191), discussed later in the section Introduction to log interpretation.

Dual Laterlog The dual laterlog replaces the single laterlog device and consists of deep- (RLLD) and shallow-reading (RLLS) measurements. The log contains both curves in tracks 2 and 3, and gamma-ray in track 1. The microspherically focused device (MSFL) has electrodes within a pad that are forced against the borehole wall, thereby providing a very shallow reading of Rxo. When a dual laterlog-microspherically focused log combination is run, it is possible to correct for formation invasion using a tornado chart and derive Rt (Alberty, 1992; Asquith and Krygowski, 2004). The vertical resolution of deep, medium, and shallow laterlogs is 2 ft, 2 ft and 2 to 4 inches (60, 60 and 5 to 10 cm), respectively and the radius of investigation is 45, 16, and 1 to 2 inches (1153, 410, and 2.5 to 5 cm), respectively (Alberty, 1992).

Laterlog array This device delivers five independent, focused, higher resolution and depth matched measurements (Figure 192). The intention of this device is to better account for borehole effects, invasion and problems that arise from using laterlog and dual laterlog devices in thin beds (i.e., shoulder-bed effects).

MicroresistivityMicroresitivity devices are also of the pad-type (Figure 193) and therefore used specifically to estimate the resistivity of the flushed zone (i.e., Rxo), minimizing the effects of irregularities in borehole shape (Asquith, 1982; Asquith and Krygowski, 2004). When run with a deep penetrating tool, the influence of the flushed zone can be removed from readings of the deep device and a better understanding of Rt derived. This device, like most logging devices, combines resistivity and gamma ray determinations.

MicrologThis pad-based device detects the presence of mudcake. By inference the presence of significant mudcake indicates that invasion has occurred and also suggests the presence of a porous formation (Asquith, 1982). However, this device does not work well in saltwater drilling fluids where Rmf ~ Rw or gypsum-based drilling fluids (Asquith and Krygowski, 2004). Microlaterlog, Proximity logs, and spherically focused logs are also derived from pad type logging devices. The typical vertical resolution of microresistivity devices is 2 to 3 inches (5 to 7.5 cm) with a radius of investigation of between 1 and 4 inches (1 to 10 cm) (Alberty, 1992).

Figure 192. The focusing pattern for a laterlog array device, Mode 0 measures mud resistivity. Modes 1 to 5 measure formation resistivities at different depths from the borehole. The red lines are the measure currents, and the white lines are the focusing currents (image ? 2005 Schlumberger, Ltd. used with permission).



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Porosity and lithology logs

The three types of porosity log include:

Sonic logs

Density logs

Neutron logs

Sonic logs This is an open hole, borehole compensated, porosity log that measures the interval transit time ( t) of a compressional sound wave through the formation. The interval transit time ( t) is the reciprocal of matrix velocity and is therefore expressed in microseconds per unit distance. The acoustic 慶licks? emitted from the transmitter travel faster through formation than through the drilling fluid and are picked up by the receiver located on the same tool (Figure 194). Example values for t are (Wyllie et al.,1958):

Because interval transit time is dependent upon rock type and rock density (i.e., mineral density and cement), and also by the fluid within the pores, it can, therefore, be related to formation porosity. Sonic logs (like all logs) are best used in conjunction with other logs (e.g., density, SP, resistivity). Sonic logs also work best in consolidated and compact formations. There are two types of sonic devices: the compensated compression wave sonic device and the full waveform sonic (FWS) device. The FWS device contains an array of receivers designed to detect shear velocities, this log is used by log analysts to determine the mechanical properties of the lithologies of interest. Sonic devices have a vertical resolution of 2 ft (~0.5 m) with a radius of investigation of 6 in. (~12 cm) (Alberty, 1992). For an excellent overview of the sonic log and the application of correction factors see Asquith and Krygowski (2004).

Formation density log The formation density tool is another 憄ad-type? device that measures the electron density of a formation. This tool consists of source (Cobalt-60 or Cesium-137) that emits medium-energy gamma rays into the formation. The gamma rays collide with electrons in the formation and lose energy and/or are scattered; redirected as a photon of reduced energy (i.e., Compton scatter), scattered energy is detected by the device. Compton scatter is a direct function of the number of electrons present within a formation (electron density) and, therefore related to bulk density (Kg/m3 or g/cc) (Alberty, 1992).

This device is used to: determine formation porosities when lithology is known, determine lithology in conjunction with other logs, detect gas-bearing zones, and identify uncommon minerals in evaporite beds. Bulk density (pb) values for common reservoir minerals (with zero porosity) are:

Compensated neutronThis is a neutron-emitting pad-type device. The neutrons are created from a chemical source within the sonde, which may be a mixture of americium and beryllium. This device responds to the hydrogen (H) ion concentration of a given formation as an amount of hydrogen per unit volume of formation. The emitted neutrons collide with H ion nuclei, pass into a thermal state, and undergo capture by a nucleus with the subsequent emission of gamma rays, which are in turn

Figure 194. A logging truck and sonic tool.

Mineral Actual density: p (Kg m3) Detected density: pb (Kg m3)

Dolomite 2870 2876

Calcite 2710 2710

Quartz 2648 2648

Anhydrite 2960 2977

Lithology sec/m sec/ft

Dolomite 143 43

Limestone 156 47.6

Sandstone 182-168 55-51

Anhydrite 164 50



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detected by the device. In a clean, shale-free, sandy formation filled with water or oil, the neutron device measures only liquid-filled porosity. Neutron porosity values will be lower in gas filled pores than in pores filled with either oil or water, this creates the so-called gas effect(Asquith, 1982). Neutron logs are also used to detect the presence of coal. Most neutron log curves are reported in either limestone or sandstone porosity units, whereas older logs may be reported in API units. This tool can be run in cased hole, however this device is very sensitive to hole rugosity (Alberty, 1992) and borehole size (corrected by caliper). Neutron log responses can also vary depending upon changes in lithology, mudcake thickness and formation fluid characteristics (filtrate/formation fluid).

Auxiliary devices

Caliper tools This device is specifically designed to ascertain changes in borehole diameter and, to some extent, geometry. Caliper tools are extensible devices that have one, two, three, four, or six arms (Figure 195). Some caliper devices are cleverly arranged so as to ascertain two different measurements simultaneously; for example density log and caliper, where the tool ensures a good borehole wall contact for the emission of lower energy gamma rays and determines hole diameter. The extensible arms are spring-loaded, which are only extended during the retraction of the tool, and changes in hole rugosity are determined by a combination of extension and compression of the arms. Caliper logs are invaluable for assessing hole dimension, which is required for calculating cement volumes following the running of casing.

Formation tester/reservoir characterization instrument These devices are designed to measure the formation pressure, without having to resort to the expense of a full drill-stem test (DST). Because this is a wireline device several sequential tests can be conducted, in open hole, during a single tool run (Smolen, 1992). Formation testers permit variations in pressure among various formations to be determined. Formation testers are specifically useful in measuring reservoir pressures, information that can be used to determine the existence of reservoir compartmentalization (Video 24). An important feature of the formation tester is the ability to obtain an actual fluid sample, via a chamber that has a capacity of 40 liters in the larger tools (Smolen, 1992).

Dipmeter This pad-type device is specifically designed to determine the angle of formation dip and provide the nature and orientation of planar surfaces, such as faults and bedding planes (Goetz, 1992). Dipmeters (Figure 196) are comprised of three or more extensible arms, each bearing an identical sensor. A bedding plane or fault crossing the borehole at an angle would generate measurable anomalies at each sensor, which would register against differences in depth (Figures 197, 198). The usual measurement is microresistivity (Goetz, 1992). The true orientation of the device is achieved through the use of three orthogonally mounted magnetometers and accelerometers.

Several properties can be derived from a dipmeter determination, such as the orientation of subsurface bedding, lamination thickness and regularity, layering contrast and continuity, and the presence of flaser and load structures. Most data, once processed by the engineer, is presented as either an arrow or tad-pole plot (Figure 198). The position of the 慴ody? against a vertical scale indicates dip, whereas the orientation of the tail indicates the direction of strike (Goetz, 1992).

Figure 195. Four-arm caliper tool.

Video 24. Animation showing a repeat formation tester, from 揟 he Making of Oil? (? 1997b Schlumberger, Ltd. used with permission).



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Borehole imaging devices

The televiewer The televiewer is an acoustic reflection device that uses a rotating ultrasonic transducer as the imaging unit. High frequency waves, ranging from 200 kHz to 1 MHz, are bounced off the borehole wall, detected by the device and relayed to a surface computer (Luthi, 1992). The transducer(s) can be deployed as 慺ocused?or 憉nfocused? and rotate at between 3 to 16 rotations per second. True orientation of the device (i.e., a constant reference) is obtained by use of a magnetometer. The televiewer can provide two basic types of log; one that is based upon reflected wave amplitude, and a second that is based upon two-way travel time. Images derived from a televiewer (Figure 199)

Figure 197. A six-arm, dipmeter log (from Goetz, 1992).

Figure 196. A four-arm dipmeter tool showing relevant orientation measurements (from Goetz, 1992).

Figure 198. Dip data on an arrow plot (left) and the corresponding structure shown as a sketch section (from Goetz, 1992).

Figure 199. Borehole televiewer images showing (a) a fracture (arrow) and (b) drill marks (arrow) (from Luthi, 1992).

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Figure 199. Borehole televiewer images showing (a) a fracture (arrow) and (b) drill marks (arrow) (from Luthi, 1992).



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are typically in gray scale; darker tones of gray representing lower reflected amplitudes (i.e., density) and higher two-way travel times (i.e., distance). The televiewer is essentially a device that provides a continuous 360o surface measurement of the borehole wall, and provides information on the presence of lithologic fractures (Figure 199a), borehole geometry, and bedding planes. However, artifacts such as drill marks (Figure 199b), and hole rugosity can effect performance. The two-way travel times provide a measure of borehole dimension, useful for wellbore volume calculations (Luthi, 1992).

Depiction of borehole images Before progressing much further, it is worth considering what the image in Figure 199 represents and the orientation of that feature in the subsurface! Does the fracture represent a planar surface or a tightly folded surface? A study of Figure 200 will help! Images derived from imaging devices (e.g., televiewer and formation microscanners) are unfurled 360o depictions of the inside of the borehole and orientated according to azimuth. Unfurled images typically contain azimuthal data (Figures 199b, 200). A planar feature (e.g., fracture, fault) therefore, would have a sigmoidal appearance; the angle of dip derived by the amplitude and orientation by noting the bearing associated with the features of interest or the maxima and minima of a curved surface (Serra, 1984; Serra, 1989; Dueck and Paauwe, 1994; Hurley, 2004).

Electrical borehole scanning

Formation Microscanner®

(FMS) and

Fullbore Formation MicroImager®

(FMI) are trade names for electrical borehole imaging devices and represent a development of the dipmeter and microresistivity device previously discussed. Electrical borehole imaging devices typically have four or more extensible arms that have an array of electrodes; there are 64 electrodes on the FMS tool and 191 on the FMI tool; each electrode is 0.2-in. diameter, and individually monitored. As either tool is tracked up the borehole, the amount of current emitted from each electrode is recorded as a function of azimuth and depth. Each array, therefore, produces a microresistivity 慽mage? of the borehole wall (Video 25). Earlier devices had two to four pads, and provided a discontinuous unfurled image (Figure 200). More recent tools, however, have more pads and even additional 慺lip-out?pads that provide a full 360o coverage, for a given nominal borehole size (Luthi, 1992). Early FMS images were gray scale in which the darker tones represented lower resistivities. However, the current trend is towards color enhanced images, with the most conductive events identified as black and the most resistive as lighter colors (Figures 202, 203).

Like the acoustical televiewer device, the electrical borehole-imaging device is also subject to minor problems, such as pad 憇tand-off? (due to mudcake) and is sensitive to minor changes in tool speed (Luthi, 1992). However, that said, this electrical device has been capable of not only imaging fractures and bedding planes, but, because of the fine spacing of the electrodes it has been capable of detecting unconformities, the presence of stylolites, cross-bedding, erosional surfaces, and finely intercalated formations (Figures 201 and 202).

Using such a device to recognizing specific sedimentological features, subtle plays such as the Middle Devonian channel sands have been followed and successfully exploited within the Mitsu field of Alberta, Canada (Dueck and Paauwe, 1994), a play that would have otherwise proven difficult.

Video 25. An electrical borehole scanning device, from 揟 he Making of Oil? (? 1997b Schlumberger, Ltd. used with permission).

Figure 200. The depiction and orientation of borehole images(after Serra, 1984; Serra, 1989; Dueck and Paauwe, 1994;Hurley, 2004; and others).



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Nuclear magnetic resonance logging

BackgroundThe nuclear magnetic resonance (NMR) device is relatively new and provides a lithology-independent measure of effective porosity, total porosity, and differentiates between irreducible and moveable (i.e., 慺ree? water (Stambaugh, 2000).

Formation fluids contain differing amounts of hydrogen that varies with composition (e.g., oil versus water) and physical state (i.e., gas and fluid). All hydrogen nuclei are spin, although in the natural state the spin orientation is random and the net magnetization is zero. However, when a strong external magnetic field (from the NMR device) passes through the formation, the protons are aligned or polarized. The state of polarization increases exponentially in time (Freedman, 2006). An antenna in the NMR device emits a pulsating radio frequency that induces a magnetic field causing the spin-axes to tip away from the original (i.e., polarized) alignment. When the antenna is turned off and the magnetic pulse is removed, the resonance relaxes and the signal decays (Henderson, 2004), producing a signal called the spin echo. Repeated pulses create a spin echo train which is used to interpret fluid and formation properties. The polarization time is known as Tp and the time constant used to characterize the magnetization buildup is known as T1, whereas T2

represents the transverse decay time, commonly known as relaxation time (Henderson, 2004; Freedman, 2006).

For a given fluid type, T2 has been shown to be proportional to pore size, in which micropores are associated with the fastest relation times compared to free fluids and fluids within larger pores (Stambaugh, 2000; Henderson, 2004); in this way NMR logs can be used to differentiate between irreducible and free-water (Figure 203).

Figure 201. An example FMI log used to track channel sands in the Mitsue Field, Alberta, Canada (image courtesy of Glen Isle Exploration Ltd. and by authority of the

Figure 202. FMI images showing different sedimentological structures: top left shows a collapse breccia, top right vuggy limestone, lower left shows slumped sandstone and lower right shows a turbidite deposit (image ? 2005 Schlumberger, Ltd. used with permission).

Figure 203. Hypothetical T2 distribution, showing partitioning of the T2 distribution into irreducible and free water using empirically determined cutoffs. For sandstone 慉? is 33 ms, whereas the cutoff for limestone is 100 ms (after Schlumberger; Halliburton; Freedman, 2006; and others).

Figure 201. An example FMI log used to track channel sands in the Mitsue Field, Alberta, Canada (image courtesy of Glen Isle Exploration Ltd. and by authority of the Canadian Society of Petroleum Geologists).



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ApplicationReservoir fluids possess different polarization times (T1) and relaxation times (T2). In this way NMR logs can be used to characterize and differentiate between formation fluids (e.g., oil/water), and for a given formation fluid (i.e., water) determine the presence of clay-bound, capillary-bound, and free water. More recently, NMR logs have been used to provide estimates of pore-size distribution, grain size (clastic reservoir) and estimates of permeability (Henderson, 2004; Freedman 2006).

Sidewall coring devices A sidewall coring device allows small (e.g., 3 5 cm) solid plugs of selected lithologies to be obtained from pre-determined depths, without the high cost of traditional coring. The sidewall device may be capable of obtaining more than two dozen sequential core plugs in a single tool-run. The location of each core plug is pre-selected and recorded. This device represents and excellent option for the visual confirmation of lithologies, the determination of laboratory porosity and permeability measurements, or scanning electron microscope analysis, etc., on actual rock material.

Cased hole tools

There are many good reasons why it might be necessary to run logs in cased hole, for example; the need to check the integrity of cement through casing, the existence of an unstable or overpressured formation, or perhaps there were changes in formation property since the casing or liner was set. However, not all tools can be run in cased hole. Devices that can be run inside casing, include the gamma ray (and spectra log) and various neutron devices. These devices have been discussed. However, one tool that is gaining popularity is the pulsed neutron tool. As the name implies, pulses of high-energy neutrons are emitted from a source within the tool, pass through the casing and bombard the formation. When the neutrons are captured within the formation, gamma rays are emitted, which are, in turn, detected by the tool (a gamma-ray spectrometer). The prime use for this tool is the derivation of the distribution of the elements carbon and oxygen by bombardment neutrons of specific energy

Logging tool suitability

Logging tools are designed to be run for only a limited range of borehole size and condition, either because of the diameter of the tool (minimum borehole size), or because of the limitations of the extensible arms (max. size). Not only that, but some tools are not suited in some invert mud systems, also some tool combinations do not work well. Table 11 is quick-check tool table (Alberty, 1992).

Table 11. A tool reference table: where ? ?favorable, ? ?marginal and ? ?unfavorable (from Alberty, 1992).



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Introduction to log interpretation

Example use of charts and nomograms

Formation temperature (Tf )Temperature increases with increasing depth. The resistivity of a fluid (i.e., formation waters) decreases with increasing salinity and increasing temperature and therefore, corrections must be applied. Schlumberger Gen-6 chart (Figure 204) will be used in this worked example.

Please refer to Figure 204. Temperature scales are along the bottom and the top of the chart, representing measured bottom hole temperatures for mean surface temperatures in either Fahrenheit or Celsius respectively. The oblique blue lines running diagonally across the chart are geothermal gradients (assumed to be linear). Depth is on the ordinate.

Example Total depth 5,175m (~15,000 ft), mean surface temperature is 16 oC (80 oF), the bottom hole temperature is 98 oC(~200 oF), and the depth of interest is 3,050 m (~10,000 ft).

Locate the respective temperature scale of interest (i.e., either Fahrenheit or Celsius indicated by a short red arrow). Locate the bottom hole temperature in either Celsius of Fahrenheit (circled in red). Locate the total depth. Descend (Celsius) or ascend (Fahrenheit) along the appropriate (solid green) line to the line representing the total depth value, selecting the (diagonal) geothermal gradient that bisects that point. The indicated geothermal gradient in this example is 1.82 oC/100 m (1.0 oF/100 ft).

Ascend along that gradient to 3,050 m (~10,000 ft) and ascend or descend vertically intercepting the corrected temperature (Tf) of 75 oC or 175 oF representing the formation temperature at 3,050 m (~10,000 ft) respectively.

Figure 204. Chart for estimating geothermal gradient and formation temperature (image ? 1997a Schlumberger, Ltd. used with permission).



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Temperature correction for resistivity The resistivity of a fluid (i.e., brine) measured at the earth抯 surface is different to that measured at depth, and since resistivity changes with temperature, therefore a correction must be applied to derive an accurate value for Rm at a specific depth of interest. It is assumed that when the temperature of a solution is increased the salinity stays constant. We will use the Schlumberger chart GEN-9 to correct Rm (Figure 205).

Example: Resistivity of drilling fluid is 0.06 ohm-m at 139 oF.

What is Rm at 179 oF? Using GEN-9 (Figure 205), locate 0.06 ohm-m at 139 oF on the vertical and horizontal axes respectively. Draw a vertical line connecting the two values (i.e., 0.06 ohm-m at 139 oF), from the horizontal axis (i.e., arrow 慳? . The intercept of 0.06 ohm-m at 139 oF is on the salinity line of 60,000 ppm (dark blue line). Descend diagonally (arrow 慴? to a new intercept of 179 oF along that line and read off the new value for Rm along the vertical axis (i.e., arrow 慶? , which is 0.048 ohm-m.

Figure 205. Resistivity/temperature correction chart, Gen-9 (after Schlumberger; image ? 1997a Schlumberger, Ltd. used with permission).



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Invasion correction charts (tornado diagrams) Invasion correction charts are used to determine the depth of invasion (di), the Rxo/Rt ratio, and the true resistivity of the formation Rt(cor.). It is assumed that the contact between the invaded zone and uninvaded zone is sharp, and resistivity measurements have been corrected (Asquith, 1982). To use this diagram, enter the abscissa and ordinate with the required resistivity ratios; the point of intersection defines the depth of invasion di, the Rt/Rxo ratio, and Rt.

Example Given data: depth 2615 m (8580 ft), borehole diameter is 203 mm (8 inch), filled with a salt mud system. Data from a Laterlog: LLLD = 35 ohm-m, LLLS = 15 ohm-m, Rxo (from MSFL) = 4 ohm-m.To derive Rt(cor.) we use a tornado diagram specific to the diameter of the borehole and drilling fluid type (e.g., salt mud system). In this example we will use the Schlumberger Chart Rint-9 (Figure 206). You may wish to compile a data table like this, either hand calculating various ratios or use the math function in a spreadsheet (suggested method).

Calculate values (RLLD/RLLS) and (RLLD/RXO), use those calculated values to determine Rt/RLLD from the tornado chart (i.e., the red solid lines, ~1.39), Rt/Rxo using the solid blue lines (~12.5), and di using the dashed blue lines (~50 in. or 1.27 m). Use Rt(cor.) and Rxo to calculate Rxo (cor.).

Figure 206. A tornado diagram for determining depth of invasion and correcting Rt and Rxo (after Schlumberger; image ? 1997a Schlumberger, Ltd. used with permission).



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M-N plots for lithologyThe estimation of lithology using the M-N plot necessitates obtaining data from the Neutron and Sonic logs, and calculating coordinates for the relevant M-N* cross plot (Figure 209) which contains lithology specific regions . Data points that plot away from those regions are indicative of either a mixed lithology or porosity infilling. All data points are plotted directly on the M-N* plot! The values for M and N are calculated using the following:

where: tf = transit time for drilling fluid t = interval transit time (value from log)

pb = interval bulk density (from log) pf = bulk density for drilling fluid

Nf = neutron density for drilling fluid N = interval neutron density (value from log)

Example: Given data: tf is 185 (value for salt mud), pf is 1.1 gm/cc, Nf is 1.1 (value for salt mud), t is 60, N is .16, and pb is 2.70 g/cc, depth 9210

Using the given values for N, t, and pb, calculate the values for M and N. Apply your calculated M ? N values directly on the cross plot (Figure 207). Your values should indicate a dolomite with an anhydrite infilling.

Figure 207. Chart for estimating lithology, M-N plot (image ?1997a Schlumberger, Ltd. used with permission).

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PorosityMany would agree that the most reliable determination of porosity involve combinations of two or three different measurements. Cross plots are graphical solutions using two or three parameters to estimate formation lithology and porosity. The specific choice of cross plot depends upon the salinity of the drilling fluid (i.e., fresh/salt), the type and age of the logging device, and the terms used for apparent limestone porosity (e.g., NPHI or TPHI). The example given here uses data derived from the Combination Neutron-Density log (Figure 208).

Example:

Give data: given values for CNL is 23pu (apparent limestone porosity), bulk density (Pb) is 2.42 g/cc or Mg m3.Using a fresh-water based mud system where Pf =1.0 gm/cc, refer to Figure 210 (Schlumberger CP-1c). Use the given values to determine the point of intersection, at the point intersection read the lithology (mineralogy) and porosity ( )for that depth.

Figure 208. Chart for estimating lithology (mineralogy) and porosity (image ?1997a Schlumberger, Ltd. used with permission).



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Water resistivity (Rw) and water saturation (Sw)There are a number of methods to derive Rw (Asquith and Krygowski, 2004), although only the Archie equation will be discussed here.

Archie method for Rw

Archie demonstrated (Archie, 1942) that the resistivity of a given water-filled formation (Ro) can be related to the resistivity of the formation fluid by using a constant (F), which he termed the formation resistivity factor (ibid).

Ro = F Rw (18)

If using the Archie method, the zone chosen should be 100% water saturated, contain no clay, free from shoulder effects, and must have a porosity log available (Peveraro, 1992). Archie showed that the formation resistivity factor (F)was related to porosity ( ):

(19)

Where: = porosity

a = tortuosity factor

m = cementation exponent

Because m and a are interdependent upon each other, i.e., as a increases so typically does m (Asquith and Krygowski, 2004). The Archie equation can be reduced to (Peveraro, 1992):

Rw = Rt (20)

Water Saturation SwWater saturation probably represents the most fundamental parameter used in log evaluation. As discussed in previous chapters, water volume greatly affects the economics of a given reservoir. Sw can be calculated from Ro (i.e., wet resistivity of the formation) and Rt (the resistivity of the uninvaded zone) (Archie, 1942; Asquith and Krygowski, 2004).

where: Sw = water saturation

Rw = resistivity of the formation fluid (water)

Rt = true resistivity of the formation

n = saturation exponent (normally 2.0)

The Archie equation has been modified, often because of a, m, and n. Because the tortuosity factor a, saturation exponent n, and the cementation exponent m vary with lithology, age, and degree of compaction. They have, therefore, been empirically summed by a number of workers into a series of Formation Factors (F).

For example: for carbonates F = 1/ 2

for consolidated sandstones F = 0.81/ 2

for sands (i.e., unconsolidated) F = 0.65/ 2.15

Combining equations 18 and 21 gives the common form of the Archie equation for water saturation Sw

where: Sw = water saturation

Rw = resistivity of the formation fluid (water)

Rt = true resistivity of the formation

F = Formation factor

n = saturation exponent (normally 2.0)

(21)

(22)


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144

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