********************REFINING PETROLEUM******************

REFINING OF PETROLEUM

Petroleum is a complex mixture of organic liquids called crude oil and natural gas, which occurs naturally in the ground and was formed millions of years ago. Crude oil varies from oilfield to oilfield in colour and composition, from a pale yellow low viscosity liquid to heavy black 'treacle' consistencies.

Crude oil and natural gas are extracted from the ground, on land or under the oceans, by sinking an oil well and are then transported by pipeline and/or ship to refineries where their components are processed into refined products. Crude oil and natural gas are of little use in their raw state; their value lies in what is created from them: fuels, lubricating oils, waxes, asphalt, petrochemicals and pipeline quality natural gas.

An oil refinery is an organised and coordinated arrangement of manufacturing processes designed to produce physical and chemical changes in crude oil to convert it into everyday products like petrol, diesel, lubricating oil, fuel oil and bitumen.

As crude oil comes from the well it contains a mixture of hydrocarbon compounds and relatively small quantities of other materials such as oxygen, nitrogen, sulphur, salt and water. In the refinery, most of these non - hydrocarbon substances are removed and the oil is broken down into its various components, and blended into useful products.

Natural gas from the well, while principally methane, contains quantities of other hydrocarbons - ethane, propane, butane, pentane and also carbon dioxide and water. These components are separated from the methane at a gas fractionation plant.

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Petroleum hydrocarbon structures

Petroleum consists of three main hydrocarbon groups:

Paraffins

These consist of straight or branched carbon rings saturated with hydrogen atoms, the simplest of which is methane (CH4) the main ingredient of natural gas. Others in this group include ethane (C2H6), and propane (C3H8).

Hydrocarbons

With very few carbon atoms (C1 to C4) are light in density and are gases under normal atmospheric pressure. Chemically paraffins are very stable compounds.

Naphthenes

Naphthenes consist of carbon rings, sometimes with side chains, saturated with hydrogen atoms. Naphthenes are chemically stable, they occur naturally in crude oil and have properties similar to paraffins.

Aromatics

aromatic hydrocarbons are compounds that contain a ring of six carbon atoms with alternating double and single bonds and six attached hydrogen atoms. This type of structure is known as a benzene ring. They occur naturally in crude oil, and can also be created by the refining process.

The more carbon atoms a hydrocarbon molecule has, the "heavier" it is (the higher is its molecular weight) and the higher is its the boiling point.

Small quantities of a crude oil may be composed of compounds containing oxygen, nitrogen, sulphur and metals. Sulphur content ranges from traces to more than 5 per cent. If a crude oil contains appreciable quantities of sulphur it is called a sour crude; if it contains little or no sulphur it is called a sweet crude.

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The refining process

Every refinery begins with the separation of crude oil into different fractions by distillation.

The fractions are further treated to convert them into mixtures of more useful saleable products by various methods such as cracking, reforming, alkylation, polymerisation and isomerisation. These mixtures of new compounds are then separated using methods such as fractionation and solvent extraction. Impurities are removed by various methods, e.g. dehydration, desalting, sulphur removal and hydrotreating.

Refinery processes have developed in response to changing market demands for certain products. With the advent of the internal combustion engine the main task of refineries became the production of petrol. The quantities of petrol available from distillation alone was insufficient to satisfy consumer demand. Refineries began to look for ways to produce more and better quality petrol. Two types of processes have been developed:

breaking down large, heavy hydrocarbon molecules reshaping or rebuilding hydrocarbon molecules.

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Distillation (Fractionation)

Because crude oil is a mixture of hydrocarbons with different boiling temperatures, it can be separated by distillation into groups of hydrocarbons that boil between two specified boiling points. Two types of distillation are performed: atmospheric and vacuum.

Atmospheric distillation takes place in a distilling column at or near atmospheric pressure. The crude oil is heated to 350 - 400oC and the vapour and liquid are piped into the distilling column. The liquid falls to the bottom and the vapour rises, passing through a series of perforated trays (sieve trays). Heavier hydrocarbons condense more quickly and settle on lower trays and lighter hydrocarbons remain as a vapour longer and condense on higher trays.

Liquid fractions are drawn from the trays and removed. In this way the light gases, methane, ethane, propane and butane pass out the top of the column, petrol is formed in the top trays, kerosene and gas oils in the middle, and fuel oils at the bottom. Residue drawn of the bottom may be burned as fuel, processed into lubricating oils, waxes and bitumen or used as feedstock for cracking units.

To recover additional heavy distillates from this residue, it may be piped to a second distillation column where the process is repeated under vacuum, called vacuum distillation. This allows heavy hydrocarbons with boiling points of 450oC and higher to be separated without them partly cracking into unwanted products such as coke and gas.

The heavy distillates recovered by vacuum distillation can be converted into lubricating oils by a variety of processes. The most common of these is called solvent extraction. In one version of this process the heavy distillate is washed with a liquid which does not dissolve in it but which dissolves (and so extracts) the non-lubricating oil components out of it. Another version uses a liquid which does not dissolve in it but which causes the non-lubricating oil components to precipitate (as an extract) from it. Other processes exist which remove impurities by adsorption onto a highly porous solid or which remove any waxes that may be present by causing them to crystallise and precipitate out.

Reforming

Reforming is a process which uses heat, pressure and a catalyst (usually containing platinum) to bring about chemical reactions which upgrade naphthas into high octane petrol and petrochemical feedstock. The naphthas are hydrocarbon mixtures containing many paraffins and naphthenes. In Australia, this naphtha feedstock comes from the crudes oil distillation or catalytic cracking processes, but overseas it also comes from thermal cracking and hydrocracking processes. Reforming converts a portion of these compounds to isoparaffins and aromatics, which are used to blend higher octane petrol.

paraffins are converted to isoparaffins paraffins are converted to naphthenes

naphthenes are converted to aromatics

e.g.

catalystheptane -> toluene + hydrogen

C7H16 -> C7H8 + 4H2 catalyst

cyclohexane -> benzene + hydrogen C6H12 -> C6H6 + 3H2

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Cracking

Cracking processes break down heavier hydrocarbon molecules (high boiling point oils) into lighter products such as petrol and diesel. These processes include catalytic cracking, thermal cracking and hydrocracking.

e.g.

A typical reaction:

catalystC16H34 -> C8H18 + C8H16

Catalytic cracking is used to convert heavy hydrocarbon fractions obtained by vacuum distillation into a mixture of more useful products such as petrol and light fuel oil. In this process, the feedstock undergoes a chemical breakdown, under controlled heat (450 - 500oC) and pressure, in the presence of a catalyst - a substance which promotes the reaction without itself being chemically changed. Small pellets of silica - alumina or silica - magnesia have proved to be the most effective catalysts.

The cracking reaction yields petrol, LPG, unsaturated olefin compounds, cracked gas oils, a liquid residue called cycle oil, light gases and a solid coke residue. Cycle oil is recycled to cause further breakdown and the coke, which forms a layer on the catalyst, is removed by burning. The other products are passed through a fractionator to be separated and separately processed.

Fluid catalytic cracking uses a catalyst in the form of a very fine powder which flows like a liquid when agitated by steam, air or vapour. Feedstock entering the process immediately meets a stream of very hot catalyst and vaporises. The resulting vapours keep the catalyst fluidised as it passes into the reactor, where the cracking takes place and where it is fluidised by the hydrocarbon vapour. The catalyst next passes to a steam stripping section where most of the volatile hydrocarbons are removed. It then passes to a regenerator vessel where it is fluidised by a mixture of air and the products of combustion which are produced as the coke on the catalyst is burnt off. The catalyst then flows back to the reactor. The catalyst thus undergoes a continuous circulation between the reactor, stripper and regenerator sections.

The catalyst is usually a mixture of aluminium oxide and silica. Most recently, the introduction of synthetic zeolite catalysts has allowed much shorter reaction times and improved yields and octane numbers of the cracked gasolines.

Thermal cracking uses heat to break down the residue from vacuum distillation. The lighter elements produced from this process can be made into distillate fuels and petrol. Cracked gases are converted to petrol blending components by alkylation or polymerisation. Naphtha is upgraded to high quality petrol by reforming. Gas oil can be used as diesel fuel or can be converted to petrol by hydrocracking. The heavy residue is converted into residual oil or coke which is used in the manufacture of electrodes, graphite and carbides.

This process is the oldest technology and is not used in Australia.

Hydrocracking can increase the yield of petrol components, as well as being used to produce light distillates. It produces no residues, only light oils. Hydrocracking is catalytic cracking in the presence of hydrogen. The extra hydrogen saturates, or hydrogenates, the chemical bonds of the cracked hydrocarbons and creates isomers with the desired characteristics. Hydrocracking is also a treating process, because the hydrogen combines with contaminants such as sulphur and nitrogen, allowing them to be removed.

Gas oil feed is mixed with hydrogen, heated, and sent to a reactor vessel with a fixed bed catalyst, where cracking and hydrogenation take place. Products are sent to a fractionator to be separated. The hydrogen is recycled. Residue from this reaction is mixed again with hydrogen, reheated, and sent to a second reactor for further cracking under higher temperatures and pressures.

In addition to cracked naphtha for making petrol, hydrocracking yields light gases useful for refinery fuel, or alkylation as well as components for high quality fuel oils, lube oils and petrochemical feedstocks.

Following the cracking processes it is necessary to build or rearrange some of the lighter hydrocarbon molecules into high quality petrol or jet fuel blending components or into petrochemicals. The former can be achieved by several chemical process such as alkylation and isomerisation.

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Alkylation

Olefins such as propylene and butylene are produced by catalytic and thermal cracking. Alkylation refers to the chemical bonding of these light molecules with isobutane to form larger branched-chain molecules (isoparaffins) that make high octane petrol.

Olefins and isobutane are mixed with an acid catalyst and cooled. They react to form alkylate, plus some normal butane, isobutane and propane. The resulting liquid is neutralised and separated in a series of distillation columns. Isobutane is recycled as feed and butane and propane sold as liquid petroleum gas (LPG).

e.g.

catalystisobutane + butylene -> isooctane

C4H10 + C4H8 -> C8H18

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Isomerisation

Isomerisation refers to chemical rearrangement of straight-chain hydrocarbons (paraffins), so that they contain branches attached to the main chain (isoparaffins). This is done for two reasons:

they create extra isobutane feed for alkylation they improve the octane of straight run pentanes and hexanes and hence make them into better petrol

blending components.

Isomerisation is achieved by mixing normal butane with a little hydrogen and chloride and allowed to react in the presence of a catalyst to form isobutane, plus a small amount of normal butane and some lighter gases. Products are separated in a fractionator. The lighter gases are used as refinery fuel and the butane recycled as feed.

Pentanes and hexanes are the lighter components of petrol. Isomerisation can be used to improve petrol quality by converting these hydrocarbons to higher octane isomers. The process is the same as for butane isomerisation.

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Polymerisation

Under pressure and temperature, over an acidic catalyst, light unsaturated hydrocarbon molecules react and combine with each other to form larger hydrocarbon molecules. Such process can be used to react butenes (olefin molecules with four carbon atoms) with iso-butane (branched paraffin molecules, or isoparaffins, with four carbon atoms) to obtain a high octane olefinic petrol blending component called polymer gasoline.

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Hydrotreating and sulphur plants

A number of contaminants are found in crude oil. As the fractions travel through the refinery processing units, these impurities can damage the equipment, the catalysts and the quality of the products. There are also legal limits on the contents of some impurities, like sulphur, in products.

Hydrotreating is one way of removing many of the contaminants from many of the intermediate or final products. In the hydrotreating process, the entering feedstock is mixed with hydrogen and heated to 300 - 380oC. The oil combined with the hydrogen then enters a reactor loaded with a catalyst which promotes several reactions:

hydrogen combines with sulphur to form hydrogen sulphide (H2S)

nitrogen compounds are converted to ammonia

any metals contained in the oil are deposited on the catalyst

some of the olefins, aromatics or naphthenes become saturated with hydrogen to become paraffins and some cracking takes place, causing the creation of some methane, ethane, propane and butanes.

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Sulphur recovery plants

The hydrogen sulphide created from hydrotreating is a toxic gas that needs further treatment. The usual process involves two steps:

the removal of the hydrogen sulphide gas from the hydrocarbon stream the conversion of hydrogen sulphide to elemental sulphur, a non-toxic and useful chemical.

Solvent extraction, using a solution of diethanolamine (DEA) dissolved in water, is applied to separate the hydrogen sulphide gas from the process stream. The hydrocarbon gas stream containing the hydrogen sulphide is bubbled through a solution of diethanolamine solution (DEA) under high pressure, such that the hydrogen sulphide gas dissolves in the DEA. The DEA and hydrogen mixture is the heated at a low pressure and the dissolved hydrogen sulphide is released as a concentrated gas stream which is sent to another plant for conversion into sulphur.

Conversion of the concentrated hydrogen sulphide gas into sulphur occurs in two stages.

1. Combustion of part of the H2S stream in a furnace, producing sulphur dioxide (SO2) water (H2O) and sulphur (S). 2H2S + 2O2 -> SO2 + S + 2H2O

2. Reaction of the remainder of the H2S with the combustion products in the presence of a catalyst. The H2S reacts with the SO2 to form sulphur.

2H2S + 2O2 -> 3S + 2H2O

As the reaction products are cooled the sulphur drops out of the reaction vessel in a molten state. Sulphur can be stored and shipped in either a molten or solid state.

Click here to view a flow chart of a refinery .

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Refineries and the environment

Air, water and land can all be affected by refinery operations. Refineries are well aware of their responsibility to the community and employ a variety of processes to safeguard the environment.

The processes described below are those used by the Shell refinery at Geelong in Victoria, but all refineries employ similar techniques in managing the environmental aspects of refining.

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Air

Preserving air quality around a refinery involves controlling the following emissions:

sulphur oxides hydrocarbon vapours

smoke

smells

Sulphur enters the refinery in crude oil feed. Gippsland and most other Australian crude oils have a low sulphur content but other crude's may contain up to 5 per cent sulphur. To deal with this refineries incorporate a sulphur recovery unit which operates on the principles described above.

Many of the products used in a refinery produce hydrocarbon vapours. The escape of vapours to atmosphere are prevented by various means. Floating roofs are installed in tanks to prevent evaporation and so that there is no space for vapour to gather in the tanks. Where floating roofs cannot be used, the vapours from the tanks are collected in a vapour recovery system and absorbed back into the product stream. In addition, pumps and valves are routinely checked for vapour emissions and repaired if a leakage is found.

Smoke is formed when the burning mixture contains insufficient oxygen or is not sufficiently mixed. Modern furnace control systems prevent this from happening during normal operation.

Smells are the most difficult emission to control and the easiest to detect. Refinery smells are generally associated with compounds containing sulphur, where even tiny losses are sufficient to cause a noticeable odour.

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Water

Aqueous effluent's consist of cooling water, surface water and process water.

The majority of the water discharged from the refinery has been used for cooling the various process streams. The cooling water does not actually come into contact with the process material and so has very little contamination. The cooling water passes through large "interceptors" which separate any oil from minute leaks etc., prior to discharge. The cooling water system at Geelong Refinery is a once-through system with no recirculation.

Rainwater falling on the refinery site must be treated before discharge to ensure no oily material washed off process equipment leaves the refinery. This is done first by passing the water through smaller "plant oil catchers", which each treat rainwater from separate areas on the site, and then all the streams pass to large "interceptors" similar to those used for cooling water. The rainwater from the production areas is further treated in a Dissolved Air Flotation (DAF) unit. This unit cleans the water by using a flocculation agent to collect any remaining particles or oil droplets and floating the resulting flock to the surface with millions of tiny air bubbles. At the surface the flock is skimmed off and the clean water discharged.

Process water has actually come into contact with the process streams and so can contain significant contamination. This water is treated in the "sour water treater" where the contaminants (mostly ammonia and hydrogen sulphide) are removed and then recovered or destroyed in a downstream plant. The process water, when treated in this way, can be reused in parts of the refinery and discharged through the process area rainwater treatment system and the DAF unit.

Any treated process water that is not reused is discharged as Trade Waste to the sewerage system. This trade waste also includes the effluent from the refinery sewage treatment plant and a portion of treated water from the DAF unit.

As most refineries import and export many feed materials and products by ship, the refinery and harbour authorities are prepared for spillage from the ship or pier. In the event of such a spill, equipment is always on standby at the refinery and it is supported by the facilities of the Australian Marine Oil Spill Centre at Geelong, Victoria.

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Land

The refinery safeguards the land environment by ensuring the appropriate disposal of all wastes.

Within the refinery, all hydrocarbon wastes are recycled through the refinery slops system. This system consists of a network of collection pipes and a series of dewatering tanks. The recovered hydrocarbon is reprocessed through the distillation units.

Wastes that cannot be reprocessed are either recycled to manufacturers (e.g. some spent catalysts can be reprocessed), disposed of in EPA-approved facilities off-site, or chemically treated on-site to form inert materials which can be disposed to land-fill within the refinery.

Waste movements within the refinery require a "Process liquid, Sludge and Solid waste disposal permit". Wastes that go off-site must have an EPA "Waste Transport Permit".

HOW IT WORKS

How Do FPSOs Work? Floating Production Storage and Offloading vessels, or FPSOs, are offshore production

facilities that house both processing equipment and storage for produced hydrocarbons. The basic design of most FPSOs encompasses a ship-shaped vessel, with processing equipment, or topsides, aboard the vessel's deck and hydrocarbon storage below in the double hull. After processing, an FPSO stores oil or gas before offloading periodically to shuttle tankers or transmitting processed

petroleum via pipelines.FPSOMoored in place by various mooring systems, FPSOs are effective development solutions for both deepwater and ultra-deepwater fields. A central mooring system allows the vessel to rotate freely to best respond to weather conditions, or weathervane, while spread-mooring systems anchor the vessel from various locations on the seafloor. Usually tied to multiple subsea wells, FPSOs gather hydrocarbons from subsea production wells through a series of in-field pipelines. Once tapped by subsea wells, hydrocarbons are transmitted through flowlines to risers, which transport the oil and gas from the seafloor to the vessel's turret and then to the FPSO on the water's surface.

FPSOThe processing equipment aboard the FPSO is similar to what would be found atop a production platform. Usually built in modules, FPSO production equipment can consist of water separation, gas treatment, oil processing, water injection and gas compression, among others. Hydrocarbons are then transferred to the vessel's double-hull for storage.Crude oil that is stored onboard is frequently transferred to shuttle tankers or ocean barges going ashore, via a loading hose. Loading oil from the stern of the FPSO to the bow of the shuttle tanker is known as tandem loading. While gas is many times transferred to shore via pipeline or re-injected into the field to boost production.FPSO CharacteristicsPermanently moored, FPSOs are viable development solutions for a number of different offshore field situations. Because FPSOs can be disconnected from their moorings, these offshore production vessels are optimal for areas that experience adverse weather conditions, such

as cyclones and hurricanes.FPSOAdditionally, because FPSOs can be moved, they are a more economical solution for more marginal fields, in that the vessel can be moved to another development and redeployed once the original field has been depleted. Also, FPSOs are an optimal choice for development when there are no existing pipelines or infrastructure to transfer production to shore. Adding to the economic advantages of FPSOs, existing tankers are frequently converted into FPSOs.Used in offshore production since the 1970s, FPSOs have been historically utilized in the North Sea, offshore Brazil, Asia Pacific, the Mediterranean Sea and offshore West Africa.Oil spills do not usually occur from FPSOs, although in the late 1990s the Texaco Captain FPSO spilled approximately 3,900 barrels of oil due to human error. Besides this incident, FPSOs have spilled less than approximately 500 barrels of oil combined. Besides FPSOs, similar floating systems include Floating Storage and Offloading systems (FSOs), Floating Production Systems (FPSs) and Floating Storage Units (FSUs). Additionally, the world's first FDPSO, or Floating Drilling Production Storage and Offloading vessel, was developed in 2009 for Murphy Oil's Azurite field offshore Republic of Congo. This Azurite FDPSO incorporates deepwater drilling equipment that will help to develop the field and can be removed and reused after all the Azurite production wells have been drilled. Furthermore, the world's first FLNG or

Floating Liquid Natural Gas vessel is currently being developed.How Do Spars Work?A floating platform alternative that can support drilling, production and storage operations, the spar consists of a large vertical cylinder bearing topsides with equipment. Similar to an iceberg, the majority of a spar facility is located beneath the water's surface, providing the facility

increased stability. Mad Dog SparOriginally designed as a floating buoy to acquire oceanographic information, the main component of a spar facility is the deep-draft floating chamber, or hollow cylindrical hull. Characteristically, the hull is encircled with spiraling strakes to add stability. Additionally, the bottom of the cylinder includes a ballasting section with material that weighs more than water, ensuring the center of gravity is located below the center of buoyancy.The deep-draft design makes the spar less affected by wind, wave and currents, enabling the facility to support both subsea and dry tree developments. Additionally, the enclosed cylinder acts as protection for risers and equipment, making spars an ideal choice for deepwater developments. Furthermore, the hull can provide

storage for produced oil or gas.

Neptune SparAtop the spar hull sits the topsides, which can be comprised of drilling equipment, production facilities and living quarters. Drilling is performed from the topsides through the hollow cylinder hull; and drilling, import/export and production risers are passed through the enclosed hull, as well. The whole spar facility is then moored to the seafloor.While the hull is fastened to the sea bed through various mooring techniques, spar facilities do not require moorings to stay upright. The unique design of the spar ensures that the facility will not topple even if the moorings are not connected because the center of gravity is located below the center of buoyancy.Types of Spars

Traditional SparThere are three types of spars, including the original spar design, truss spars and cell spars. Consisting of a single cylindrical hull, the original design for spars was created in the mid '90s with the first developed for the Neptune field in the Gulf

of Mexico. Truss SparThe next rendition of the spar was the truss spar, which is similar to the original spar design, but the cylindrical hull is shorted and a truss is incorporated below it. The truss usually includes horizontal plates that help to decrease vertical movement. The truss spar is advantageous because it weighs less than the original design, and because it requires less steel, which costs less.

Red Hawk Cell Spar Source: www.anadarko.comThe most recent variation of the spar is the cell spar, which is a scaled-down version of the original design. The cell spar includes six pressure vessels gathered around a seventh vessel. Resembling massive hot dogs, these pressure vessels are more easily and cost-effectively generated through mass production. Providing the buoyancy for the facility, the vessels are held in place by structural steel, which extends below the vessels and keeps with the deep-draft design by

providing stability.How Does a Tension Leg Platform (TLP) Work?A type of floating production system, tension leg platforms (TLPs) are buoyant production facilities

vertically moored to the seafloor by tendons. TLP

DesignWhile a buoyant hull supports the platform's topsides, an intricate mooring system keeps the TLP in place. The buoyancy of the facility's hull offsets the weight of the platform, requiring clusters of tight tendons, or tension legs, to secure the structure to the foundation on the seabed. The foundation is then kept stationary by piles driven into the seabed.The tension leg mooring system allows for horizontal movement with wave disturbances, but does not permit vertical, or bobbing, movement, which makes TLPs a popular choice for stability, such as in the hurricane-prone Gulf of Mexico.The basic design of a TLP includes four air-filled columns forming a square. These columns are supported and connected by pontoons, similar to the design of a semisubmersible production platform. Nonetheless, since their inception in the mid 1980s, TLP designs have changed according to development requirements. Now, designs also comprise the E-TLP, which includes a ring pontoon connecting the four air-filled columns; the Moses TLP, which centralizes the four-column hull; and the SeaStar TLP, which includes only one central column for a hull.

Source: A Moses TLPThe platform deck is located atop the hull of the TLP. The topside of a TLP is the same as a typical production platform, consisting of a deck that houses the drilling and production equipment, as well as the power module and the living quarters. Dry tree wells are common on TLPs because of the lessened vertical movement on the platforms.Most wells producing to TLPs are developed through rigid risers, which lift the hydrocarbons from the seafloor to dry trees located on the TLP deck. Many times, steel catenary risers are also used to tie-in the subsea flowlines and export pipelines.

A SeaStar TLPTLP TypesThe third-most used type of floating production facility in the world, TLPs are ideal for a broad range of water depths. Currently, there are three different types of TLPs: full-size TLPs, mini TLPs and wellhead

TLPs.****************************PRODUCTION***********************How Does Well Acidizing Work to Stimulate Production?Stimulation is performed on a well to increase or restore production. Sometimes, a well initially exhibits low permeability, and stimulation is employed to commence production from the reservoir. Other times, stimulation is used to further encourage permeability and flow from an already existing well that has become under-productive.A type of stimulation treatment, acidizing is performed below the reservoir fracture pressure in an effort to restore the natural permeability of the reservoir rock. Well acidizing is achieved by pumping acid into the well to dissolve limestone, dolomite and calcite cement between the sediment grains of the reservoir rocks. There are two types of acid treatment: matrix acidizing and fracture acidizing.

Well AcidizingSource: MPG PetroleumA matrix acid job is performed when acid is pumped into the well and into the pores of the reservoir rocks. In this form of acidization, the acids dissolve the sediments and mud solids that are inhibiting the permeability of the rock, enlarging the natural pores of the reservoir and stimulating flow of hydrocarbons.While matrix acidizing is done at a low enough pressure to keep from fracturing the reservoir rock, fracture acidizing involves pumping highly pressurized acid into the well, physically fracturing the reservoir rock and dissolving the permeability inhibitive sediments. This type of acid job forms channels through which the hydrocarbons can flow.There are different acids used to perform an acid job on wells. A common type of acid employed on wells to stimulate production is

hydrochloric acids (HCI), which are useful in removing carbonate reservoirs, or limestones and dolomites, from the rock. Also, HCI can be combined with a mud acid, or hydrofluoric acid (HF), and used to dissolve quartz, sand and clay from the reservoir rocks.In order to protect the integrity of the already completed well, inhibitor additives are introduced to the well to prohibit the acid from breaking down the steel casing in the well. Also, a sequestering agent can be added to block the formation of gels or precipitate of iron, which can clog the reservoir pores during an acid job.After an acid job is performed, the used acid and sediments removed from the reservoir are washed out of the well in a process called backflush.For more information about reservoir stimulation,

take a look at How Does Well Fracturing Work to Stimulate Production?How Does Well Fracturing Work to Stimulate Production?Stimulation techniques are used to encourage production to flow from the reservoir rocks. Hydrocarbons are located in the spaces between pores of reservoir rock. Production is achieved when these pore spaces are connected and permeability, or the ability to transmit fluids, is such that the hydrocarbons flow out of the rock and into the well. In some reservoirs, the rocks have low permeability, and the hydrocarbons cannot be extracted for production. Other times, production is hampered by formation damage, when drilling into the reservoir rock lessens permeability. Production can be achieved in these wells via a production stimulation method called well fracturing. Performed above the reservoir formation fracture pressure, well fracturing causes a highly conductive flow path between the reservoir and the wellbore. Well fracturing actually breaks or splits the reservoir rock open to encourage hydrocarbons

to flow from the rocks into the well. A Well Before and After FracturingSource: Austin Exploration LimitedPerformed after the well has been completed, or after the casing, tubing and perforations have been applied, well fracturing has evolved over time. Starting in the 1860s and used through the 1940s, explosive fracturing used to be the most common method of well fracturing. Explosive fracturing, also known as well shooting, detonated an explosive within the well to break the reservoir rocks.Successful at stimulating production, yet dangerous, explosive fracturing introduced liquid nitrogen into the well via a tin cylinder referred to as a torpedo. The torpedo was lowered into the wellbore and detonated. The explosion created a huge hole that was then cleaned out and completed as an openhole, leaving the bottom of the well open into the reservoir.Developed in the late 1940s, hydraulic fracturing, also known as a frac job, is the practice of injecting a well with large amounts of frac fluids under high pressure in order to break the

rocks. Performed on both openhole and cased-well perforations, hydraulic fracturing quickly replaced explosive fracturing.Used in a gel-like state, frac fluids consist of water and polymers, or long organic molecules that form a thick liquid. Both oil-based and foam-based frac fluids use nitrogen bubbles to achieve the fracture. Carbon dioxide can be used, as well, to minimize formation damage.A frac job is performed in three steps. First, a large amount of frac fluids are pumped into the well. The high-pressure of the frac fluids and the continual pumping increases the pressure in the well, overcoming the strength of the reservoir rocks to break them apart. Fracing fluids are pumped into the well until the rocks are cracked to a desired length.

Different Types of ProppantsSource: HexionThen, frac fluid and propping agents are introduced into the well to extend the breaks and pack them with proppants, or small spheres composed of quartz sand grains, ceramic spheres or aluminum oxide pellets, that hold the fractures open after pumping has ceased. This is important, because then the hydrocarbons can flow through the open cracks in the reservoir rocks. Finally, the well is back flushed to remove the frac fluids.Increasing both the rate of production and the overall production of a well, hydraulic fracturing is best employed in medium and hard formations. In fact, hydraulic fracturing is used in almost all tight gas sand reservoirs. In onshore US wells, approximately 50% of the gas wells and 30% of the oil wells are fraced.Hydraulic fracturing can increase the production of a well by 1.5 to 30 times the initial rate of flow, as well as the overall production from 5 to 15%. Also, a well can be fraced multiple times during its production life.For more information about reservoir stimulation, take a look at How Does

Well Acidizing Work to Stimulate Production?How Does Artificial Lift Work?Artificial lift is a process used on oil wells to increase pressure within the reservoir and encourage oil to the surface. When the natural drive energy of the reservoir is not strong enough to push the oil to the surface, artificial lift is employed to recover more production.While some wells contain enough pressure for oil to rise to the surface without stimulation, most don't, requiring artificial lift. In fact, 96% of the oil wells in the US require artificial lift from the very beginning.Even those wells that initially posses natural flow to the surface, that pressure depletes over time, and artificial lift is then required. Therefore, artificial lift is generally performed on all wells at some time during their production life. Although there are several methods to achieve artificial lift, the two main categories of artificial lift include pumping systems and gas lifts.Methods of Artificial LiftThe most common type of artificial lift pump system applied is beam pumping, which engages equipment on and below the surface to increase pressure and push oil to the surface. Consisting of a sucker rod string and a sucker rod pump, beam pumps are the familiar jack pumps seen on onshore oil wells.

Beam PumpSource: Calsac CorporationAbove the surface, the beam pumping system rocks back and forth. This is connected to a string of rods called the sucker rods, which plunge down into the wellbore. The sucker rods are connected to the sucker rod pump, which is installed as a part of the tubing string near the bottom of the well. As the beam pumping system rocks back and forth, this operates the rod string, sucker rod and sucker rod pump, which works similarly to pistons inside a cylinder. The sucker rod pump lifts the oil from the reservoir through the well to the surface.Usually pumping about 20 times a minute, the pumping units are powered electronically or via gas engine, called a prime mover. In order for the beam system to work properly, a speed reducer is employed to ensure the pump unit moves steadily, despite the 600 revolutions per minute the engine achieves.Another artificial lift pumping system, hydraulic pumping equipment applies a downhole hydraulic pump, rather than sucker rods, which lift oil to the surface. Here, the production is forced against the pistons, causing pressure and the pistons to lift the fluids to the surface. Similar to the physics applied in waterwheels powering old-fashion gristmills, the natural energy within the well is put to work to

raise the production to the surface. Hydraulic PumpSource: SchlumbergerHydraulic pumps are generally composed of two pistons, one above the other, which are connected by a rod that moves up and down within the pump. Both the surface hydraulic pumps and subsurface hydraulic pumps are powered by power oil, or clean oil that has been previously lifted from the well. The surface pump sends the power oil through the tubing string to the subsurface hydraulic pump installed at the bottom of the tubing string, the reservoir fluids are then sent up a second parallel tubing string to the surface.Electric submersible pump systems employ a centrifugal pump below the level of the reservoir fluids. Connected to a long electric motor, the pump is composed of several impellers, or blades, that move the fluids within the well. The whole system is installed at the bottom of the tubing string. An electric cable runs the length of the well, connecting the pump to a surface source of electricity.

Electric Submersible PumpSource: SchlumbergerThe electric submersible pump applies artificial lift by spinning the impellers on the pump shaft, putting pressure on the surrounding fluids and forcing them to the surface. A mass producer, electric submersible pumps can lift more than 25,000 barrels of fluids per day.An emerging method of artificial lift, gas lift injects compressed gas into the well to reestablish pressure, making it produce. Even when a well is flowing without artificial lift, it many times is using

a natural form of gas lift. Gas LiftSource: Tech Flo Consulting LLCThe injected gas reduces the pressure on the bottom of the well by decreasing the viscosity of the fluids in the well. This, in turn, encourages the fluids to flow more easily to the surface. Typically, the gas that is injected is recycled gas produced from the well.With very few surface units, gas lift is the optimal choice for offshore applications. Occurring downhole, the compressed gas is injected down the casing tubing annulus, entering the well at numerous entry points called gas-lift valves. As the gas enters the tubing at these different stages, it forms bubbles, lightens the fluids and lowers the pressure.In the US, the majority of wells, 82%, employ a beam pump. Ten percent use gas lift, 4% use electric submersible pumps, and 2% use hydraulic

pumps.What Is EOR, and How Does It Work?Oil production is separated into three phases: primary, secondary and tertiary, which is also known as Enhanced Oil Recovery (EOR). Primary oil recovery is limited to hydrocarbons that naturally rise to the surface, or those that use artificial lift devices, such as pump jacks. Secondary recovery employs water and gas injection, displacing the oil and driving it to the surface. According to the US Department of Energy, utilizing these two methods of production can leave up to 75% of the oil in the well.The way to further increase oil production is through the tertiary recovery method or EOR. Although more expensive to employ on a field, EOR can increase production from a well to up to

75% recovery. Enhanced Oil RecoverySource: SchlumbergerUsed in fields that exhibit heavy oil, poor permeability and irregular faultlines, EOR entails changing the actual properties of the hydrocarbons, which further distinguishes this phase of recovery from the secondary recovery method. While waterflooding and gas injection during the secondary recovery method are used to push the oil through the well, EOR applies steam or gas to change the makeup of the reservoir.Whether it is used after both primary and secondary recovery have been exhausted or at the initial stage of production, EOR restores formation pressure and enhances oil displacement in the reservoir.There are three main types of EOR, including chemical flooding, gas injection and thermal recovery. Increasing the cost of development alongside the hydrocarbons brought to the surface, producers do not use EOR on all wells and reservoirs. The economics of the development equation must make sense. Therefore, each field must be heavily evaluated to determine which type of EOR will work best on the reservoir. This is done through reservoir characterization, screening, scoping, and reservoir modeling and simulation.Thermal RecoveryThermal recovery introduces heat to the reservoir to reduce the viscosity of the oil. Many times, steam is applied to the reservoir, thinning the oil and enhancing its ability to flow. First applied in Venezuela in the 1960s, thermal recovery now accounts for more than

50% of applied EOR in the US. Thermal RecoverySource:

Alberta Geological SurveyChemical InjectionChemical injection EOR helps to free trapped oil within the reservoir. This method introduces long-chained molecules called polymers into the reservoir to increase the efficiency of waterflooding or to boost the effectiveness of surfactants, which are cleansers that help lower surface tension that inhibits the flow of oil through the reservoir. Less than 1% of all EOR methods presently utilized in the US consist of chemical injections.Gas InjectionGas injection used as a tertiary method of recovery involves injecting natural gas, nitrogen or carbon dioxide into the reservoir. The gases can either expand and push gases through the reservoir, or mix with or dissolve within the oil, decreasing viscosity and increasing

flow. Carbon Dioxide EORSource: Lawrence Livermore National Laboratory Carbon dioxide EOR (CO2-EOR) is the method that is gaining the most popularity. While initial CO2-EOR developments used naturally occurring carbon dioxide deposits, technologies have been developed to inject CO2 created as byproducts from industrial purposes.First employed in the US in the early 1970s in Texas, CO2-EOR is successfully used in Texas and New Mexico and is expected to become more widely spread in the future. Nearly half of the EOR employed in the US is a form of gas injection. Other EOR applications gaining acceptance are low-salinity water flooding, which is expected to increase production by nearly 20%, and well stimulation, which is a relatively low-cost solution because it can be employed to single wells (rather than the whole reservoir).Offshore EOR ApplicationsAlthough EOR applications are predominantly employed onshore, technologies are being developed to expand the reach of EOR to offshore applications. Challenges that presently exist for offshore EOR include economics of the development; the weight, space and power limitations of retrofitting existing offshore facilities; and fewer wells that are more widely spaced contributing to displacement, sweep and lag time.Currently, the application of EOR is being considered for a number of offshore developments. With successful subsea processing and secondary recovery methods employed in offshore environments through water and gas injection, the technologies to apply EOR methods is quickly nearing.EOR in the USThe US Department of Energy estimates that currently there are 89 billion barrels of additional oil trapped in onshore reservoirs. This is in great contrast to the country's current domestic proven reserves, which is estimated at 21.9 billion barrels. The DOE stresses that much of this production could be tapped by implementing EOR methods, namely the injection of

carbon dioxide. Area Focus for Potential EORSource: DOEIn fact, the governmental agency claims that the pervasive application of EOR technologies on US reserves could increase the country's oil recovery from approximately 30% to more than 60%. If this oil was added to the US proven reserves, the country would rank fifth in the world for the size of its reserves.If this oil could be recovered, the country's dependence on foreign oil would be greatly depreciated, an effort for which the US has been striving. However, a wider application of EOR methods on US reservoirs requires a much higher cost of production, and the price of oil must legitimize the investment.

**********************************LNG*******************************Because of its physical state, natural gas is inherently a domestic product. As a gas, the hydrocarbon must be transported by pipeline, which restricts the number of end users. Liquefied Natural Gas (LNG) was developed in 1964 as a solution to this problem.With LNG, gas is liquefied and transported internationally via tankers and then regasified into its original state for distribution and sale. Additionally, the hydrocarbon takes up significantly less space as a liquid than a gas; LNG is approximately 1/600th the volume of the same amount of natural gas.

LNG Liquefaction PlantSource: Center for Liquefied Natural GasLNG has transformed the natural gas market, making previously unrecoverable natural gas finds an economic reality. In other words, stranded gas reservoirs, for which pipelines were too costly to construct, can now be produced, transformed into LNG and transported via tanker.LiquefactionWhen in the reservoir, natural gas is found in three states: non-associated, where there is no oil contact; gas cap, where it is overlying an oil reserve; and associated gas, which is dissolved in the oil. The composition of the natural gas defines how it will be processed for transport. Whether staying in its gaseous state or being transformed into a liquid, natural gas

from the well must undergo separation processes to remove water, acid gases and heavy hydrocarbons from the recovered natural gas.The next step in processing is determined by what type of transport the gas will undergo, and specifications are met according to the transportation system. For LNG, additional processing is required before the condensation of the gas to remove the threat of crystallization in the heat exchangers in the liquefaction plant. When chemical conversion is used to liquefy natural gas, the conversion process determines which preliminary process must be used. Additionally, fractionation between methane and heavier hydrocarbons is performed during liquefaction. This way, after regasification the fuel can be loaded directing into the distribution

network of pipelines. LNG Liquefaction PlantSource: Center for Liquefied Natural GasNatural gas is liquefied by lowering the temperature of the hydrocarbon to approximately -260 degrees Fahrenheit (-160 degrees Celsius). This temperature drop liquefies the methane present in the natural gas, making transportation at atmospheric pressure in the form of LNG possible. LNG is mainly constituted of methane and generally contains ethane, as well. Liquefied Petroleum Gas (LPG) may also be present in the LNG.TransportationLNG is then introduced into specially insulated tankers and transported around the world. LNG is kept in its liquid form via autorefrigeration. This is a process in which the fuel is kept at its boiling point. Through autorefrigeration any additions of heat are offset by the energy lost from the LNG vapor, vented out of the storage and used to power the tanker.

LNG Being Loaded Onto a TankerSource: Center for

Liquefied Natural Gas LNG Tanker at SeaSource: Center for Liquefied Natural GasLNG has little to no chance of igniting or exploding should a spill occur. When LNG is vaporized into its gaseous form, the fuel will only burn when mixed with air in concentrations of 5 and 15%. Additionally, LNG and the vapors associated with it do not explode in an open environment.Regasification

LNG Regasification PlantSource: Center for Liquefied Natural GasOnce it has reached its destination, the LNG is offloaded from the tanker and either stored or regasified. The LNG is dehydrated into a gaseous state again through a process that involves passing the LNG through a series of vaporizers that reheat the fuel above the -260 degree Fahrenheit (-160 degrees Celsius) temperature mark. The fuel is then sent via established transportation methods, such as pipelines, to the end users.ApplicationsAlthough limited because of the number of liquefaction and regasification facilities located worldwide, LNG is gaining momentum. Major ongoing LNG projects include the multi-billion-dollar Gorgon LNG project in Australia, as well as the Olokola LNG project in Nigeria and the LionGas LNG project in the Netherlands.According to the EIA, countries in Asia Pacific are the largest exporters of LNG, and the Middle East is also a leading LNG exporting region. Historically some of the largest importers of LNG, Japan and South Korea depend almost solely on internationally produced LNG for their natural gas needs. European countries also import a large percentage of the LNG produced globally. Emerging markets for the fuel are China and India, although those countries are currently pursuing major pipeline deals in an effort to increase their natural gas imports.Currently, LNG represents only about 1% of the natural gas consumed in the United States. Right now, the country imports LNG from Trinidad and Tobago, Qatar, Algeria, Nigeria, Oman, Australia, Indonesia and the UAE.According to the US Federal Energy Regulatory Commission (FERC), there are currently eight LNG processing facilities in operation in the country; seven are regasification plants, and one is a liquefaction facility. Presently, there are 40 additional LNG projects under consideration in the US. LNG imports are expected to increase to an average of 15.8% or 4.8 Tcf of the natural gas used in the US by 2025.

******************SUBSEA****************How Do Subsea Trees Work?

Used on offshore oil and gas fields, a subsea tree monitors and controls the production of a subsea well. Fixed to the wellhead of a completed well, subsea trees can also manage fluids or gas injected

into the well. Source: Cameron Since the 1950s, subsea trees have been topping underwater wellheads to control flow. A design taken from their above-ground cousins, subsea trees are sometimes called xmas trees because the devices can resemble a tree with decorations.Subsea trees are used in offshore field developments worldwide, from shallow to ultra-deepwaters. The deepest subsea trees have been installed in the waters offshore Brazil and in the US Gulf of Mexico, and many are rated for waters measuring up to 10,000 feet deep.Types of Subsea TreesThere are various kinds of subsea trees, many times rated for a certain water depth, temperatures, pressure and expected flow.The Dual Bore Subsea Tree was the first tree to include an annulus bore for troubleshooting, well servicing and well conversion operations. Although popular, especially in the North Sea, dual bore subsea trees have been improved over the years. These trees can now be specified with guideline or guideline-less position elements for production or injection well applications.Standard Configurable Trees (SCTs) are specifically tailored for company's various projects. A general SCT is normally used in shallower waters measuring up to 1,000 meters deep.High Pressure High Temperature Trees (HPHT) are able to survive in rough environments, such as the North Sea. HPHT trees are designed for pressures up to 16,500 psi and temperatures ranging from -33 C to 175 C.Other subsea trees include horizontal trees, mudline suspension trees, monobore trees and large bore trees. Companies that manufacture subsea trees are Aker Solutions,

Cameron, FMC Technologies and Schlumberger. How Do Risers Work?

Conduits to transfer materials from the seafloor to production and drilling facilities atop the water's surface, as well as from the facility to the seafloor, subsea risers are a type of pipeline developed for this type of vertical transportation. Whether serving as production or import/export vehicles, risers are the connection between the subsea field developments and production and drilling facilities.

Multiple Riser ConfigurationsSource: www.atlantia.comSimilar to pipelines or flowlines, risers transport produced hydrocarbons, as well as production materials, such as injection fluids, control fluids and gas lift. Usually insulated to withstand seafloor temperatures, risers can be either rigid or flexible.Types of RisersThere are a number of types of risers, including attached risers, pull tube risers, steel catenary risers, top-tensioned risers, riser towers and flexible riser configurations, as well as drilling risers.The first type of riser to be developed, attached risers are deployed on fixed platforms, compliant towers and concrete gravity structures. Attached risers are clamped to the side of the fixed facilities, connecting the seabed to the production facility above. Usually fabricated in sections, the riser section closest to the seafloor is joined with a flowline or export pipeline, and clamped to the side of the facility. The next sections rise up the side of the facility, until the top riser section is joined with the processing equipment atop the facility.Also used on fixed structures, pull tube risers are pipelines or flowlines that are threaded up the center of the facility. For pull tube risers, a pull tube with a diameter wider than the riser is preinstalled on the facility. Then, a wire rope is attached to a pipeline or flowline on the seafloor. The line is then pulled through the pull tube to the topsides, bringing the pipe along with it. Building on the catenary equation that has helped to create bridges across the world, steel catenary risers use this curve theory, as well. Used to connect the seafloor to production facilities above, as well as connect two floating production platforms, steel catenary risers are common on TLPs, FPSOs and spars, as well as fixed structures, compliant towers and gravity structures. While this curved riser can withstand some motion, excessive movement can cause problems.

Top-Tensioned Risers Source: www.atlantia.comUsed on TLPs and spars, top-tensioned risers are a completely vertical riser system that terminates directly below the facility. Although moored, these floating facilities are able to move laterally with the wind and waves. Because the rigid risers are also fixed to the seafloor, vertical displacement occurs between the top of the riser and its connection point on the facility. There are two solutions for this issue. A motion compensator can be included in the top-tensioning riser system that keeps constant tension on the riser by expanding and contracting with the movements of the facility. Also, buoyancy cans, can be deployed around the outside of the riser to keep it afloat. Then the top of the rigid vertical top-tensioned riser is connected to the facility by flexible pipe, which is better able to accommodate the movements of the facility.First used offshore Angola at Total's Girassol project, riser towers were built to lift the risers the considerable height to reach the FPSO on the water's surface. Ideal for ultra-deepwater environments, this riser design incorporates a steel column tower that reaches almost to the surface of the water, and this tower is topped with a massive buoyancy tank. The risers are located inside the tower, spanning the distance from the seafloor to the top of the tower and the buoyancy tanks. The buoyancy of the tanks keeps the risers tensioned in place. Flexible risers are then connected to the vertical risers and ultimately

to the facility above. Hybrid Riser SystemSource: www.2hoffshore.com A hybrid that can accommodate a number of different situations, flexible risers can withstand both vertical and horizontal movement, making them ideal for use with floating facilities. This flexible pipe was originally used to connect production equipment aboard a floating facility to production and export risers, but now it is found as a primary riser solution as well. There are a number of configurations for flexible risers, including the steep S and lazy S that utilize anchored buoyancy modules, as well as the steep wave and lazy wave that incorporates buoyancy modules.While production and import/export risers transfer hydrocarbons and production materials during the production phase of development; drilling risers transfer mud to the surface during drilling activities. Connected to the subsea BOP stack at the bottom and the rig at the top, drilling risers temporarily connect the wellbore to the surface to ensure drilling fluids to not leak into the water.

Sources

Deepwater PetroleumExploration and Production

A Primer of OffshoreOperations, Third Edition

Marine Riser Systems   Subsea Blowout Preventers

How Do Umbilicals Work?

Transferring power, chemicals, communications and more to and from subsea developments, umbilicals are literally the lifeline to subsea trees, manifolds, jumpers, sleds and controls. The connective medium between surface installations and subsea developments, umbilicals can include electrical, hydraulic, chemical injection and fiber optic connections.

(SSIV) UMBILICALSSource: http://www.jdrcables.comUmbilicals are enclosed with an outer ring specially designed for the subsea environment to which it will be deployed. While they must withstand everyday wear and tear, as well as seabed temperatures, Umbilicals are also deployed in ultra-deepwater and HP/HT environments. Umbilicals connect from the surface facility to the subsea development through an Umbilical Termination Structure (UTS). From the UTS, umbilical services are transported to the various subsea equipment located on the field. Many times umbilical services are "flown" from apparatus to apparatus via a flying lead, which is similar to the common extension cord.The number of umbilicals used varies by development because each subsea project is unique. Additionally, umbilicals can be single or multiple connections in a single line. For example, umbilicals might just include chemical injection tubes, while others can include telecommunications cables, as well as electrical cables, bundled together and encased in a single line.Umbilicals that incorporate multiple connections are referred to as integrated umbilicals. While integrating umbilicals can save on development and installation costs, several different umbilicals may still be required for the

development. Control UmbilicalSource: http://www.fmctechnologies.comThere are several purposes for subsea umbilicals. Hydraulics are used to activate subsea wells, and some umbilicals pump chemicals into the production stream. Electrical umbilicals connect to subsea control panels and transmit information about temperature, pressure and subsea integrity, as well as electrical power to the subsea equipment. Fiber optic cables can instantly relay information to the surface about what's happening below. Advances in umbilical technology have allowed companies to offer umbilicals that are integrated with flowlines, as well. In this hybrid form, the flowline is surrounded by electrical umbilicals, and the group is then encased with tubing.

Sources