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104 REGIONAL REPORT:

INDIA

IMPROVING EXPLORATION SUCCESS

New approach describes the indescribable

Ventura basin still holds hidden treasure

Navigation sensor technology aids marineseismic survey

Seismic can be relevant in shales

FRONTIER EXPLORATION

Geological review of deepwater Liberian basinoutlines prospectivity

Iranian discoveries continue

LAND RIG ADVANCES

Combined experience brings designed-for-purpose top drive to market

Two brakes in one improve performance,maintain cost

SUBSEA TECHNOLOGIES

Collaboration is key to expanding subseatechnologies for deep water

Seabed compression advances boostdevelopment options

SERVICE AND SUPPLY VESSELS

Offshore support fleet steering a positive course

Brazilian E&P spending fuels major supplyvessel growth

IndustryPULSE:Post Macondo: Stabilityreturns to Gulf Reduncies and additions affect safetyand cost in new government regulations.

EXPLORATION & PRODUCTIONW O R L D W I D E C O V E R A G E

APRIL 2012VOLUME 85 ISSUE 4

A HART ENERGY PUBLICATION www.EPmag.com

36

‘Always be prepared’ is not just

for Boy Scouts anymore.

Balancing Risk& Reward

8

WorldVIEW:The classic ‘elephant’ huntertakes aim in Central Asia

An independent operator in three underexploredrepublics in Central Asia has the know-how to accessa huge pool of resources in the region’s vast andprolific hydrocarbon basins.

12

Unconventional:HaynesvilleThe Haynesville can compete

As the largest producing gas play in North America,

the Haynesville shale is a highly competitive asset.

44

46

50

54

58

66

62

74

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86

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80

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COVER STORY

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AS I SEE IT

The new look for 2012 5

MANAGEMENT REPORT

Using balanced scorecarding in mature fields 16

The face of the oil and gas industry is changing 20

DIGITAL OIL FIELD

Virtual reality simulation improves offshore training, safety 22

‘Big Data’ requires efficient analytics, bandwidth, content 26

EXPLORATION TECHNOLOGY

USBs – Friend or foe? 31

WELL CONSTRUCTION

New RSS drills from spud to TD in one run 33

PRODUCTION OPTIMIZATION

Is the industry brave enough to freeze its Arctic plans? 35

TECH WATCH

R&D investment in Brazil continues to surge 96

TECH TRENDS 100-101

INTERNATIONAL HIGHLIGHTS 108

ON THE MOVE/INDEX TO ADVERTISERS 110-111

LAST WORD

Methane in water wells unrelated to hydraulic fracturing 112

E&P (ISSN 1527-4063) (PM40036185) is published monthly by Hart Energy Publishing, LP, 1616 S. Voss Road, Suite 1000, Houston,Texas 77057. Periodicals postage paid at Houston, TX, and additional mailing offices. Subscription rates: 1 year (12 issues), US $149;2 years (24 issues), US $279. Single copies are US $18 (prepayment required). Advertising rates furnished upon request. POSTMASTER:Send address changes to E&P, PO Box 5020, Brentwood, TN 37024. Address all non-subscriber correspondence to E&P, 1616 S. VossRoad, Suite 1000, Houston, Texas 77057; Telephone: 713-260-6442. All subscriber inquiries should be addressed to E&P, 1616S. Voss Road, Suite 1000, Houston, TX 77057; Telephone: 713-260-6442 Fax: 713-840-1449; [email protected]. Copyright © Hart Energy Publishing, LP, 2012. Hart Energy Publishing, LP reserves all rights to editorial matter in this magazine. No article may bereproduced or transmitted in whole or in parts by any means without written permission of the publisher, excepting that permission to

photocopy is granted to users registered with Copyright Clearance Center/0164-8322/91 $3/$2. Indexed by Applied Science, TechnologyIndex and Engineering Index Inc. Federal copyright law prohibits unauthorized reproduction by any means and imposes fines of up to$25,000 for violations.

DEPARTMENTS AND COMMENTARY

ABOUT THE COVER Managers must walk a fine line between being overly

cautious and careless. New integrated schemes can help them integrate risk

management at a corporate level. (Cover design by Laura J. Williams)

COMING NEXT MONTH The May issue of E&P looks at offshore technology as it affects explo-

ration and drilling, and a special feature examines deepwater challenges and solutions. Additionally,

the regional report provides a technology and regulatory update for the Gulf of Mexico. Other features

focus on extending reservoir life, sand and water management, and international shales. As always,

while you’re waiting for the next copy of E&P , rermember to visit EPmag.com for news, industry, updates,

and unique industry analysis.

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ONLINE CONTENT APRIL 2012

PREMIUM CONTENT Subscribe @ EPmag.com/explorationhighlights

AVAILABLE ONLY ONLINE

SIS Global Forum: New tools tackle heavy

oil, digital oil field

By Rhonda Duey, Senior Editor

Taking integration to the next level, model-based

technologies aid in heavy oil production and

maximize the potential of the digital oil field.

SPE/IADC: Sustainability

encompasses people too

By Tayvis Dunnahoe, Senior Editor

Aside from technology and innovation, the impor-

tance of people in the oil and gas industry was a

topic discussed at the recent SPE/IADC Drilling

Conference in San Diego, Calif.

CERAWeek: Exploration, technology

critical to future energy supply

By Nancy Agin, Associate Editor

In a dynamic and increasingly challenging world,

the E&P industry must take on new energy fron-

tiers while continuing to invest in cutting-edge

technology R&D to satisfy fluctuating demand.

BSEE: Tackling BOP maintenance/inspection

By Scott Weeden, Senior Online Editor

ABS & ABS Consulting are working with original

equipment manufacturers, drilling contractors,

and oil companies to determine industry practices

for BOP maintenance, inspection, and testing.

R E AD T H E L AT E S T E P m a g .c o m

I N D U S T R Y N E W S

New gas discovery in Alon A block,offshore Israel

The Noble-operated #1-Tanin well in theAlon A block has unlocked 1.2 Tcf to 1.3Tcf, according to partner Delek Group.

WEBINARS

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A ConversationAbout EnergyPolicy, NaturalGas, and Jobs

Energy Outlook 2012: Where AreOil, Gas, and NGLPrices Headed?

EvaluatingThe Eagle Ford:

Geology andGeophysicsReview

Encana reports horizontal Tuscaloosa Marine shale producerThe company has completed a horizontal Tuscaloosa Marine shaleproducer in St. Helena Parish, La., that has flowed 280 bbl of 40°API oil,98 Mcf, and 1,277 bbl of water per day.

Kuwait Energy strikes oil in WesternDesert Concession

A new discovery in Egypt’s Western Desert AbuSennan Concession initially flowed 835 b/d.

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Ah, Spring. It’s the time when a young man’s fancy turns to love, accord-

ing to Lord Tennyson. But if a young man is working in oil and gas, that

fancy turns instead to readjusting expectations for the year ahead.

Yes, it’s that time of year when we toss out those 90-day old annual forecasts

that populated industry trade publications as 2012 arrived. You recall the old narrative: a double-digit increase in capital spending was

an early harbinger of further expansion in the domestic drilling market and

additional proof that the international arena was on the verge of a significant

activity increase.

The narrative was nice while it lasted. But a funny thing happened on the

way to spring 2012. Domestically, natural gas prices per Mcf dropped below

the value of a large Starbucks latte. Natural gas drilling followed suit, with

significant rig count declines in the Haynesville and other dry gas drilling

regions.

By the time 4Q earnings calls wound down in early March, operators were

discussing reduced domestic budgets for any project that involved methane.

It seems the term “gas” had become a four-letter word.So where does that leave us for 2012?

The new narrative calls for a flat rig count domestically as operators target

liquids, even as they reduce gas-drilling efforts. The good news is that opera-

tors should see relief from escalating field costs. Pressure pumping capacity

additions made sense in an aggressive oil and gas market. Now that the gas

market is weakening and assets are rotating into liquid plays, the inflection

point on when the industry overbuilds has moved into 2012 versus the 2013

event the pressure pumpers discussed previously.

Internationally, the offshore is the place to be as deep water rapidly devel-

ops momentum in West Africa, Brazil, and the Gulf of Mexico (GoM). By

year-end, accelerating tightness in the ultra-deepwater segment should

increase rig rates and tighten equipment availability in both the deepwaterand midwater segments.

Meanwhile, the jackup market gives every indication of improvement

globally. In some cases, it involves markets like the Middle East where the

Saudis are expanding programs to offset potential global supply disruptions.

Closer to home, the GoM shelf has become more intriguing as it undergoes

consolidation. Perhaps the most notable indicator that the times are changing

was found when a long-time onshore midcap operator acquired its first off-

shore shelf package to generate cash to finance development in the Missis-

sippi Lime.

Gulf oil and gas as a free cash flow generator? Now that’s something to stir a

young man’s fancy.

As ISEE IT

1616 S. VOSS ROAD, STE 1000HOUSTON, TEXAS 77057

P: +1 713.260.6400 F: +1 713.840.0923www.EPmag.com

The new look for 2012

7

Read more commentary at

EPmag.com

RICHARD MASON

Chief Technical Director,

Upstream, Hart Energy

Senior Editor RHONDA [email protected]

Senior Editor TAYVIS DUNNAHOE

[email protected] International Editor MARK THOMAS

[email protected]

Associate Editor NANCY [email protected]

Assistant Editor CODY Ö[email protected]

Corporate Art Director ALEXA SANDERS

Senior Graphic Designer LAURA J. WILLIAMS

Production Director& Reprint Sales JO LYNNE POOL

Senior Editor/Manager,

Special Projects JO ANN DAVYChief Technical Director, Upstream RICHARD MASON

Director of Business Development ERIC ROTH

Group Publisher RUSSELL LAAS

Editorial Advisory Board

CHRIS BARTON

Sr. VP Business Development, Oil & Gas., KBR

KEVIN BRADY

VP, Sales & Marketing,Verdande Technology Inc.

MIKE FORREST

Exploration Consultant, formerly with Shell

JOHN M. GILMORE JR.

Director of Global Industry Solutions UpstreamOil & Gas, Invensys Operations Management

CHRIS JOHNSTON

VP & Managing Director, North America, Ensco

ULISSES T. MELLO

Manager, Petroleum & Energy Analytics, IBM

DONALD PAUL

Executive Director, University ofSouthern California Energy Institute

EVE SPRUNT

Business Development Manager,Chevron Energy Technology Co.

MANUEL TERRANOVA

Sr. VP Regional Operations & Global Sales,Drilling & Production, GE Oil & Gas

RONNIE WITHERSPOON

Sr. VP of Marketing & Business Development,Nabors Drilling USA LP

DENNIS A. YANCHAK

Sr. Geosciences Advisor, Apache Corp.

Vice President, Digital MediaRONS DIXON

Senior Vice President, Consulting GroupE. KRISTINE KLAVERS

Executive Vice PresidentFREDERICK L. POTTER

President & Chief Operating OfficerKEVIN F. HIGGINS

Chief Executive OfficerRICHARD A. EICHLER

E P

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BOEMRE. As a result, the current pace of permit approval

lags far behind historical norms. Even fairly routine per-

mits, such as commingling production or abandoning a

well, take an extended period of time to obtain.In addition, the BSEE seems to have adopted a “deemed

submitted” process, under which it will not start to review

a permit application until it deems the application to be

complete. Thus, an application that is approvable but is

missing one piece of data must be resubmitted – and

seems to go to the back of the permitting queue – before

the BSEE will review and approve it. The concept of

deemed submittal cannot be found anywhere in the Inte-

rior Department’s drilling permit regulations. Rather, it

seems to be borrowed from the department’s planning

document approval process, where the department uses

the concept of deemed submittal to extend the statutory time period for acting on planning documents. This

deemed submittal system sometimes results in substantial

delays when an operator is forced to make repeated resub-

missions before the government will deem an application

to be submitted so the review process can begin.

The repercussions of these delays go beyond the simple

length of time it takes to obtain a permit. Operators also

suffer due to the lack of predictability in the process.

The ability to schedule rigs, manpower, and the purchaseof raw materials is integral to whether many offshore

prospects can be explored for and developed economi-

cally. The lack of certainty about how long it will take an

operator to obtain a permit unnecessarily adds to the costs

of offshore exploration and development and makes the

exploitation of some prospects impossible.

Two years after the GoM oil spill, the regulatory envi-

ronment is certainly more stable than it was immediately

following that tragic event. The government has allowed

drilling activities to resume and has, at least for the

moment, ceased its practice of repeatedly issuing substan-

tive requirements through NTLs and other informalguidance documents. However, some problems with the

government’s regulatory regime remain. Perhaps most

notably, the period of time it takes to obtain permits is still

too long and unpredictable. Hopefully, the government

will be able to address these issues in the near future.

Apri l 2012 | EPm ag.com 10

industryPULSE

Regulators are catching upMacondo hit home the fact that technical advances were outpacing federal regulations.

By Rhonda Duey, Senior Editor

Regardless of one’s opinion about the reaction of the

US government to the Deepwater Horizon disaster,

the fact is that it was a wake-up call for those agencies

and organizations responsible for regulating the off-

shore oil and gas industry. In the two years that have

elapsed since the incident, these groups have been

tasked with reviewing their existing regulations and, if

necessary, updating them to acknowledge new tech-

nologies and techniques that have been developed for

deepwater drilling.

Brian Khey, Ltd. Cmdr. for the US Coast Guard, has

been visiting industry events explaining his agency’splans to overhaul current regulations. “Our regula-

tions are petty old, so we’re trying to update them,”

Khey said. “The industry outpaced the government’s

delay of putting new regulations out.”

While the process is ongoing, Khey said the indus-

try should expect policy updates and “hopefully a

modernization of the requirements.” Already, he said,

a draft guidance has been issued for dynamic posi-

tioning and the emergency disconnect procedures

that accompany station keeping. The agency held a

public hearing in February and is sifting through

industry feedback.

“The guidance will be a huge change in the way we

look at dynamic positioning and communications that

go on between the navigational launch of the marine

crew and the drilling crew if something bad doesoccur and they’re unable to maintain station,” he said.

The Coast Guard is charged with ensuring the safe

operation of vessels, and its regulations cover offshore

drilling. Its purview includes electrical and power

generation and emergency systems.

Khey characterized the relationship between the

Coast Guard and the industry as one where the indus-

try is seeking to understand potential regulatory

changes so that companies can ensure they can com-

ply. The Coast Guard also is working with the Bureau

of Safety and Environmental Enforcement to define

roles and harmonize requirements that overlap.He admitted that the Macondo disaster was an eye-

opening experience for his agency. “It hit home the

importance of us updating our regulations,” he said.

“The question we’ve asked ourselves is, ‘What are the

important things we should be looking at, and are we

looking at them?’ We’re reevaluating that and making

sure that our inspectors are truly looking at the impor-

tant things that keep our offshore operations safe.”

For more information on changing regulations, visit

Homeport.uscg.mil .

8/10/2019 EPM-4


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The classic ‘elephant’ huntertakes aim in Central AsiaAn independent operator in three underexplored republics in Central Asia has the know-how

to access a huge pool of resources in the region’s vast and prolific hydrocarbon basins.

At the core of the Asian continent lie three former

Soviet Union states that hold enormous conven-

tional resource potential in vast, largely underexplored

basins. In these larger states, bordering or near the

Caspian Sea, the region’s terrain is considered to be asdiverse and rugged in its extremes as any in the world with mountains, deserts, and harsh operating conditions.

For more than 20 years, Tethys Petroleum Ltd. has

worked extensively in most of the oil- and gas-bearing

areas in Kazakhstan, Tajikistan, and Uzbekistan and has

honed its knowledge operating in these challenging envi-

ronments and climates. It also has the distinction of being

the only independent E&P company simultaneously oper-

ating in all three countries, where it has a mix of produc-

ing and exploration assets with near-term cash flow and

significant upside potential.

Tethys CEO David Robson, a geologist by background,believes some of the most prolific geologic basins in the

world exist in Central Asia, where large-scale petroleum sys-

tems could potentially be found using more accurate geo-

logical models of the region and recently acquired data.

“You’ve got real opportunity in areas that have hardly

been scratched,” he said. “And although there was some

development done in Soviet times, there are still large

areas that were not explored or have barely been

explored.”

Strategically positioned

Tethys began working the Caspian region in earnest with afairly limited role as a smaller independent, developingminor shallow gas fields in the area and initiating the first

dry gas development in Kazakhstan.

“We started working in Kazakhstan in 2003, began

our first gas development in 2005, and brought that

onstream in 2007,” Robson said. “Now that was develop-

ing shallow gas at really quite shallow levels – only about

450 m (1,476 ft) – and that was the focus to getting cash

flow going. That’s the way our company works; we like to

get cash flow, and then we like to go out and explore for

bigger things.”

The company has since grown into a more substantial

role as a key Central Asia player, concluding, for example,

the first production-sharing contract (PSC) in Tajikistan,

where Robson also functions as a founder of the President’s

Investment Council. More recently, proposals to diversify

Tajikistan’s gas import and export infrastructure via the

Navrouz project that will carry gas from Afghanistan has

put the company at the forefront of regional development.

According to Robson, Tethys no longer is focused onexploiting small deposits but rather is targeting large andgiant structures, particularly in Kazakhstan, which con-

tains 3% of the world’s oil and where, in 2010, the com-

pany discovered a new oil province to the west of the Aral

Sea with its Doris discovery well.

Wildcat successIn Kazakhstan, Tethys holds 100% working interest in the

Kyzyloi production contract, the Akkulka exploration con-

tract, the Akkulka production contract, and the Kul-Bas

Dr. David Robson, CEO, Tethys (Images courtesy of Tethys

Petroleum Ltd.)

Nancy Agin, Associate Editor


worldVIEW

8/10/2019 EPM-4


worldVIEW

exploration and production contract, encompassing a net

area of more than 8,000 sq km (3,089 sq miles).

With production from its Kazakh oil and gas assets driv-

ing cash flow, Tethys’ current major focus is the Doris oilfield, which lies in the Akkulka exploration contract area.

Robson considers Doris the company’s biggest achieve-

ment to date, noting that it is the first discovery of oil in this

portion of the North Ustyurt basin, with the nearest pro-

ducing field being several hundred kilometers away.

“We began our deep exploration program on this struc-

ture, which in those days was called Akkulka, looking for

what we believed to be oil on the structure’s flanks,” he

explained. “The area has been explored to an extent in the

past by the Soviets and also by the Japanese national oil cor-

poration. But they were using much more conventional

geologic models. We’ve applied more up-to-date models,and we were successful in finding the Doris field, which we

are now in the process of appraising and developing.” According to Robson, this is a very productive field,

with the first well flowing high-quality oil at approximately

7,000 b/d with a restricted choke. “This oil is very light.

It’s got no sulfur. It’s got no paraffin. You can almost drink

it,” Robson said. “It’s a green oil. It’s beautiful.”

Tethys brought Doris online in September 2010 follow-

ing its discovery in February, installing the first oil infra-

structure in the basin with its Phase 1 pilot production

facility. The lack of infrastructure, the remote and hostile

environment, and extreme temperatures from +55°C to-45°C (+131°F to -49°F) were not the only obstacles.

Tethys’ operations are approximately 650 km (404 miles)

away from the nearest major town, so shipping equipment

proved to be a logistical challenge. Its recently opened oil

loading terminal has resolved some of these transport

issues, Robson explained.

“Solving the logistics is a key part of working in the

whole area,” Robson said. “We’ve been trucking oil from

the field to the nearest terminal point, which is about 450

km (280 miles) away over some quite tough terrain. But

we inaugurated a new oil loading Aral Oil Terminal in

January 2012 that is closer to the field, only 230 km (143miles) away, which we’ll use as a trans-shipment point for

bringing equipment to the field, thereby not having to

move it 650 km (403 miles) by road. Instead, we’ll take it along by rail.”

Tethys also uses a fleet of 241 trucks that load oil to and

from the terminal, and the company expects Doris pro-

duction levels will increase significantly.

“We could already do that with more trucks, but we’re

aiming to effectively improve the road,” Robson said. “And

at some point in the future, we’ll need to build a pipeline.”

By the end of 2012, the terminal, a 50/50 joint venture

with Olisol Investment Ltd., will be capable of handlingaround 12,000 b/d of oil, effectively increasing productiontwo-fold from 2,000 b/d to 4,000 b/d, and that figure could

be scaled up even further, Robson said. Doris has testedmore than 13,000 b/d from the wells on the field and couldpotentially produce close to 7,000 b/d as a continual pro-duction rate. “We’re drilling at least two more explorationappraisal wells on the field this year, which we would antici-pate enabling us to step production up even higher,” hesaid. “We’re also testing as part of that program a prospect downdip of Doris that looks to be very substantial in size.”

Pioneering deep explorationIn Tajikistan, which Robson referred to as the company’s

“jewel in the crown,” Tethys is sitting on some of the world’s

“most attractive” acreage and, longer term, hopes its deepexploration efforts will transform the country into a hydro-carbon exporter. It also recently made the first oil discovery

since the country won independence in September 1991.

Testing is under way to determine its commercial viability.

Tethys first broke ground in this untapped region nego-

tiating the first PSC for the Bokhtar area to the southwest,

which is nearly equivalent in size to Switzerland. Most sig-

nificantly, the PSC includes almost the entire Tajik portion

of the Afghan-Tajik basin, an underexplored extension of

the greater Amu Darya basin. The Tajik portion’s deeper

subsalt horizons could be analogous to the supergiant gas

and gas condensate fields in neighboring Turkmenistanand Uzbekistan, Robson said.

“Southern Tajikistan is a geologist’s dream, with many

different structures, reservoirs, and prolific source rocks,”

he said. “Tethys’ 35,000-sq-km (13,514-sq-mile) area is an

enormous part of this basin, containing anticlines and

thrust structures, salt domes, and other associated oil and

gas traps, and we believe from our recent work there is

potential for enormous Jurassic reefs below the regional

salt layer. A recent geophysical survey has identified what

could be considerably large structures of gas, oil, or con-

densate below the salt; however, nobody knows because no

well has ever been drilled below it.”Robson believes Tethys’ pioneering exploration of these

supergiant subsalt structures ultimately could prove to be

transformative for the company, which is actively seekinginvestment partners for this project.

Uzbekistan also is driving cash flow. Here Tethys imple-

mented the first use of radial drilling and is currently

engaged in production-enhancing operations with NHC

Uzbekneftegaz at the North Urtabulak oil field. The field,

also situated in the prolific Amu Darya basin, is in its last

stages of development.

“It’s got a little oil left, and we’re squeezing the last drops

EPmag.com | April 2012

8/10/2019 EPM-4


out of the sponge so to speak,” Robson said. “But we’re

now in the process of negotiating with the Uzbek govern-

ment for another field that is only 10 km (6 miles) away

called Chegara, which is a producing field but is not asmature and has not been developed as much as our exist-

ing asset.”

The company also has signed a memorandum of under-

standing with the Uzbek national oil company to acquire

exploration acreage in the northern part of the country

near the Doris oil development across the Kazakh border.

“Companies have looked for oil there and have yet to

find any,” he said, “but they have found gas. We think

they’re not looking in the right place, and we think we

know how to find oil there.”The contract is expected to be finalized by year-end

2012.

Tapping the Asian marketIn Robson’s view, the company’s central location in Asia is

a strategic advantage both in terms of learning the lay of the land and maintaining good working relationships with

neighboring – and energy-hungry – emerging economies

like India and, particularly, China, which is making signifi-

cant investments in regional oil and gas projects.

Within this broader context, Robson believes much of

the market for its Central Asia resources will be to the east.

As such, it has developed strong relationships in China and

the Pacific Rim, with Robson serving as board director of

the Pacific Basin Economic Council. Given China’s risingenergy consumption in particular, Robson is bullish on

regional natural gas prices in the long term.

“Today China uses only about 4% of natural gas in its

primary energy mix, but the Chinese government has pub-

licly stated they want to take that up to a level between 15%

to 20%,” he said. “So even if you see no further energy

growth in China, which I think is highly unlikely given that

the economy is certainly growing, the increased demand

for gas is massive.”

According to Robson, the gas will come as LNG from Aus-tralia or the Middle East or as pipeline gas, “but the logical

place for that gas to come from is Central Asia,” he said.

“Tethys is a classic ‘elephant’ hunter,” Robson continued.

“Its strategy is to increase production and short-term cash

flow to become self-funding to continue financing this type

of exploration and protect downside risks. This is the case

in Tethys’ work in Kazakhstan and Tajikistan.“But we see great opportunities in the Chinese market, in

the European market, and potentially in the Indian market

for our Central Asia energy resources, and indeed much of

our focus will be to capitalize on these opportunities.”


worldVIEW

More than 200 trucks are loaded with crude oil from the Doris field in Kazakhstan at the Tethys-operated Aral Oil Terminal, which was

inaugurated in January.

8/10/2019 EPM-4


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O ver the years, many innovations have come and

gone in the oil and gas industry. From rod pump-

ing technology to the latest smart wells, technology

introduced in the past decade has had a significant impact. Companies are finding oil and gas reserves inthe most remote parts of the world, viewing the subsur-

face in virtual reality, and drilling wells under conditions

unimaginable just 10 years ago.

Innovation (even in oil and gas) is frequently the

result of shared best practices between diverse industries.

One methodology used by industries such as retail and

telecommunications is the balanced scorecard (BSC).

This tool is popular because it allows users to tie financial

and nonfinancial metrics together on one dashboard.

Additionally, it can juxtapose seemingly unrelated vari-

ables together. Based on the successes of the BSC in otherindustries, oil companies should leverage these best prac-

tices to monitor their progress in mature fields.

Mature fields are the cash cow of most oil and gas pro-

ducing companies. However, mature fields are a run-

rate business with notoriously slim margins, and they

need to be monitored closely. Using a BSC would allow

management to monitor these returns against other crit-

ical nonfinancial imperatives.

Production companies need to effectively align their

goals and business objectives at every level of the organi-

zation and adapt these objectives to tangible and achiev-

able goals specific to an employee’s supporting role.In addition, the industry needs to ensure that field

activities ultimately lead to achieving the vision and strat-

egy of the organization, improve internal and externalcommunications, and monitor organization perform-

ance against strategic goals.

On a more granular level, asset managers worry about

declining production and reaching production targets.

As difficult as these challenges are, corporate goals also

must be addressed. These “big picture” objectives are

all too frequently left in the boardroom or on analysts’

desks and are rarely percolated down to the individual

pumper who is ultimately responsible for achieving

them on a field level.

Can these be better managed by a BSC?

A bit of historyThe idea of BSCs was originated by Robert Kaplan and

David Norton as performance-measurement frameworks.Their goal was to add strategic nonfinancial performancemeasures to traditional financial metrics and give man-

agers and executives a more balanced view of organiza-

tional performance. The methodology was adopted by

mainstream industry in the early 1990s as software appli-

cations to measure metrics became more abundant. How-

ever, the roots of this approach started in the early 1950s

in work done by both General Electric and French engi-

neers, who created Tableau de Bord , a dashboard of per-

formance measures.

Increasingly, BSCs are being used by corporations.

According to Bain and Co., by 2004 approximately 57%of global companies were using some form of BSCs.

Recent success stories indicate that corporations are

seeing the benefits of using this type of analysis to track

and achieve their goals.

The oil and gas industry is more traditional; it tends to

be conservative in its management and adoption of new

methodologies. Going forward, the industry would ben-

efit from using this “balanced view” to ensure the efforts

in mature field management are supporting the overar-

ching goals of the corporation.

Success and failureFor each individual industry, there exist different vari-ables in the scorecards such as financial, customer feed-

back, internal processes and learning, and growth. The

following case study provides one example of how a cor-

poration customized its scorecard to meet the overall

goals of the company. It is important to note that busi-

ness scorecards are the result of the individual com-

pany’s culture and financial needs of monitoring.

Shat-R-Shield is a 40-year-old manufacturer specializing

in plastic-coated shatter-resistant lamps to ensure that

overhead lighting fixtures in factories and assembly plants

Using balanced scorecarding

in mature fieldsA ‘balanced view’ can help ensure that efforts in field management are supporting the

overarching goals of the corporation.

Rob Hull, Halliburton


managementREPORT

8/10/2019 EPM-4


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http://slidepdf.com/reader/full/epm-4 19/111 Apri l 2012 | EPm ag.com 18

do not shatter during produc-

tion. Ten years ago, the com-

pany introduced the discipline

of strategic planning into the

business as it realized theimportance of having the

entire organization work

toward a common goal. Over

the next few years it incorpo-

rated components of various

strategic models. Management

set targets for the company

and selected initiatives to meet

corporate goals. However,

using such elements such

as Vision, Mission, SWOT

analysis, and Customer Valuepropositions, the team soon

began to realize it wanted to

take it one step further.

In 2005, the management team attended some train-

ing in which members were introduced to the concept

of a key performance indicator (KPI) BSC, and they

decided to try the approach. The team was successful

for the first time since it was measuring objectives across

the entire corporation, but there were too many objec-

tives. They used this as a learning exercise since for the

first time Shat-R-Shield was measuring performance.

The next challenge managers faced was to find meas-ures for the internal processes and learning and growth

perspectives of their operational KPI scorecard. Though

they went through the basic steps to provide the founda-

tion, they found it a bit crude. In 2008, the team obtained

training for the CEO and others, which allowed them to

redo their scorecard and move it into the next iteration

for the corporation. Results:

• The company took the operational KPI scorecard to

a more integrated balanced scorecard with these

focus areas:

– Optimized business systems;

– Improved process management; and– Improved product development;

• It implemented training for the organization to

“outsource the explaining” for the framework of

the BSC; and

• It reduced 20 strategic objectives to eight manage-

able ones.

The BSC approach achieved significant results within

the organization, both in terms of targets reached and

in terms of effecting a change in mindset throughout

the company. The organization started over with the

scorecard in 2010, and by the end of the year, Shat-R-

Shield had netted more income than in the previous his-

tory of the company. In addition to forming integrated

teams to execute these initiatives, Shat-R-Shield is cur-

rently training to cascade its strategic organization-wide

scorecard throughout the company to ensure clarity and

alignment. This is the foundation to achieve the five-

year growth strategy that it currently has in place.

Practical application to mature fieldsThis example lends itself to tying all the facets together in

a mature field. Sometimes a simple KPI-based scorecard

cannot cascade through the organization, so enabling the

cascading can impact the bottom line of the company.

When there is an ability to tie all the elements together,

companies can begin to realize the needed results within

the low-margin mature field.

Numerous oil and gas companies have implemented

this concept with varying results to transform a passive

process into a more concise daily plan. Several groups are

responsible for different aspects of mature fields. Having

a BSC that will provide the necessary metrics and alsocommunicate the corporate goals for the mature field

will add significant value and foster the communication

throughout the organization.

As simplistic as this may seem, being able to use

this methodology in a mature field when operators are

dealing with thousands of low-margin wells can add sig-

nificant value when a quick response is needed. If the

scorecard is made graphical, users will have a tool that

will provide the necessary vehicle to communicate the

overall corporate goals as well as individual field plan-

ning, deliverability, and well production.

managementREPORT

A balanced scorecard helps communicate corporate goals at the field level. (Image courtesy

of Halliburton; Source: Epmreview.com/Balanced-Scorecard-Usage-Survey-2010.html )

8/10/2019 EPM-4


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The oil and gas industry is a global business that under-

stands the meaning of “resource scarcity.” With an ever

larger workforce required to meet the needs of projects

around the world, never has this term applied so aptly to what is fast becoming one of the rarest of global commodi-

ties: human talent.

Competition for talent is reshaping

how oil and gas companies think

about their human capital needs

and the strategies they are

developing to optimize their

access to qualified workers.

This new paradigm

requires focus on using

the critical skills essential

to strategy execution andproject delivery.

Talent acquisitionand mobilityThe structural misalign-

ment between the current

skills of the workforce and

those that will be required in

the future is forcing companies

to look beyond their immediate

needs and actively participate in the

development of the industry’s future talent pipeline. Many are actively engaged with the educa-

tion sector, seeing the need to both attract students to the

industry and its occupations and to assist in defining the

new skills and competencies required to be effective in

tomorrow’s world. Partnering with leading colleges and

assisting with curriculum development have become recog-

nized activities within corporate talent management teams.

This all comes too late for the industry’s middle-tier

employees. Skills are being developed in new graduates,

and these are well developed in the over-50 generation of

the workforce. However, these same skills are lacking in

the 30- to 50-year range. As Deloitte highlights in its 2011

Trends report, the industry has lost a generation, and the

result is a severe shortfall of experienced managers and

leaders. In response, the oil and gas industry is taking

ownership of the problem and investing heavily in the

training and development of its emerging talent.

Global rotational programs are increasingly popularas they allow employees to develop a broad base of skills

across countries and regions and work with

experienced mentors. Developing career

competencies is becoming a prerequi-

site for success in an environment

where change is constant and

challenges are escalating

in complexity.

Fortunately, technologies

supporting talent acquisi-

tion and mobility man-

agement are steppingup to facilitate this. For

organizations to accu-

rately capture the skills

of their workforce, plot

their talent whereabouts,

and link this with business

needs, fully integrated sys-

tems are required.

An integrated system provides

greater insight into available talent

and draws upon employee and recruit-

ing data to help model and plan career pro-gression routes for employees. Entry-level engineers

often join an organization with the goal of upward mobil-

ity and eventually graduating to team lead or management

level. Petroleum engineers with training and exposure to

the organization’s business can be prepared for future

advancement.

Employees benefit because they gain insight into future

opportunities and potential career paths. They understand

the time commitment to advance and can identify others

who have followed a similar career trajectory. Managers

and employees have access to more information, which

The face of the oil and gas industry

is changingHow are large, global organizations – many with long and entrenched histories and practices –

aligning their workforces to leverage today’s business opportunities in the new world?

Sylvia Vorhauser-Smith, PageUp People


managementREPORT

8/10/2019 EPM-4

http://slidepdf.com/reader/full/epm-4 22/111EPmag.com | April 2012 21

facilitates productive conversations and meaningful devel-

opment plans that correlate to the organization’s goals.

Talent management technology that provides a line

of sight into required competencies, training requisites,certifications, and other data points across the global

talent base help managers better understand available

talent, where the gaps are, and the development needs

for future success. Using the system, organizations can

foster mentoring relationships to help employees develop

new skills and prepare for advancement. This serves the

dual purpose of keeping employees engaged while

demonstrating the company’s commit-

ment to internal growth.

For multinationals operating in

numerous countries and workplace

jurisdictions, the complexities of talent management are making robust and

dynamic systems essential to effective

workforce management. This complex-

ity is exacerbated by the growing trend

of large multinationals being headquar-

tered predominately in OECD coun-

tries yet experiencing their greatest

growth in the emerging markets. The

borderless workplace needs a border-

less workforce.

Career planning, performance, developmentIncreasingly, organizations recognize that performance,

development, and employee career paths sit on the same

continuum. High performers require constant develop-

ment to challenge and grow their abilities, and career pro-

gression is their goal. Most organizations today recognize

the necessity for the dual-career carriageways of manage-

ment and technical mastery, the former developing lead-

ership breadth and the latter functional depth. In fact,

career paths and career plans are emerging as the leading

indicator of employee retention and are a “go/no-go”

deciding factor for many “Gen Y” employees.

Companies are actively surveying their employees tounderstand what really matters. Many have workforces

that span four generations: their wants and needs are

as diverse as their constituents, and the concepts of pro-

gression and rewards can have a variety of meanings. For

example, many mature workers are more interested in

flexible work and mentoring others than climbing the cor-

porate ladder. By contrast, young workers want a clear line

of sight to career advancement and specific development

milestones that will enable them to achieve rapid progres-

sion. Again, technology is the talent manager’s friend.

With the ability to dynamically map, link, and illuminate

career path options, talent management technologies that

unify processes from talent acquisition to succession plan-

ning allow both the employee and manager to optimize

career planning.

Knowledge transfer, succession managementMultinational corporations are subject to a “double

whammy” knowledge transfer challenge: shifting knowl-

edge from senior, experienced (and soon-to-be-retiring)

employees to the next generation and leveraging organi-

zational know-how and best practices across geographic

and cultural boundaries.

Inter-generational knowledge transfer

requires recognition of the differences

in preferred approaches to ensure the

exchange is optimized. Much researchhas highlighted differences, for exam-

ple in learning styles and communica-

tion channel preferences, between

older and younger workers. Across

cultures, different values, norms, and

expectations can present roadblocks to

effective knowledge transfer, to which

many frustrated expatriate leaders will

attest. The oil and gas industry has its

own additional challenges: offshore oil rigs and remote

sites can limit access to technology we otherwise take for

granted. Together, there is any number of hindrances tothe orderly and timely transfer of information from point

A to B.

The ultimate litmus test of effective talent management

is the bench strength of an organization’s succession plan.

Succession tests the applied processes and tools of all the

other stages of the talent management life cycle:

• Robust sourcing and selection practices fuel the

succession pipeline with new recruits and fresh

experience;

• An effective performance process engages high

performers to produce and excel;

• Active development processes continuously build thecapabilities required of employees in the future; and

• Dynamic, challenging career paths stretch employees

and create the conditions that allow them to reach

their full potential.

All change brings both threat and opportunity. The

changing face of the oil and gas workforce requires a

talent management response that leverages the opportu-

nities through the application of new processes and sup-

porting technologies. In this high-growth and competitive

landscape, human resources are scarce, and the war for

talent is real.

managementREPORT

The borderless

workplaceneeds a

borderless

workforce.

8/10/2019 EPM-4


Putting people on offshore platforms, FPSOs, and

other remotely operating vessels just for training pur-

poses not only is costly, but it introduces risk to platformoperators, their co-workers, the facility itself, and the envi-

ronment. Because of advances in simulation, visualiza-

tion, and interactive gaming technology, however, it is

now possible for offshore operators to learn much of

their craft in a safe, realistic training environment.

Reducing risk Virtual reality simulation is particularly well-suited for

use in upstream E&P, where remote and unsafe

locations are increasingly common. This type of

technology enables platform operators to receive

80% to 90% of their training in a virtual environ-ment, which can significantly reduce cost and

risk. For example, risk of injury can be elimi-

nated because operators are not immediately

placed in an unfamiliar offshore environment.

They are less likely in a position to make a mis-

take that could lead to negative consequences,

such as a spill, and less likely to encounter an

emergency situation they have never before

experienced.

Simulated training also is useful for operations

based in extreme climates such as the Arctic or

in remote locations. For such sites, it is better todeploy fully trained operators rather than rely on

only partially trained operators who are expected

to learn in the field. The risk to operators, equip-

ment, and the environment in such extreme

locations might be comparable to other closer or

near-shore locations, but if the trainee somehow

instigates an emergency or other abnormal situa-

tion in such remote and harsh environments, it isharder to respond as efficiently.

Simulated training can be especially valuable

in high-hazard areas. Some drilling areas in the

Caspian Sea, for example, come with a high amount of

sulfur and sour gas, with high pressure levels and very

high temperatures. Sending untrained or partially

trained operators into these environments is dangerous.

Advanced training, however, can reduce the risk consid-

erably. Using virtual reality simulation, trainees canrehearse and respond to problems and abnormal situa-

tions repeatedly so they know exactly where they are

supposed to be and what they are supposed to do if the

situation occurs in real life.

Managing new talentSimulators also provide access to and knowledge of facil-

ity processes, enabling remote management through

digitalOIL FIELD

Virtual reality simulation

improves offshore training, safetyThree-D virtual reality simulators provide high-fidelity operations, maintenance, and safety

training in a cost-effective, low-risk setting.

John Gilmore, Invensys Operations Management

The EYESIM immersive virtual reality training system integrates virtual walk-

throughs of facilities such as this offshore oil platform with advanced simu-

lation and modeling software. (Images courtesy of Invensys Operations

Management)

8/10/2019 EPM-4


Breaking

Arctic barriers .

.nn

W

No

11IM ,

Z

At ION ,

we

are

driven

to solve the toughest problems

in

the most

challenging environments.

In the frigid

waters of

the

Arctic

where

no

modem seismic existed

, ION

created

and

employed

new technologies that

enabled data

acquisition und er ice. As a

result

, ION

was able to

acciuire

data further north than ever

before

and dramatically extend the

traditional

data

acquisition sea son. From the

Arctic

to the desert ,

transition

zone

, shallow

obstructed

marine

and other

demanding

environments,

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unmanned execution and robotic control in hazardous

areas. Simulators can help train operators on new sys-

tems as well as train new or younger operators andengineers in a real-time, immersive environment, help-

ing companies retain and replenish the specialized

knowledge they need to improve their operations.

Not only does simulation provide trainees with a more

realistic environment for extended practice sessions,

it promotes safer shutdowns

and turnaround and also speeds

knowledge acquisition by expos-

ing operators to best practices,

procedures, and site-specific

processes more quickly, further

reducing the risk of operatorerror. Users interact with the

virtual facility via devices such

as game controllers, data gloves,

or joy sticks. Special optical

and audio devices such as

head-mounted displays, 3-D

graphics, and surround sound

provide a realistic setting for

training simulation.

New software

One virtual reality system that isbeing implemented in upstream

oil and gas applications is the 3-D

EYESIM immersive virtual reality

solution from Invensys Opera-

tions Management. The EYESIM

technology links control room

operators to field and mainte-

nance operators by means of a

high-fidelity process simulation

and virtual facility environment.

It provides complete facility crew training to improve

skills that are critical to safety by enabling operators toperform tasks in a simulated environment, allowing them

to react quickly and correctly, facilitating reactions in

high-stress conditions, and instilling standards for team-

work and communications.

The Invensys solution is based on a modeling engine

powered by the company’s SimSci-Esscor DYNSIM simu-

lation software, which is coupled with a high-performing

virtual reality engine and a high-quality 3-D modeling/

scanning toolset. The simulations are based on first-

principle modeling of the platform so the operator

experience is similar to what would be experienced

on a real platform, right down to ambient noise, light,

and conditions.

The EYESIM simulator has now been extended toiPhone and iPad users, and all “touch” facilities are

available for a complete user experience. The mobile

EYESIM offering, using Cloud computing, allows users

to be “virtually” trained on systems, operational proce-

dures, and plant environments. Extending the EYESIM

model to mobile devices allows

unfettered access to procedures,

processes, and operational state-

ments of work without having to

be at a terminal.

The mobile EYESIM also can be

used for simulating facility experi-ences in the classroom. Instruc-

tors and supervisors can monitor

dynamically and in real time a

trainee’s position and behavior in

the virtual facility environment

through a client application run-

ning on a hand-held device.

Increasing safety,efficiencyExperience is sometimes defined

as “recognizing your mistake thesecond time you make it.” Virtual

environments help teach trainees

how to adapt to rapidly changing,

extremely hazardous operating

conditions so they can make their

first mistake in a risk-free envi-

ronment. These are the skills

operators traditionally have had

to develop within the school of

hard knocks.

Simulation technology serves a valuable HSE function

as well because operators are more fully and capably trained before implementing an operational procedure

or process. Simulators can be used for predictive analy-

sis, teaching safety procedures such as escape routes,

tracking and visualization, accident investigation, and

standardized escalation and remediation procedures. By

documenting safety and environmental procedures, sim-

ulators also can facilitate and improve regulatory com-

pliance with the goal of helping to reduce emissions.

Three-D immersive virtual reality training helps trainees

achieve goals quicker and with fewer risks to themselves,

their communities, and their environment.

The mobile EYESIM offering allows operators

to simulate and monitor systems, operational proce-

dures, and plant environments in a

virtual environment on hand-held devices.

digitalOIL FIELD

8/10/2019 EPM-4


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The world is now entering a new era of big scale in which

the amount of data processed and stored by enterprises

is breaking down existing architectural constructs. A major reason for this breakdown is that data are growingon two axes: volume and usage.

The industry has coined the expression “big data”

to describe this, and although there is no universally

accepted definition, International Data Corp. defines big

data as “a new generation of technologies and architec-

tures designed to economically extract value from very

large volumes of a wide variety of data by enabling high-

velocity capture, discovery, and/or analysis.”

The massive increase in scale is occurring for a number

of reasons. The one that has the most impact on the oil

and gas industry is the enormous growth in machine- anduser-generated data such as microseismic, multicompo-

nent 4-C, and time-lapse seismic data from distributed

control and surveillance systems; downhole sensors;

mobile devices; and myriad other sources. Cost pressures

also are driving consolidation of data centers – enterprises

can no longer afford business units to run their own IT

infrastructure. Planned moves to cloud computing and

the demands of hundreds of thousands of users on fewer

centralized systems all contribute to the need for new

thinking to accommodate this increased scale.

A change in mindsetFor decades, the industry has been living on the frontierof data storage, compute, and visualization technologies in

areas such as seismic imaging, real-time data, and reser-

voir modeling. Companies manage petabytes of data and

generate new data at rates between 30% and 70% a year.

The ability to store large amounts of data is evident, but

the real challenge is being able to acquire, process, man-

age, and turn such voluminous data into insight, make

information available to the right people, and to do it all

in much shorter time frames. All of these forces together

are putting an enormous amount of pressure on existing

infrastructures, from compute and applications to net-

work and, especially, the data storage platform.

Traditional approaches are not able to scale to the level

needed to ingest all of the data and to analyze, deliver, and

store at the speeds required in the new big data era. Big

data is breaking today’s storage infrastructure along three

major axes:

•Complexity. Data are no longer just text and numbers;

data deal with real-time events and shared infrastruc-

ture. The information is now linked, it is high-fidelity,and it consists of multiple data types. Applying normal

algorithms for search, storage, and categorization is

becoming much more complex and inefficient;• Speed. High-definition video, sensor data, seismic data

– all of these have very high effective ingestion rates.

Businesses have to keep up with the data flow to make

the information useful. They also have to keep up

with ingestion rates in order to drive ever faster busi-

ness outcomes; and

•Volume. All collected data must be stored in a location

that is secure and always available. With high volumes

digitalOIL FIELD

‘Big Data’ requires efficient analytics,

bandwidth, contentAs the amount of important information continues to increase, companies will need to think

creatively to manage and act on it.

Peter Ferri, NetApp

Big Data will challenge companies to master their ABCs – ana-lytics, bandwidth, and content. (Image courtesy of NetApp)

8/10/2019 EPM-4


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http://slidepdf.com/reader/full/epm-4 30/111EPmag.com | April 2012

digitalOIL FIELD

of data and such ridiculously large files, IT teams have to make decisions

about how, where, and how long to store data without increasing opera-

tional complexity. This can cause the infrastructure to quickly break on

the axis of volume.NetApp has divided the solution sets for managing data at scale into three

main areas called the “Big Data ABCs”: analytics, bandwidth, and content. Each

area has its own specific challenges and unique infrastructure requirements.

Providing efficient analytics for extremely large datasets is critical. Compa-

nies are laying the foundations for the digital oil field, and monitoring tech-

nologies are streaming hundreds of gigabytes of information a day for a single

field. With new computational approaches like Hadoop and next-generation

data warehouses from vendors like Teradata, companies will be able to gain

increased insight from this data, predict future performance, and solve prob-

lems in real time.

Bandwidth solutions focus on obtaining better performance for very fast

workloads like seismic imaging. Companies are acquiring higher resolution andhigher density wide-azimuth datasets and are using much more complex pro-

cessing algorithms to meet the reservoir challenges around deep water, subsalt,and presalt. Trace densities now are in the millions of traces per square mile,

and channel counts are in the hundreds of thousands. All of this is pushing past

the limits of today’s processing facilities and infrastructures. In these environ-

ments it is common to talk about data throughputs in the tens of gigabytes per

second and storage densities approaching two petabytes in the space of a single

computer room floor tile.

The content solution area focuses on the need to provide boundless secure,

scalable data storage. Content solutions must enable storing virtually unlim-

ited amounts of data so enterprises can store as much data as they want, find

them when they need them, and keep them forever. It is estimated that overthe next five years, digital archive capacity will grow nearly 10 times. This is

ushering in new object-based storage solutions and access methods like cloud

data management interface to addresses the needs of these organizations to

access petabyte-scale globally distributed repositories across multiple sites.

Enterprise-level efficiency features also are helping to stem the tide of capacity

growth through features such as data deduplication and lossless compression

that can reduce the storage requirements for both pre- and post-stack seismic

data by as much as 50% – significant savings for the multipetabyte environ-ments typical in upstream oil and gas.

Data life cycle

The Big Data ABCs should not be seen as distinct silos but rather as stages within a data lifecycle as data flow through these segments. For example, an

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Those of us with a few decades under our belts can

remember a workplace in which computers did not

exist. By and large, we’ve welcomed computers and

their subsequent improvements – the mouse, color

monitors, e-mail, and Internet access.

But few things drive productivity better than ade-

quate storage devices. It used to take five or six floppy

disks to load some computer programs; now that can

be managed with a single CD. I once owned an exter-

nal hard drive, not as a backup but because I neededthe extra storage space. With the advent of the USB

interface, a flash drive or memory stick can store

gigabytes of data on a device no bigger than my

little finger.

In the world of geophysics, USB

drives have had an immediate and

impressive impact on the trans-

fer of seismic and well log

data. These are large

datasets that usually can’t

be e-mailed or even

stored on a DVD. But with the USB drive rev-

olution, geophysical

contractors typically

deliver data to their

clients on devices that

connect via USB ports.

This may be changing.

Several major companies,

concerned about security

and malware issues, are mov-

ing to ban the use of USB ports

within their companies. While this iscertainly a quick solution to the security

issue, the backlash that will be felt within E&P

departments will be huge.

I’ve talked to several geophysicists who are con-

cerned that this ban will seriously hamper their ability

to collaborate with other companies. They also worry

about how they will get their seismic data from their

suppliers. And they worry about presenting at confer-

ences. When presented with alternatives such as e-

mailing the presentation or using their own laptops,

many simply find these solutions unacceptable, partic-ularly when a PowerPoint presentation containing

seismic examples can be several megabytes in size.

Additionally, some companies are banning the use

of DVDs and CD-ROMs, which have been

industry standards for years for archiv-

ing technical conferences and pro-

viding collateral material such

as maps from contractors.

Some companies will pro-

vide exceptions to an out-

right ban, but even those

will require passwordprotection and encryp-

tion, which can slow

things to a crawl.

I think it’s time for

the industry to come

to grips with its dueling

needs for productivity and

protection. The IT industry

can be a huge help here.

Already Cloud computing is

reducing data storage and pro-

cessing headaches in other industries,and its adoption in the oil and gas indus-

try could reduce the need for external storage alto-

gether. In the meantime, care needs to be taken not

to make such all-encompassing decisions without

proper analysis. Banning USB inter-

faces might solve the security

issue, but geoscientists and

engineers are not going

to be very happy with the

consequences.

USBs – Friend or foe?

The lowly, ubiquitous USB port is at the center of a controversy at

major companies.


EPmag.com

RHONDA DUEYSenior Editor

[email protected]

31

explorationTECHNOLOGY


8/10/2019 EPM-4


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Yet again, the SPC/IADC Drilling Conference show-

cased an impressive amount of new tools and tech-

nology bound for field applications worldwide. Held

in San Diego, Calif., March 6-8, the drilling sector was

well represented by a number of companies working to

increase drilling efficiency through the application of

innovative new technology.

As the shale plays of North America and abroadbecome more important to overall reserves, technology

is trending toward enhancing these applications.

Rotary steerable systems (RSSs) have been in play for

some time and have proven to be a valuable asset when

building curve to access the reservoir sooner. Meeting the

challenges of drilling unconventional plays is time-consum-

ing with conventional tools. Even with current RSS systems,multiple trips are sometimes required, which can increase

cycle times for spud to first production.

A new RSS system was launched in San Diego that may

allow operators to access shale reserves in one fast run.

The AutoTrak Curve RSS from Baker Hughes wasdesigned to kick off deeper into the well, exposing

more of the reservoir.

For most unconventional plays, there is a high demand

for greater buildup rates to maximize the lateral lengths

in the reservoir. Operators typically rely on steerable

motor assemblies to drill the curve and lat-

eral. According to Baker Hughes, the Auto-

Trak Curve system is capable of drilling

curves at a buildup rate of up to

15˚/30 m (100 ft) with continuous

drillstring rotation. One of the

key benefits of this system isthat it can be used to drill the

vertical, curve, and lateral

section, typically in a sin-

gle run. By eliminat-

ing slide intervals

and improving

rate of ROP, this

system may help drillers to

reduce cycle times even further.

According to Mathias

Schlecht, Baker Hughes vice president of Drilling Service,

“In some shale plays, the AutoTrak Curve system has

reduced drilling time up to four days and saved operators

60% of the rig time per well,” he said.In addition, continuous string rotation reduces torque

and drag for better wellbore quality. This also reduces

cleanup time and eases the path for casing running and

fracturing operations. Landing the reservoir faster

increases the pace for the remaining processes such as

completing, producing, and moving to the next well.

The AutoTrak system is fitted with on-bottom downlinkcommands for fast directional control. The commands

can be sent manually using rig pump controls, a design

feature included to limit the footprint on the rig site.

The tool also can be controlled from the surface com-

puter using the automated downlink system. The system

allows steering targets to be changed without interrup-

tion, and the optional battery allows directional surveys

while making connections.

Time will tell if this system is viable. This closed-loop

drilling system is fully programmable and has currently

undergone more than 10,000 hours of rigorous field test-

ing in some of the toughest unconventional environ-ments in North America, according to Baker Hughes.

“We specifically engineered this system to meet

the needs of those drilling in unconventional oil

and gas plays,” said Scott Schmidt, president

of Drilling & Evaluation. With fewer com-

ponents than the typi-

cal RSS tool, the

company hopes to drive a new

performance and reliability

standard.

For

mostunconventionalplays, there is a highdemand for greater

buildup rates to maximizethe laterallengths in

the reservoir.

wellCONSTRUCTION

New RSS drills from spud

to TD in one runSystem offers smarter well bores with more directional control.


EPmag.com

TAYVIS DUNNAHOESenior Editor

[email protected]

EPmag.com | April 2012 33

8/10/2019 EPM-4


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The era of the Arctic as an offshore producing

province is upon us. Innovations in production flow

assurance, subsea technologies, long-distance tiebacks,

real-time remote control and monitoring – and of

course ice-resistant platforms where needed – mean

that pioneering developments are starting to proceed

in this harshest of environments.Russia is taking a lead role in the opening up of the

Arctic Circle, especially while authorities in Alaska and

Canada stall their plans as regulations are necessarily

reviewed post-Macondo. The start of production drilling

in Russia’s Arctic waters from Gazprom’s Prirazlomnoe

platform in the eastern Pechora Sea is due this summer

or sooner.

The importance of this activity being carried out to

the best of the industry’s ability, and with zero margin

for error, cannot be overstated. We all saw how the indus-

try was portrayed and perceived following Macondo.

So the efforts this industry is taking to enhance itscapabilities in this regard should be applauded. At a

recent gathering of oil industry representatives, govern-

ment, and academia in Norway, the Vice Chairman of

the operators’ association Oil & Gas Producers (OGP),

Joep Coppes, stressed the work of its Arctic Coordina-

tion Task Force and how the industry can contribute to

the sustainable development of the “High North.”

Earlier this year, the OGP formed an Arctic Oil Spill

Response Technology Joint Industry Project (JIP) with

Shell, ExxonMobil, Statoil, BP, Chevron, Cono-

coPhillips, Eni, North Caspian Oil Co., and Total.

The JIP is researching seven areas:

• Behavior of dispersed oil under ice and dispersant

efficacy-testing in Arctic environments;• Environmental impacts of Arctic spills and the

response to them;

• Trajectory modeling in ice;

• Oil spill detection/monitoring in low visibility and ice;

• Mechanical recovery;

• In situ burning in Arctic environments; and

• Experimental field releases.

According to Joe Mullin, JIP program manager, pre-

vention of spills is a priority as well as the response to any

spill that could occur. “In the last few decades,” he said,

“the industry has made significant advances in Arctic

spill prevention and response technology, and by work-ing together in this four-year JIP, we will increase knowl-

edge and opportunities to test equipment, conduct field

experiments, and develop oil spill response technology.”

But with the JIP not due for completion for four

years, is this the time for the industry to ask itself

whether it should undertake any Arctic

activity until the findings of this study

are known? The consequences, if

the industry proceeds unpre-

pared, could be disastrous.

productionOPTIMIZATION

Is the industry brave enough tofreeze its Arctic plans?With Gazprom to start production drilling soon in the Arctic offshore, theneed for the industry’s oil spill prevention and response capabilities in thefrozen North to be ready for action should be paramount.


EPmag.com

MARK THOMASInternational Editor

[email protected]

Gazprom’s Prirazlomnoe platform is on location in the Pechora

Sea and will soon start drilling production wells in an area

where the ice can attain a thickness of 50 m (164 ft).

(Photo courtesy of Gazprom)

8/10/2019 EPM-4


Apr il 2012 | EPma g.com

COVER STORY:

ISK MANAGEMENT

Balancing risk& reward

Rhonda Duey

Senior Editor

‘Always be prepared’is not just for Boy Scoutsanymore.

oiled down to its bare essentials, “risk manage-

ment” is not that hard a concept to under-

stand. It requires identifying dangers,

assessing the likelihood that they will happen, determin-

ing their potential impact, and deciding whether to take

the plunge or play it safe.

The oil industry is no different than other industries in

that it has to manage risk. The difference lies in the num-

ber of risks that need to be managed. Obviously there is

the geological risk of drilling an expensive dry hole or

encountering a dangerous gas kick while drilling. There

is technical risk in terms of equipment failures as well as

the traditional geological and engineering uncertainties.

There is financial risk; regulatory risk; market risk; risk for

the security of personnel; and above all risks associated with

health, safety, and the environment. Managing all of theserisks in an effective manner is an enormous challenge.

“Traditionally in risk management everything is very

siloed,” said Guarav Kapoor, COO of MetricStream. “Each

group is handling risk at the business level or at the func-

tional level.” Kapoor and other experts hope to see this

shift to risk management at the corporate level.

Enterprise risk managementKnown as enterprise risk management (ERM), this con-

cept is the purview of a few specialty consulting firms like

MetricStream and HSE Technology Corp. Jason Rhoads,

general manager of ERM Services and Solutions for the

latter, said ERM is a “big animal.”

“We try to separate the strategic side of ERM by working

with executives and general managers to determine

a technological roadmap of how to get to where they

want to be with their enterprise,” he said. “It’s taking

off little bites.”

This approach, he added, is across the board – legal

risk, reputational risk, operational risk, etc. “The

roadmap of technologies could be 10 years out, and they

start working with individual iterations to get there.”

The company works with multiple software vendors to

help oil and gas companies refine their risk manage-ment strategy. The goal is to centralize that strategy,

allowing executives to identify and allocate assets to

the high-risk areas of the organization.

“You should be able to reallocate assets across your

organization because it’s a company you are trying to

run, not individual departments,” Rhoads said.

Added Kapoor, “In the last three or four years we

have been seeing a major shift toward what I call

integration of risk management, which means that

companies are starting to realize that the impact

of one risk failure on another risk failure is very

high. Let’s say the price of oil goes up and some currency

fluctuates, and then there is an oil spill – the impact can

be compounded 40 times.”

Up all nightThis type of integrated approach can help managers sleep

more soundly at night, Rhoads said. “You can put a system

in place with Excel worksheets, Access databases, and

forms, but the process doesn’t exist in technology; it exists

among people, procedures, and policies,” he said. “You do

training so people follow these policies and procedures.

“The system is an aid, but it’s not going to make people

do their jobs.”

Current risk management software, he said, has action

item management. “Being able to digitally assign action

items, determine what needs to happen and why, deter-mine what it is attached to, who needs to do it, and by

when, will give a person a good night’s sleep. I think peo-

ple are good at identifying what happened, what went

wrong, and what was done, but when you get down to

addressing corrective actions, that’s a gray area.”

The magnitude of the problemHow big a deal is risk management? Big enough that

Michael Walls, a professor in the Division of Economics

and Business at the Colorado School of Mines, has for

many years taught a three-day course on “Managing Risks

and Strategic Decisions in Petroleum Exploration and

Production.” Walls’ course focuses on techniques for man

aging the entire complement of risks associated with the

E&P sector. Using advanced techniques in decision analy-

sis, sensitivity analysis, value of information, and portfolio

management, Walls demonstrates how companies can

take a comprehensive approach to risk management and

prudent decision-making.

Yet even within this scope Walls said that companies

need to refine their approach to risk. “Even today some

companies think about valuation and petroleum issues in

a deterministic fashion, meaning they are not considering

the uncertainties they face; they are not thinking in aprobabilistic or stochastic fashion,” Walls said. “Many firm

have become much more sophisticated in thinking about

the issues they face in a probabilistic way, thereby improv-

ing the quality of their E&P decisions. But there are still a

lot of companies that have not adopted these techniques

in a comprehensive manner.”

Often, he added, company analysts might understand

probabilistic thinking, but their senior managers still

approach problems and decision-making in a determinis-

tic manner. “When I work with companies, I try to get

them to think more probabilistically. They live in an

COVER STO

RISK MANAGEM

EPmag.com | Apr il 2012

B

8/10/2019 EPM-4


uncertain world, and that’s what we’re trying to get them

to better characterize.”

Walls agreed that risk management has to become part

of the corporate culture, and he added that companiesneed to evaluate all of their risks and understand how they

influence potential outcomes and performance. “Man-

agers must consider the interaction between the risks that

they face,” he said. “Just as individual investors try to

reduce risk through diversification, E&P firms can con-

struct diversified portfolios of E&P assets to reduce their

exposure to risk.”

A simple example is a company whose assets are all nat-

ural gas. Their price risk and asset values fluctuate in

direct correlation to the price of natural gas. Most compa-

nies reduce this risk by having more diversified portfolios.

The same can be said of technical risk. A company withconventional projects in the Gulf of Mexico and uncon-

ventional projects in the Marcellus shale has uncorrelated

technical risks because the geology is completely different

in the two regions.

“Companies should try to capture some of these uncor-

related outcomes and properly mange assets to allow the

firm to minimize its risks and preserve return,” he said.

“To do that in a sophisticated way, you have to understand

the risks that you face in each project, and you have to

understand how project X correlates with project Y.”How does a disaster like Macondo factor into the risk

management scheme? “Macondo was one of those low-

probability outcomes with a significantly high impact, and

it’s so far out on the distribution curve that most of us

don’t even think about it,” Walls said. “It’s clearly a lesson

in why we should think about and better understand these

low-probability, high-consequence events.

“As a manager, I’m trying to understand how a whole

series of independent events all lined up perfectly to cause

this to occur. In fact, there are uncertainty analysis tech-

niques called rare-event simulations that allow us to better

understand these kinds of risks and communicate theireffects to decision makers.

“In the future there will be something in that set of

events that will cause a company to catch it and keep it

from happening again. It is all about providing clarity with

regard to the uncertainty firms face and improving the

quality of decisions under conditions of uncertainty.”

COVER STORY:

RISK MANAGEMENT

It is one thing to manage risk from an office or board

room. It is quite another thing to manage risk when

pirates are boarding one’s drillship or local communities

are blowing up one’s pipelines.

For AKE Ltd., a risk mitigation company, managing

these risks is all in a day’s work. The company provides

clients with analysts who keep them up to date on risks in

areas in which they operate. For a global industry like oil

and gas, this type of intelligence can be critical to keep-

ing operations running smoothly.

“Anywhere where there tends to be instability in the

world, you’ll find other sectors that pull out,” said John

Drake, a senior risk consultant with AKE. “But energy com-

panies have a little higher risk tolerance. They are more

willing to face risk to do business.”

What kinds of risks do they face? Kidnapping is a major

fear, as is piracy and terrorist attacks against assets such

as platforms and pipelines. Often, Drake said, it boils

down to local communities that feel they are not benefit-

ting from the presence of the energy industry.

“They want to express their frustration at that, so they’ll

attack the nearest representation of the industry,” he said.

But different groups strike out for different reasons.

Somalian pirates, for example, are in it for the money.

They are intent on finding out who owns the vessel to

demand a ransom. “The perception off the coast of Soma-

lia is that a ship associated with the oil and gas sector is

likely owned by a very rich, powerful organization that

will be able to pay a large ransom,” he said.

Piracy off the coast of Nigeria, on the other hand, is often

more politically motivated. “They are interested in making

money but also are trying to put political pressure on the

government,” Drake said. “Their attitude seems to be,

‘We’re going to keep attacking the oil and gas industry

until we see some benefit from it in our infrastructure and

schools and services.’”

Ultimately, he said, piracy stems from three factors:

poverty, lawlessness, and proximity to major shipping

lanes. The energy industry will not be able to change

poverty or lawlessness in a country like Somalia. But it can

be prepared. “People worry about the cost of risk man-

agement because it can seem like a big cost center,”

Drake said. “But if you do it properly, it’s a structure of costs

you can factor into your accounting.

“If you have an incident, the costs can start to mount

very quickly. It’s an unknown factor.”

Risky businessRisk management is never more acute than when human lives are in danger.

8/10/2019 EPM-4


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COVER STORY:

RISK MANAGEMENT

Collaboration is increasingly critical to managing

well construction risk. While technology produces

remarkable results, the most significant gains in well-

bore construction process safety are being achieved

across traditional disciplines, products, and services.Bringing drilling contractors, manufacturers, and

service companies into the well planning process at an

early stage captures resources that are rich in expertise

and technology and orients them toward the overall

objective of constructing a high-integrity well bore to

total depth (TD). While this is not novel, it is ever more

imperative to ensuring project success.

In difficult wells, process safety is a major considera-

tion to the execution of well construction. Subsurface

conditions in these wells are pushing traditional tech-

nologies and work processes to their limits. Delivering

discrete technologies and siloed services can be limitingand potentially hinder success.

Technologies such as closed-loop drilling (CLD) and

drilling-with-casing (DwC) are information-intense and

cross-discipline by nature. They require a new level of

industry collaboration and engagement.

Finding new answersThere is a significant difference between being asked to

run 457 m (1,500 ft) of 133 ⁄ 8-in. casing in the hole and in

helping mitigate hazards and ensuring wellbore integrity

to TD. That difference changes the relationship from a

“call-out” service to a collaborative partnership with ashared measure of success.

Greater alignment with the success of the project leads

all parties to engage in collaborative risk assessment

within the context of the operational envelope. The ear-

lier in the project cycle this collaboration occurs, the

greater the degree to which the outcome can be positively

influenced. By collaborating, operators and service com-

panies are in a much better position to understand, antic-

ipate, and mitigate risk as well as reduce costs.

In particular, this collaboration taps into the strengths

of integrated service companies. In addition to novel

technologies, these organizations provide important

new perspectives and experiences. Cross-discipline

experts and engineering assets encourage a high degree

of interaction within these services and with the opera-

tor. This collaboration is the vehicle for identifying new

options and arriving at new solutions for enhancing

process safety throughout wellbore construction.

Closed loop enhances well controlProcess safety contains many elements, not the least of

which is maintaining well control through the well con-

struction process. Well control involves understanding

and managing wellbore dynamics such as pore pressure

and fracture gradients while drilling with the intent to

eliminate or mitigate well control events and anomalies.

Traditionally, well control has largely been the

province of mud systems and BOPs. But these methods

alone are increasingly insufficient to manage HP/HT

wells and narrow pore-pressure/fracture gradient win-

dows. The repercussions are well control incidents andthe inability to execute planned well designs that reach

TD with the optimal hole size.

The leading edge of enhancing primary well control is

a set of scalable CLD technologies. These systems, which

include various managed pressure drilling (MPD) meth-

ods, use a novel fluid circulating system to achieve a

major advance in wellbore monitoring and control. The

advances are having a step-change effect on enhancing

the protection of people, the environment, and assets.

Less time spent fighting well problems also can result in

a significant reduction of costs.

Collaboration with the operator early in the planningprocess is imperative to successful CLD applications.

The importance lies in the fact that CLD applications

must be engineered according to subsurface factorssuch as lithology, pressures, and temperatures. The plan-

ning process also facilitates training of operator and rig

personnel on various closed-loop methods. Planning

also helps anticipate modifications to deepwater rigs,

which may involve changes to riser systems and deck

accommodations. This type of collaboration already is

impacting new rig designs that anticipate closed-loop

configurations.

Collaboration enhances

process safetyWorking with service companies early in the planning process drives efficiency.

David Pavel, Weatherford International Ltd.

8/10/2019 EPM-4


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COVER STORY:

RISK MANAGEMENT

Total depth collaboration Another critical element to process safety is wellbore

integrity. From a tubular running and casing drillingperspective, collaboration is fundamental to the well

construction process. This leads to novel hazard mitiga-

tion methodologies that integrate advanced tubular run-

ning service capabilities on the rig floor with extensive

subsurface expertise and capabilities.

Multidisciplinary service company engineers provide a

common interface with the operator to identify, under-

stand, and mitigate subsurface hazards. This in-depth

engineering expertise is essential to developing a clear

understanding of operator objectives. These engineers

engage a broad scope of in-house specialists to help

define potential wellbore problems and recommend

appropriate methods and ancillary technologies withinthe context of constructing a high-integrity well bore to

the planned objective.

This collaborative process guides the application of

DwC technology, which enables rotation, reciprocation,

and circulation while drilling with the casingstring. An

inherent advantage to process safety is the ability to isolate

trouble zones such as lost circulation or over-pressured

zones behind-pipe while drilling and casing the well.

In addition, the ability to reciprocate the pipe during

cementation results in better cement placement that

enhances zonal isolation. This not only improves long-

term wellbore integrity but also aides in preventing well

control issues that could result in a blowout.

The ability to rotate and circulate casing in apredrilled section helps ensure that casingstrings are

landed at the target depth, which also helps ensure

that wellbore construction remains true to the optimal

design. Among the benefits is the reduction of long

openhole exposure times achieved by eliminating

drillpipe tripping.

Building integrated solutions While the scope of services involved vary

greatly, collaboration provides the starting

point from which the operator and

service company explore well con-struction options and innovate

solutions.

An example is a recent proj-

ect in Latin America. A major

operator was planning reentry

wells to reach reserves below a

depleted zone. The operator

was exploring options and

asked Weatherford about DwC

services. As engineers began to

explore the operator’s objectives and

challenges, the collaborative process greatly increased the options under consideration.

Ultimately it was concluded that DwC was not

the optimal solution for drilling the depleted zone.

But because project parameters were better understood,

engineers were able to recommend other better-

suited options.

The success of the effort clearly illustrates that if

operators are to benefit from consideration of all the

options, service companies should be brought into

the loop early in the planning stages.

The collaborative path ahead As the industry continues to drill more difficult wells,

the risks associated with hazards become substantially

higher, placing process safety as the paramount consid-

eration. The result is a growing need for collaboration.

By involving service companies in the planning process,

operators enhance the integration of technology and

accelerate its adoption, help drive efficiencies and pro-

ductivity, and promote cross-organizational collabora-

tion. These advances are central to enhancing process

safety and achieving wellbore construction objectives in

the most challenging applications.

A congruous approach to

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F

or centuries, inventors have used models to predict the

behavior of their inventions under various environmen-tal conditions. Model airfoils convinced the Wright broth-

ers that heavier-than-air flying machines could transport

people into the heavens. Model hulls proved the viability

of offshore vessels, including drilling rigs, long before the

actual vessel was built and launched. Today, dynamic reser-

voir models and mechanical earth models help engineers

characterize the way reservoirs will behave under produc-

tion or stimulation.

Yet the model-based approach has its disadvantages.

Whereas reservoir behavior can be characterized using

models constructed from evolving formation data, reser-

voir description still depends on painstaking, time-con-suming analysis of rock and fluid samples, both involving

discrete parameters. Application of models to predict

accurate discrete parameters in complex media has

proven to be impractical; there are too many possibilities.

About 10 years ago Bob Freedman, a scientific advisor

and project manager at Schlumberger, developed a new

method based on radial basis function (RBF) mapping

for accurately solving complex reservoir characterization

problems. The method was first introduced to the indus-try in a paper published by Freedman in the SPWLA

Petrophysics Journal, V. 47, pp. 93-111, 2006. The new

method relies on databases acquired on reservoir rocksand fluids to accurately represent the complex physics.

Over the past few years, considerable success has been

experienced in the accurate prediction of critical rock

and fluid properties that are difficult to impossible to

measure in situ .

Successes exemplify valueIn the recent past, determination of the properties of live

oil samples was time-consuming and problematic. Physical

and empirical model-based methodologies were used to

relate crude oil properties to nuclear magnetic resonance

(NMR) measurements. Nevertheless, critical properties

were difficult to determine because of the inherent com-

plexity of crude oils. The physics connecting the NMR

measurements to the oil properties are contained within a

laboratory database of NMR and pressure-volume-temper-

ature measurements performed on a representative suite

of live oil samples. By mapping NMR measurements suchas T2, for example, to live oil properties such as viscosity ormolecular composition, properties of samples not in the

database can be estimated with accuracy. A mapping func-

tion that is a linear combination of Gaussian radial basis

functions is calibrated using the database and is applied to

predict the desired properties.

The power of RBF mapping for crude oil description is

just the tip of the iceberg. The technique can be used to


IMPROVING

EXPLORATION SUCCESS

New approach

describes the indescribableAn innovative application of advanced mathematics has provided geoscientists

and engineers with an accurate, model-independent way to predict critical reservoir

properties from well log data.

Vivek Anand, Bob Freedman, Steve Crary,

and Chanh Cao Minh, Schlumberger;

Robert L. Terry, Maersk Oil Company; Loris Tealdi, Eni

FIGURE 1. Computed results of a highly complex reservoir sec-

tion illustrate excellent agreement between predicted and

measured mobility. (SPE 134011; log data courtesy of Eni)

8/10/2019 EPM-4


IMPROVING

EXPLORATION SUCCESS

predict virtually any parameter for which a representative

database can be developed.

From innovation to breakthrough

The RBF technique has been applied to the prediction of effective permeability from well log data. Effective perme-

ability has been one of the most elusive parameters facing

reservoir and production engineers. Complexities in min-

eralogy, lithology, and pore geometry, to name a few, have

made determination of this fundamental mobility param-

eter virtually impossible to predict. Formation testers can

provide spot measurements of fluid mobility; however,

these are only valid at the exact spot of the test. Connect-

ing the dots has been pure guesswork.

The famous Archie saturation relationship is the basis

of modern well log interpretation. Yet this relationship

contains saturation and cementation exponents that are just now beginning to be determinable. For NMR inter-

pretation, petrophysicists have had to choose betweenthe Timur-Coates and Schlumberger-Doll Research empir-

ical models to estimate effective permeability to oil. These

model-based techniques work reasonably well under a

limited set of conditions. Elimination of models provides

for the first time the ability to predict effective permeabil-

ity to oil under any condition.

To develop and prove this application, a worldwide data-

base of 104 whole core samples (79 sandstone and 25 car-

bonate) was developed from precise laboratory testing.

Parameters such as irreducible water saturation, effective

permeability to oil, and NMR T2 distributions were meas-ured under tightly controlled conditions. From these data,

radial basis mapping functions were developed whereby

effective permeability to oil could be accurately predicted

from readily available well log information. Extending the

application of RBF mapping techniques, such parameters

as molecular compositions; saturations, aromatics, resins,

and asphaltenes; fractions; and viscosities of live crude oils

have been estimated with unprecedented accuracy.

Field examples prove the point A complex lithology example is represented by a well

drilled using synthetic oil-based mud. Density, neutron,and resistivity logs were acquired while drilling. NMR andformation pretest fluid mobilities were acquired using

wireline tools. Figure 1 shows the results. The lithology is

a highly complex mixture of sandstones, clays, muscovite,

and dolomite (right-hand track). Oil is predominately

indicated in the clean high-porosity sands. The computed

effective permeability to oil (mobility) is shown in Track

2, with good agreement to the oil mobility test points

from the pretest pressure tool (green dots). While the

effective permeability curve appears as a continuous

black line, it is only valid in the oil sands. A completion

design that focuses on the high-permeability peaksshould provide the highest productivity.

A deepwater well provides the second example (Figure

2). While the sand body that represents the target reser-

voir is relatively large and contiguous, porosity and perme-

ability are much lower than the previous example. Despite

the uniform appearance of the sand body, the mobility

curve shows several breaks with very low relative perme-

ability. Accuracy of the permeability prediction is con-

firmed by good agreement with the pretest pressure

mobility points in Track 2. Selective perforating can

avoid the tight spots and maximize flow into the comple-

tion, especially in the shaly portion seen at the bottom15 m (50 ft) of the reservoir.

A new paradigmThe success in accurate prediction of critical parameters

in complex situations is highly encouraging. It has proved

to resolve issues that have plagued producers for decades.

In a macro sense, the application of RBF mapping her-

alds a breakthrough in formation and fluid characteriza-

tion and hints at potential applications in well stimulation

analysis and prediction as well as enhanced recovery

design and evaluation.

FIGURE 2. A high-profile deepwater well example illustrates the risk

of assuming uniform permeability by simply connecting the dots.

(SPE 134011; log data courtesy of Maersk)

8/10/2019 EPM-4


California’s Ventura basin has been in production

since 1861, the year Lincoln was sworn in as Presi-

dent and the first shots of the American Civil War were

fired. Approximately 100 oil and gas fields have been

discovered since, with cumulative production from thebasin exceeding 4 Bboe.

Although activity has slowed in recent decades, several

E&P operators remain intrigued by the basin’s explo-

ration potential. They believe discoveries remain to be

made and are working to identify bypassed targets

masked by Ventura’s complex geology; deeper zones

analogous to Oxy’s 2009 discovery in the nearby San

Joaquin basin; and sweet spots in the Monterey shale,

the pervasive source rock that has recently become an

unconventional reservoir target.

Integrated studyBecause of challenging topography, urbanization, envi-

ronmental concerns, and subsurface complexity, ground-

based seismic acquisition is not a practical alternative in

most parts of the basin. In 2010, Houston-based NEOS

GeoSolutions approached several E&P operators about

sponsoring a basin-scale survey that would rely not on any

single geophysical dataset but on a methodology in which

all available geological, geophysical, geochemical, and

petrophysical data would be accessed and simultaneously

integrated and interpreted.

A seismic image, when it exists, can be extremely useful

in revealing the structures within the earth, but othergeological and geophysical measurements can bring even

more clarity to the interpretation as they reveal important

things about basin architecture, fault and fracture sys-

tems, rock properties, and fluid distributions.

To complement existing 2-D seismic lines, well logs,

and geologic maps in the public domain, NEOS acquired

a series of airborne geophysical measurements over

roughly 2,600 sq km (1,000 sq miles) of the onshore

Ventura basin. The newly acquired datasets included:

• Gravity – to delineate deep basin architecture and

basin-scale structural features;

• Magnetics – to map regional fault and fracture networks; and

• Hyperspectral data – to detect oil seeps and micro-

seepage impacts on surface vegetation.

On some basin-scale projects like this one, additional

datasets such as radiometrics and electromagnetics also

are acquired.

These nonseismic datasets delivered new insights to the

program’s underwriters, even when interpreted individu-

ally. For instance, the gravity data showed the presence of

a much deeper sediment column in portions of the basin

that had limited well penetrations. In addition, gravity

measurements highlighted several unknown and untestedmini-basins along the edges of the main basin depocenter.

An analysis of the magnetic data provided further

exploration insight. The vast majority of the fields in

the Ventura basin are aligned with identifiable magnetic

anomalies that correlate with deep-seated fault systems,

something that could be expected in a tectonically active,

structurally driven basin. An analysis of the hyperspectral

data highlighted a larger number of seeps throughout the

basin. Geoscientists on the ground confirmed the seep

anomalies detected using the airborne sensor platform.

Armed with the location of new depocenters and mini-


IMPROVING

EXPLORATION SUCCESS

Ventura basin still holds

hidden treasureA multimeasurement exploration approach breathes new life into an old basin.

Chris Friedemann, NEOS GeoSolutions

In this gravity model of a portion of the Ventura basin, California,

deeper sedimentary depocenters are shown in purple. Produc-

ing well locations appear as black dots, dry holes as blue dots.

(Images courtesy of NEOS GeoSolutions)

8/10/2019 EPM-4


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basins from gravity data, the ability toidentify regional fault systems using mag-

netic data, and the presence of direct and

indirect hydrocarbon indicators on the

surface from hyperspectral imaging,

explorationists are now able to qualita-

tively identify new leads and play types

throughout the Ventura basin.

New exploration toolsThe NEOS methodology provides interpreters with an

additional tool to aid in the search for hydrocarbons. This

is based on a geostatistically driven, software-enabledsearch for the unique measurements and attributes that

correlate with known fields (or high production rate

wells) in a basin or designated area of investigation. Once

these “correlative anomalies” with known fields (or wells)

are identified, a proprietary software package based on

pattern recognition algorithms is used to identify the same

set of correlative anomalies in areas without well control.

In essence, the software is searching for unexploited parts

of the basin that share the same set of “geo-anomalies” as

the area’s known fields and highest producing wells.

What measurements are used as part of the search? In

the case of Ventura, nearly 50 raw datasets and calculatedattributes were considered, including items like Bouger

gravity and the first vertical derivative of reduced-to-pole

magnetic data. The methodology determines the statisti-

cal relevance of each measurement and attribute, elimi-

nates measurements and attributes that are not relevant,

and mathematically determines the weighting factors to

apply to each statistically relevant dataset and attribute.

The result is an objective, mathematically driven map of

the entire basin, highlighting areas that are being flagged

as relatively more prospective or productive. As with any

measurement or tool, the interpreter does not blindly fol-

low the output but instead uses the insights provided to

derisk previous exploration concepts and to identify pos-

sible new leads worthy of further study.

In the case of the Ventura basin, geostatistical method-ology was applied to four separate geologic horizons that

are producing today, including the shallow Pico forma-

tion, the Sespe, the Miocene (effectively the Monterey

shale zone), and the deep Eocene. The shallow zones had

more well penetrations and discoveries than the deeper

intervals. Nonetheless, even the shallow Pico contains sev-

eral high-potential exploration anomalies that have yet to

be drilled. The results become even more interesting as

the investigation goes deeper, where the number of well

penetrations into geostatistically identified anomalies is

even smaller and, therefore, the corresponding explo-

ration potential is even higher.The methodology is injecting new life into an old basin,

arming Ventura operators with the additional data and

insights they require to unlock a new wave of exploration

in the years ahead. Whether a play is old or new, conven-

tional or unconventional, a multimeasurement interpre-

tation approach can often complement data that already

exist and help geoscientists understand the attributes that

determine where fields might be located within a basin or

why some wells are more productive than others, even

when completed similarly within the same geologic hori-

zon or area of the play.

LEFT: A NEOS geoscientist “ground-truths” Ventura

airborne hyperspectral measurements using a

handheld analytical spectral device. An oil seep

exists about 2 m (6 ft) behind the geoscientist.

BELOW: In this geostatistical assessment of theprobability of liquid hydrocarbons in the shallow

Pico formation, hot colors correspond to a high

probability of oil. Black dots represent producing

wells within the Pico horizon.

IMPROVING

EXPLORATION SUCCESS

8/10/2019 EPM-4


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NCS SubSea, a company that provides survey, naviga-

tion, and positioning services for the oil and gas

industry, evaluated and approved Sparton Navigationand Exploration to provide integrated navigation sen-

sors for use in the first integrated navigation system for

the P-Cable High-Resolution Multi-streamer Seismic sys-

tem. This technology was developed to provide oil and

gas producers with an ultrahigh-resolution image of

the geology from the seabed down to approximately

2,000 m (6,000 ft). This information is valuable as it

illuminates potential hazards such as gas pockets and

chimneys as well as providing a good picture of ancient

river channels, ice gouge, and similar features. NCS

worked closely with

Subsea Systems andGeometrics to devise

the proper hardware

that would allow for

development of an

advanced software

product that provides

proper and precise

real-time positioning of

the hydrophone array.

NCS was closely

involved with both Sub-

Sea Systemsand Geometrics in

developing a naviga-

tion and positioning

technology that would

precisely and continu-

ously provide a real-

time position and

shape analysis for the

P-Cable Seismic system,

as well as ancillary in-

water equipment.

To achieve this, the companies knew they had to start

with a clean slate, meaning they did not want to use any

of the existing “off the shelf” products.

Product requirementsTo commence evaluation of a navigation system, the

product requirements had to be defined to ensure the

product chosen met the challenges of the multistreamerseismic technology application. As such, the require-

ments for a navigation system were:

• Low cost;

• Low power;

• Small size and mass;

• High accuracy;

• X,Y, and Z real-time data output;

• Robustness to withstand the elements and the rigors

of the application environment; and

• Fast update rates.


IMPROVING

EXPLORATION SUCCESS

Navigation sensor technology

aids marine seismic surveyA new digital compass provides a clear view of the geology from the seabed.

Al Hise, NCS SubSea; John Thorson, Sparton Navigation

and Exploration; Craig Lippus, Geometrics

A new compass aids in

navigating the P-Cable Towed Array.

(Image courtesy of Geometrics/Fugro West, Inc.)

8/10/2019 EPM-4


With the advent of MEMS sensor technology, the digital compass has

emerged as a leader in price-performance, offering a number of advantages

to the designer as a method of providing and maintaining accurate heading.

A digital compass typically consists of magnetometers (used to measure the

earth’s magnetic field to determine magnetic north), and accelerometers

(used as a tilt sensor to compensate for the orientation of the magnetometers


IMPROVING

EXPLORATION SUCCESS

TOP: Computed streamer positions are derived using surface GPS data coupled with the

heading information from the compass units. BELOW: The effectiveness of the software repre-

sentation is due in part to the Sparton compass. (Image courtesy of Sparton Navigation and

Exploration)

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due to pitch and roll). Digital compasses also can be aug-

mented with the use of gyroscopes (angular rate sensors

used to compensate for magnetic disturbances and

dynamic environments).

Designing the compassUltimately, the MEMS-based digital compass design met

the product requirements and was selected for testing.

Based on positive test results, Subsea Systems and NCS

chose the digital compass because of its extremely com-pact size and three-axis reference output. Another key

aspect was the Ethernet capability. The digital compass

is integrated at 6.25-m or 12.5-m (20.5-ft or 41-ft) inter-

vals along a towed wire called a “cross cable” between

two diverters, which provide the necessary horizontal

lift to spread the cable. The digital compass resides in

a titanium housing that also serves as an attachment

point for a seismic streamer. These seismic streamers

also have digital compasses integrated in their tails,

meeting another key design consideration; they have

to fit inside the existing streamer canister dimensions.

The compasses

provide accurate and

reliable heading informa-

tion, delivered over the Ethernet backbone, allowing the system to use

those headings in conjunction with surface

GPS positions to derive the true shape of the

cross-cable and the seismic streamers, all in real time.

An important design consideration was having a com-

pass that could be integrated inside of the in-water

equipment. Attaching external devices that housed digi-

tal compasses was not feasible due to the close spacing

of equipment while it was being deployed and towed.

The Sparton units met this challenge well, allowing for

even tighter spacing configurations for the in-water

equipment.

Vision of efficiencyThe computed positions of the streamers and the cross

cable are derived using surface GPS data coupled with

the heading information from the compass units. Note

the digital compass heading information in the data

form top right of the figure.

Eddie Majzlik, technical manager and product devel-

opment lead for NCS, said, “We were able to easily inter-

face with the Sparton personnel and communicate not

only on a highly technical level but also on a common

sense level; they were able to understand our needs, ableto articulate that understanding very well, and revert in

a timely manner with something that met the scope and

worked very well. Ultimately, they provided a three-axis

digital compass that was small in scale, large in function-

ality, robust enough for the offshore subsea environ-

ment, and allowed for communication and data transfer

via Ethernet.”

NCS SubSea and Geometrics/P-Cable technicians

were able to see immediate commercial success, and

they credit Sparton with playing a critical role in the

process.

IMPROVING

EXPLORATION SUCCESS

The schematic shows the P-Cable system being towed behind the

vessel and the subsequent types of near-seabed surface geo-

logic features that are imaged. (Image courtesy of Sparton Navi-gation and Exploration)

Apri l 2012 | EPm ag.com

8/10/2019 EPM-4


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Shale plays have become one of the important sources

of hydrocarbons, both domestically and globally.

Due to their unique nature, shale plays have demon-

strated challenges to geoscientists in reservoir E&P. In

searching for the sweet spots of a shale formation, geo-scientists must rely on seismic data, microseismic data,

core data, well data, and a wealth of other technologies

to characterize and model what is frequently a highly

heterogeneous formation. The defining factors of a

sweet spot include rock properties such as brittle/

ductile quality, in situ stress, and total organic content.

Project reviewThe Eagle Ford shale is located in the Western Gulf

Basin and trends across South and East Texas. This Cre-

taceous formation is the source rock for the Austin

Chalk oil and gas formation. The seismic data coverabout 340 sq km (130 sq miles) across Karnes and Live

Oak counties and was acquired by Seitel. The seismic

survey is in the primary production zone of a wet

gas/condensate window. There are two existing wells

inside of the seismic survey. The seismic data were

processed through full-azimuth prestack depth migra-

tion with continuous azimuth reflection angle gathers

as the primary outputs.

ObjectivesShales are frequently highly heterogeneous in nature.

Seismic data, with properly preserved amplitudes andsampled in the angle domain, contain information

related to lithology and rock properties. Properly

processed and analyzed, the seismic data are not only

relevant in prospect identification but also are an impor-

tant data source for well planning in a shale play. The

objectives of this study are:

• To observe shale heterogeneity by examining and

analyzing different seismic attributes such as fre-

quency-dependent attributes, structural attributes,

and trace shape attributes;

• To determine and map the shale brittleness using

rock mechanical attributes such as Poisson’s ratioand Young’s modulus; and

• To estimate stress and its orientation by deriving,

evaluating, and integrating amplitude versus angle versus full azimuth (AVA(Z)) and residual moveout

attributes.

Well data analysisThere are two vertical wells inside the seismic survey

that include both sonic and density logs. The well data

are used in seismic-to-well calibration operations to

determine the shale formation depth and thickness,

to derive wavelets from seismic angle stacks, and tobuild the impedance background models.

Seismic attribute visualization/interpretationPost-stack seismic amplitudes are used to interpret struc-

tural horizons and to generate many types of seismic

attributes. The key process in post-stack seismic attribute

analysis is to examine and analyze different seismic attrib-

utes and then narrow them down to a manageable num-

ber that contribute to the understanding of the target.

Structural attributes such as curvature and coherence

are used to delineate seismic scale discontinuities such


IMPROVING

EXPLORATION SUCCESS

Seismic can be relevant in shales

A novel interpretation and characterization of an Eagle Ford shale play used geometric,mechanical, and full-azimuth seismic attributes.

Joanne Wang and Duane Dopkin, Paradigm;

Richard Kelvin, Seitel

FIGURE 1. In a co-visualization of curvature and facies classifica-

tion map, colors represent facies as delineated from seismic

trace shapes. Faults are easily identified with the curvature

attribute. (Images courtesy of Paradigm)

8/10/2019 EPM-4


IMPROVING

EXPLORATION SUCCESS

as faults. Physical attributes like spectral decomposition

sample seismic energy variations with frequency and can

be useful in evaluating thin bed effects like tuning.

Organized classification attributes based on trace shapesimilarity, for example, are useful in detecting changesin facies, lithology, and rock properties.

Figure 1 is a co-visualization of a cur-

vature attribute and the trace shape

classification attribute for the interval

of Eagle Ford shale. Major faults trend-

ing northeast are easily identified with

the curvature attribute. One of the

wells penetrates a visible fault. Trace

shapes are delineated by nine organ-

ized and structured groups of “seismic

facies” represented by different colorsthat indicate changes within the shale

interval. This attribute demonstrates

the heterogeneous nature of the

shale formation. Co-visualizing the

two attributes not only allows us to

describe the geology with each attrib-

ute but also the attributes’ relation-

ship to each other. For example, wecan visualize how the facies change

relative to faulting to understand if

the faults act as the boundary for the

facies and are responsible for theircompartmentalization behavior. Fault-

ing could help explain the distribu-

tion of ductile and brittle behavior in

the Eagle Ford shale.

Geomechanical attributegeneration and interpretationOne property that defines sweet spots

is shale brittleness. Where the shale

is brittle, it responds favorably to

hydraulic fracturing and stimulation

when compared with the ductileregions within the shale. Mapping the

shale brittleness is important in the

process of prospect identification and

characterization. Shale brittleness can

be described by some of the mechani-

cal attributes that can be derived from

seismic and well data, such as Pois-

son’s ratio and Young’s modulus.

Seismic inversion is a pathway to

estimate these attributes and proper-ties in 3-D. Great care must be given

to the data preparation (e.g. wavelet analysis and back-

ground model building), inversion parameter optimiza-tion, and quality control to ensure the accuracy of the

compressional (P) and shear (S) wave impedances. Pois-son’s ratio and Young’s modulus (times Rho) can subse-

quently be derived from the P and S impedances.

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A shale brittleness indicator can be developed using

both the Poisson’s ratio and Young’s modulus Rho attrib-utes. Figure 2 shows the result of the 3-D distribution of

the shale brittleness indicator in the Eagle Ford forma-

tion. Geobodies that represent higher brittle zones can be

isolated and mapped using

cross-plotting operations.

The extracted geobodies

can be incorporated into

the reservoir model.

In situ stress estima-tion and mappingUnderstanding stress and

its orientation is critical in

well planning and hydraulic

fracturing program design.

The acquired seismic data

include a rich surface sam-

pling of azimuth data. Anin situ decomposition of the

recorded seismic wavefield

into continuous azimuth reflection angle gathers in

depth can be used to estimate stress and stress orienta-

tion. In the study area, the Eagle Ford formation ranges

in depth from approximately 3,445 m to 3,845 m (11,300ft to 12,600 ft) dipping from northwest to southeast at an

average dip less than 2 degrees. Horizontal transverse

isotropy (HTI) media could be assumed for the localEagle Ford layer. Two independent approaches were used

to estimate layer anisotropy in a HTI media, one based on

full-azimuth amplitude sampling and the other based on

full-azimuth residual (velocity) moveout sampling. Both

measure the azimuthally dependent behavior of the data

in depth.

Figure 3 shows the stress map derived using AVA(Z)

inversion from the full azimuth reflection angle gathers.

The stress intensity is represented by both the back-ground color and the length (magnitude) of the vector.

The orientation of the vector represents the azimuth of

the symmetry axis perpendicular to the orientation of

the maximum horizontal stress. Full-azimuth reflection

angle gathers are used to systematically measure HTI

anisotropy effects of less than 1% with repeatability and

confidence. These types of results are not possible with

conventional surface azimuth sectoring approaches.

Seismic data carry critical information related to rock

properties and stress, which are among the determining

factors for sweet spot prospecting. Technologies are

available to generate seismic attributes that can fully characterize the geology of the shale plays, including

structural features, formation heterogeneity, rock prop-

erties, and stress. Highly desired information such asshale brittleness and stress can be extracted from the

seismic data, making seismic data more relevant in the

exploration and exploitation of shale resource plays.

FIGURE 4. Sweet spot identification requires a

workflow that takes well and seismic data into

account.

IMPROVING

EXPLORATION SUCCESS

FIGURE 2. A distribution of a shale brittleness indicator in the

Eagle Ford formation shows geobodies representing higher brit-

tle zones.

FIGURE 3. Stress intensity is represented by both the color and

the length of the vector. The orientation of the vector represents

the azimuth of the symmetry axis perpendicular to the orienta-

tion of the maximum horizontal stress.

8/10/2019 EPM-4


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8/10/2019 EPM-4


The Liberian basin comprises offshore Liberia and

Sierra Leone. Details of the regional structure and

petroleum prospectivity of this frontier margin have not

been well understood. In 2000-2001, TGS acquired 9,382line km (5,715 line miles) of regional 2-D seismic data,and an interpretation report was released in 2007 and

revised in 2010. Between 2007 and 2011, a series of 3-D

seismic surveys was acquired over several blocks in the

Liberian basin. All of these datasets have provided better

understanding of the regional structure and petroleum

prospectivity of this frontier margin.

In 2009-2010, a new long-offset seismic survey was

performed in Liberian ultra-deep waters to evaluate its

hydrocarbon prospectivity and provide a good-quality

extension of existing seismic into ultra-deep waters. Evalu-

ations of all the 2-D and 3-D datasets have provided a

good understanding of the structural evolution and

hydrocarbon potential of Liberian frontier waters.

Geological backgroundThe geological evolution of the Liberian basin is related

to the opening of the Atlantic Ocean. The offshore

Liberia margin is bound by the Sierra Leone transform

system to the north and the St. Paul transform system tothe south. The area is structurally complex, with trans-pressional and transtensional systems associated with

these major fault zones. Between the major fracture

zones, the upper Cretaceous depositional environments

were less affected by major faulting, which allowed depo-

sition of thick deepwater shales and turbidite sands.

Exploration in offshore LiberiaOn the offshore Liberian continental shelf, two

exploratory drilling stages took place (1970-1972 and

1984-1985) with a total of nine wells in 400 m (1,310 ft)

maximum water depth. Oil shows were encountered ineight of the wells, but no commercial discov-

ery was made. Deepwater economics and lack

of good-quality modern seismic data were

among the main reasons for early termination

of exploration campaigns.

Recent advances in deepwater technology

have opened up the region to a new phase of

exploration. In offshore Sierra Leone, the

Venus B-1 discovery well (2009), drilled in

1,800 m (5,905 ft) water depth, found 14 m

(46 ft) net of hydrocarbon pay in upper Cre-

taceous deepwater fan sands. This was fol-lowed by the Mercury-1 discovery in 2010.

Mercury-1 was drilled in 1,600 m (5,245 ft) water depth and encountered 41 m (135 ft)

net of oil pay within the same play.

In 2011, two exploration wells were drilled

offshore Liberia, Apalis-1 and Montserrado-1.

Apalis-1 found upper Cretaceous source and

reservoir rock with oil shows. Montserrado-1

was drilled to a depth of 5,400 m (17,720 ft)

and made a noncommercial oil discovery in

late Cretaceous reservoir sands. The well


FRONTIER

EXPLORATION

Geological review of deepwater

Liberian basin outlines prospectivityNew data and drilling results show great promise offshore Liberia.

Muhammad S. Tamannai, Ian Deighton,

and Peter Conn, TGS

The location of the Liberian basin shows its proximity to the major transfer fault

zones. (Images courtesy of TGS)

8/10/2019 EPM-4


encountered good-quality, water-bearing sands in the

main objective. In a deeper secondary target, 8 m (26 ft)

of hydrocarbon pay was intersected, and a sample of

light oil was recovered.

Petroleum systems evaluation

Two petroleum systems exist in the offshore Liberian

basin, early Cretaceous and late Cretaceous. Exploration

wells drilled on the shelf show that the early Cretaceous

contains three or more oil-prone marine and lacustrine

(Type II/III) source rock intervals that extend in age

from Aptian to Albian.

Abundant structural traps are potential targets within

the lower Cretaceous system. They are mainly fault

blocks and fault-associated structural closures related

to transtensional regimes during the mid-Cretaceous rift-ing event. Where found as transpressional pop-ups, these

structures can be associated with strike-slip motions. Fault

blocks were the main exploration targets in wells drilled

on the shelf. They also exist in ultra-deep water, where

they could be potential exploration targets.

The late Cretaceous system is the most important.

Source rocks are formed by late Cenomanian to Turon-

ian organic-rich (Type II) marine shales depositedthroughout the central and southern Atlantic during a

global anoxic event. Within this system, significant

recent discoveries have been made offshore Ghana,

Liberia, and Sierra Leone. Multiple sandstone reservoir

targets overlie the potential source rock interval.

Following recent discoveries, stratigraphic traps are

now seen as the most prospective play type in the off-

shore Liberian basin (and throughout the West African

transform margin). Deepwater fan and lobe structures

occur throughout the mid- to upper-Cretaceous

sequence, providing potentially attractive reservoirs. A

regional channel/fan complex has been identified andmapped across from the slope extending into the deep

basinal areas between intra-Campanian and top Creta-

ceous. Seismic imaging allowed delineation of multiple

fans within this thick complex. The presence of sand


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FRONTIER

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bodies is indicated by

brighter seismic ampli-

tudes within each fan.

Basin modelingShelf wells have been used

to constrain a regional

crustal model, which was

used as the starting point

for stretching-based

thermo-tectonic geo-his-

tory modeling. In addi-

tion to the shelf wells,

pseudowells have been

modeled at various

selected deepwater loca-tions to understand sedi-

ment paleo-temperatures

within the study area.

Extreme crustal stretch-

ing associated with early

Cretaceous Atlantic rift-

ing resulted in rapid

subsidence to bathyal

conditions in the late

Albian.

Two main source rock

intervals (Turonian-Ceno-manian and late Albian)

were modeled for hydro-

carbon expulsion. The

modeling indicated that:

• Burial and tempera-

ture conditions in

Liberia ultra-deep

water are such that

the Cretaceous source rocks expelled hydrocarbons

during the late Cretaceous to present;

• Early Cretaceous source rocks would have under-

gone peak expulsion within the late Cretaceous; and• The major phase of expulsion of Turonian-Ceno-

manian source rocks occurred throughout the late

Cretaceous to early Paleogene.

In summary, the study indicated several aspects of

Liberian basin geology:

• The study area is structurally complex in parts. Its

evolution and architecture are controlled by ocean

spreading and transform movements. It is bounded

by the Sierra Leone and the St. Paul transform zones;

• Extensive thick channel/stacked fan complexes

(within late Albian-top Cretaceous) have been iden-

tified extending from mid-shelf across to the ultra-

deep basin;

• Upper Cretaceous stratigraphic and Lower Creta-

ceous structural play types (tilted fault blocks) havebeen identified and evaluated;

• An Albian lacustrine shale and a regional Turonian-

Cenomanian marine shale are the two main source

rocks in the study area. Thermal modeling indicates

that these source rocks are mature, with peak expul-

sion throughout the late Cretaceous to early Paleo-

gene; and

• Numerous potential hydrocarbon indicators

(bright/dim amplitudes, gas chimneys) have been

identified, suggesting working hydrocarbon systems

that have been proven by recent drilling results.

A regional Liberian ultra-deep seismic line shows the complete sedimentary sequence. Structural traps

and some potential hydrocarbon indicators (fluid conduits) also are shown.

A composite seismic line extending from Liberian shallow waters to ultra-deep basins (>4,000 m, or

13,525 ft water depth) shows three fans identified between intra-Campanian and top Cretaceous.

8/10/2019 EPM-4


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In a global ranking of geologic provinces in terms of

petroleum resources, the Zagros and Persian Gulf

basins are among the richest provinces. According to

the “BP Statistical Review of World Energy June 2011,”

these areas hold 2,777 Tcf of natural gas reserves, roughly

40.5% of the world’s total. Several supergiant nonassoci-ated gas reservoirs have been found in this region.

The Permo-Triassic successions (the Dehram group inIran and its lateral equivalent, the Khuff formation), are

major gas-producing intervals in these basins. The super-

giant North Dome/South Pars field alone is estimated to

hold about 19% of the world’s total gas reserves, produc-

ing gas and condensate from these intervals.

Dehram reservoirsCurrent data indicate 38 petroleum fields in the

Dehram intervals of Iran. The majority of the Dehram

reservoirs are clustered in the Eastern Zagros or Farsand offshore Fars provinces. In addition, these succes-

sions offer potential petroleum exploration opportuni-

ties in the Western Zagros.

Moreover, 14 giant/super-

giant Dehram gas reservoirs

(about half of the total gas

reserves of Iran) are in the Per-

sian Gulf, and several Dehram

giant/supergiant gas reservoirs

are not developed yet, accord-

ing to the 2009 “Iran Energy

Balance Sheet.”These Dehram reservoir dis-

tributions and their absence inthe Dezful Embayment and

Izeh Zone indicate main con-

trols of Qatar-Kazerun and

Balarud faults for these reser-

voir configurations. No infor-

mation is available for the

Dezful Embayment and the

Izeh Zone because no wells

have penetrated the Triassic

and deeper intervals. The Dehram sediments in the

Dezful Embayment are too deep (deeper than 6,000 m,

or 19,685 ft) to have been reached by the drill bit.

Petroleum system componentsThe Paleozoic petroleum system is the main petroleum

system in the Persian Gulf basin and surrounding areas,

particularly in Qatar/Fars High. The Lower Silurian Sar-

chahan formation (or Qusaiba Hot shales) is believed to

be the main source rock for this petroleum system. Ther-mal evolution studies denote inception of oil generationin the Middle Jurassic in areas of greatest subsidence,

while the gas window was reached locally as early as the

Middle Cretaceous. Then, gas was accumulated in the pre-

Zagros trap structures. Major reservoir rocks of this system

are the oldest reservoir rocks in Iran and consist of three

formations, Faraghan, Dalan, and Kangan. The Dashtak

formation, containing shale, claystone, anhydrite, and

limestone, is the regional and efficient cap rock of the

Dehram reservoirs.

Geologic history and depositional settingThe Permian rifting along the Zagros by the opening of

the Neotethys Ocean coincided with transgression and


FRONTIER

EXPLORATION

Iranian discoveries continue

In this world-class setting, the potential for major gas discoveries is high.

Behrooz Esrafili-Dizaji and Hossain Rahimpour-Bonab,

University of Tehran

Most of the Dehram reservoirs are

situated in the Fars and offshore Fars

areas, but a few reservoirs are in the

Lurestan province and Bandar Abbas

hinterland. Reservoir distributions in

these basins indicate the roles of

Qatar-Kazerun and Balarud faults

on reservoir system configurations.

(Modified from Bordenave, 2008)

8/10/2019 EPM-4


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deposition of the cyclic, dominantly shallow marine car-

bonates and evaporites of the Early Permian to Early Tri-

assic Dehram group. The lithology of this group ranges

from siliciclastics to limestones and dolomites, anhy-

drites, and shales.

The Faraghan formation is composed of clastic deposits.

In fact, this formation represents post-Hercinian continen-tal deposition in fluvial to deltaic systems. It is a time

equivalent to the Unayzah formation in the Arabian coun-

tries. The Unayzah formation hosts enormous oil and gas

potential in the fields of Saudi Arabia. Results of deep

drilling in the Persian Gulf indicate that this formationhas good reservoir properties. As expected, with deeper

drilling, Faraghan reservoirs could be new discoveries in

the Persian Gulf area in the future.

The Middle-Late Permian Dalan formation is the mid-

dle interval of the Dehram group and is divided into

three units, Lower Dalan, Nar, and Upper Dalan mem-

bers. The lower and upper units consist of carbonates

with approximately 160 m and 180 m (525 ft and 590 ft)

thickness, respectively. Based on reservoir properties,

Dalan reservoirs are divided into four reservoir units

from base to the top, including K5 (Lower Dalan), Nar

member, and K4 and K3 (Upper Dalan). Most of theDalan gas reservoirs are hosted by the formation’s upper

part (K4 and K3) in the Persian Gulf area. Dalan reser-

voirs are associated with shallow carbonates (particularly

grainy facies of oolitic shoals) of paleoplatform. In this

platform, mud content of the facies (grain/mud ratio)

increases basinward, so reservoir characteristics decrease

accordingly; for example, mean porosity decreases from

9% in the Persian Gulf reservoirs to 3% in the Interior

Fars reservoirs.Therefore, on a regional scale, reservoir characteris-

tics are mainly a function of the depositional environ-

The Triassic Dashtak formation provides efficient seal for the

Faraghan, Dalan, and Kangan reservoirs. (Courtesy of the Uni-

versity of Tehran)

Two microphotographs from Faraghan rock types indicate textu-

rally inverse, poorly sorted quartz arenite in A and poorly sorted,

medium sand-size quartz arenite with carbonate cements in B in

the Golshan field. (Figures from M. Mehdinia)

The oomoldic shoal facies of Lower Kangan (K2) from the South

Pars gas field are one of the main reservoir rock types, particularly

in fractured and dolomitized intervals. (Courtesy of the University

of Tehran)

8/10/2019 EPM-4


FRONTIER

EXPLORATION

ment in both the Dalan and Kangan

reservoirs, but in some fields fracturingand dolomitization are the main impact

on reservoir quality.

The Early Triassic Kangan formation

is a major gas and condensate reservoir

in many fields in the Iran territories.

Inhouse data indicate that 28 gas reser-

voirs have been discovered from the

Kangan formation in the Zagros and

Persian Gulf basins. The depositional

system of the Kangan formation is simi-

lar to the Permian platform, but seemingly there were no major paleo-

highs and reefal bodies as depicted for the Dalan formation. Besides, from

Permian to Triassic, there is a decreasing trend in the volume of anhydrite

facies and an increase of shale facies. Based on reservoir properties, Kan-

gan reservoirs are separated into two main reservoirs units, K2 and K1.Development of clean oomoldic shoal facies bodies after the Permo-Trias-

sic mass extinction led to high reservoir quality in the lower part of Kan-

gan Formation (K2), which is known as an excellent reservoir unit.

Discoveries continueIran has several supergiant and many giant gas fields in the Permo-Triassic

Dehram group, all in the southwestern area. In the last 10 years alone, seven

fields have been found in Iran. Based on current data, Early Permian

sequences, particularly the Faraghan and Zakeen formations, now can be

considered as good targets for gas reserves, particularly in the Persian Gulf,

so deeper drilling will be necessary for new discoveries in this area.

Apparently, there are local paleohighs and seaways along the Zagros (with reef bodies or emergent pre-Permian clastic units) that

separated the Dalan depositional system from the open Neotethys ocean during the Permian era. (Compiled from Szabo and Kherad-

pir, 1978; Insalaco et al., 2006)

TABLE 1: The eight supergiant Dehram gas

fields of Iran. (Iran Energy Balance Sheet,

2000-2009)

Field Recoverable reserve

South Pars 360 Tcf

North Pars 47 Tcf

Kish 45 Tcf

Golshan 25-45 Tcf

Tabnak 21.2 Tcf

Kangan 20.1 Tcf

Nar 13 Tcf

Aghar 11 Tcf

TABLE 2: Dehram group subdivisions, lithologies, and depositional settings.

Name Age General lithology Depositional environments

Kangan E. Tr iassic Carbonate and Epir ic carbonate systemevaporite,with minor shale

Dalan M.-U. Carbonate and Epiric carbonate systemPermian evaporite

Faraghan E. Permian Shale, sandstone, Fluvial to deltaicand conglomerate

8/10/2019 EPM-4


Top drives have been adopted as

standard equipment in the oil

patch. While there are many well

known providers for this important

component, most drillers can count

them on one hand. One small serv-

ice company, Global Drilling Sup-

port (GDS) International, has taken

lessons learned and developed a

new high-performance top drive

that can be customized per the spe-cific needs of each application.

Keith Holliday, president and

CEO, and Paul Nicholson, vice presi-

dent, are top drive veterans, with

more than 35 combined years of

experience in manufacturing, servic-

ing, rebuilding, and operating top

drives. Holliday and Nicholson origi-

nally founded GDS as a service com-

pany in 2008 focused on repairing

and rebuilding top drives and provid-

ing parts service for all major brands. In2009, the company’s focus took a different

direction as its owners began to consider the

development of a new top drive design.

Having had years of experience dealing with

a number of chronic problems while either

servicing or operating top drives, Holliday

and Nicholson set out to build a tema that could produce a top drive that would effec-

tively address many of the issues that

often plague existing designs. The

result of their efforts was the com-

pany’s Global Drilling Machine

(GDM) line of top drives. This line

of top drives represents an evolu-

tionary upgrade to existing designs

formulated to deliver a combination

of high torque, reliability, and main-

tainability. To meet a wide range of

market applications, the GDM lineincludes a range of top drives from

500 tons to 800 tons.

Design conceptThe design of the GDM line of top

drives was directed by a core set of

objectives – providing a rugged

mechanical design with a minimum

number of failure points that was

also capable of producing both high-

torque and high-rpm output. In addi-

tion, the GDM top drive was conceived toprovide ready access to all common main-

tenance areas, adding to the speed and ease

of service and repair operations. Personnel

safety also was factored into the GDM enve-

lope, with built-in work platforms supplied

as standard for the top drives.

Manufactured under an API 8C License

(Cert. No. 8C_0161), GDM top drives offer a

number of key features. Both the 500- and

800-ton models use industry-standard GE

drive motors, with a unique self-aligning cou-


LAND RIG

ADVANCES

Combined experience

brings designed-for-purposetop drive to market

Much like major operators, the top drive market is driven by a select number of players

globally. A small Houston-based company hopes to level this playing field

engineering an evolved generation of top drives from the ground up.

Tayvis Dunnahoe, Senior Editor

The GDM top drive was conceived to provide ready

access to all common maintenance areas, adding to

the speed and ease of service and repair operations.

(Images courtesy of GDS International)

8/10/2019 EPM-4


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adjustable pipe handling module, allows for automatic

positioning with the racking board and derrick man.

Proprietary remote IBOP actuator Another key feature of all GDM top drives is GDS’

advanced remote internal blowout preventer (IBOP)

actuator. Already proven as an aftermarket component

on a wide range of top drive models, this remote actuator

offers a number of features not found on conventional

IBOP actuators. To begin, this unit is based on a design

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actuator provides ample room for elevator links to pass,

and its three-cylinder design allows uniform actuation.From an operational perspective, this GDS actuator

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proven unit also provides manual operation through

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The 850 and beyond

The GDM 850 is designed to operate at 1,570 continu-

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Built to deliver the torque required by today’s demand-ing deepwater and horizontal drilling applications,

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The GDM 850’s static brake capacity is rated at 57,000

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use, the GDM 850 weighs less than 35,000 lbs and is 7 m(23 ft) tall with 120-in. elevator links.

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In spite of its demand as a global commodity, the price

of oil can be wildly unpredictable. A jumble of geopo-

litical forces, environmental factors, and seasonally fluc-tuating demand combine to make oil futures prices

anything but certain. But the cost of drilling for that

oil is a different story.

Whether oil prices are up or down, the drilling costs

can be reliably predicted to become more expensive. A

significant component of oilfield exploration is the spe-

cialized equipment required. In many situations, engi-

neering innovation helps to contain costs rather than

contribute to the incessant upward spiral.

That is the case with the new dual-actuator Aqua-

Makks drawworks brake developed by Wichita Clutch,

headquartered in Wichita Falls, Texas. The dual-actua-

tor option adds another layer of versatility and cost-

effectiveness to Wichita’s line of AquaMakks brakes.

Looking for a better solution

Tri-Service Oilfield Manufacturing (TSM) is a leadingmanufacturer of drawworks for the drilling and service

rig industry. For more than a half century, TSM has

been supplying the global oil industry with a complete

line of drilling and service equipment. Along the way,

the company has built a worldwide reputation for qual-

ity, reliability, and customer satisfaction.

Searching for a way to control equipment costs, TSM

contacted Wichita Clutch and inquired about the possi-

bility of developing a single brake solution that would

be more cost-effective and readily available than the

dual-action brakes the company was previously using

on its drawworks. “TSM wanted a more economicalsingle-unit assembly that would provide both tension

braking and spring-set failsafe parking,” said George

Nemec, Wichita Clutch area sales manager.

Responsible for controlling the process of lowering

and retrieving tons of equipment thousands of feet into

and back out of the earth, the braking system of a draw-

works assembly is obviously a critical component. And

since they are subject to nearly unimaginable stresses,

extended downtime for repair or replacement of draw-

works brakes can be costly. TSM has used Wichita’s

brakes in their drawworks assemblies for a number of

years, and Wichita had earned a reputation for quality products and reliable customer support. So there was a

comfort factor for TSM in turning to Wichita Clutch

with its request.

TSM engineers collaborated with Wichita Clutch in the

design of the new braking solution. “Wichita was given

our performance parameters such as static and dynamic

stopping and retarding conditions,” said a representative

of the TSM engineering team. “Wichita then sized the

brake as required to meet our desired service factor. The

physical size was also reviewed to ensure that our draw-

works and the brake were a good match.” Speed of deliv-


LAND RIG

ADVANCES

Two brakes in one improve

performance, maintain costIn many situations, engineering innovation helps to contain development costs

rather than contribute to the upward spiral.

Tayvis Dunnahoe, Senior Editor

The Dual Actuator AquaMaKK’s water-cooled brake provides

both failsafe parking and precision tension braking capability in

one unitized assembly. (Images courtesy of Wichita Clutch)

8/10/2019 EPM-4


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ery was also critically important, and Wichita was able to

beat the closest competitor’s lead time by 50%.

Two brakes in oneThe resulting solution was Wichita Clutch’s dual-actua-

tor AquaMakks brake. According to Richard Mayberry,

engineering manager at Wichita Clutch, “TSM wanted

to be able to use the brake as the primary static holding

or parking brake, along with being used as a dynamic

brake.” The goal was achieved. In dynamic tensioning

mode, the AquaMakks dual-actuator brake can absorb

up to 3,400 HP – 35% more than the closest competitor.

And for static parking, the unit provides a torque rating

sufficient to hold 750,000 lbs on 12 lines.

The AquaMakks incorporates a number of innovative

features. Perhaps the most pioneering is the composite water jacket.

High-tech compositesThe use of metal is losing its iron grip on the world of

manufacturing. Advanced composite materials offering

dramatic improvements in strength-to-weight ratios and

superior corrosion resistance are replacing metal in

many applications. Consider Boeing’s new 787 Dream-

liner – half of its primary structure is built of composite

materials. And yet the Dreamliner is setting new per-

formance standards unmatched by aircraft of traditional

all-metal construction. The benefits of modern compos-ites are applicable to many industries outside the field of

aerospace. Wichita Clutch took a cue from the aero-

space industry in solving a problem that has plagued the

operators of heavy-duty industrial brakes for decades.

“In the oilfield, sometimes the water used in brake

cooling systems is not of a high quality,” Mayberry

explained, “and over a short period of time can severely

corrode the working internals of a water jacket. But the

composite material water jacket of the AquaMakks is

impervious to widely ranging quality issues.”

The superior corrosion resistance of the AquaMakks is

a boon to offshore operators using saltwater as a coolant,but water quality also is an issue in many locales. Some

Texas oil fields, for instance, must deal with highly acidic

water with a very low pH value – very corrosive to water jackets of traditional iron construction.

A side benefit of the AquaMakks composite water jacket

is significant weight savings, with a weight reduction of

50% or more compared to brakes using iron water jackets.

This can result in weight savings of thousands of pounds

in the largest units, significantly benefitting mobile appli-

cations such as truck-mounted units. And the advantages

of composite construction come without any sacrifice in

strength. In stress testing, engineers were unable to

induce a structural failure even when stressing the unit to

more than four times its maximum design load.

Easy maintenance, retrofit

The dual-actuator AquaMakks also helps operators keepdown costs by making maintenance faster and less labor-

intensive. When the copper alloy wear plates need to

be adjusted, the process is as simple as removing some

shims; disassembling the unit is not required. Inspection

and maintenance also are simplified with the open case

design, providing easy access to key components. To speed

the process of repair and replacement, the AquaMakks

design uses fewer mounting bolts than competing units.

In addition, the design of the AquaMakks enables

quick and easy replacement of older single-actuator

brakes. Mayberry said, “[The main design challenge]

was to make the dual actuator assembly such that it canbe retro-fitted onto existing brakes without impact to

the rest of the brake unit. Simply remove the normal airtube holding plate, install the dual-actuator head assem-

bly, and go back to work.”

There is even an option for easy interchangeability with

competing models by matching the mounting bolt pattern

and tooth profile. In fact, making the unit interchange-

able with other models was a unique TSM requirement.

According to the TSM representative, “No significant

changes need to be made to the drawworks to drop in

this brake in place of competitor units.”

LAND RIG

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work is still ongoing, with major players such as Total and

Hess recently joining the project.

This kind of collaborative approach will be increasingly

typical as the industry uses subsea technologies to pro-duce its deepwater and ultra-deepwater assets.

“Subsea infrastructure is the delivery vehicle for the

reservoir: we need to understand subsurface uncertainty

and deliver the right system at the right time,” Blake said.

“Subsea major capital projects are a significant part of

Chevron’s strategy, and upcoming large subsea projects

will need strong project management skills and leader-

ship with a focus on improving on-time delivery perform-

ance, aftermarket support, and experienced support

personnel.”

He also pointed out that Chevron has increased its

planned investment in subsea technology R&D over thenext five years, and it will continue to operate its Center

of Excellence model for subsea, with hubs in Aberdeen,Perth, and Houston. The company also is set to more

than double its number of subsea engineers.

Subsea gas/liquid separationLuc Riviere of Total’s R&D Deep Offshore team, present-

ing at the same event, highlighted the company’s suc-

cesses in deepwater West Africa, especially the Pazflor

project in Block 17 offshore Angola.

Among several industry firsts, Pazflor saw the first

implementation of subsea gas/liquid separation – anadvance that enabled the project’s economic viability. It is

the first project to deploy a development plan based on

gas/liquid separation at the mudline spanning several

reservoirs, with a trio of subsea separation units (SSUs)

installed. Each one consists of four retrievable packages:

a gas-liquid separator, two hybrid pumps to boost theliquids, and a manifold to distribute the effluents to the

separator and pumps. The hybrid pumps combine multi-

phase stages compatible with the presence of gas in the

liquid and a centrifugal stage to improve efficiency.

Riviere said that with many more marginal fields to be

developed via subsea tiebacks, the industry is now able to

largely meet the challenge thanks to recent advances in

subsea processing, subsea gas/liquid separation, electrical

heating of flowlines, all-electrical systems, and the arrival

of new installation vessels.

Horizon disaster showed subsea capabilitiesDave Turner, BP vice president, Subsea ProductionOperations, stressed how even the worst events can have

a positive input. According to Turner, the Deepwater

Horizon accident:

• Pushed the limits for complex simultaneous opera-

tions and multi-ROV operations;

• Operated multiple major vessels in close proximity

for an extended period of time;

• Constructed complex novel seabed systems;

• Connected the system to dynamic positioning vessels

in short timeframes;

• Conducted extensive monitoring campaigns; and• Demonstrated the skills of the subsea industry.

Turner went on to highlight the importance of areas

such as condition monitor-

ing and integrity manage-

ment, internal learning and

improvement, and tools and

technology advances (BP is

working on areas such as

HIPPS, production boost-

ing, and HP/HT).

He concluded that

the recruitment of freshtalent into the subsea arena

remains a crucial challenge.

“The glue that holds all thistogether is human capability

and capacity ... and human

capability is the greatest

challenge we have across

the subsea supply chain.

As an industry, we need

to work on this together,”

he concluded.


SUBSEA

TECHNOLOGIES

According to Peter Blake at Chevron, technology investment

will be focused, collaborative, and leveraged to enable subsea

developments in deep water and ultra-deep water, where the

projects are becoming increasingly complex and technology-

driven. (Graphic courtesy of Chevron)

8/10/2019 EPM-4


Statoil is pioneering the world’s first subsea gas com-pression project to eventually boost production when

needed on its flagship Åsgard field in the North Sea.

The company is in the vanguard of a growing industry movement toward the general acceptance and implemen-tation of various subsea processing solutions to improverecovery of oil and gas reserves from brownfield develop-ments across the globe. These solutions include seabedseparation, single and multiphase hydrocarbon boosting,raw seawater injection, sand handling, and produced water reinjection.

All of these solutions will play a key part in enabling theindustry’s inexorable advance into deeper waters andmore remote environments.

Gas compression is arguably the most

important piece of equipment in thesubsea toolbox as the industry positionsitself to meet these future challenges.

According to Statoil Senior Vice Presi-dent for Subsea and Marine Technology Bjørn Kåre Viken, “Subsea compressionis the most important single part of thesubsea factory. My opinion is that we arenot that far from realizing a subsea fac-tory – Statoil is ahead on this. All theother operators are thinking along thesame lines, but someone has to go in

front. And when it comes to subseacompressors and subsea technologyin general, we are in the lead. This isan important technology to have inour toolbox.

“But also importantly, this is beingbusiness-driven. We are not doing thisfrom a technology point of view itself;it is connected strongly with the businesscase. It has to compete with otherconcepts.”

Statoil first officially confirmed it was

opting for gas compression on the seabed for Åsgard inOctober 2010 before making the final investment deci-sion last year.

So why opt for subsea compression? As any field ages,its natural pressure declines, meaning that compression isneeded to extract more gas and get it to a platform. Until

now, the standard solution has been for that compressionto be done on a platform or from shore. However, thecloser the compressor is placed to the wellhead, the moregas can be extracted because the compressor’s suctionpressure will be lower than if it is installed on a platform.To achieve this, Statoil will place two massive compressorsnear the wells on Åsgard that will provide enough pres-sure to transport the gas to the platform.

The Gullfaks 2030 and Ormen Lange pilot projects will

eventually benefit from the technology; technology qualifi-

cation and testing are under way at both developments.


SUBSEA

TECHNOLOGIES

Seabed compression advances

boost development optionsA Norwegian player is lining up a queue of gas compression projects that will greatly

enhance the industry’s subsea toolbox for IOR and much more.

Mark Thomas, International Editor

A field schematic shows the planned layout of Statoil’s Åsgard field offshore Norway,

which will feature a huge subsea compression station weighing 4,800 tonnes. (Images

courtesy of Statoil ASA)

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SUBSEA

TECHNOLOGIES

Åsgard was not the first field to opt for subsea compression – anotheropportunity was assessed in 2008 by Statoil for its Tune field offshoreNorway. Although there was a clearproduction acceleration and increased

recovery effect, it was not possible todevelop a sufficiently robust businesscase at the time. The knowledge gainedfrom studying this opportunity for what was a relatively small field where a sim-ple multiphase compressor systemcould be applied did not go to wasteand is being taken further in the workbeing done on the Gullfaks subseacompression project.

According to Statoil, the GullfaksSouth recovery rate already is 62%, and

the combination of subsea compres-sion and conventional low-pressureproduction in later phases could lift the total recovery rate to 74%. This would increase production by 3 Bcmof gas, or an additional 6%.

Statoil also has identified severalother small- and medium-sized fields aspotential candidates for the technology.But it is Åsgard that leads the way, withthe subsea compression system aimed at increasing pressure from the field’s

Subsea no longer necessarily means small, as this scale image from Statoil demonstrates. The Åsgard compression station will feature

two 11.5 MW compressors, with the substantial power requirement to be supplied by a high-voltage electricity system from the Åsgard

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Midgard and Mikkel reservoirs in Blocks 6507/11 and6407/12, and 6407/7, respectively. This could enhancerecovery by up to 28 Bcm and 14 MMbbl of condensate

(around 278 MMboe), the company has estimated.Two conventional compressor trains, each with aninlet/anti-surge cooler, will be used along with a com-mon scrubber and condensate pump. The moisture willbe removed from the gas before it is compressed on theseabed.

The Midgard and Mikkel gas reservoirs were developedas subsea installations in the Halten Bank area of the Nor- wegian Sea, around 200 km (124 miles) offshore. The wellstream from the two fields, located 50 km (30 miles)and 70 km (43 miles) away, respectively, is sent in thesame pipeline to the Åsgard B platform. Current analysis

shows that by year-end 2015, the fields’ pressure willbecome too low to avoid unstable flow and maintain ahigh production profile to the platform, with the low pressure unable to transport the gas.

For Åsgard, qualification of components began in

2005, with work including the development of a suitablescrubber capable of handling solids as well as liquids.

Statoil said the application of the two massive 11.5

MW compressors, plus coolers, separators, and pumpsin one subsea template, will involve an investment of almost US $2.6 billion. Much has gone into developing acompact compressor design, with motor and compressorhoused in the same casing and motor cooling using theprocess gas.

A high-voltage electrical power distribution system willbe provided via submarine cables from the Åsgard A FPSO.

The $590 million contract for the design and con-struction of the gas compression system is being carriedout by Aker Solutions, which is also doing the modifica-tions on Åsgard to provide electricity to the system.

The compression station (4,800 tonnes) and manifoldstation (900 tonnes) will be installed in 250 m to 325 m(820 ft to 1,066 ft) water depth by Italy’s Saipem, whichalso will carry out the lifting of a new module onboardthe Åsgard A FPSO.

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Today, the Haynesville shale is the largest producing gas

play in North America. It produces some 6.5 Bcf/d, a

remarkable rise from zero production in 2007. Indeed,

this upstart shale gas play now accounts for 10% of total

daily US gas production.

And yet the book on the Haynesville is that it is uneco-

nomic in today’s gas market. It is a dry gas play, and the

deep, hot, and highly pressured formation requires very

costly wells. Rigs have been relocated from the North

Louisiana and East Texas environs of the Haynesville to

such liquids plays as the South Texas Eagle Ford.

Not everyone shares a dim view of the Haynesville,

however. A major proponent of the play is Calgary-based


UNCONVENTIONAL:

HAYNESVILLE

The Haynesville can competeAs the largest producing gas play in North America, the Haynesville shale

is a highly competitive asset.

Peggy Williams, Editorial Director

Integrated workflow key tomanaging risk in shale playsContributed by CGGVeritas

Optimism drives our business. From Spindletop to today,

it only takes one spectacular well to start a boom, but

possibly dozens of dry holes or, in today’s shale plays, sub-

economic wells to turn that optimism into realism.

CGGVeritas has developed an integrated workflow, which

includes high-quality 3-D seismic survey design and acqui-

sition through reservoir characterization, to derive detailed

geomechanical and lithological models that can guide moretargeted and effective drilling and completion programs.

The company has published results for the Haynesville

shale using the Tri-Parish CGGVeritas multiclient data (SEG

2011). The Hampson-Russell multi-attribute analysis of vari-

ous reservoir quality indicators was used to predict actual gas

production at the wells covered by the study, and excellent

correlation was achieved. With this strong link established

between seismic attributes and production measurements,

several areas of high potential (sweet spots) for future devel-

opment were identified.

The first step in identifying potentially productive zones

is to understand the lithological and geomechanical prop-erties that control reservoir quality. In the Haynesville shale,

prestack simultaneous inversion was used to extract acoustic

and shear impedances to predict properties such as density,

porosity, brittleness, mineral composition, and total organic

content, which were calibrated against existing well infor-

mation. This showed that rock properties of the lithology

above and below the Haynesville are very different from

those within it (even though post-stack seismic reflection

amplitudes may look similar). Having identified the poten-

tial sweet spots, the effectiveness of hydraulic stimulation

was assessed by using stress estimates derived fromanisotropic analysis of the wide-azimuth seismic data cali-

brated against available core measurements.

The strength of this technique is the number of different

attributes used to produce the models. No single attribute

produces a reliable correlation with production, but by

applying multi-attribute analysis to a wide range of litho-

logical and geomechanical properties, areas of potentially

high production can be predicted. Partners in this study

have commissioned further proprietary studies over their

licenses.

This workflow is as applicable to liquids as to gas and is

being extended to shale oil reservoirs. The models can beused to predict reservoir drainage geometry and induced

fracture behavior so that the most productive well locations

and fracture stages can be determined, reducing exploration

risk. The risks associated with drilling hazards and hydraulic

stimulation also can be mitigated by locating ductile areas and

identifying faults that might allow leakage of gas or proppant

out of the desired zone. This study will enable optimal drilling,

completion, and recompletion of the Haynesville to power US

energy for decades.

The first six months of production predicted from seismic and

correlated to actual values are shown. Note potentially high

production areas (circled) that have not been drilled. (Image

courtesy of CGGVeritas)

8/10/2019 EPM-4


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Encana Corp. The Canadian senior has applied its skillset

to its prime Haynesville land position, and it claims that

the results speak for themselves. In an early November

2011 conference call with investors and shareholders,

Encana talked up the Haynesville and perhaps changed a

few minds about the realities of this prolific resource play.

The Haynesville has led Encana’s recent corporate pro-

duction growth. “For 2011, we expect to average 505

MMcfd, more than 50 times what we were producing just

three short years ago,” said Eric March, Encana executive

vice president. “The Haynesville shale represents extraor-

dinary opportunity.”

Engineering efficiency, advanced horizontal drilling and

completion technologies, and lower cost structures are

making the Haynesville a highly competitive, economically

robust resource play that has a long-term future, he said.

In recent years, Encana worked to retain its core lease-

hold. The company has 250,000 net acres in the heart of

the Haynesville and mid-Bossier plays, and the majority of

that is now held by production (HBP), said Paul Sander,


The Haynesville is an Upper Jurassic-age shale in northern

Louisiana and eastern Texas, situated between the Cotton Val-

ley sandstone group and Smackover limestone formation.

There were more than 2,000 Haynesville wells drilling, permit-

ted, or waiting on completion as of March 2012. (Map and

data courtesy of Louisiana Department of Natural Resources)

8/10/2019 EPM-4


UNCONVENTIONAL:

HAYNESVILLE

vice president, Midcontinent business unit. Now that the

HBP grind is largely behind it, Encana is applying its

resource play hub development strategy to the Haynesville.

The approach calls for drilling fewer, longer laterals at

optimum spacings and employing lower cost, higherrecovery completions. Already, Encana has driven costsdown to US $3.70/Mcf in the Hay-nesville, a remarkable drop from morethan $5.50/Mcf in 2008. Going forward, Encana targets supply costs of lessthan $3/Mcf.

“We expect to achieve this through a

combination of improved well perform-

ance and reduced cost structures, prima-

rily through the implementation of our

resource play hub model,” Sander said.

Pad drilling and increased efficien-cies are pillars of Encana’s program. Inits Credence area, where it owns 100% working interest, Encana has reduceddrill times by 38% and drill costs by 30% since 2009. Completion efficiency and costs also have improved even as well lengths and completion intensity have increased.

Since the first quarter of 2010, thenumber of frac jobs Encana haspumped per month has doubled. “Most

recently, we pumped as many as 145completion stages from a single crew ina single month,” Sander said. “Andmore stages mean lower average costs.”

The wells also are getting better.Encana has tweaked its designs to placemore sand in the completions networkto reduce the impact of embeddedproppant, and that has translated toimproved well performance. Declinesalso have moderated. According toSander, it is less costly for the company

to invest in bigger completions on fewer wells than it is to drill more wells withsmaller completions. “Ultimately, we areheading to 106-acre spaced wells oreven 160-acre spaced wells,” he said.

On the production front, Encana hashad good success with slowback, a prac-tice that limits a well’s production rateto keep the surface pressure drop to lessthan 25 psi per day. Wells produced withthe slowback method appear to havehigher estimated ultimate recoveries on

the order of 5%. “Around one-half of our wells employedthis practice in 2011, and it is now our standard practice,”Sander said.

The upshot of all Encana’s engineering, innovation, and

best practices is an affirmation that the Haynesville is truly a top-tier, highly competitive asset, said the company.

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T

he worldwide market for offshore support vessels

(OSVs) has been in recovery mode since the financialcrisis of 2008 and the resulting plunge in oil prices, withsome regions recovering better than others. Now, the off-shore industry is seeing positive outlooks around the world in 2012.

This has been primarily because of the recent high andstable oil price, with Brent Crude peaking in May 2011 at more than US $126/bbl. It has remained above $100/bbl, which has been fueling increases in oil company confi-dence and spending. With forecasters predicting that theoil price will average around $110/bbl this year, oil andgas companies will once again be able to pursue more

marginal fields in far deeper waters that would not beprofitable otherwise.

The rise in oil company spending on E&P has a “water-fall” effect on the whole offshore industry, with E&P com-

panies requiring more drilling rigs, which in turn needsupplying and moving. This is where the offshore support sector comes in.

Other industry sectors also are having a knock-on effect

on the offshore industry such as renewables, where thereis an overlap in the tonnage required for certain tasks,especially construction and installation. This has tight-ened some markets, especially in the North Sea andEurope, where vessels are able to compete for jobs inboth industries – and are therefore less reliant on justone or the other.

US Gulf of MexicoThe US market has faced many problems over the past few years: the financial crisis, the fall in oil prices and – just as the industry had started to recover – the Deepwater Hori-

zon disaster, which put a halt to activity in the US Gulf of Mexico (GoM) region.

With the moratorium on deepwater activity institutedas a result of the oil spill, rates for supply vessels plum-

meted, and many vessels were laid up or relo-cated to other regions. When the moratorium was lifted in October 2011, it took some timefor activity to begin increasing because of thecomplicated nature involved with applying fordeepwater permits.

These hurdles were eventually overcome,and activity is now steadily increasing. And,

because of the number of vessels that left theregion for greener shores, there is a shortageof good quality DP2 PSVs, and rates havestarted to rise. The industry also has startedto see increased rates for anchor handlers,but not as much as had been seen beforethe Macondo disaster in the GoM whenthey were in extremely short supply.

There is an expectation that 2012 is thebeginning of a new revival for the GoM asmany owners are starting to renew their new-build programs, and some substantial orders

0

20

40

60

80

100

120

140

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

35%

40%

2006 2007 2008 2009 2010 2011 2012e

U S / B i l l

i o n

c

a n

g e

% change in E&P Spending

Brent Crude Price

Changes in E&P Budgets vs. Oil Price


SERVICE AND

SUPPLY VESSELS

Offshore support fleet

steering a positive courseAfter troubled times for some regions, the OSV market around the world looks set to enjoy

better times as offshore support vessel operators move to meet growing demand

from oil and gas companies.

Daniel Quarm and Ian Coates, Derrick Offshore Ltd.

The rising oil price has fueled increased spending plans by oil companies, which

is in turn leading to renewed confidence and investment by supply vessel opera-

tors to meet growing demand. (Source: Barclays E&P Spending Survey/IEA)

8/10/2019 EPM-4


8/10/2019 EPM-4


SERVICE AND

SUPPLY VESSELS

Piracy is another factor that plagues

the region, especially around Nigeria

where attacks are almost an everyday

occurrence that do not just affect theshipping industry. As well as affecting the

vessels, the attacks also increase

insurance costs and deter other compa-

nies from investing in the region.

Meanwhile, East Africa is a region

showing immense growth potential and

opportunity, but there are signs that this

area will take a few more years to fully

mature. This is because of security con-

cerns and the lack of clarity in the region

in terms of local content laws that could

arise. With Somalia so close to countrieslike Mozambique and Tanzania, where

exploratory work is accelerating, many

owners are wary of the region and will

want to stay clear until the situation

resolves itself.

Asia PacificIn the lead up to the 2008 financial crisis

which led to many oil and gas companies

significantly reducing their spending

budgets, operators active in Southeast

Asia and the Pacific already had a signifi-cant number of vessels on order and

many being delivered at the same time.

This led to massive market oversupply

with little activity occurring, which has

left many newbuilds idle. Anchor han-

dlers were the worst hit among the off-

shore fleet with the 5,150 BHP design the

most popular in this region because

of its shallower waters.

It has taken a long time for activity to

rebound, but the industry is seeing signs

of this, especially in Malaysia and Aus-tralia, where the majority of offshore

projects seem to be focused on the pres-

ent. Projects such as Gorgon and Ichthys in Australia have

been a lifeline for some operators, with large injections of

cash from Shell and the other oil companies. But quaran-

tine laws around Australia have not made matters easy,

and few operators qualify for some of the work.

Orders for newbuilds are on the rise, however, and activ-

ity levels are expected to continue rebounding through

2013 as other regions such as Vietnam increase their activ-

ity levels.

Looking ahead When oil companies are more confident, this allows the

service and supply industry to budget in line with them.

While this growth in confidence and activity is occurring in

some regions globally, it is only now starting to happen in

others where specific market conditions have not allowed

recovery until the present time. The overall outlook for the

OSV market, meanwhile, looks to remain on a steadily

improving course for the remainder of 2012.

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

$45,000

$50,000

Average PSV Charter Rates (US$)

North Sea

US Gulf

Asia Pacific

West Africa

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

$45,000

$50,000

Average PSV Charter Rates (US$)

North Sea

US Gulf

Asia Pacific

West Africa

Rates in most areas are on the rise, with the US GoM market steadily increasing and

the volatile North Sea market still buoyant yet largely influenced by seasonal weather

patterns. (Data courtesy of Derrick Offshore Ltd.)

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

$180,000

$200,000

Average AHTS Charter Rates (US$)

North Sea

US Gulf

Asia Pacific

West Africa

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

$180,000

$200,000

Average AHTS Charter Rates (US$)

North Sea

US Gulf

Asia Pacific

West Africa

The anchor handling market is expected to steadily improve, with the heavily

impacted GoM starting to revive after a torrid time post-Macondo. (Data courtesyof Derrick Offshore Ltd.)

8/10/2019 EPM-4


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B

razil’s booming supply vessel sector is the fastest-

growing market in the world, driven by the sheernumbers required for E&P activities in the country’s

deepwater and ultra-deepwater basins.

While the country’s shallow and benign market seg-

ment is by no means quiet, it remains a relatively stable

one with around 50 vessels in action. But the Harsh &

Deepwater (H&D) segment’s operating fleet is soaring

in size, from 60 vessels in 2005 to nearly 160 vessels in2010, according to IHS-Petrodata.

This impressive annual growth rate of 22% is almost

entirely due to the dramatic surge in upstream E&P activ-

ity in the deep and ultra-deep waters of the presalt Cam-

pos and Santos basins. Broken down a little further, thedemand for platform supply vessels (PSVs) has been grow-

ing faster than for anchor handling tug supply (AHTS)

vessels. In 2005 the mix was about 50/50, while in 2010

the mix was 60/40 in favour of PSVs, IHS-Petrodata said.

But as is always the case in Brazil, the issue of local con-

tent is a key factor with the government having clearly

stated its desire to develop and increase its domestic

offshore yard activity, so that all supply vessels oper-

ating in Brazil can be built there.

The H&D supply vessel fleet in Brazil is mostly

modern, and all the Brazilian-built vessels are built

after the year 2000. As of late 2011, around one-third of the fleet in operation was built in Brazil

while the rest was built internationally.

As a result of the government’s desire to develop

and expand domestic yard activity the Brazilian

authorities launched a financial incentive scheme

called “Prorefam III” to directly stimulate in-coun-

try construction of 146 offshore supply vessels

(OSVs) before year-end 2014. This number is fur-

ther split into 82 PSVs and 64 AHTS units.This has seen organizations such as the Brazilian

development bank BNDES, which is providing

massive financial support for the development of the

country’s booming oil and gas sector, plough hundreds

of millions of dollars into the building of both PSVs and

AHTS vessels.

In 2010, for example, it financed projects to build 58PSVs and AHTS vessels:

• 19 PSVs (CBO – Grupo Fischer);

• 15 PSVs and 4 AHTS (Bram – Edison Chouest);

• Eight PSVs and 5 AHTS (WSOffshore – Wilson Sons

and Ultratug);

• Four PSVs (Starnav – Detroit); and

• Three AHTSs (Dof Navegação – DOF).

If domestic yards in Brazil are able to deliver supply

vessels in line with the Prorefam III plan, nearly all

AHTS units operating in the country’s offshore sector in2014 will be Brazilian-built, while the number of interna-

tionally-built PSVs in operation that year will still beabout 15 vessels more than in 2010 as demand growth is

expected to be higher than construction plans, accord-

ing to IHS-Petrodata.

It added that it is unlikely that the Prorefam III aims

will be reached. The number of PSVs is expected to be

close to the target level, but the construction of more

Apr il 2012 | EPm ag.com 90

SERVICE AND

SUPPLY VESSELS

Brazilian E&P spending fuels

major supply vessel growthA massive increase in upstream expenditure in Brazil is driving a strong demand

for supply vessels as oil companies tackle deep and ultra-deepwater areas

where there is little or no infrastructure.


The Maersk Leader AHTS vessel will

start work for Petrobras offshore

Brazil later this year on ultra-

deepwater projects.

(Photo courtesy ofMaersk Supply

Services)

8/10/2019 EPM-4


complex-to-build AHTS units is expectedto lag behind significantly. “In total weexpect total demand for internationally-

built AHTS and PSVs to be higher in2014 than in 2010. We do not believePetrobras will delay field developmentsdue to a lack of Brazilian-built rigs and vessels. We expect a practical approachbased on contracting international ves-sels until sufficient domestic resourcesare available,” the analysis firm stated ina paper at OTC Brasil 2011.

That belief is backed by three recently issued contracts by Petrobras to Den-mark’s Maersk Supply Service (MSS)

totaling US $281 million. All three contracts are four years in

duration starting in December 2012 andinclude the AHTS vessels Maersk Leader, Maersk Lancer ,and Maersk Launch . The vessels will be involved in ultra-

deepwater anchor handling with both conventional andtorpedo anchors.


SERVICE AND

SUPPLY VESSELS

Petrobras alone has an estimated shipbuilding demand for 192 OSVs offshore Brazil until

2015, with the Brazilian government’s Prorefam III initiative aimed at supplying the mar-ket with 146 new vessels. (Table courtesy of the Brazilian development bank BNDES)

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“Brazil is a strategically important growth market

for Maersk Supply Service, and these contracts

reinforce our strong relationship with one of the

industry leaders in deepwater E&P,” said CarstenPlougmann Andersen, CEO. MSS has 11 vessels cur-

rently operating offshore Brazil for Petrobras, its

biggest single customer, and five vessels for other inter-

national oil companies.

Petrobras remains the dominant client in Brazil collo-

quial, representing nearly 80% of demand. Meanwhile,OGX represents about 5% of demand while other opera-

tors represent 8% of demand, and a spot market also has

started to emerge.

Petrobras’ investment plan for 2011-

2015 shipbuilding demand is still huge,

with 192 new units forecast by 2015 and

281 by 2020. This is in addition to the 50

drillships and semisubmersible rigs, and50 FPSOs and production semisubs it

also is forecasting until 2020.

A key question emerging is on the

exact timing of future demand growthand yard construction capacity growth in

Brazil as international contractors

remain concerned about future demand

for vessels built outside the country.

IHS-Petrodata expects an average

annual demand growth for the next

five years of 14% for H&D supply ves-

sels in Brazil. On top of the forecast

rise in E&P spending for Petrobras and

other operators, the longer distances

and less existing field infrastructure

in the emerging Espírito and Santosbasins will also result in a requirement

for more supply vessels for both

drilling rigs and field productionplatforms.

Assuming the same growth trends for

AHTS and PSVs as in recent years, the

mix in 2015 will be about 70/30 in

favor of PSVs compared to 60/40 in

2010, although there is some uncer-

tainty about this, according to IHS-

Petrodata.

However, the long-term trend will bethat supply vessel contractors with

Brazilian ambitions will have to build

their fleets in Brazil. The main chal-

lenges appear to be potential delays

and cost overruns for newbuildings, as

well as higher operating costs than in

other regions.

Editor’s Note: Excerpts for parts of this arti-

cle have been taken from OTC Brasil 2011

paper 22507, presented by IHS-Petrodata.

SERVICE AND

SUPPLY VESSELS

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Petrobras plans to invest US $4.5 billion in R&D overthe next five years, especially on advancing technolo-

gies for ultra-deepwater oil production. “We are encourag-

ing industrial groups to set up research centers, includingforeign companies, that will register or apply for patents inBrazil,” said Aloizio Mercadante, former R&D ministerand now education minister.

The company’s future plans are mainly directed for thedevelopment of deepwater oil exploration in the AtlanticOcean below a thick layer of salt. Estimated at 50 Bbbl ormore, these discoveries could more than triple Brazil’s2011 proven crude oil reserves of 16.4 Bboe.

The goal is to prepare the country to become the fifthlargest oil producer. Also, by overcoming materials andequipment challenges, the Brazil government is working

to rank among the main exporters of crude.

Seeing Brazil as a good investment opportunity andrecognizing the quality of local universities, the biggest suppliers of Petrobras are establishing an intellectual part-nership with the company in addition to trade ties. Theminister cited biotechnology, biofuels, and environmentalresearch among the projects being developed.

Cenpes (Centro de Pesquisas Leopoldo AmericoMiguez de Mello) is the Petrobas R&D center, created in1970 at the campus of the Federal University of Rio de Janeiro (UFRJ). Since 2005, Cenpes has invested $700million modernizing and expanding its facilities. This hasattracted international firms with operations in the Brazil-ian oil industry including Schlumberger, FMC Technolo-gies, GE, Halliburton, Cameron, and Baker Hughes.

The investments in the experimental infrastructureCenpes constructed are critical for implementing a tech-nological strategy. The physical space of the R&D centerhas nearly doubled. Another 183,000 sq m (2 million sq

ft) were added on, reaching 297,000 sq m (3.2 million sqft) and making it one of world’s largest applied researchcenters. Research facilities at decentralized sites addanother 276,000 sq m (3 million sq ft).

The new Cenpes facilities were inaugurated in 2010. Inaddition, Petrobras also has semi-industrial experimentalplants, operational in several Brazilian states, integratedinto its industrial units. “Cenpes has become the largest research center in the southern hemisphere and one of the five largest in the area of oil and gas worldwide,” Cen-pes General Director Carlos Tadeu da Costa Fraga said.

Resources for developing solutionsIn recent years, Petrobras has consistently ranked amongthe world’s top five investors in energy R&D, investingaround 6% of revenue. Growth is not limited to the skillsof the workforce.

The financial resources earmarked for R&D at Petro-bras have been increasing, especially over the last five years, keeping pace with the mushrooming investmentsthe company has made in other areas. The company has alarger number of industrial projects, and its technologicalchallenges also have multiplied. Of around $2.7 billioninvested in R&D between 2009 and 2011, 59% was allo-

Apr il 2012 | EPm ag.com 96

R&D investment in Brazil

continues to surgeIncreased investment at Cenpes and other Brazilian research centers isfacilitating growth in technology R&D and innovation.

Jean Marlin, Contributing Editor

techWATCH

The Petrobras R&D facilities at Ilha do Fundão (Fundão Island),

Rio de Janeiro, include 227 new laboratories, making it the

largest research center in the southern hemisphere and one of

the five largest in the area of oil and gas worldwide. (Images

courtesy of Petrobras News Agency)

8/10/2019 EPM-4


cated to E&P and 21% to new processing, refining, andpetrochemical technologies. Although only 2% was allo-cated to biofuels, this represents $31.7 million, ranking

Petrobras among the top 10 investors in biofuel R&D inthe world today. The amount of research dedicated toenvironmental issues focuses mainly on atmospheric pol-lution and water resource management.

Cenpes research facilities

Research is simply not possible without quality laboratory infrastructure, and Brazil’s current legislation for the oiland gas industry has enacted incentives for innovation.

If the development of an exploration block in Brazilleads to significant production, operators are required tospend 1% of the value of future production on local R&D.

For now, the 1% rule only has a significant impact onPetrobras, with an R&D budget of $1.2 billion. Interna-tional operators also will see their obligations surging asproduction from recent finds come online.

Industry-wide, the 1% obligation is expected to gener-

ate a cumulative total of $9.5 billion in R&D spending inBrazil by 2020, according to a National Agency for Petro-leum, Natural Gas, and Biofuels survey estimate. Actual

spending will depend on the vagaries of oil prices and pro-duction growth as well as possible changes in the laws gov-erning how the oil money is spent.

By building domestic innovation capability, the govern-ment not only is driving Brazilian science and technology but also reaping direct benefits, whether in terms of human resource training or in attaining higher quality and faster results from joint research projects.

Cenpes has 130 laboratories and 30 pilot plants, employ-ing a technical staff of approximately 1,800, of whom 807are graduate researchers and 314 are engineers responsi-ble for the early design stages of major undertakings.

This is a genuinely unique arrangement since few oilcompanies have their basic engineering teams actually inside their research centers, bringing designers andresearchers closer together and encouraging the appli-cation of technological innovations in the company’s


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engineering projects. Petrobras currently is investingmore in training its personnel than at any other timein its history.

Approximately 511 technicians are operating andmaintaining Cenpes’ experimental facilities, whichrange from conventional laboratories to semi-industrialexperimental plants, some of which are located withinthe company’s production facilities. This also bringstechnology development nearer to implementation.

R&D partnerships

Very substantial input is due to significant experimentalinfrastructure investments in partner institutions (universi-ties and providers of goods and services in Brazil). Cenpes

works closely with these partners, sharing facilities and

developing solutions together.Petrobras has invested on average around $300 million

per year in Brazilian universities, with consistent input over the past three years.

These “Thematic Networks” are projects that are beingdeveloped in laboratory facilities built at Brazilian universi-ties under Petrobras’ management model for technology.The partnerships are approximately four times larger interms of area than existing Cenpes facilities. It is estimatedthat for every Cenpes researcher there are about 15 exter-nal researchers working at universities, suppliers, and part-ner facilities due to these networks.

This growth was rapid and made possible after the com-pany identified 50 strategic issues in the oil and gas sectorand selected potential partners for each of them. Today,Petrobras has more than 100 Brazilian R&D institutions

working in partnership with Cenpes.

With the advent of presalt E&P, the scale and complexity of the demands on Petrobras have grown considerably,requiring an expansion that has made Brazil’s oil and gastechnology facilities among the best equipped in the world.

Many traditional suppliers also have turned to Petrobrasfor long-term strategic partnerships involving cutting-edgetechnologies and technical expertise.

The pioneer was Schlumberger, which in 2010 inaugu-rated the Center for Research in Geo-engineering and hassince contracted 50 Brazilian researchers. The center playsa leading role in presalt carbonates in deepwater andultra-deepwater fields.

Three specially designed, fully integrated laboratoriesfor testing and evaluating rocks and fluids in controlledenvironments were installed at the Schlumberger R&Dcenter. In addition, the geo-engineering technology centerfor developing end-to-end geosciences and geo-engineer-ing workflows is using the Ocean application development framework and Petrel seismic-to-simulation software.

It also hosts a WesternGeco GeoSolutions Hub thatprovides seismic data integration-optimized solutionsto address specific regional challenges. The center has

10,000 sq m (107,639 sq ft) of office, laboratory, andconference space and staffing capacity for 300 people.Ongoing research programs are a multiteam effort of Schlumberger companies (Drilling & Measurements,Smith, M-I SWACO, Geoservices, and TerraTek Geome-chanics Laboratory) and include marine electromagnet-ics, petrophysics, reservoir engineering, geomechanics,drilling optimization, and completions.

BG Group announced that it will invest close to $1.5billion in its Global Technological Center in Rio de

Janeiro by 2021. BG expects its annual R&D spending inBrazil to rise from zero last year to $50 million/year by 2014, to $100 million/year by 2016, and to more than

$200 million/year in 2021, according to DamianPopolo, BG technology manager in Brazil.

Additionally, Baker Hughes is opening a technology center at Campinas, Technip has opened a research cen-ter in Espírito Santo state, and IBM has opened a tech-nological center in Rio.

According to the calculations of the Rio de Janeirostate government, these companies together haveinvested approximately $303 million.

Andy O’Donnell, president of the Western Hemi-sphere for Baker Hughes, sees the company opening anew level of collaboration with customers and universi-


ties in Latin America. “They will build together a new generation of highly specialized wellbore construction

tools and services to economically produce the presalt reservoirs offshore Brazil. Besides strengthening thecapability to provide local solutions, the new center inBrazil represents the next phase in the expansion of Baker Hughes’ global technology network,” he said.

Cenpes also seeks to strengthen its international ties

with universities and research institutes to act as the

linchpin between these scientific institutions and some

of Brazil’s major suppliers. This is paving the way for

faster technological development throughout the entire

energy sector supply chain. One example is the Glasgow

Caledonian University (GCU), which signed a Letter

of Intent to work with UFRJ, focusing on its School of Engineering and Built Environment and UFRJ’s Cento

de Technologia.

And FMC Technologies has opened a $40 millionsubsea research center at UFRJ, the largest subseatechnology research center in South America. As GCUhas a five-year collaboration agreement with FMC Tech-nologies in Scotland to undertake R&D in new sensordevelopments for the subsea oil and gas industry, theagreement between the universities also can lead tothe development of new collaborative R&D activitiesbetween GCU, UFRJ, and FMC Technologies.

Innovation and practical applicationThe Petrobras 2011-2015 Business Plan calls for $224.7

billion of investments and is a robust plan backed by aportfolio of highly attractive opportunities.

It was conceived to move the Brazilian oil-relatedgoods and services industry forward, providingdevelopment opportunities in equipment, services,and technology for an internationally competitiveoil and energy sector.

The company’s vision is supported by a coherenttechnology strategy, driven by business goals andfounded on long-standing, tried, and tested technologi-cal competence, with strong investments in generatingand, above all, applying knowledge. This practical appli

cation is guided by four principles that orient researchproject management: strict alignment with business anda focus on results, implementation of technology solu-tions, technology cooperation, and building local capacity. Increased investments at Cenpes are aimed at further implementing these goals and spurring techno-logical innovation.

“At Petrobras, innovation is viewed as the practicalapplication of the knowledge acquired to ensure that itis translated into positive business results,” Fraga said.“We are convinced that innovation is the only path tosuccess in today’s highly competitive environment.”

Cenpes installations include a 3-D simulation dome for group visualization of presalt projects.

8/10/2019 EPM-4


Cable recording systemstreamlines land seismic operationsThe INOVA Geophysical G3i cable-based channel record-

ing system is a flexible, portable technology that can beused to capture 2-D, 3-D, and 4-D data in a wide range

of land seismic surveys, including high-density wide-

azimuth acquisition in challenging environments.

The G3i land recording system supports more than

100,000 channels and features advanced ground elec-

tronics and high-productivity vibroseis capabilities. It

also has a rugged aircraft-grade aluminum enclosure

and polycarbonate exterior for improved durability in

the field.

According to INOVA, the system requires less field

equipment to transport, maintain, and troubleshoot,

so surveys can be carried out with more efficiency. Forexample, the unit deploys power-down-the-line technol-

ogy to evenly distribute battery power to multiple field

station units using the power supply and fiber tap units

along with standard 12V batteries. Additionally, these

ground electronics consume only 235MW of power per

channel measured at the power supply, the company

said. The system also features a 1.2-kg compact remote

acquisition module station with four analog channels, asopposed to using the existing single channel stations

offered by competitors. Inovageo.com/G3i

New service improves directionalcontrol in unconventional zonesPathFinder, a Schlumberger company, has releasedthe iPZIG at-bit inclination, gamma ray, and imaging

service to optimize well placement through early bed

boundary detection, specifically in high-efficiency

drilling applications. The new at-bit imaging service has

been successfully tested in unconventional zones such as

coalbed methane, heavy oil, and shale plays in North

America and Australia.

According to the company, the iPZIG service features

sensors placed directly behind the drill bit, providinggreater directional control and accuracy while drilling

when compared to conventional technologies. Data

reflecting changes in lithology and bottomhole assembly

orientation also can be identified using the new service,

so rapid geosteering adjustments in the well trajectory

can be made while staying in the production zone longer.

These data help reduce directional drilling risks and

allow for optimal well placement in critical hole sections.

In one application in a North American shale play,

the operator drilled a 1,524-m (5,000-ft), 8½-in. lateral

section in an abrasive formation. The iPZIG at-bit meas-

urements were used to control well trajectory, enablingthe bit to remain in the target zone 100% of the time,

according to PathFinder. slb.com/ipzig

Latest ROV offers upgradesfor speed, agility in deep waterThe Tomahawk multi-role ROV manufactured by theForum Subsea Technologies Sub-Atlantic product line

can be deployed in demanding deepwater environments

such as in the Gulf of Mexico, Brazil, and West Africa

and requires less personnel and a reduced level of spe-

cialism to operate relative to electro-hydraulic work-

class systems, the company said.The latest Sub-Atlantic ROV offering is rated to 3,000

m (10,000 ft) water depth and can be used for survey,

well intervention, and drilling support tasks. Combined


techTRENDS

The INOVA G3i land recording system has been successfullydeployed by BGP for high-productivity vibroseis techniques in a

western China oil field. (Image courtesy of INOVA Geophysical)

Garaged facing inward, the Sub-Atlantic Tomahawk multirole

ROV can simultaneously carry camera boom arms on the front

and TSS440 search coils on the rear. Garaged facing outward, it

can be fitted with manipulators (front) and intervention tooling

(rear). (Image courtesy of Forum Subsea Technologies)

8/10/2019 EPM-4


techTRENDS

with the Sub-Atlantic 3,000v, 400Hz small diameter

tether technology makes the product’s speed and agility

ideal for live-boating operations as well, according to

Forum Subsea. It also can be equipped with a 10kW hydraulic power unit for running heavy-duty manipula-

tors, tools, and work skids and features a 35kW power

system. The open deck space and payload are supported

by a large buoyancy area, providing a stable platform.

Additional features include coarse wave division

multiplexing and dual gigabit Ethernet options and

a communication junction box to easily integrate the

operators’ own equipment, which can be monitored,

controlled, and diagnosed using the Forum Subsea

Sub-Atlantic subCAN system. F-e-t.com

Corrosion, marine debris cleaning systemmaintains onstream assetsParadigm Flow Services has launched the Pure-Flow

chemical cleaning system to aid in the removal of

corrosion accumulation and marine growth in fire

mains critical to the safe operation of offshore oil and

gas installations. The new solution is particularly effec-

tive in eliminating buildup in aging assets, where pipe

work can be older than 25 years, according to Paradigm.

The chemical treatment works to remediate biofilm,

marine growth, and corrosion caused by bacteria, which

can restrict water flow, thin pipeline walls, and cause

blockages in deluge nozzles. Pure-Flow is generatedin situ and can be injected into a live fire main system

while maintaining pressure and without having to shut

down operations or dismantle pipe work, such as in tra-

ditional methods like high-pressure jetting. The clean-

ing agent also degrades quickly into sea salt after use

and is approved for use in environmentally sensitive

areas, the company said.

As part of the Paradigm firewater deluge liftetime

solutions, the system includes internal video inspections

backed by deluge testing results showing that blockages

and restrictions have been eliminated and helping oper-

ators comply with HSE inspections. Paradigmflow.com

New pressure pumping vesselto set sail for North Sea in 2013 A Baker Hughes pressure pumping vessel currently

under construction has been chartered by a subsidiary

to provide offshore stimulation services on Maersk Oil’s

assets in the North Sea. The eighth stimulation vessel in

the Baker Hughes pressure pumping fleet, the Blue Orca

will feature enhanced safety systems with redundant

back-up blending and pumping capabilities to support

high-rate and high-volume multizone fracturing opera-

tions and minimize delays in high-cost offshore environ-

ments, the company said.

The vessel will be rated to 15,000 psi and offer 15,000

hydraulic horsepower pumping capacity as well as the abil-ity to pump at rates of more than 60 bbl/min. Engineer-

ing work on the marine and stimulation systems is under

way, and completion is set for late 2013. Bakerhughes.com

Software suite improvesreservoir characterization analysisThe CGGVeritas company Hampson-Russell Software

and Services has redesigned its suite of reservoir charac-

terization applications across a wide range of seismic

exploration and reservoir characterization technology

platforms, such as AVO analysis and inversion to 4-D and

multicomponent interpretation. The HRS-9 software

suite features new architecture that includes a common

intuitive interface and data management system to

improve custom workflows.

According to CGGVeritas, the software interface acts as

a dashboard, integrating all functionality from the previ-ously separate programs into a single application. This

solutions-based approach to reservoir characterization

provides geoscientists with more in-depth data analysis,

further reducing exploration risk, the company said.

Additional advancements include multi-threaded 64-

bit computing, allowing for the managed use of multiple

CPU cores, batch processing for optimum resource

scheduling, and the ability to cross-link output and

input processes. Cggveritas.com

– Nancy Agin , Associate Editor

The ability to differentiate facies type along with its probability

of occurrence using the enhanced HRS-9 software suite can

yield much more refined risk analysis. (Image courtesy of

CGGVeritas)

8/10/2019 EPM-4


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The exploration and development of new oil and gasreserves are critical for India. One of the world’s

fastest-growing emerging economies today has to import nearly three-quarters of its oil supplies to feed soaringdemand – in 2010 the subcontinent, along with China,accounted for 40% of the global increase in oil demand.

But despite the government’s efforts over the past decade to entice western players into its upstream sec-tor, a general perception within the industry of ratherchaotic licensing rounds and conflicts between the state-run major Oil and Natural Gas Corp. (ONGC) and thecountry’s industry regulator, the Directorate General of Hydrocarbons (DGH), are threatening to derail India’sambitious growth plans.

India has a projected growth rate of 8% to 9% per year, and its energy needs are expected to triple by 2035from 468 million tonnes of oil equivalent (MMtoe) at present to nearly 1,405 MMtoe.

At the forefront of the challenge to find new reservesare ONGC and the privately-run Reliance IndustriesLtd. (RIL). Although ONGC has by far the lion’s sharein terms of acreage and production at present, it wasRIL that little over a year ago took the boldest step by entering into its US $7.2 billion strategic partnership with BP. The UK major’s reasons for partnering withRIL were to pursue upstream opportunities in the pro-

lific Krishna Godavari (KG) basin, which lies onshoreand offshore the east coast between Chennai andKolkata, and to create a pathway into the downstreamsector to provide the country with fuel.

Back in 2008 BP and Reliance formed a 50/50 joint venture (JV) for deepwater exploration D17 block in theKG basin, where seismic data acquisition is due to get under way this year.

But the mega-deal last year saw the two companiesenter into a partnership to cooperate across the entirehydrocarbon value chain. In the upstream, BP took a30% stake in 23 almost entirely deepwater blocks cover-

ing around 270,000 sq km (104,200 sq miles), with bothto also bid together for incremental opportunities inother deepwater blocks off India’s east coast.

With Reliance as the operator, BP also is now bringingits subsurface understanding to the table, helping RILoptimize gas recovery from high-profile projects such asthe world-class KG-D6 block. This block currently provides around 45% of all gas produced in India fromfields such as D1 and D3 (22 wells including 18 produc-ers) but has been suffering from declining production volumes due to reservoir complexity, higher than envis-

aged water ingress, and natural reserves decline.Significant steps already have been undertaken by the

JV technical teams in assessing these complexities, basedon which plans for workovers, side tracks, and addi-tional wells have been planned, with execution subject to necessary approvals.

The early signs are already encouraging – the D6gas fields had completed 900 days of 100% uptime andzero-incident production by year-end 2011. Average gasproduction from the block was 55.9 MMcm/d, with acumulative production of 1,257 Bcf since inception. Average oil production for 2011 from the block was


REGIONAL REPORT:

INDIA

India in a race against time

to find new reservesIndia’s thirst for more energy to feed the world’s second-fastest growing economy

means it needs to find and produce new and large oil and gas reserves quickly

if it is to achieve its growth goals.


Vantage Drilling’s Platinum Explorer deepwater drillship is on a

five-year contract with ONGC offshore India. (Photo courtesy of

Vantage Drilling)

8/10/2019 EPM-4


21,971 b/d, with cumulative output of 14 MMbbl of oil

and condensate since inception.

The companies are now working up an integrated

field development plan for all the gas discoveries in KG-D6, encompassing existing wells and other satellite dis-

coveries within the block to maximize capital efficiency

and accelerate monetization. An outline development

plan for four satellite fields was approved in January,

with engineering studies now foregoing. These four

fields will eventually be tied back 76 km (47 miles) to

the existing production facilities on the D1-D3 fields.

Reliance also was busy with the drill bit over the

course of 2011, making six discoveries including W1 in

the KG-V-D3 block, as well as onshore wells AF1, AJ1,

AT1, AN1, and AR1 in its CB-10 block. It has submitted

an integrated appraisal program for all its CB-10 discov-

eries. The company has submitted initial proposals forcommerciality to the DGH for review and discussion for

the discoveries of D33 in the GS-01 block (recently

approved by the Government), D39 and D41 in the KG-

V-D3 block, and D36 in the KG-D4 block.

Further appraisal of these finds is scheduled through

2012.

East coast crown jewel

India’s east coast remains the crown jewel for the


REGIONAL REPORT:

INDIA

End of an era as the New Exploration Licensing Policymakes way for open system

India’s long series of successful licensing rounds held

under the banner of its New Exploration Licensing Pol-

icy (NELP) are set to come to an end.

Increasingly complex and fractious NELP rounds that

have seen awards for its latest round (NELP-IX) repeatedly

delayed have led to plans to implement an open licens-

ing policy in the future.

The NELP-IX round originally saw regulators plan to

award 33 blocks by September 2011, but this has been cut

to just 14 after India’s upstream regulation committee, theEmpowered Committee of Secretaries (ECS), recom-

mended cancelling at least 10 bids where it felt the gov-

ernment was being offered less than 15% net present

value of profit petroleum.

Final approval sits with the Indian Cabinet Committee

on Economic Affairs, but among the bids currently set to

be hit by this decision are ones from Reliance Industries,

ONGC, Indian Oil Corp., Oil India, Bharat Petro Resources,

and Hindustan Petroleum Corporation Ltd.

Significantly, bids for a total of seven deepwater blocks

and three shallow water blocks were recommended for

rejection by the ECS in what could be a serious blow to

the country’s supposed deepwater ambitions.

Reliance bid for six out of 34 areas originally offered for

licensing in the ninth NELP licensing round, including for

the Andaman deepwater blocks AN-DWN-2010/3 and

AN-DWN-2010/4. A consortium of ONGC and Oil India

Ltd. also bid for the same blocks. The ECS also recom-

mended turning down ONGC’s offer for two other

Andaman Sea blocks, AN-DWN-2010/1 and AN-DWN-

2010/2, where it was the sole bidder.

It also recommended turning down bids by a consor-

tium of ONGC-OIL and GAIL for deepwater block GS-

DWN-2010/1, and another by ONGC-OIL-BPRL for Kerala-

Konkan deepwater block KK-DWN-2010/1.

The one bright spot for the frontier deepwater zone is

that a consortium of BG Group and BHP Billiton has provi-

sionally won a deepwater block in the Mumbai basin

(Block MB-DWN-2010-1). BG said its qualifying bid for the

block will, if formally approved, see it act as operator of

the consortium with a 50% stake. The block off the west

coast of India is approximately 350 km (217 miles) off-

shore and covers an area of 7,963 sq km (3,074 sq miles).

Water depths range more than 2,000 m (6,562 ft).

The NELP rounds previously have been of great value

to India, with the prior rounds attracting more than US $11

billion of investment commitments and seeing 87 oil and

gas discoveries reported so far. A total of 235 exploration

blocks have been awarded overall. However, problems

with NELP-IX have prompted the Indian government and

the Directorate General of Hydrocarbons – after the round

is completed – to implement plans to offer exploration

acreage under an Open Acreage Licensing Policy (OALP)

instead of the yearly NELP rounds, similar to how bids areaccepted in the UK and Canada.

The OALP is proposed to be implemented on a sectoral

basis, with the help of data repositories from the country’s

NOCs such as ONGC until such time as a full National Data

Repository is set up and operational.

An open system is seen as the way forward to enable

a more flexible approach for operators and is being

implemented to further encourage international compa-

nies to participate in what will be perceived as a simpler

system and will open up the country’s entire acreage.

8/10/2019 EPM-4


REGIONAL REPORT:

INDIA

country’s offshore sector, and ONGC is focused onthe area.

The company already has oil flowing from its G1-GS15

field development in the KG basin, with the GS15 por-tion of the project lying in shallow water around 5 km(3 miles) offshore. However, the G1 portion of thedevelopment will see ONGC bring onstream what will beits first operated deepwater project offshore India, withthe field located nearly 30 km (19 miles) from the coast in 500 m (1,640 ft) of water.

The G1 field is planned to come onstream in May 2012, at a rate of 2 MMcm/d, while output from GS15 isexpected to plateau at more than 9,000 b/d. Develop-ment of several other nearby fields is scheduled to get under way before year-end and through 2013.

Close by it also has the high-profile KG-DWN-98/2block, which lies adjacent to Reliance’s D6 fields. ONGCis planning to start a first production phase within thenext six years and has previously flagged overall invest-ment levels of nearly $8 billion for the project.

Cairn India had made four discoveries in the blockbefore selling a 90% stake to ONGC in 2005. ONGCthen made a further six discoveries and its first ultra-

deepwater discovery, UD-1, in the block. The UD-1discovery lies in the southern part of the block in2,841 m (9,321 ft) water depth and would be by farthe most technologically challenging ultra-deepdiscovery in the country.

The company is focusing on two options, one being astandalone development of the main field area, whilethe other would involve an integrated development of the main field as well as the northwest area of the block.Initial estimates place development costs at nearly $3 bil-lion for the first phase, with in-place reserves estimatedby the DGH at 3.9 Tcf of gas.

Up to 11 production wells would be drilled at UD-1 toinitially produce it, with a peak rate eventually predictedat around 715 MMcf/d.

However the state-owned major, with its limiteddeepwater experience, remains on the lookout for anexperienced western partner after losing former blockpartners Statoil and Petrobras several years ago when it decided the block was not a priority.

Although the BG Group has been repeatedly linked with ONGC, ConocoPhillips has recently thrown its hat in the ring over a possible multi-block partnership; how-ever, this remains in the early stages of discussion.

It has been reported that up to 19 blocks offshoreeast and west coasts could be part of a deepwater explo-ration deal.

Off the country’s west coast there already are somepromising discoveries that ONGC is progressing. Thecompany has a potential fast-track development underconsideration for the Daman (Main) and Daman(North) prospects in the B-12 and C-24 blocks.

Doubling reservesStrategically, ONGC remains on a clearly stated mis-

sion to double its reserves to 12 Btoe by 2020, finding

new reserves via the drill bit and using new technologiesto improve its recovery factor. The goal is to raise thefactor from around 28% in 2000 to a planned 40% by the end of this decade.

It already has made significant progress in this regard, with its recovery factor raised from the initial 28% figureto 33.5% in 2011. A total of 15 out of 21 IOR/EOR rede- velopment projects have already been completed, withan estimated cumulative gain of 64 million tonnes.ONGC currently has 107 well stimulation units inaction, with 121 drilling rigs in action (87 onshore,34 offshore).

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SOUTH AMERICA

EWT under way on Iracema

An Extended Well Test (EWT) is under way in the pre-

salt Iracema area of the Santos basin offshore Brazil

using the FPSO BW Cidade de São Vicente . The floater is in

Block BM-S-11, with the unit connected to well RJS-647

in 2,212 m (7,258 ft) water depth. The facility is gather-

ing technical data on the behavior of the reservoirs andoil flow along with other data, which will support devel-

opment of the final production system expected to start operations at the end of 2014 via the installation of the

150,000 b/d FPSO Cidade de Mangaratiba . During the

EWT, the well is expected to produce at a restricted flow

of approximately 10,000 b/d of oil.

Repsol’s sweet find in Campos basin

Repsol Sinopec and its partners have made a high-impact

ultra-deepwater discovery on the Pão de Açúcar prospect

in the Campos basin offshore Brazil. Partner Statoil said

the discovery well encountered two presalt accumulationscomprising a hydrocarbon column of 480 m (1,575 ft)

with a total pay of around 350 m (1,148 ft). A drill stem

test performed in a partial section of the pay zone flowed

5,000 b/d of light oil and 28.5 MMcf/d of gas.

Trinidad & Tobago deep round

Trinidad and Tobago’s latest deepwater licensing round

was due to open March 29. The 2012 Deep Water Com-

petitive Bid Round has a closing date of July 30, according

to the Ministry of Energy and Energy Affairs (MEEA).

Road shows were held in Houston and London, where six

selected deepwater blocks were unveiled. The six blocksoffered are in the East Coast Marine area and Trinidad

and Tobago Deep Atlantic area. PGS, in conjunction withthe MEEA, has acquired 6,766 km (4,204 miles) of marine

multiclient 2-D data over approximately 43,000 sq km

(16,602 sq miles) of the offshore area.

AFRICA

Chariot to get rolling with Namibian wildcat

Chariot Oil & Gas will kick off its exploration program off-

shore Namibia after signing a rig contract for the first

deepwater well, Tapir South. The Maersk Deliverer semisub-

mersible rig was due to arrive at the planned well location

by the end of March, with the wildcat forecast to take upto two months to drill. The Tapir South prospect, which is

estimated to contain around 604 MMbbl of oil, will be

drilled in approximately 2,108 m (6,916 ft) water depth to

5,100 m (16,733 ft) TD.

Statoil joins Tanzanian party

Statoil has joined the growing ranks of operators lining up

potential major gas developments offshore East Africa

after confirming success with its first ultra-deepwater well

offshore Tanzania. The company encountered 120 m (394

ft) of excellent quality reservoir with high porosity and

high permeability in the Zafarani exploration well inBlock 2, with logging results proving up to 5 Tcf of gas in

place. The find was made in 2,582 m (8,472 ft) waterdepth, with the well to be drilled to a planned TD of

approximately 5,100 m (16,733 ft).

NORTH AMERICA

ATP’s Morgus field flows oil

ATP Oil & Gas has announced initial production rates

from its Mississippi Canyon Block 942 A-3 (#2) well in

excess of 7,000 boe/d, of which 85% is oil. The well,located on the Morgus field in the Gulf of Mexico

(GoM), encountered 73 m (239 ft) of net pay. This is

the fourth well brought on production at the Telemark

Hub location via the ATP Titan floating drilling and pro-

duction platform. ATP operates the hub in approxi-

mately 1,219 m (4,000 ft) water depth.

Cascade FPSO onstream

Production is flowing from the deepwater Cascade/

Chinook field through the BW Pioneer FPSO vessel in the

GoM via the Cascade-4 well, which is approximately 250

km (155 miles) offshore in 2,500 m (8,202 ft) water depth.The production well was drilled and completed in LowerTertiary reservoirs. The BW Pioneer is the first FPSO to pro-

duce oil and gas in the GoM and has the capacity to

process 80,000 bbl of oil and 500 MMcm/d of gas.

Caesar/Tonga begins producing in deepwater Gulf

Anadarko Petroleum has started production at the

Caesar/Tonga development in the Green Canyon area

of the deepwater GoM from the Constitution spar in 1,524

m (5,000 ft) water depth. Production is expected to ramp

up to 45,000 boe/d from the first three subsea wells.

EPmag.com

READ MORE ONLINE

For additional

information on

these projects

and other globaldevelopments:


internationalHIGHLIGHTS

8/10/2019 EPM-4


internationalHIGHLIGHTS

CGGVeritas kicks off Tabasco 3-D survey

CGGVeritas has begun acquiring the Tabasco 3-D multi-

client survey near the Kuparuk and Alpine oil fields

on Alaska’s North Slope. The company is deploying itshigh-productivity vibroseis acquisition and EmphaSeis

broadband vibroseis technologies for the first time on

the tundra to acquire the 345-sq-km (133-sq-mile) sur-

vey. The first migrated data is scheduled to be delivered

in July 2012.

EUROPE

Statoil’s Skrugard

success in Barents

Statoil has successfully drilled appraisal well7220/5-1 on the Skrugard

discovery in the Barents

Sea offshore Norway. The

well was drilled in 388 m

(1,273 ft) water depth,

reaching a total depth

(TD) of 1,740 m (5,709 ft).

The well encountered a 25-

m (82-ft) gas column and a

48-m (157-ft) oil column in

the Middle-Lower Jurassicreservoir, Stø, and Nord-

mela formations. Together

with the Havis field, which

was discovered at the

beginning of 2012 southwest of Skrugard in the PL532

license, recoverable oil reserves in the area are now more

than 500 MM bbl.

Irish appraisal success on Barryroe

Providence Resources has confirmed the presence of high-

quality light oil within a potentially extensive sandstone

system at its Barryroe appraisal well in the North CelticSea. The appraisal well 48/24-10z was drilled to 2,301 m(7,550 ft) TD and encountered a primary basal sandstone

reservoir interval within the predrill depth prognosis. Indi-

cations of hydrocarbons were seen while drilling, and wire-

line logging has confirmed the presence of 12 m (41 ft) of

net pay in both oil and gas-bearing zones, with the oil gra-

dient being consistent to that of light 40°API crude oil.

Duo hits gas offshore Romania

The OMV Group and ExxonMobil have reportedly

encountered approximately 71 m (233 ft) of net gas pay

at the Domino-1 well offshore Romania. The well is in

the Neptune block in 930 m (3,051 ft) water depth.

MIDDLE EAST

Saudis stepping into Red Sea

Saudi Aramco plans to drill its first deepwater well in

the Red Sea by year-end 2012. The company expects

to establish up to 100 Bbbl of new oil from its existing

fields in the Kingdom over the next several decades via

enhanced oil recovery methods as well as discovering

additional reserves in unexplored areas such as the Red

Sea. The initiative also is expected to increase the com-

pany’s natural gas production 40% by 2014. The com-

pany also is working on increasing its rate of oil recovery

from fields from 50% to 70% in the coming years. Saudi Arabia has 267 Bbbl of proven reserves, about one-fifth

of the world’s total.

Total snaps up Yemen block

Total has acquired a 40% operating interest in the Block

3 exploration license onshore Yemen from Oil Search.

The license covers an area of 2,954 sq km (1,141 sq miles)

in the eastern section of the Marib basin. Total’s partners

will be the Austrian OMV, the Czech MND, and state-

owned Yemen General Corp. for Oil and Gas (YGC).

Once the transaction has been completed, the joint ven-

ture will resume exploration with a seismic survey, whichmay be followed by the drilling of an exploration well.

ASIA/PACIFIC RIM

Natuna prize for Premier

Premier Oil has confirmed its latest test on the Lama

formation within the deepwater Anoa field in the Natuna

Sea Block A offshore Indonesia was successful. The WL-5

development well was deepened to 3,356 m (11,012 ft) TD

to investigate the exploration potential of the Lama for-

mation. The well encountered approximately 91 m (300

ft) of fractured Lama sandstones and was tested andflowed gas at a rate of 17 MMcf/d through a 48 ⁄ 64-in. choke.

South China Sea project gets green light

China’s State Oceanic Administration has approved the

environmental impact assessment (EIA) for the Beibu

Gulf project, which comprises the development of the

WZ 6-12 and WZ 12-8 West oil fields in the South China

Sea. First oil production from the Beibu Gulf project is

expected by year-end 2012. The ramp-up to full-field

peak production is anticipated during 2013, according

to project partner Roc Oil (19.6%).

Estimates confirm Skrugard holds

at least 250 MMbbl of recover-able oil and approximately 10

Bcm of associated gas. (Map

courtesy of Statoil ASA)

8/10/2019 EPM-4


on theMOVE

People

The Center for Offshore Safety has

appointed Charlie Williams executivedirector.

Shell has named Andrew Brown

upstream international director and a

member of the Executive Committee,

based in the Netherlands. Additionally,

Malcolm Brinded has stepped down as

an executive director.

Former 3M Chairman,

President, and CEO George

Buckley (left) has taken thereins as chairman, Expro.

The Society of Petroleum Evaluation

Engineers (SPEE) has elected a new

Executive Com-

mittee consisting

of President Mar-

shall Watson (topleft), Vice Presi-

dent Richard

Krenek (bottom

left), Past-Presi-

dent Barry Ashton

(top right), and Secretary-Treasurer

Samantha Meador (bottom right).

Stephane Constant has taken up the

newly created post of chief technology

officer, Xodus Group, to lead the com-

pany’s integration of surface and sub-surface services.

Offshore Installation Services Ltd., an

Acteon company, has selected Jeremy

Punnett to head the company’s project

management and specialist installation

services as global president.

Jan Grimnes, founder and CEO of

Technoguide AS, has joined the board

of ffA as a non-executive director.

Joe Miller (right) has been

promoted to vice president

and general manager for

Devin International, a sub-

sidiary of Greene’s Energy Group.

The board of Petrobras has elected

José Eduardo de Barros Dutra as cor-porate and services director.

Sigma Offshore has named Geir Eik vice

president, Internal Turret Systems.

TO

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ADVERTISER INDEX

American Jereh International . . . . . . IBC

Baker Hughes Incorporated . . . . . . . . 39

Cameron . . . . . . . . . . . . . . . . . . . . . . . 2, 3

Checkers Industrial Safety Products . . 106

CNPC Greatwall Drilling Co. . . . . . . . 34

Cudd Energy Services . . . . . . . . . . . . . 71

Diamondback Industries . . . . . . . . . . . 25

Dragon Products, Ltd. . . . . . . . . . . . 49, 93

E&P . . . . 84, 85, 94, 95, 102, 103, 107, 110

Emerson . . . . . . . . . . . . . . . . . . . . . . . . . 9

Expro . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Expro Group . . . . . . . . . . . . . . . . . . . . 79

FlexSteel . . . . . . . . . . . . . . . . . . . . . . . . 27

Fugro Jason . . . . . . . . . . . . . . . . . . . . . . 57

Gas Gun, The . . . . . . . . . . . . . . . . . . . . 78

Gefco . . . . . . . . . . . . . . . . . . . . . . . . . . 68

Halliburton . . . . . . . . . . . . . . . . . . . . 6, 81

ION . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

J&J Truck Bodies & Trailers . . . . . . . . . 59

Mechanix Wear . . . . . . . . . . . . . . . . . . 41

Mewbourne Collegeof Earth & Energy . . . . . . . . . . . . . . . . 11

M-I Swaco . . . . . . . . . . . . . . . . . . . . . . . . 4

ModuSpec . . . . . . . . . . . . . . . . . . . . . . 69

Momentive . . . . . . . . . . . . . . . . . . . . . . 91

National Oilwell Varco . . . . . . . . . . 19, 77

Newpark Drilling Fluids . . . . . . . . . . . 32

P2 Energy Solutions . . . . . . . . . . . . . . . 55

Paradigm BV . . . . . . . . . . . . . . . . . . . . 51

Polarcus DMCC . . . . . . . . . . . . . . . . . . 30

PTS Inc. . . . . . . . . . . . . . . . . . . . . . . . . IFC

R360 . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Rockwell Automation . . . . . . . . . . . . . . 89

Roxar AS . . . . . . . . . . . . . . . . . . . . . . . . 67

Schlumberger . . . . . . . . . . . . . . 5, 87, BC

Society of Petroleum Engineers . . . . . 98

Spectrum . . . . . . . . . . . . . . . . . . . . . . . 61

TAM International . . . . . . . . . . . . . . . . 47

TEAM Oil Tools . . . . . . . . . . . . . . . . . . 53

Tenaris . . . . . . . . . . . . . . . . . . . . . . . . . 17

Tervita . . . . . . . . . . . . . . . . . . . . . . . . . .15

Tetra Technologies . . . . . . . . . . . . . . . 73

TGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Weatherford International, Ltd. . . . 28, 29

Zeeco . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Expansions

HB Rentals has expanded its presence

in Australia by introducing four new product lines including A60 Tempo-

rary offshore accommodation and liv-

ing quarters modules and ATEX Zone

one pressurized A60 cabins, refrigera-

tor containers, and workshops.

Houston-based WellEzhas opened a

new regional office in Denver, Colo. The

company offers complete well lifecycle

reporting for oil and gas operators.

AVEVA has established a new office inSeoul, South Korea, that incorporates a

dedicated product training center. The

office also hosts sales, marketing, product

support, and administration functions for

AVEVA customers in South Korea.

Champion Technologies is launching a

new training academy in April. Courses

will focus on areas such as corrosion,

production chemistry, asphaltenes and

gas hydrates, microbiology, and phase

separation.

Expro has opened its new operations

base in the Shekou industrial zone in

China. The facility’s workforce com-

prises both operational and support

employees responsible for servicing

operations in the South China Sea.


Group PublisherRUSSELL LAAS

Tel: [email protected]

Associate PublisherDARRIN WEST

Tel: 713-260-6449

[email protected]

United StatesCanada / Latin America1616 S. Voss Road, Suite 1000

Houston, Texas 77057 USA

Tel: 713-260-6400

Toll Free: 800-874-2544

Fax: 713-627-2546

Regional Sales ManagerJULIE B. FLYNN

Tel: 713-260-6454

[email protected]

Regional Sales ManagerHENRY TINNE

Tel: 713-260-6478

[email protected]

Advertising Sales RepresentativeERIC MCINTOSH

Tel: 713-260-6471

[email protected]

Sales ManagerEastern Hemisphere

DAVID HOGGARTH

Tel: 44 (0) 7930 380782

Fax: 44 (0) 1276 482806

[email protected]

Advertising CoordinatorCAROL NUNEZ

Tel: 713-260-6408

[email protected]

Subscription ServicesE&P

1616 S Voss Road, Suite 1000

Houston, Texas 77057

Tel: 713-260-6442

Fax: 713-840-1449

[email protected]

List SalesMICHAEL AURIEMMA

Venture Direct

212.655.5130 phone

212.655.5280 fax

[email protected]

MARKETING | SALES | CIRCULATION

11

on theMOVE

The Expro Shekou base has a permanent

staff of 12 employees supervised by China

Operations Manager Matthew Milne and has

already supported three successful well sub-

sea landing string campaigns for the CNOOC

Yacheng project. (Photo courtesy of Expro)

E P

'

8/10/2019 EPM-4


The rapid expansion of Marcellus shale gas extraction

in the Appalachian basin of the northeastern US has

prompted significant public concern regarding the poten-tial for groundwater impacts due to hydraulic fracturingoperations. This concern has been heightened by media

coverage suggesting that hydraulic fracturing operations

and gas extraction activities in northeastern Pennsylvania

(Susquehanna County, in particular) have resulted in wide-

spread occurrences of methane in shallow groundwater.

However, the results of an extensive water well survey by

GSI Environmental Inc. indicate that methane is com-

monly found in drinking water aquifers prior to proxi-

mate drilling activities in Susquehanna County. In

addition, a review of relevant geologic and historic infor-

mation, as well as isotopic analyses ofdissolved gases, suggests that methane

in Susquehanna County water wells

is most likely associated with sources

in the shallow subsurface or Upper

Devonian gas-charged deposits that over-

lie the deeper Marcellus shale targeted for

commercial development.

This finding reinforces the need for

evaluation of potential stray gas

impacts based upon multiple

lines of evidence in order to

properly assess the sourceof methane impacts and the

risks associated with gas well

drilling and hydraulic fractur-

ing operations.

Shale gas drilling activities

first began in Susquehanna

County in 2006. However,

historical publications and

geologic records show that

elevated methane concen-

trations have been

observed in springs and water wells for more than 200 years

in the area. In the 1950s, the morning ignition of the water

fountain at Rush High School was a daily ritual. In addition,

local water well drillers report frequent encounters with

shallow gas-bearing deposits, particularly within the sand-

stone units of the Upper Devonian Catskill and Lock Haven

formations. Indeed, predrill sampling and testing of more

than 1,700 water wells by Cabot Oil and Gas Corp. inSusquehanna County from 2008 through 2011 foundmethane to be present in 78% of the water wells prior to

nearby gas well drilling activities. These predrill samples

were obtained from water wells located at least 300 m

(1,000 ft) away from active drilling operations. In this

dataset, methane concentrations in water wells within 1 km

(0.6 miles) of the nearest active gas well were comparable

to those in water wells greater than 1 km away, suggesting

no relation to gas development activities on a regional

scale. Rather, elevated methane levels in groundwater

showed a clear relation to topography .

In addition to geologic and historic evidence for shallow natural gas sources, the isotopic signatures of dissolved

gases in Susquehanna County also suggest that the

observed methane levels are not likely associated with

deep Marcellus shale gas. In 2009 and 2010, the Pennsylva-

nia Department of Environmental Protection and Cabot

collected samples of dissolved gases from 14 water wells in

Susquehanna County for geochemical analyses to deter-

mine the origin of impact. The carbon and hydrogen iso-

topic signatures of the dissolved gases were found to be

consistent with either thermogenic gases from Upper and

Middle Devonian deposits overlying the Marcellus shale,

microbial gases formed in shallow glacial drift and allu- vium, or a mixture of the two. These data show that the

presence of elevated methane in water wells throughout Susquehanna County could be explained without any con-

tribution from Marcellus shale related to the hydraulic

fracturing process.

In several cases, site-specific investigations may be

required to determine the source of methane in individual

water wells. However, based upon available information it

is premature at best to conclude that gas well drilling and

hydraulic fracturing activities are having any regional-scale

impacts on shallow groundwater resources.

Apri l 2012 | EPm ag.com

Methane in water wellsunrelated to hydraulic fracturingAn extensive study backs what the locals already know – water wells inPennsylvania have contained methane for hundreds of years.

J.A. Connor, L.J. Molofsky, and S.K. Farhat,

GSI Environmental Inc.; A.S. Wylie and T. Wagner,

Cabot Oil and Gas Corp.

lastWORD

112

Historical

publications and

geologic records show

that elevated methane

concentrations have been

observed in springs and

water wells for more than

200 years in the area.

8/10/2019 EPM-4


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@

jereh.com; tanwei

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