Revista E&P - Agosto 2011

8/10/2019 Revista E&P - Agosto 2011

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E P M A G . C O

NOCs changethe game

A U G U S T 2 0 1 1

ROV/AUV

Rock Physics

Cost and Risk Management

DownholeSystems and

Solutions

Drilling and

CompletionFluids

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COST AND RISK MANAGEMENT

Understanding shale fractures leads to betterproduction, lower cost

Real-time whirl detector improves RSS reliability,drilling efficiency

New approach takes health, safety interventionto a new level offshore

Enterprise risk management evolves to take onglobal business

ROCK PHYSICS

From seismic data to prospect identificationand drilling models

Digital rock physics provides new insight intoshale reservoir quality

DRILLING AND COMPLETIONS FLUIDS

Chrome-free WBM a viable option forultra-HP/HT applications

Unconventional resources benefit from custom

chemical regimes

DOWNHOLE SYSTEMS AND SOLUTIONS

Pump up the volume

ROV/AUV

Investment resurgence buoys ROV market

AUVs take on pipeline inspection

IndustryPULSE:The business case for a newleadership paradigm

Industry executives must lead the push to regain thepublic’s trust.

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

AUGUST 2011VOLUME 84 ISSUE 8

A HART ENERGY PUBLICATION www.EPmag.com

COVER STORY

30

Friends or Foes?The changing role of NOCs meansIOCs must leverage their expertiseto access new reserves.

6

WorldVIEW: Unconventionalenergy matters

Informed by more than 40 years in theenergy industry, investment banker Thomas A. Petrielooks forward to what the future holds for the oil andgas industry.

10

Unconventional: Granite Wash

Midcontinent’s Granite Washhas true grit

A revival in the Anadarko basin has awakened a

geologically challenging, liquids-prolific tight sandsresource play.

38

41

44

46

48

52

54

57

62

66

82 REGIONAL REPORT:

SOUTH EAST ASIA

72

74



AS I SEE IT

Safety takes a step forward 5

MANAGEMENT REPORT

Maximize business efficiency through

all-encompassing processes 14

DIGITAL OIL FIELD

G&G software accelerates user productivity 16

SAP application executes more data loads in less time 21

EXPLORATION TECHNOLOGY

RTM aids in earthquake study 25

WELL CONSTRUCTION

Is the ‘old school’ still the only school? 27

PRODUCTION OPTIMIZATION

Technology tidies up EOR’s act 29

TECH WATCH

New production profile predictor methoddetermines well performance 76

TECH TRENDS 80

INTERNATIONAL HIGHLIGHTS 86

ON THE MOVE/INDEX TO ADVERTISERS 91

LAST WORD

Getting to ‘yes’ on shale gas 92

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. Singlecopies are US $18 (prepayment required). Advertising rates furnished upon request. POSTMASTER: Send address changes to E&P, 1616 S Voss Road, Suite 1000,Houston, Texas 77057. Address all non-subscriber correspondence to E&P, 1616 S. Voss Road, Suite 1000, Houston, Texas 77057; Telephone:713-260-6442. All subscriber inquiries should be addressed to E&P, 1616 S Voss Road, Suite 1000, Houston, TX 77057; Telephone: 713-260-6442 Fax: 713-

840-1449; [email protected]. Copyright © Hart Energy Publishing, LP, 2011. Hart Energy Publishing, LP reserves all rights to editorial matter in this maga-zine. No article may be reproduced or transmitted in whole or in parts by any means without written permission of the publisher, excepting that permission tophotocopy is granted to users registered with Copyright Clearance Center/0164-8322/91 $3/$2. Indexed by Applied Science, Technology Index and Engineering IndexInc. 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 The main photo illustrates the global dynamic

between NOC/IOC relationships, a strategy that has created major link-ups in the

form of strategic partnerships, alliances, and areas of mutual cooperation down

all avenues of the energy pipeline. On the left is an Epidote Amphibolite metamor-

phic rock core sample (colorized for our cover) imaged at 100 x magnification.

(Image courtesy of PetroArc International; cover design by Laura J. Williams)

COMING NEXT MONTH Read the September issue of E&P to find out what’s new in the geo-

physical market and to get an update on activity in the North Sea. Additional features in the issue take

a look at advances in multilaterals and extended reach drilling, stimulation technology, and ways to

improve production rate and quality. The Marcellus shale, one of the most active unconventional plays

in North America, is the shale focus for the month.

As always, while you’re waiting for the next copy of E&P , remember to visit www.epmag.com for news,

industry updates, and unique industry analysis.

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ONLINE CONTENT AUGUST 2011

Gullfaks sidetrack hits 170-m

gas, condensate zoneStatoil has reported pay in its Opal

exploration well in the Norwegian

North Sea.

PREMIUM CONTENT Subscribe @ EPmag.com/explorationhighlights

Hydrocarbon shows in Green Point shale in NewfoundlandAccording to Shoal Point Energy, a petrophysical analysis from the

#3K-39 well in Newfoundland’s Green Point shale play has confirmed

a thick section of producible unconventional light oil.

AVAILABLE ONLY ONLINE

Arctic, Deepwater Drilling To

Drive Global Rig DemandBy Larry Prado, Activity Editor

Harsh environments – Arctic and deepwater –

will fuel growth in rig demand through 2015.

Management approach addressesasset lifecycle

By Judy Murray, Editor

Total cost of ownership considers the

value of an asset from installation to

decommissioning.

Coast Guard reinforcessupervision of foreignoffshore drilling unitsBy Elizabeth Johnston, Editorial Intern

New policy focuses on risk-based

targeting of foreign-flagged vessels

in US waters.

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

Tullow taps oil in Ugandaexploration areaLondon-based Tullow Oil Ltd. reportedthat the #1-Jobi-East and #3-Mpyo wells

in Uganda’s onshore Exploration Area 1

(EA1) have encountered oil accumulations.

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Safety has long been a priority for the global oil and gas industry, but it moved

onto center stage nationally in the US following the Macondo incident in the

Gulf of Mexico. The Bureau of Ocean Energy Management, Regulation and

Enforcement (BOEMRE) was formed from the Minerals Management Service fol-

lowing the event and took on the responsibility of overseeing the safe and environ-mentally responsible development of energy and mineral resources on the US

Outer Continental Shelf.

The BOEMRE has led some of the most aggressive and comprehensive reforms

to offshore oil and gas regulation and oversight in US history. These reforms,

which strengthen requirements from well design and workplace safety to corporate

accountability, are being pursued with the goal of ensuring the US can safely and

responsibly develop its energy resources.

In working toward this goal, BOEMRE recently announced that it would employ

multidisciplinary teams instead of individual inspectors to carry out inspections on

offshore oil and gas facilities. While this approach will be more thorough, it presents

a challenge because it requires additional human resources from an industry in

which human resources are extremely limited.Fortunately, there may well be a host of qualified understudies waiting in the

wings.

As the Space Shuttle program winds down at NASA, there are thousands of techni-

cians, engineers, and scientists who will be laid off. According to Emil Peña, execu-

tive director of the National Corrosion Center at Rice University, this is a skilled

workforce that could – with some training – step into the roles that need to be filled

by the BOEMRE.

The goal of transferring technology in the form of human capital was the impetus

behind the formation over the last two months of the Energy Safety Institute (ESI).

Peña, who was instrumental in the creation of ESI under the umbrella of the

Greater Houston Partnership, said preserving human resources is one of the key

objectives of the institute. “One of ESI’s primary goals is to facilitate technology transfer by moving people from their roles in SRQA (safety, reliability, quality assur-

ance) at the Johnson Space Center (JSC) into new roles with the BOEMRE.”

ESI is basically about technology, Peña said. “You can transfer some of this tech-

nology, and there also is the opportunity of utilizing some of the assets that are avail-

able at JSC, such as labs, buildings, test facilities, and other resources.”

Peña believes using JSC to transfer knowledge

from the space program to energy, whether it is

ocean or land, is a win-win situation because it

allows SRQA programs developed for the space

program to be refocused on an industry that is

comparably challenging in terms of safety.

As ISEE IT

EPmag.com | August 2011

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

TEL: +1 713.260.6400FAX: +1 713.840.0923

www.EPmag.com

Safety takes a step forward

5

Read more commentary at

EPmag.com

JUDY MURRAY

Editor

[email protected]

Editor JUDY [email protected]

Senior Editor RHONDA [email protected]

Senior Editor TAYVIS [email protected]

International Editor MARK THOMAS

[email protected]

Associate Editor NANCY [email protected]

Corporate

Art Director ALEXA [email protected]

Senior GraphicDesigner LAURA J. WILLIAMS

[email protected]

Production Director& Reprint Sales JO LYNNE POOL

[email protected]

Senior Editor/ManagerSpecial Projects JO ANN DAVY

[email protected]

Executive EditorOnline RICHARD MASON

[email protected]

Online Editor REBECCA [email protected]

Director ofBusiness Development ERIC ROTH

[email protected]

Group Publisher RUSSELL [email protected]

Vice President, Digital Media

RONS DIXON

Senior Vice President, Consulting Group

E. KRISTINE KLAVERS

Executive Vice President and CFO

KEVIN F. HIGGINS

Executive Vice President

FREDERICK L. POTTER

President and Chief Executive Officer

RICHARD A. EICHLER

O

o

H A R T

E N E R G Y


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industryPULSE

The business case for anew leadership paradigmIndustry executives must lead the push to regain the public’s trust.

Ahuman resources executive at a Fortune 500 natural

gas company, acclaimed for world-class environmen-

tal and sustainable energy solutions, recently bemoaned

his firm’s inability to interest talented students in employ-

ment opportunities with his firm – even during the softest recruiting year in memory. His explanation: students

believe the oil and gas industry is broken.

And no wonder.

Words and actions of opinion leaders in media, gov-

ernment, academia, and even business make it appear

that the industry is focused solely on money and profits

for shareholders without regard for the environment or

the communities in which it does business. For example,

accounts of the 2010 Macondo oil spill in well-read busi-

ness publications indicted the entire offshore drilling

industry along with BP’s approach to managing safety

and risk.Similarly, journalists and politicians publicly

question the effects of transforming

densely settled urban and suburban areas

into “heavy industrial sites” to

produce natural gas, saying

that contamination and

pollution result in unac-

ceptable health risks

that demand restric-

tion through taxa-

tion and regulation.

To counter theseperceptions, indus-

try spokespeople

point out that tech-

nology has enabled the energy industry to meet the ris-

ing worldwide demand for fuel, power generation, and

petrochemical feedstock with expanded supplies; more

efficient extraction, production, and distribution meth-

ods; and lower emissions. They speak about research

results that show that offshore industry professionals

have extremely high job satisfaction scores. These rebut-

tals have not been effective in stemming the tide of neg-

ative perceptions about the industry, however.The truth? It is a mixed bag. There are many strong,

effective, and ethical leaders in the oil and gas industry

who are highly motivated to bring discipline and purpose

to the forefront in both practice and perception. How-

ever, there are other companies that are just coming

around to this viewpoint, and yet others that are lagging.

The entire industry needs to more swiftly develop new

paradigm leaders or risk that the laggards’ actions will

continue to serve as a drag on the industry’s reputation.

A new leadership paradigm

So what does the industry need to do tochange the perception that it is broken,

establish trust with customers, and attract

a new generation of employees? A very

good start would be to embrace

a new type of leadership that

rewrites the broken

script that has left

certain companies

unable to adapt to

the leadership

demands of the

21st century.This new leader-

ship model provides

a different frame-

work for the industry

to address its challenges,

one founded on the pillars

of purpose, ethics, and value for

multiple stakeholders.

The new paradigm demands an

expanded set of leadership capabilities

at all levels in oil and gas firms.

W. Bruce Bullock and Frank R. Lloyd,

SMU Cox School of Business

New paradigm oil and gas

leaders must be multidimensional

and embody the industry’s commitments,

externally and internally, including those

that express larger purpose, social legitimacy,

and ethical responsibility. (Image courtesy of

SMU Cox School of Business)



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• Purpose. New paradigm leaders articulate the organi-

zation’s larger purpose and focus on organizational

rather than individual success;

•Ethics. New paradigm leaders communicate truthfully and with transparency, maintain relationships based

on reliability and reciprocity – in a word, trust – andstand up for their beliefs while providing channels for

others to constructively address conflicts betweenstated and enacted values in the organization; and

• Multiple stakeholders. New paradigm leaders strive to

align the organization’s multiple stakeholders’ interests

and get them moving in the same direction.

This new thinking is already under way. Rex Tillerson,ExxonMobil’s chairman and CEO, articulates key ele-

ments of the new paradigm in ExxonMobil’s 2010 Outlook

for Energy . “Demand for energy is tied to the human desirefor a better life,” Tillerson writes. “By enabling people to

become more productive – and expanding their opportu-

nities – access to reliable, affordable energy can transformpeople’s lives and the communities in

which they live. Energy also plays a key role in advancing social progress.

“Expanding access to modern energy

will be essential to meeting global targetsfor reducing poverty and hunger and

improving health and education.”

It is this kind of purpose put into

motion that must guide actions and yield results. Purpose serves as a motiva-tor for employees and a compass for the

long-term direction of the company.

Of necessity, energy firms have long been among themost engaged within communities and the political enti-

ties with whom they operate. As the complex globalindustry matured in the 1960s beyond the founding gen-

erations of explorers, successive industry challenges made

it difficult to embrace leadership behaviors beyond thosefocused on production, efficiency, and profits.

New paradigm leadership is a way to regain behaviors

needed to gain trust and respect from a wide range of stakeholders: communities; customers; prospective

employees; and opinion leaders in politics, education,and journalism.

Big payoffThe payoff for the energy industry to develop new para-

digm leaders is potentially huge. New paradigm leader-ship can attract the best investors. A 2007 University of

Pennsylvania Wharton School of Business study found that

30 companies that managed to optimize stakeholder valuerather than shareholder value outperformed the S&P 500

at three-, five-, and 10-year intervals up to 700%. In Built to

Last , Jim Collins and Jerry Porras show that organizations

driven by purpose outperformed the general market 15:1

and outperformed comparison companies 6:1.New paradigm leadership also can attract the best cus-

tomers. The Edelman Trust Barometer shows customerstake positive action based on their trust in a company,

including 84% recommending it to friends and colleaguesand 77% paying more for its products and services.

Research also shows trust and leadership integrity are

key factors that move employees to higher engagement,bringing about greater customer loyalty, employee reten-

tion, productivity, quality, and safety. 2010 data from the

Ethics Resource Center show that employees respond toan ethical culture with improved loyalty and willingness

to go the extra mile. Organizations with strong ethical values experience less misconduct, more frequent report-

ing of misbehavior, and less retaliation on the job.

The biggest payoff for a new leadership paradigm inthe energy industry could be its effect on

new talent. Meeting the global demand forreliable and affordable sources of energy

produced responsibly requires new tech-

nologies and enormous investments. As aresult, the industry’s workforce will become

increasingly skilled and sophisticated. At

the same time, the industry faces an exodus

of experienced employees as the baby boom generation retires. Attracting andretaining new skilled talent therefore is

mission-critical.

If the industry were better known for its new paradigm– its larger purposes, its ability to align the interests of

multiple stakeholders, and its ethical climate – it would

do better in attracting and retaining talented young peo-ple, especially those of the millennial generation who

wish to do well by doing good.

Talent pool

Based on the behavior of students at the Cox Schoolattending undergraduate, graduate, and executive devel-

opment programs, energy holds a lot of appeal as anindustry because of its potential purpose. Student interest

in these programs is growing, and the school is adding

programs to meet the demand. However, many energy

companies have a way to go in terms of moving from an

interesting opportunity to a preferred employer or even an

esteemed employer, such as a Southwest Airlines, Apple

Computer, or GE. An energy industry guided by new para-

digm leadership can attract the best talent, best customers,

and best investors and thus face a bright future.

industryPULSE

The new paradigm

demands

an expanded set

of leadership

capabilities at

all levels in oiland gas firms.



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Unconventional energy matters

Informed by more than 40 years in the energy industry, investment banker Thomas A. Petrielooks forward to what the future holds for the oil and gas industry.

This summer, Thomas A. Petrie celebrates 40 years inthe oil and gas industry, first as an oil securities ana-

lyst and subsequently as an M&A advisor and investment banker. He has been vice chairman of Bank of America

Merrill Lynch since Petrie Parkman & Co., the Denver-

and Houston-based energy investment banking firm that he co-founded, merged with Merrill Lynch in December

2006. Formerly he was managing director and senior oil

analyst with First Boston Corp.Petrie was a keynote speaker at the Hart Energy Devel-

oping Unconventional Oil (DUO) Conference in Den- ver in late May, after which he spoke one-on-one with a

Hart Energy editor.

You have said that the development of unconventional oil in

the US has come at an especially fortuitous time, given geopo-

litical events and your belief in peak oil.

Yes. I see development of unconventional oil in theBakken shale and the Three Forks formation in NorthDakota and Montana as a world-class, 21st-century

opportunity. It’s a function of people-driven innovationand significant technological advances.

The timing of these unconventional opportunities and

a host of others that are candidates to become sources of new liquids in the US couldn’t be more propitious. When

you look at what’s going on geopolitically, with unrest

ranging up to civil war throughout the Middle East andNorth Africa and the post-Macondo implications for off-

shore drilling and US supply, to have such a new set of opportunities unfold at this time is remarkable.

The North American upstream oil and liquids sector is

morphing into a new era and a new ballgame. Further,the opportunities to develop associated midstream infra-

structure to fully exploit these resources are enormous.

What are current macro supply-and-demand fundamentals?

In terms of demand, some one-half trillion bbl of oilhave been consumed since 1945. The peak oil argument

would say there’s another 1.2 trillion or so remaining; amore optimistic viewpoint would add about 30% to 50%

to that figure.Regardless, prodigious consumption is the order of

the day. It’s important to keep that in mind despite

crosscurrents of political unrest and concerns about a

slowdown in US and worldwide energy demand fromthe weak economy.

Another big driver in the supply-demand picture isthat since 1970, miles driven in the US have declined.

But population growth worldwide continues. In 1950,

there were 2.5 billion people on the planet. Today, thereare just under 7 billion, and through 2030, it’s expected

we’ll add another 1 billion; from 2030 to 2050, another

1.5 billion.So, from now until 2050, we’ll add as many new peo-

ple to the planet as were present in 1950. And much of that population growth is occurring in emerging mar-

kets where per-capita consumption rates are rising quite

rapidly. The developed world is expected to stay fairly

Thomas A. Petrie, vice chairman, Bank of America Merrill Lynch,

recently spoke at the Hart Energy DUO Conference in Denver in

late May. The development of unconventional oil, he noted, is a

function of people-driven innovation and significant technologi-

cal advances.

Susan Klann, Contributing Editor

Aug ust 201 1 | EPm ag.com 10

worldVIEW



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Dr. Satya Gupta , Sr. Research Director

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There’s also a confrontation/power struggle develop-

ing between Saudi Arabia and Iran, and I think what

happened was a warning shot across the bow to let Iranknow that the Saudis are looking to take definitive action.

There’s only so much the Saudis can do to increase out-put over the course of the year, however, until more refin-

ery capacity opens up that can handle their oil. At the

end of this year, new capacity will come on in Port Arthur(Texas), and in the near term, about 1 MMbbl/d will

come on elsewhere in the world to allow them to pushcrude to India, China, and other parts of Asia.

OPEC’s president has signaled there may be an emer-

gency meeting before the fall meeting. The situation willturn on what happens to oil prices if the Saudis make

good on their threat to push more oil to market.

What about the stability of Saudi Arabia? Saudi Arabia is the linchpin for security of supply out of the Persian Gulf. During my recent trip there, I was struck

by how much King Abdullah is on top of the situation. It

isn’t a totally clear case that Saudi Arabia remains stable,but the issue is at least largely deferred because of some

very proactive actions he has taken and because of thegood will he enjoys thanks to his anti-corruption pro-

grams of the past decade.

I think the issue is succession. Now may be the time forSaudi Arabia to break out of the rough resemblance it has

had to China in the 1970s and Russia in the 1980s, when

octogenarians ruled. It’s time for leadership to pass to at least the next generation, and maybe ultimately two.

The concept that a monarch in the Middle East is anabsolute power – nothing could be further from the

truth. Effectively it is a consensus-building position,

more so than our own US presidential role is, at least incurrent times.

In the region as a whole, this is just the beginning of the first chapter of change in the Middle East. It will

take decades to work out.

What’s your view on the recent decision to release oil from the

Strategic Petroleum Reserve? This was a coordinated effort with 27 other nations, with

the US supplying half of the 60 MMbbl/d total over the

30 days, at 30 MMbbl or 1 MMbbl/d. It gets criticized by some as price management, but really it is supply man-

agement, given the loss of Libyan oil, which is tough on

Europe. Putting oil on the market helps to loosen upthe ability of the world supply system to adjust, with

some supply from Nigeria and Algeria that would have

gone to the US being redirected to Europe.

It also applies some pressure to prices, which theSaudis are probably willing to accept. It contributes to

pressure on Iran, which wants to maintain levels of out-put and keep prices higher. The bottom line is we were

flirting with significant demand destruction at oil prices

above $100/bbl.

If you had the Obama administration’s ear, what would you

recommend?

We need to figure out how to accelerate the use of more

natural gas to substitute for oil imports and how to con- vert optimal development of unconventional oil into the

system. These two actions would create jobs and

enhance energy security.

If we can intelligently use more gas to displace coalin power generation and in more portions of our trans-portation network – a variation on T. Boone Pickens’

plan involving 18-wheelers – we can, on the margin,

make a difference, with lower emissions, cleaner air, andreduced import dependence. This is alongside the bene-

fits from 1.2 MMbbl/d coming out of the Bakken in thenext decade, 800,000 bbl from the Eagle Ford in the

same time frame, and something additional from the

Niobrara and Monterey shales.That’s what’s so wonderful about the petroleum sector –

the ability of producers to adapt down the food chain, fig-

uring out how to capture exposure and move it on to thenext party that can prosecute it. The development of the

unconventionals is bottoms-up and technology-driven, with astute people figuring out what to do next.

“I refer to it as the looming reality of practical peak oil. We’re

there.” – Thomas A. Petrie

worldVIEW

1



For many oilfield services companies, global market

opportunities mean international assignments are

becoming the rule rather than the exception. People

and equipment work with projects that demand signifi-

cant attention to such things as logistics, local legislativerequirements, payroll, and local content requirements.

At the same time, customers of oilfield services compa-

nies are concerned with the continuing rise in operating

costs and demand that goods and services are provided

ever more cost-effectively – exerting pressure on margins

and profitability.

Traditional generic management systems already strug-

gle to deal effectively with the complexities of the oil and

gas business. When components of the business in differ-

ent locations use different systems, it can be a struggle to

bring together the vital information necessary to support

successful international project assignments.Failure to manage this information results in higher

costs, lower productivity, and greater potential for human

error. A disjointed approach to managing people, suppli-

ers, equipment, and billing puts operations and busi-

nesses at risk.

Integration is the key A single integrated system is the key to having the right

people, with the right equipment, in the right part of

the world with the right certifications at the right time –

at a profit.

Integrated software packages such as SAP allow compa-nies from medium-sized enterprise to major oilfield serv-

ice and drilling companies to increase efficiency across

the board. The resultant improvements in information

distribution and reporting support management deci-

sion-making and aid delivery of more effective services.

The Advantage Oil & Gas for Oilfield Services System,

which is based on SAP best practice, was developed by

Absoft in response to requests from the industry for a

solution capable of aligning human resources planning;

equipment order and delivery; certification; payroll;

billing streams; and more.

Advantage provides a complete picture of these opera-

tions and facilitates complex planning, taking intoaccount very specific issues related to people, supply

chain, and equipment handling.

For example, the system is able to communicate any

effects that a delay to a trained staff member or certificated

piece of equipment coming on site could have on the next

phase of a project. As well as tracking people, Advantage is

able to track materials and equipment from the vendor to

the yard and onward to projects, improving asset utiliza-

tion and management of third-party equipment.

The system maximizes the use of both human resources

and equipment while reducing the cost of management

and boosting revenue by capturing all billable work. It enables companies to establish and maintain a standard-

ized process across their worldwide operations, which is

crucial to the global oil and gas marketplace.

Programmed with local standards for more than 45

countries worldwide, Advantage ensures legal compliance

and reporting requirements are met in the UK and else-

where. It simplifies and unifies the onerous tasks of sched-

uling and tracking workforce movements and handling

industry-specific workforce events such as the registration

and maintenance of regular and irregular shift patterns

and mass crew rotation changes.

Maximize business efficiencythrough all-encompassing processesTraditional management systems struggle to deal effectively with the complexities of global

oil and gas operations. A new approach gives companies an edge.

Don Valentine, Absoft Ltd.


managementREPORT

A single integrated system is the key to allowing companies

to increase efficiency across the board. (Image courtesy of

Absoft Ltd.)


http://slidepdf.com/reader/full/revista-ep-agosto-2011 17/92EPmag.com | August 2011 1

managementREPORT

Routine daily tasks such as completion of timesheets

and work progress logs also are integrated into the system

to ensure accurate billing. Accessing Advantage at the

worksite allows urgent updates to be carried out on thestatus of a piece of work if an issue arises, which in turn

allows appropriate action to be planned and executed to

keep work on schedule. The integrated system provides a

clear and unified overview of operations and allows main-

tained profitability. Detailed cost planning, tracking, and

reporting procedures mean service companies can prove

competence during both tender and work phases.

The system at work Absoft recently implemented the SAP HR solution using

the Advantage implementation methodology and tools

for a major international oil and gas company, migratingall of its data from a legacy system to SAP in harmony with

the company’s other global business units.

The data transfer included sensitive personnel informa-

tion for more than 500 employees across the UK, includ-

ing principal bases in Aberdeen and

London, making complete and secure

transfer crucial to the implementation.

Moving all of the employee data to

the SAP system allows for the future

implementation of the Advantage sys-

tem’s wider human capital manage-

ment elements, including personnelcost planning, appraisal tracking, and

competency mapping.

Centralizing data from disparate sys-

tems into SAP is fundamental to the

system, as this allows its components

to be used globally, handling regional

variations such as currency or legisla-

tive requirements in a single package.

Because the data are held in SAP, the

client is able to add further modules

with the knowledge that all of the data

required are available within the systemin use when new processes like person-

nel cost planning are being enabled.

The client’s main goal was to bring

its UK system in line with its global

implementation of SAP across its busi-

ness operations, a goal that has been

completed successfully.

Central to the implementation was

knowledge transfer. Absoft’s team

trained the client’s IT management

group and the business to ensure on-

going administration could be taken forward on site.

Absoft provides additional support when required.

Developing the solutionThe ability to share the necessary knowledge and training

on the ongoing development of the system, which helped

the company clinch the deal at competitive tender, was a

key aspect of Absoft’s service.

The company’s oil and gas team continues to engage

with the sector to investigate solutions to challenges

faced in day-to-day operations. These include quarterly

forums specifically aimed at oil sector employees work-

ing in supply chain, operations, and maintenance.

SAP is used by a significant number of energy compa-

nies. Providing an arena where participants can discuss

good practice and topical issues is already helping busi-nesses to make the most of their investment in the system.

The sessions also have allowed Absoft to continue to

develop additional capabilities within the software that

reflect the industry’s needs.

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Oil and gas operators often deal with large regional

projects, sometimes involving more than 200,000

wells, which can result in a tidal wave of data coming from

a number of different users and various disciplines. Thechallenge for many operators is to improve decision-mak-

ing by using data that are relevant, qualified, and sani-

tized. With rapidly expanding functionality, it is becoming

increasingly important for geology and geophysics (G&G)

software users to quickly find the specific data workflows

they need to use on a day-to-day basis. For this reason, the

latest release of Petrel includes improvements that focus

on the behavior and needs of the human users – the most

critical element of success with G&G projects.

A new way of working

The Studio E&P knowledge environment has beencreated to streamline everyday tasks through workflow

improvements and is scalable from the individual to the

largest enterprise. Studio functionality enables organiza-

tions to scale to the enterprise level while also allowing

multi-user collaboration without the burden on perform-

ance issues. Users can use data within an earth-model

context while interpretation team knowledge is also cap-

tured and stored so that it is carried forward and embel-

lished rather than recreated. Through the live knowledge

environment, data are kept fresh. This allows the users of

that data to make decisions based on the most up-to-date

information available as opposed to the “stale” data that often plague many G&G projects.

Despite using advanced science and technology, G&G

interpretation and modeling has always required an ele-

ment of art where the geologists and geophysicists become

the artists. As a studio provides a space for artists to profi-

ciently execute their craft, the Studio environment focuses

on ease of use and intuitive design to empower the G&G

professional.

Finding relevant dataE&P companies have access to massive volumes of private,

commercial, and public data from a diverse range of loca-

tions. The search capability of Studio, Studio Find, can

provide an index to this distributed database and enable

users to look within the context of their specific projects

to reduce or eliminate irrelevant information. This

focused process of information retrieval has been widely

documented in academic research about “dimensions of

relevance,” where relevance can refer to what is valid, reli-

able, and current. The new environment enables a variety

of searches in addition to geographical area such as proj-

G&G software acceleratesuser productivityA new knowledge environment focuses on the human interface to improve user efficiency

and advance corporate knowledge capture.

Floyd Broussard, Patrick Dineen and Keith Tushingham,

Schlumberger Ltd.

The Studio Find allows users to see all data available in the main

Petrel 2-D or 3-D window. (Images courtesy of Schlumberger Ltd.)

Users can access, transfer, publish, and store information to

enhance the company knowledge base with Studio Knowledge.

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ect type (e.g. exploration, development) and the role of

the person searching to aid in the fast access of data and

information significant to their needs.

Map services A growing volume of information is available in the form

of visual maps – some public (e.g. Google Earth), some

commercial, and some proprietary to E&P organizations.

This information, which is typically updated frequently,

has historically been uploaded at the start of a project,

where it can soon become out-of-date. Studio Find pro-

vides immediate access to live ArcGIS data via web map

and ArcGIS services in current 2-D and 3-D windows. It

automatically handles multiple coordinate reference sys-

tems, which can be a major issue in exploration projects

that cover large areas.The map data are available as a series of layers and can

be filtered using smart search capabilities such as particu-

lar keywords, data types, projects, users (originators), or

well depths. Users can zoom in to reveal increased detail

of information. This zooming often involves further filter-

ing to focus the search and bring the data volume to a

manageable level and maximum relevance. For example,

users can select wells penetrating a particular depth,

drilled by a particular operator, and/or completed with

specific technologies.

Data annotationThe data and map-based information discovery capabili-

ties of the Studio environment are key elements to its

focus on collaboration and knowledge capture. Another

component is the ability to tag content, therefore helping

to qualify the information, provide context and insight

into previous ideas, and enrich the combined thought

processes. This basic functionality is common in PC appli-

cations such as Adobe Acrobat, where text editors can

leave sticky notes or links to comments. Petrel users

might insert geo-referenced comments such as “This

was a quick interpretation done in a rush to meet a tight

deadline,” or “The interpretation of these West Africanturbidites is based on an analog from deepwater Brazil.”

In addition to simple text comments, Studio Annotate

allows links to related documents that give users a more

complete understanding of their peers’ contribution to

projects. These could include details of well completions

such as the additives and proppants used. Annotation also

can contain diagrams and photographs, like those of sur-

face equipment installed downhole. Easy access to this

type of information should enable a more comprehensive

analysis of offset wells to optimize the design of new

drilling and completions programs.

Session sharingThe old adage “a picture is worth a thousand words” is

certainly the case with G&G modeling. Appropriate visu-alization makes it possible for people with diverse expert-

ise to absorb large amounts of information quickly. These

people often are in different locations, so multinational

oil and gas companies use web-based systems for remote

collaborative meetings. A long-standing problem even for

high-performance applications is that many commercial

global collaboration tools cannot handle data volumes

fast enough. The new Studio Share software module

has been specifically tailored for the 3-D visualization

tools of Petrel, presenting a high-performance system

in which sessions can be shared on multiple screens

around the globe.

Capturing knowledgeNew collaboration tools and integrated multidisciplinary

workflows permit multiple members of an asset team

to build models and develop plans together. Team mem-

bers often change, and details can be quickly forgotten as

people move between projects. Studio Annotate provides

context through quality tagging attributes, indications as

to who contributed to certain parts of the G&G processes,

and notes on different decisions.

A structured “Publish” model enables shared access to

content “blessed” by an expert individual or team whilemaintaining privacy of the “sandbox,” where individuals

can test their ideas. The result is a higher quality corpo-

rate data repository, with intermediate and trial datasets

and models remaining on individual users’ computers for

personal use. Real-time alerts are sent to relevant users

when new qualified information is published, notifying

them of updates and synchronizing versions among the

multidisciplinary team. Team members can be notified as

soon as information changes or when a new surface has

been created or updated. Users can then view and load it

immediately, so interpretation is always up to date.

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Global companies need reliable enterprise solutions

to manage their assets. While enterprise resource

planning tools such as SAP help to streamline these

processes, their sheer size can sometimes compromise

the flexibility required to nimbly manage a worldwide

portfolio.Rowan Companies Inc. has a fleet of 22 high-spec off-

shore jackup rigs and 32 deep-well land drilling rigs, and

it also owns and operates a manufacturing division that

produces equipment for the drilling, mining, and tim-

ber industries. The company’s specialty is delivering

innovative drilling products and systems for hard-to-drill

deep gas wells.

Rowan’s operations – from company headquarters in

Houston to offshore drilling locations in the Gulf of Mex-

ico, the Middle East, the North Sea, Mexico, Egypt, and

Trinidad – require robust information technology such as

SAP’s enterprise applications, specifically SAP ECC 6.0.Because the company uses hundreds of SAP financial

documents and thousands of line items on a regular

basis, maintaining accurate records and keeping data up

to date for planning, billing, and accounting purposes is

a major challenge. SAP’s reliability, breadth, and depth

make it a critical investment for Rowan companies. How-

ever, the breadth and depth that make the system so

valuable frequently result in new levels of complexity

and inflexibility, making it difficult for nontechnical

users to fully leverage the power of SAP.

ChallengesRowan tasked its SAP project team with improving the

efficiency of monthly billing cycles as well as simplifying

the process for entering new financial data into the sys-

tem. The team quickly encountered several challenges.

Integrating master data from multiple legacy systems

into SAP was creating faulty data and causing frequent

errors. While assessing the monthly billing process, the

SAP project team discovered that every company bill

required significant manual input. For example, numer-

ous line items for operating hours, catering, mainte-

nance, etc., had to be input manually from forms into

SAP. Finally, the Rowan team found that the billing and

journal-entry process consisted of painstaking copying

and pasting, as much as 13 lines at a time from Excel

spreadsheets. This combination of erroneous data and

tedious manual entry caused delays in month-end clos-

ing as well as a lot of frustration.

Solution

Initially, the SAP project team and IT support staff usedSAP’s Legacy System Migration Workbench (LSMW),

a tool that supports the one-time or periodic transfer of

data from a variety of sources without programming to

upload journal entries. However, the LSMW data-migra-

tion fixes were inflexible and, due to the constantly

changing requirements either internal or mandated by

governing organizations, time-consuming to update.

Then Capgemini, a provider of consulting, technol-

ogy, and outsourcing services, introduced Rowan to Win-

shuttle’s Transaction tool at a technology conference.

The Transaction tool records the steps that a user takes

to complete any SAP transaction and maps the relevant

SAP fields to an Excel spreadsheet, creating a file tem-

plate that can be run to “shuttle” data between Excel

and SAP.

Rowan Assistant Controller Andy Hart immediately

recognized the value of Transaction. With Winshuttle

Transaction, Hart and his team members discovered

digitalOIL FIELD

SAP application executesmore data loads in less timeNew user-friendly tool eases data transfer.

Ray Vincenzo, Contributing Editor

The Transaction tool sped up Rowan’s master data cleanup proj-

ect. (Image courtesy of Winshuttle)



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they could better focus their efforts on specific pieces of data cleanup. “We

had one large LSMW that was built to edit all of the fields in a Vendor Mas-

ter Record,” Hart said. “However, it was the Vendor Tax ID numbers withinthese records that specifically needed to be cleaned up.” Once the team

gathered the Tax ID numbers, they could easily create a Winshuttle tem-plate on the fly to update the Tax ID number field without having to worry

about an Excel spreadsheet that contained all of the Vendor fields.“Projected to take six months, the master data clean-up project was

completed in just four, leaving time for additional end-user training and

post-production support,” Hart said. Winshuttle Transaction also allows the Rowan SAP project team to address

error elimination when uploading data from legacy system. Because Transac-tion tracks all of the data it “shuttles” into SAP, the software provides auto-

mated error alerts to the Rowan team, making it easy and efficient to retrace

the data migration steps in Winshuttle and address specific causes of faulty data.

Results

Winshuttle enables Rowan to greatly accelerate SAP data transfer, complet-

ing thousands of journal entries in a fraction of the time required with man-ual data entry. “What were once dreaded and laborious journal entries are

now user-friendly and easy to organize,” Hart said. “We have saved so much

time that we consider Winshuttle worth the cost just for the journal entry input.”

Not only do the books now close on time, they are completed a weekearly. In addition, Transaction reduces the time associated with reporting

and reconciliation. Hart said he generated 1,274 cost center reports in 13minutes.

Transaction also helps increase productivity within the billing department.

Employees used to spend many unnecessary hours copying nine lines at atime from the customer contract into Excel, updating the billable hours for

each line, and then pasting them into the billing screen in SAP. Now all of

Rowan’s contract billings are created with a Winshuttle template. The billingagent puts in all the header type information (customer, contract number,

date, etc.) and then runs a script to read the contract lines out to the tem-plate. The agent fills in the time to bill for each type of service, marking the

unused lines for deletion, and runs a second script to create the sales order.

“It probably wouldn’t be too bold to say that Winshuttle saved us from an

entire process redesign of billing,” said Rick Sonora, billing manager at Rowan.

Future plans

Since Winshuttle makes it possible for Rowan to execute more accurate data

loads in less time, Hart’s team has more resources available to think strategi-cally about SAP deployment.

“Winshuttle improves our productivity as a team and as an organization,so we’re better able to step back and take a broad look at the overall effi-

ciency of our financial implementation,” Hart said. “The more we do that,

the more opportunities we see for Winshuttle to help us perform data conversions in far less time.”


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When Repsol-YPF launched its Kaleidoscope project

four years ago, its purpose was to study new hard- ware alternatives to realize the promise of reverse time

migration (RTM) for oil and gas exploration.

What the company perhaps didn’t envision was theother potential uses of the computer. Repsol is now

partnering with the US government to develop a betterunderstanding of how earthquakes occur. The project,

being conducted offshore Costa Rica, is intended to

help scientists visualize and monitor the folds in the tec-tonic plates in the region.

“We’re really trying to understand zones around the

world that produce large earthquakes,” said Nathan L.Bangs, senior research scientist, Institute for Geophysics

at the University of Texas-Austin. “This is a scientific pur-suit to understand the process of subduction zones,

which are the settings that produce large earthquakes.”

In addition to the University of Texas, the Universityof California-Santa Cruz and the Spanish Institution

for Research are also involved in the project.

Costa Rica is a natural choice for the study. Bangs said

the area regularly produces fairly large earthquakes inthe range of 6.5 to 7.2 magnitude on the Richter scale.

Already it has been the subject of much study.

“There have also been some 2-D profiles,” he said.

But we really need 3-D seismic to look at some of thestructural details and to map out the plate interface zone

that slips during the earthquake.”Because of the nature of the area,

it is possible for the team to

study the subduction zone at relatively shallow

depths. Bangs said

the Cocos plate, anoceanic crust, is

subductingand

extending beneath

the Caribbean plate. A large 3-D survey

was collected earlier

this year, and Repsolis processing that

data, first in a con-

ventional time domain and then in depth. The depthimaging will be conducted using the RTM algorithm

Repsol developed for the Kaleidoscope project.

“Usually people think that RTM is only good for sub-salt,” said Francisco Ortigosa, geophysics director for

Repsol-YPF. “In other areas of the world where we

explore, we’ve found that RTM is very suitable for thiskind of environment where you have thrusting over

thrusting and complex structures.“We think we have technology that is very suitable for

this environment.”

Time processing should be complete by November,

with a final depth migration ready in May 2012. “It’sgoing to be a challenging project, but we are pretty sure

we can get a very high-fidelity image of the subsurface in

this part of the world,” Ortigosa said.

For Bangs and his colleagues, this will be a tremen-dous help. “These are very complicated structural set-

tings,” he said. “This is a subduction zone that has a

collision between two plates, and the collision processproduces a tremendous amount of deformation of the

overlying plates.”He added that the goals are to see the plate interface

more clearly and also to study the effect of the tectonic

movement on fluids. Fluids are squeezed out of therocks, and the pressures they produce are important for

controlling the strength of the fault zone, he said.

For Ortigosa, the partnership is a good example of cooperation between industry and academia. “We are

concentrated on our business, of course,” he said. “But it’s a nice opportunity to collaborate with academia in a

mutually beneficial project for

both parties. It’s part of Rep-sol’s commitment to be socially

responsible.”

RTM aids in earthquake studyRepsol’s Kaleidoscope project is being tapped to increase understandingof tectonic movement.


EPmag.com

RHONDA DUEYSenior Editor

[email protected]

2

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wellCONSTRUCTION

More and more, engineers are developing new

ways to improve on the old way of doing things.

As Hart Energy ramps up for its DUG Eagle Ford

Conference to be held in San Antonio, Texas, Oct.

10-12, the question of how technology impacts uncon-

ventional resource development has become a major

focus for the E&P editors.

Newer tools, such as rotary steerable systems and

real-time acquisition devices designed specifically forhorizontal applications (i.e. an average shale well),

make headlines on a regular basis. Rig design, namely

in the areas of automation, pad drilling, and smaller

footprints, are a major focus for many operators and

the companies that supply these rigs to market.

The debate looms large over whether or not

the burgeoning unconventional resource sector

requires an unconventional approach to rig design.

This debate is compounded by the generation gap

among all fields within the industry. As older, more

experienced crews become exposed to newer, more

advanced systems, there often is resistance to adopt-ing these tools or even admitting that they some-

times work. The “old school” is often the only

school when discussing the best methods to drill

a well.

The expression “Nintendo generation” is

sometimes used to refer to the newest genera-

tion of oil and gas workers. These engineers

are characterized by a high level of computer

literacy, a keen disposition to plug-and-play

technology, and a tendency to lose interest

in careers that do not consistently introduce more

advanced technology at a rapid pace. The “new

school,” as it seems, will require different approaches

to drilling technology, which is often set on doing

things the old way.

The difficult decision is for drilling contractors and

their customers to determine exactly what tools and

equipment are obsolete, which ones will be

standard in the future, and what

other technologies can have major

benefits if adopted for the oil and gas

industry.In an effort to define some of these

possibilities, the E&P editors are cur-

rently organizing an in-depth workshop

to look at this scenario as well as many

others that have a direct effect on a com-

pany’s bottom line. Namely, it takes more

than just capital to drill a well. Having the

right tools and the right people is a defining

factor in overall drilling costs.

By now, the industry has devised a

number of innovative approaches that are

proving themselves daily in shale playsthroughout North America. New equip-

ment is accepted readily if it drastically

improves productivity; but in areas where

the equipment “works just fine,” the more

important question is, “Are we using the

right tools for

today, or was it

the right tool

for 20 years

ago?”

Is the ‘old school’ still the only school?

With the rapid pace at which shale plays are being brought online inNorth America, can conventional tools keep up with the pace?


EPmag.com

TAYVIS DUNNAHOESenior Editor

[email protected]

EPmag.com | August 2011 2

Having the right tools

and the right people

is a defining factor

in overall drilling

costs.



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Next-generation technology that helps extract trapped oil from mature oil fields is always going to

be of interest, especially when it can be done without the

cost of drilling any new wells. When it also involves work-ing at the microbiological level or is connected with car-

bon capture and sequestration, it is highly topical. Twoadvances in these areas illustrate the possibilities.

Biotechnology is reaching into all aspects of the oil

and gas business, from helping to overcome flow assur-ance challenges in deepwater pipelines to releasing oil

that would otherwise remain trapped in the ground.Conventional oilfield technology extracts around a

third of oil-in-ground, a figure being slowly but consis-

tently improved. Generally it’s accepted that improvingthe global reserves recovery rate by just 1% equates to

between 20-30 Bbbl of additional oil.

One Houston-based venture being backed by theEnergy Technology Ventures (ETV) financing group

(comprised of GE, NRG Energy, and ConocoPhillips) is

biotechnology specialist Glori Energy. ETV’s aim is tohelp accelerate the commercialization of Glori’s AERO

(Activated Environment for Recovery of Oil) System,

which could extract up to an additional 45% beyondthat obtained from traditional recovery processes.

The system involves introducing a mix of safe nutri-

ents into waterflooded oil fields to stimulate the growthof indigenous microbes, which temporarily modify thefluid pathways to redirect water and improve oil mobility.

The ability to be able to customize its treatments tooptimize the microbiology of each oil field is an advance

that means operators would be able to micromanage

and extend a mature asset’s production profile without having to drill any new wells, with all the cost savings

and environmental benefits that this entails.

Boosting output from mature assets with no new wellsis also one of the aims of a landmark carbon capture and

storage project by Shell subsidiary Cansolv Technologies

Inc. using its expertize in CO2 capture technology.Cansolv got the government go-ahead for construc-

tion of an integrated carbon and sulphur capture sys-tem at Boundary Dam power station in Saskatchewan,

Canada. The approval allows one of the world’s first commercial-scale carbon capture and storage facilities,

lead by the Saskatchewan Power Corp.

The project not only fully integrates and rebuilds anaging lignite coal-fired unit but will see the captured

CO2 used for enhanced oil recovery on nearby fieldsby 2014.

Steve Bryce, president of Cansolv, estimates it will cap-

ture about one million tonnes of CO2 every year. Can-solv’s patented technology uses regenerable amines to

capture CO2 and SO2.

Both these innovative examples provide clean, envi-ronmentally friendly solutions and result in enhanced

production levels, with no wells having to be drilled. If

these are indicative of other

next-generation technologiesin the pipeline, the industry

is in good hands.

productionOPTIMIZATION

Technology tidies up EOR’s actCommercialization of next-generation solutions shows a cleaner way ahead.


EPmag.com

MARK THOMAS

International Editor

[email protected]

2EPmag.com | August 2011

Glori’s AERO System could extract up to

an additional 45% beyond that obtained

from traditional recovery

processes.



OVER STORY:

OC REPORT

August 2 011 | EPmag.com

FRIENDSOR FOES

The changing roleof NOCs means IOCsmust leverage theirexpertise to access

new reserves.

Mark Thomas, International Editor


The role and influence of national oil companies(NOCs) is rapidly transforming along with the rela-

tionships they are forming among themselves and withinternational oil companies (IOCs).

The days of NOCs focusing exclusively on domestic

activities are over. The new approach is a globalizedstrategy focused on international expansion, technology exchange, and industry engagement. This has createdmajor link-ups between NOCs and IOCs in the form of strategic partnerships, alliances, and areas of mutualcooperation down all avenues of the energy pipeline.

Although not all state-owned oil and gas entities arefollowing in the steps of leading energy conglomerateslike Petrobras, Statoil, Petronas, and China’s CNPC andCNOOC, the trend is catching on – and fast.

As E&P continues to expand into new frontiers suchas ultra-deep water, the Arctic, and unconventionalresources like shale gas, the inherently different strengths of IOCs will enable them to maintain relation-ships with the NOCs in a changing energy landscape.But the relationships going forward will be very different from those of the past.

NOC spending powerRising global activity and spending power of NOCs is

shrinking the pool of opportunities for IOCs. Many IOCs have reacted to this situation by adjusting theiroperating models and capitalizing on strengths suchas technological and operational know-how, securingaccess to capital markets, and the ability to better man-age risk or fast-track projects.

The key appears to be how IOCs can leverage theirtechnology, know-how, and value to assist an NOC inbetter developing its resources. This is the path aheadfor many western majors and independents as they seek

to access new hydrocarbon resources, often in areas previously inaccessible.

As much as 80% of global oil reserves today are con-trolled by NOCs, up from less than 15% in the 1960s.

NOCs also control 75% of oil production. The story issimilar for gas.

As NOCs look to develop these vast resources, they recognize that they need the IOCs as much as IOCsneed them – at least for now. Petrobras, CNPC, Rosneft,and many others openly acknowledge these relation-

ships are the best way to acquire or transfer the techno-

logical and commercial expertise needed in new energy frontiers.

It is no surprise, therefore, that companies like BP,ExxonMobil, Shell, and Chevron have been able tocement and expand their established relationships

with state energy companies around the world.

Instruments of government According to John Westwood, chairman of internationaladvisors for Douglas-Westwood, as state-owned bodies,NOCS operate as an instrument of the government and,as such, tend to act in the best interest of their sovereignnation. And many of them still have huge oil reserves.

Meanwhile, “there is significant evidence to suggest that the majority of IOCs have passed peak production

and are now in decline,” Westwood said. When Westwood entered the energy industry in the

1970s, IOCs controlled 80% of the world’s oil reserves.Today that position has switched, and NOCs directly con-trol 78%. He believes this has major implications for IOCs.

In the 1980s, some IOCs had “really shot themselvesin their corporate feet” by changing their businessmodel, Westwood said. The “What business are we in?”approach caused many of them to abandon upstreamR&D – believing this was the role of their suppliers –and cast off much of their in-house technical expertise.

This greatly boosted some of the major oilfield tech-nology suppliers. In many instances, NOCs can easily buy all the expertise they need from the service compa-nies and have less need for the skills, route-to-market,and finance of the IOCs, according to Westwood.

“Some NOCs are not willing to cooperate with IOCson an equity-sharing basis,” he said. “As a result, a largeproportion of the global oil reserves –conventionalonshore resources that are relatively cheap to produce –are difficult for the IOCs to access.”

Meanwhile, reduced opportunity has forced IOCsinto higher cost areas where they still have the internalexpertise to overcome technological challenges. These

areas include deep water, horizontal drilling, subseacompletions, or enhanced recovery, Westwood said.

Accordingly, deep water, for example, will be a primary means of reserve replacement for IOCs.

But in some cases the NOCs need to cooperate withthe IOCs, Westwood said. “This has been particularly true for tackling complex multibillion-dollar gas process-

ing projects such as LNG liquefaction plants.”

Forming new alliancesBP is one major that has recognized the need to formnew partnerships with resource holders, characterized by

Topsides on the FPSO Cidade de São Vicente on Petrobras’ pio-

neering Lula Field. The Brazilian NOC has become “IOC-like” in

terms of its in-house technical expertise and is a world-leader in

the deepwater and presalt frontier. (Photo courtesy of Petrobras)

COVER STO

NOC REPO



its ongoing ambition to strategically align with Russia’s

Rosneft. While this proposed alliance is still the subject of deli-

cate negotiations with TNK-BP, the reason behind it issimple – it offers huge upside in terms of enabling

potential access to Russia’s Arctic Continental Shelf.

The agreement would create the first major equity-linked partnership between an NOC and IOC. The

terms would see Rosneft hold 5% of BP’s ordinary vot-ing shares in exchange for approximately 9.5% of Ros-

neft’s shares, bringing BP’s total shareholding in

Rosneft to 10.8%. The proposal demonstrates a majorstep-change in the thinking behind a relationship

between an NOC and IOC.

BP CEO Bob Dudley commented in a recent investor

presentation that the company is stepping outside thetraditional IOC model.

“We’re focusing on long-term value by investing in the

key inputs – namely, safety, capability, technology, and

relationships,” Dudley said. “But we’re also evolving themodel of what an IOC does. Clearly, project scale and

complexity, requiring access to financing, technology,and capability, continue to enable IOCs to uniquely

invest in our industry’s challenges – deepwater projects

are a prime example, and we remain deeply committedto this important resource.”

Dudley said BP also is pursuing new kinds of relation-

ships with NOCs and major resource holders. “We don’t see them only as competitors but increasingly as part-

ners when our capabilities are suited to their needs,”he said.

According to Dudley, potential deals such as the Ros-

neft alliance – which would also see the company estab-

lish an Arctic technology center in Russia – provide a

platform from which BP can “seek additional opportuni-ties for international collaboration.”

This typifies the way BP is mirroring global trends.“Growth in energy demand and economic activity is

coming almost entirely from the emerging economies,”

Dudley said, pointing to Brazil, Russia, India, and Chinaas the most significant players.

Rosneft clearly sees the advantage of increasing its

partnerships. The company also signed an agreement with ExxonMobil to collaborate in the potential devel-

opment of resources in the Black Sea. The companiesplan to form a joint operating company, with Rosneft

holding a 66.7% stake and ExxonMobil holding the

remainder. They expect to begin exploration in the

Tuapse Trough area next year.Both companies will evaluate joint E&P opportunities

elsewhere and will invest in deepwater technology R&D.

Changing roles Jay R. Pryor, vice president of business development at

Chevron, underscored the need for NOC/IOC partner-ships in a keynote address at the World National Oil

Companies Congress 2011, highlighting two critical

trends – the long-term energy investment challenge andincreasingly difficult resource areas available for devel-

opment.

Building out the energy infrastructure to meet futuredemand will be an enormous undertaking, with the

International Energy Agency estimating that US $33 tril-lion in investment will be needed to meet global

demand by 2035. And with several major energy-con-

suming countries now abandoning nuclear power, the

COVER STORY:

NOC REPORT

NOC’s motivations and strategies for investment and expansion often differ from those of IOCs. (Source: XU Xiaojie (2007), PFC Energy

(2010), IEA research, FACTS Global Energy (2009)



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COVER STORY:

NOC REPORT

demands on fossil fuels could take on still greaterurgency. The world will need the equivalent of at least

three new “Saudi Arabias” by 2020 to make up for

declines in existing oil fields, he said. At the same time, the development prospects available

are growing increasingly difficult to pursue. The indus-try is facing deeper reservoirs, heavier crudes, tight gas

formations, and ever-more-remote locations that are

subject to harsher weather conditions.

“Needs bring national oil companies and interna-tional oil companies together, and transformative tech-

nologies are often crucial to addressing these needs,”Pryor said. “NOCs and resource holders look to IOCs to

unlock the value of stranded resources. They do so by applying ingenuity to pair new technologies and practi-

cal know-how.

He used Chevron’s Tengiz field as an example. “InKazakhstan, we more than doubled production from the

Tengiz field,” he said. “This is the deepest known super-

giant reservoir. And it has some of the most dauntingchallenges in the world.

“Innovative systems return produced sour gas intothe field at extreme pressures. This helps preserve the

Tengiz field’s high current reservoir pressures.”

It is important, he added, to keep in mind the chang-ing roles of NOCs and IOCs. “NOCs include highly suc-

cessful companies – which have advanced management and technology greatly,” he said. “(But) more and more,

we need to identify particular projects where specific

NOC-IOC partnerships will bring greater value thaneither can provide individually. By definition, NOCs

must proceed in a manner consistent with and support-

ive of national policy. For that reason, it’s even more

incumbent on IOCs to

approach new projects not only in terms of the business

proposition but in the frame-

work of the countries and thecommunities in which they

operate.” Acknowledging that “there

will be gaps” for both NOCsand IOCs, he said this createsan opportunity for both part-

ners to step in and fill those gaps with capital, resources

management, or technology.

Using historical linksRoyal Dutch Shell spent much of 2010 firming up agree-

ments with NOCs in China, Qatar, and Saudi Arabia cov-ering new natural gas potential.

That momentum continued, with Shell and CNPC

signing a Global Alliance Agreement in June emphasiz-

ing their intent to pursue mutually beneficial coopera-tion opportunities internationally and in China.

The two parties also signed a Shareholders Agreement to establish a well manufacturing joint venture (50%

each). The intent is to develop an innovative, highly automated well manufacturing system (WMS) that could

significantly improve the efficiency of drilling and com-

pleting new wells onshore, specifically with tight gas,shale gas, and coalbed methane in mind.

Shell also signed a protocol with Russia’s Gazprom last

year for strategic global cooperation. Among the oppor-tunities the companies will consider are further develop-

ment of bilateral cooperation in hydrocarbon E&P in western Siberia and the Russian Far East, cooperation

in the downstream oil products business in Russia and

Europe, and Gazprom participation in Shell upstreamprojects outside Russia.

Asian NOCs most activeSome of the most active NOCs are in Southeast Asia,

where there is a growing interest in unconventionalresources, particularly shale gas.

According to Ernst & Young’s NOC monitor report,estimates from the US Energy Information Administra-

NOCs have raised their E&P spend-

ing budgets this year more than the

IOCs and above the industry aver-

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has a planned acquisition of one-third of AnadarkoPetroleum’s assets in the Maverick basin in Texas’s Eagle

Ford shale play. KNOC will fund 100% of Anadarko’s

drilling costs in the area this year and 90% annually thereafter in return for acreage in the oil-rich Eagle

Ford and in the underlying Pearsall shale that mostly produces gas.

Privileged accessNOCs are in the driver’s seat, controlling a large per-

centage of the world’s oil and gas as well as much of itsmajor infrastructure systems.

Of the top 25 oil and gas reserves holders and produc-

ers, 18 are NOCs, according to the World Bank. In addi-tion, it is estimated that 60% of the world’s undiscovered

reserves lie in countries where state companies have privi-leged access.

Due to different priorities, NOCs often generate lower

revenue, are less profitable, and produce a significantly lower percentage of their upstream reserves than their

IOC counterparts. They have widely varying structures,functions, and complex mandates compared to the rela-

tively simple IOC mantra of maximizing shareholder

returns. And they must be seen to deliver a wide rangeof socioeconomic and political objectives for their sover-

eign governments in the national interest, often whileunder political pressure.

With their profit focus, IOCs do not operate undersuch restrictive guidelines and have developed a skill

set that enables them to manage risk better than some

of their state counterparts.These fundamental differences between the NOCs

and IOCs are why the proliferation of strategic alliancesand partnerships is taking place – different needs bring

them together.

With frontiers no longer based on geography but increasingly represented by high-risk challenges, the vast

majority of the world’s NOCs are signaling their wish tocontinue a mutually beneficial relationship with IOCs to

unlock stranded reserves and mitigate risks.

COVER STORY:

NOC REPORT

SPE ANNUAL TECHNICAL CONFERENCE

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COST AND RISK

MANAGEMENT

Much of the public and political concern about shale gas extraction is centered on water impacts.

This includes complaints from residents in states such

as Pennsylvania and New York that their water wells have

become contaminated with methane, speculation by some environmental groups that the fluids used in thehydraulic fracturing process will migrate upward to lev-

els where it can contaminate groundwater, and concern

that spills will impact surface water.Such concerns, whether legitimate or not, are threaten-

ing development of an extremely valuable energy source, with estimated recoverable reserves currently estimated

at more than 60 Tcf in the US (worth approximately US

$250 billion at a wellhead price of US $4/mcf).Shales hold enormous potential. The Barnett shale

underlying the Dallas-Fort Worth area of Texas has

produced natural gas commercially since 1981, whenMitchell Energy drilled the first gas well. Today, improved

technologies are moving the shale gas industry towardever safer, cleaner, and more efficient production.

Natural fractures are keyNatural fractures exist in almost all shale gas reservoirs.

In many, the fractures are healed or sealed and aretherefore assumed to play no role in production. There

is increasing evidence that natural fractures influence

the hydraulic fracturing process, the delivery of gas tothe wellbore, and the total oil content (TOC) or rich-

ness of the gas shale itself and thus the “grade” of theresource. Natural fractures also can influence the verti-cal extent of fracs, the vertical gas flow, and the potential

for environmental impacts.Discrete fracture network (DFN) analysis of natural

fracture systems provides a new tool to better under-

stand the hydraulic fracturing process and the produc-tion of gas resources from such tight rocks. Although

the DFN approach was introduced to the oil industry inthe 1980s, the ability of DFN simulators to incorporate

both natural and hydraulic fractures is relatively recent.

This ability depends on improved understanding of the

underlying mechanics of hydraulic fracturing.Until recently, all frac fluid that did not directly support

fracture propagation was treated as “leak off” and accom-

panied by a reduction in the hydraulic efficiency of theprocess. It is now recognized that fracing also can reacti-

vate natural fractures, providing an increased tributary

drainage volume for gas production. Natural fractures

thus have a dual role – in some reservoirs, higher natural

Bill Dershowitz and Mark Cottrell, Golder Associates

This computer-based

model shows the tributary

drainage volume for fractures

in a rock mass, illustrating the

amount of interference between gas production wells.

This DFN computer-based model

shows natural fractures in a rock mass with each

type indicated by color. (Images courtesy of Golder Associates)

Understanding shale fractures leads

to better production, lower costDFN simulation is shedding new light on natural and hydraulic fracture systems.



fracture densities imply reduced production, while inother reservoirs, higher natural fracture intensities are

indicative of higher production possibilities.

Similarly, when considering the potential environmen-

tal impacts of hydraulic fracturing, fully understanding

the direction and extent of any hydraulic fracture treat-

ment prior to implementing the frac is beneficial.

The vertical height of the hydraulic fracture is con-

trolled by the presence of lower modulus rock units

above the reservoir layer – hydraulic fractures consis-

tently terminate when they encounter these ductile

quenching units. The existence of high fracture intensi-

ties in these overlying units means those units are softerand therefore better able to terminate vertical frac prop-

agation. It is through such geological understanding

that the risks to the environment from hydraulic fractur-

ing can be effectively controlled.

Improved observations of natural fracture systems

through careful log interpretation can provide essential

insights to understanding fully the in situ stress state –

essential for improving fracing design and gas produc-

tion and maintaining environmental safety.

DFN modeling couples the geomechanics and fluid

flow in the fracture network and the rock matrix and

supports the design of a well-constrained, reliable, andproductive drilling and fracing program.

Golder Associates has developed and used FracMan

DFN models for both natural and hydraulic fracture

assessment. FracMan provides a key tool for improving

production from shale gas and understanding and

reducing environmental risks. The predevelopment

analysis of hydraulic fracturing and fluid flow demon-

strates the care being taken to manage gas and fluid

migration and can go a long way toward assuring regula-

tors and other stakeholders, such as local residents and

political leaders, that their concerns are being satisfied.

Microseismic monitoring comes of ageRecent advances in microseismic monitoring, including

the development of low-energy surface-based monitor-

ing techniques, provide a key insight to the hydraulicfracturing process. This can be used to validate DFN

geomechanical analyses and to help demonstrate con-

trol of fracing operations to environmental regulators.

Microseismic monitoring detects the hundreds of

small seismic events that occur when rocks slip past each

other during network fluid flowing. Using arrays of geo-

phones to record and triangulate microseismic events

makes it possible to build a 3-D image of the fracturing

rock mass. This image can be combined with the simu-

lated microseismic picture generated inside the Frac-

Man model, providing understanding and validation to

both the DFN modeling and the fracing process.Geomechanical modeling also can support a com-

pany’s decision-making process. It can contribute to the

planning of drilling, completion, and stimulation and

production strategies required for horizontal multifrac

wells designed to complement natural fracture systems.

Geomechanics can help optimize the best trajectory of a

well; it can help determine the in situ stress conditions

for safe and efficient fracing around geohazards. And it

also can help determine the optimal pressure conditions

during drilling to avoid unwanted processes like hole

collapse and formation damage.

No two shale gas reservoirs are the same (even withinthe same basin). It is of paramount importance that inte-

grated approaches be used to simultaneously address safe

and efficient production from shale reservoirs.

Through combining geomechanics, petrophysics, and

seismology, the use of horizontal wells and hydraulic

fracture stimulation can be used to safely develop shale

based resources.

This DFN

model shows

the natural fractures

with simulations of the

microseismic response that can

be expected during hydraulic fracturing.


COST AND RISK

MANAGEMENT

This image is a simulation of the microseismic response

during hydraulic fracturing in a rock mass. Small

earthquakes generated as parts of the rock mass

slide past each other.



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COST AND RISK

MANAGEMENT

Backward whirl can impact well economics, reducingdrilling efficiency and rate of penetration (ROP),

increasing non-productive time (NPT), and damagingdownhole tools.

Backward whirl occurs when the drillstring switches

from being in sliding contact to rolling contact with theborehole. Once a drillstring assembly goes into rolling

contact with the borehole, it rotates backwards around

the center point, essentially climbing the hole. The drill-string then starts to process backwards, creating traction

on the borehole, and continues to rotate at a high fre-

quency, depending on the clearance between the drill-string and the borehole. Eventually, it rotates clockwise

on its axis while traveling counter-clockwise around the

inside of the hole. If left unchecked, backward whirl canbe stopped only by shutting down the drilling operation.

Although backward whirl can occur in all well environ-ments, it is more likely at lower inclinations (vertical

drilling) and is estimated to randomly occur to somedegree in 40% of all wells. As the inclination increases

and the drilling trajectory becomes more horizontal,

the likelihood of backward whirl decreases, but it canstill occur.

Friction and high speedFriction between the contact points of the drillstring –

drill bit, bit cutters, stabilizers, or collars – and the bore-hole is crucial. As friction between the contact points and

the hole increases, backward whirl becomes more likely.

Furthermore, sharp edges on the drillstring can bite intothe rock, creating traction that can lead to backward whirl.

Backward whirl can reach frequencies anywhere from 5to 30 times the speed of the drillstring. This speed makes

the force especially violent, creating a combination of

high fatigue-loading and strong impact-loading conditionsthat can cause significant vibration and irreparable dam-

age to downhole tools.

A technology designed to detect backward whirl in real

time has been developed to combat this phenomenon,

which has serious ramifications if not controlled early inits self-perpetuating cycle.

Weatherford International Ltd.’s Real-Time WhirlDetector is proving to be a valuable tool in controlling

backward whirl, which is occurring more frequently with

the increasing use of rotary drilling. It is of particular con-cern with rotary steerable systems (RSS), which require

the drilling mechanism to rotate continuously whiledrilling. The tool was designed to operate with the com-

pany’s Revolution rotary steerable system.

The technology uses existing sensors on the rotaryor RSS mechanism itself to provide a real-time warning

that backward whirl is beginning to occur. With early

intervention, the engineer and rig crew can take immedi-

Daryl Stroud, John Pagett, and Daniel Minett-Smith,

Weatherford International Ltd.

A full-scale backward whirl simulation rig provides the ability to

study whirl in a research setting. (Images courtesy of Weather-

ford International)

Real-time whirl detector improves

RSS reliability, drilling efficiencyNew tool addresses need to detect and control backward whirl

to mitigate downhole drilling risks.



ate action to adjust drilling parameters in the bit weight

or RPM to reduce the effects.

Lab and field testingThe theory was tested in a a well in Oklahoma created for

field testing. Engineers observed that during a whirl

event, friction on the drillstring increased. Therefore, the

required drive torque also increased, creating more and

more energy going into the wellbore, which fueled the

backward whirl. When torque on the drive system builds

up at the surface, the drillstring winds up, stops for sev-

eral seconds, breaks free, and then accelerates at a very

high speed before spinning out. Backward whirl is

believed to occur during the spin-out phase.

The system was deployed in six wells in three geo-

graphic regions from July 2008 to April 2009.The detection system works by transmitting a real-time

warning to the surface from the downhole sensor, having

calculated a number indicating the severity of the back-

ward whirl event so appropriate action can be taken.

There are three levels of backward whirl – low, moderate,

and high. Once the backward whirl action reaches the

severe level, drilling must be stopped and evasive action

taken immediately. If the event is moderate, less extreme

measures can be taken, such as adjusting the drilling

parameters to shift the event back into the low range.

The objective is to reduce the whirl motion such that

drilling does not have to stop.

Successful deploymentThe system has had a marked impact in drilling optimiza-

tion in a variety of well environments. In Central Europe,

a motorized Revolution RSS assembly had been deployed

in horizontal gas wells for a period of time. But on one

well, operators using the detection system began receiv-

ing high backward whirl readings with real-time warnings

that action was needed. In checking the BHA, they discov-

ered the stabilizers were undergauge for what essentially

was a poor-quality, overgauge hole, which created

increased clearance between the borehole and the stabi-lizers. The deviation from stable drilling created the

increased whirl intensity.

Using the downhole data, engineers made the decision

to install new stabilizers on the BHA, which resulted in

the operator achieving the maximum ROP for that partic-

ular environment while maintaining stable drilling. When

the BHA was examined following drilling operations, it

was apparent that the equipment had sustained signifi-

cantly more damage during periods of high backward

whirl than incurred during runs where backward whirl

was low. Subsequently, similar BHA stabilization measures

were taken in other wells where increasing whirl intensity

was detected following stabilizer wear.

The system also was used successfully in a North Sea well

to maximize ROP. Prior to deployment of the system, the

drilling parameters had been adjusted to provide more

weight on the bit and increase RPM. These adjustments

created adverse drilling dynamics, compromising direc-

tional performance and tool reliability. The whirl detector

allowed the operator to apply a set of drilling parameters

that achieved balanced drilling performance and compo-

nent reliability. With balance restored, drilling ahead con-tinued at the maximum ROP possible for the drilling

conditions. Ongoing updates of whirl severity were com-

municated to the surface at a frequency of one per minute.

Since mid-2010, Weatherford has deployed the back-

ward whirl detection system in hundreds of operations,

including all Revolution RSS assemblies worldwide. The

system has actively prevented down-

hole tool failures, increased average

ROP, and reduced NPT.

References available.


RSS deployment using real-time whirl severity updates.

EPmag.com

READ MORE ONLINE

There is more

to the story…



COST AND RISK

MANAGEMENT

Generally, HSE focuses on such factors as environ-

mental, organizational, job-related, and human and

individual characteristics. Missing from this list, however,

are cultural and relationship factors. In the oil and gas

sector, the impact of culture and relationships is best illus-trated by their effect on health and safety intervention.

Most people in the oil and gas industry work alongside

others. For that reason, most unsafe acts are witnessed by a

colleague who potentially could intervene. When some-

one who witnesses an unsafe act makes the choice to inter-

vene, this action can be a powerful safety mechanism.

The problem is that people can be reluctant to inter-

vene because they fear the response they might get from

colleagues, direct reports, or those senior to them. They

also may not know how to intervene or lack the necessary

skills or confidence.

Many organizations within the oil and gas sector iden-

tify intervening as a key part of their behavior-based safety

system. Some also recognize that people need to be

actively encouraged and supported to intervene through

initiatives that:

• Raise awareness among staff of the cultural and rela-

tionship factors that influence people’s readiness to

intervene; and• Support staff to develop their confidence and skills in

intervening.

The challenge is to provide this encouragement.

Shell and Petroleum Geo-Services are two global organ-

izations that have recognized the value of intervention as

a safety process. They have invested time and resources to

develop drama-based training programs that provide a

hands-on approach to meeting these objectives.

Nils storyShell’s behavior-based safety system is based around three

Golden Rules: complying, intervening, and respecting.Shell redesigned a series of mobilization workshops for its

seismic and marine vessel crews to reinforce these rules in

the context of personal responsibility.

In diverse groups in terms of rank and role, crews dis-

cussed their experiences and their attitudes toward

intervening in response to a drama called “Nils Story.”

The story is based on a real incident concerning two

highly trained and experienced electricians named

Anders and Nils. In the scenario, there is faulty equip-

ment on Nils’ vessel that requires urgent repair. Anders

offers to help because he has had a similar problem on

his own vessel. They set to work. In the course of execut-ing repairs, there is an explosion that leaves Anders

dead and Nils needing hospital treatment.

In the investigation that follows, Nils admits that in

addressing the emergency, he and Anders failed to com-

Glen Robertson, Forum Interactive

Most people in the oil and gas industry work alongside others.

Often people fail to intervene in unsafe operations because of

personal relationships with their coworkers. One of the goals of

action-based training using drama is to show how friendships

can lead to a relaxed work attitude in which basic safety proce-

dures can be ignored.

New approach takes health, safety

intervention to a new level offshoreUnderstanding the factors that influence human behavior create a safer work environment.



ply with basic safety procedures. The relationship between the two men is high-

lighted as a critical factor. Their close friendship led to a relaxed and informal

approach in which basic safety procedures were ignored.In short, Nils trusted Anders and felt obliged to him for his offer of help.

This encouraged him to overlook his own responsibilities, which led to a pas-

sive attitude despite his own authority and experience.

In sharing their views and experiences, the crews who watched the drama

identified the cultural and relationship factors that influence their readiness to

intervene:

• Not wanting to offend senior people or create conflict with peers;

• Assuming senior people know what they’re doing;

• Feeling pressure from peers to keep quiet; and

• Feeling pressure from leaders to get the job done quickly.

Factors like these cannot be dealt with unless people are given the opportu-

nity to identify them and acknowledge their impact. Stories and action learn-ing techniques have proven to be an accessible and powerful way of doing this.

Improving the quality of interventionsPGS also identified fear of conflict as a barrier to intervening. The company

employs a system of “safe cards” that enables staff to report unsafe acts and sit-

uations. The objective was to improve the quality of interventions by providing

staff with the opportunity to practice and develop skills.

This was achieved by introducing a story-led training program. The safe card

content was used to create a drama, presented by actors, portraying a series of

typical unsafe acts and situations.

The culture and values of office-based staff within PGS was highlighted by

the characters’ behavior in the drama. This was then examined by staff, which worked with the actors to question and discuss what they had witnessed from

both angles: the person making the intervention and the person whose behav-

ior is being questioned.

This process gave individuals within PGS the opportunity to explore and try

out how they might intervene in a safe learning environment. The fact that

they did this alongside colleagues helped support a culture shift within the

team in which the importance of intervention was understood and its practice

encouraged and accepted.

New approach, valuable solutionsThere is no doubt that cultural and relationship factors influence people’s readi-

ness to intervene. By acknowledging and addressing these factors, and by givingpeople the opportunity to practice behaving differently, organizations can

develop intervention as one safety mechanism that can make a difference.

Though this approach is certainly novel, a number of major organizations

within the sector have used it to address the serious concern of worker safety.

Many have invested in new action-based training techniques in which drama

can be used to address culture and relationship issues that act as barriers to

intervention. The success of this approach has been visible in shifting attitudes

and improved confidence among staff and managers to take personal responsi-

bility for safety.

A sound slide of Nils story can be found on Forum’s website, www.foruminteractive.co.uk.


COST AND RISK

MANAGEMENT

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tional risks as well as financial ones –

and reaching beyond compliance.

Fundamentally, enterprise risk man-

agement starts with three questions:“What are the risks to my business?”

“What controls do I have in place

to mitigate those risks?”

“Are those controls working?”

To effectively manage risk, every

manager must be able to answer these

questions on a day-to-day basis. To

achieve this goal, organizations must

have a core process for identifying

and understanding their risks and

determining how they are being

addressed.

Five steps to successFundamentally, risk management is

a straightforward series of five steps.

These same five steps are employed

when managing any risk in any depart-

ment of any business.

The simplicity of this process is what makes a true ERM

solution valuable and manageable.

Step 1 is risk identification. Risk ID is the cornerstone

of an effective ERM program because a risk has to be

identified before it can be managed. There are thousandsof ways to identify risks, but whatever the methodology

used, it must be accurate.

Step 2 is risk analysis. An organization must understand

the impact of a risk on its objectives and goals. A functional

ERM solution enables identified risks to be evaluated in

terms of an organization’s risk appetite. Risk matrices, scor-

ing models, and materiality thresholds contribute to the

level of impact a particular risk may have on business.

Step 3 is control identification. A company has to

determine what is currently being done to manage risks

and what else can be done to further minimize them.

This step is crucial for compliance and providing confi-dence to stakeholders that a company is in control of

critical risks.

For many, this is a serious challenge. Many organiza-

tions are very good at steps 1 and 2, but when it comes

to determining what they are actually doing to control

their risks and who is responsible for that control, they

fall down. A working ERM solution provides senior man-

agement with traceability and accountability to improve

their risk control process.

Step 4 is implementation of control. Control imple-

mentation and control assurance are vital to the ongo-

ing viability of a business. For many organizations, an

audit is the first indication that there is a problem with

control. A robust ERM solution provides the ability to

ensure controls are properly assigned, accepted, and

implemented, providing accountability and governance

over risk control.Step 5 is monitoring and reporting. For many compa-

nies, this is the risk assurance or governance issue. It is

the ability to determine if commitments are being kept

and if risk management processes are working. This step

is critical for continuous improvement. An organization

should be able to determine if the controls it has in

place are in fact reducing its risk, if the company is

meeting its goals, if departments are lagging, or if criti-

cal actions are not being completed.

This step answers that critical question, “Are my con-

trols working?” and enables organizations to learn from

experience, track performance, and improve operations.

The competitive advantageIdentifying, understanding, and mitigating key risks

are critical to sustainable growth in today’s complex

global markets. Investment banks are looking for more

reliable bets. Governments are looking for better busi-

ness partners. Communities are looking for safer places

to work.

A corporation in control of its risks provides these

benefits and has a tremendous advantage over its com-

petition in the race for resources.

Risk-taking remains a fundamental component of the growth and competitiveness of

any business.


COST AND RISK

MANAGEMENT



ROCK

PHYSICS

Of what use is uncalibrated seismic and scattered log

data when the customer needs answers to where

and how to drill? This thought underlies a majorprospect identification project offshore Western Aus-

tralia. Schlumberger and WesternGeco collaborated to

give their customers what was wanted and needed.

The project began when the Australian Government

was planning to offer a large offshore tract between the

Io/Jansz and Scarborough gas fields on Australia’s

Northwest shelf. WesternGeco performed a 5,000-sq-km

(1,950-sq-mile) 3-D seismic multiclient survey of the area

in advance of the lease sale.

However, searching such a vast volume using seismic

data alone is costly and time-consuming. WesternGeco

worked with Schlumberger Data & Consulting Servicesto determine that a well-calibrated gas-sand probability

cube could be derived from amplitude vs. offset (AVO)

inversion outputs. Using advanced visualization tech-

niques, the data could then be interrogated to highlight

several direct hydrocarbon indicators and potential

prospects, an evaluation tool that could offer excep-

tional value to prospective investors.

The project, named Keystone, made use of all avail-

able data to enhance its acquisition design. Among

these were preexisting 2-D seismic surveys and well log

data from two previously drilled wells. One of the wells,

Jupiter, was a gas discovery that had never been pro-duced. The other well, Mercury, was dry. Log data from

Jupiter and an additional eight others outside the proj-

ect area were particularly valuable in calibrating

time/depth conversions as well as creating models for

each output domain in the seismic inversion, including

acoustic impedance and compressional velocity/shear

velocity ratio. The procedure derived mutual benefit

from the seismic velocities, which were used to constrain

the models and capture geological variations between

the wells. While the customer is happy to have the well

data, what is really wanted is knowledge of what is

Jorg Herwanger, Keith Myers, WesternGeco; and

Adrian Rodriguez-Herrera, Robert Nesbit and Nick

Koutsabeloulis, Schlumberger Data & Consulting Services

From seismic data to prospect

identification and drilling modelsOperating companies often ask for seismic data, but industry can deliver more.

In the top image, the Mercury well in blue intersects a structural

high in an area where no gas sands are predicted. On the new

3-D seismic data, the gas-bearing sands are seen to the west of

the Mercury well. Note that the Mercury well was drilled on old

2-D seismic data, and the fault could not be readily identified.

The middle and bottom images show high gas sand probability

was predicted for a region that was subsequently penetrated

by the Yellowglen well. (Images courtesy of Schlumberger Ltd.)



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ROCK

PHYSICS

The great majority of whole core samples recovered in

the US today come from shale reservoirs. A primary

reason for so much shale coring is that petrophysical

models require rigorous core calibration to provide reli-able data for reservoir quality, hydrocarbons in place,

and hydraulic fracturing potential.

However, the uncertainty in interpreting shale well log

data is sometimes matched or exceeded by the uncer-

tainty observed in traditional methods of analyzing core

samples. Most commercial core analysis methods are

50+ years old and were developed originally for sand-

stones and carbonates exceeding 1 millidarcy in perme-

ability. High-quality, organic-rich shale, on the other

hand, is usually lower than 0.001 millidarcy. This

extremely low permeability creates substantial chal-

lenges for existing methods and has contributed to therapid rise of a new approach to reservoir evaluation

called digital rock physics (DRP).

The DRP processDRP analysis of shales usually is performed in three

stages. Each stage provides visual and quantitative infor-

mation that can be used to select a smaller but represen-

tative volume for the next stage of analysis. Stage 1 is

performed on whole cores, Stage 2 uses plug-size sam-

ples, and Stage 3 is an ultra high-resolution 3-D pore-

scale analysis.

In Stage 1, whole cores are analyzed using calibrated

X-ray computed tomography (CT) imaging at a resolu-

tion of about 500 CT slices per linear foot of whole core.

These detailed images are obtained while the fragileshale is sealed and protected inside the aluminum core

barrel liner. This process is substantially reducing the

need to “slab” or saw-cut the core along its length in

order to photograph and describe it.

The X-ray energy data are used to determine both

bulk density (RhoB) and effective atomic number (Zeff)

for each CT slice. Zeff is analogous to the photoelectric

wireline measurement and provides key information

about lithology. Together, the bulk density and Zeff logs

provide quantitative measures to assist in discriminating

lithology, porosity, and rock facies.

In Stage 2, plug-size samples are taken at multipledepths based on the high-resolution RhoB and Zeff data

from Stage 1. Micro-CT analysis provides information on

fine-scale laminations and fracturing at a resolution of

10-40 microns. Image analysis from 2-D scanning elec-

tron microscope (SEM) data provides porosity and kero-

gen volume fraction at a resolution of a few nanometers

and also is used as a screening process to ensure repre-

sentative samples for the subsequent 3-D special core

analysis laboratory (SCAL) computations. An X-ray

energy dispersive spectrum method provides elemental

composition, which is used to compute mineralogy. This

method has the advantage of giving both volume andgeometric distribution of minerals.

The 3-D SCAL analysis begins with nanometer-scale

pore and matrix imaging. This process uses a focused

ion beam SEM (FIB-SEM) system. The system acquires

an SEM image of an ion-beam polished surface, then

uses the ion beam to slice away a few nanometers of rock

and takes another SEM image. This is repeated several

hundred times for each sample. All of the individual

images are aligned and combined into a single 3-D vol-

ume. Image processing and segmentation allow separa-

tion of the solid mineral, organic material, and pore

Joel D. Walls, Ingrain Inc.

Digital rock physics provides new

insight into shale reservoir qualityAdvanced imaging, rigorous physics, and high-speed computation combine

to reveal reservoir properties of organic-rich shales.

The image on the left shows the outer surface of a 3-D FIB-SEM

volume from an organic-rich shale. The image on the right

shows a transparency view of the distribution of connected

pores (blue), isolated pores (red), and organic matter (green).



space into unique 3-D objects. This resultant 3-D digital

rock volume is termed a “vRock” and is used for subse-

quent SCAL computation work. Absolute permeability is

computed on each vRock using a numerical methodknown as Lattice-Boltzmann.

Results and discussion

Pores in shale resource plays often are

described as belonging to one of three

classes: intergranular, intragranular, or

organic matter. From work on hun-

dreds of samples from many different

shale formations, it appears that

organic matter porosity (porosity asso-

ciated with the diagenesis of kerogen)

is especially critical in establishingunconventional reservoir permeabil-

ity. On the other hand, samples with

primarily intergranular porosity

appear to have lower permeability for

a given level of porosity.

Based on pore-scale images from a

wide range of organic shales, it can be

seen that organic material is present

in a variety of forms or textures. Three

primary forms – nonporous, spongy,

and pendular – are commonly

observed.This can be illustrated in a ternary

diagram where the bottom-right cor-

ner represents nonporous organic

components (likely kerogen) that fill

all of the available nonmineral space,

leaving virtually no porosity or fluid

flow path. The bottom-left corner rep-

resents porous or “spongy” organic

material commonly encountered in

thermally mature gas shales. The top

corner of the diagram represents pen-

dular organic material that appears tofill the small intergranular and grain

contact regions, leaving open pore

space in the larger voids.

The appearance of the pendular

organic matter, potentially a migrant

bitumen product, suggests that it may

behave as a viscous liquid at reservoir

conditions. If it is mobile under reser-

voir conditions, laboratory measure-

ments at ambient conditions could

underestimate permeability. There

also are combinations of these primary kerogen tex-

tures. The pendular style of organic material appears to

be more common in samples from oil-window shales,

whereas spongy organics are more common in gas-win-dow shales.

EPmag.com

READ MORE ONLINE

There is more

to the story…


F

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RockM od

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DRILLING AND

COMPLETION FLUIDS

T ypically, oil-base drilling fluids are preferred over their water-base counterparts in applications where bottom

hole temperatures (BHT) can approach 260° C (500° F)

with shut-in pressures to 25,000 psi, thereby requiringdensities as high as 19 lb/gal (2.2 sg). However, more

areas are prohibiting the discharge of oil-base fluids and

cuttings, which increases waste management costs andpotential liabilities. In some areas the use of oil- and

diesel-base drilling fluids is disallowed altogether. Alternatively, a newly designed, chrome-free high den-

sity water-base drilling fluid, comprising a combination of

high-grade clay, novel dispersant, and specially formulatedhigh-molecular weight synthetic polymers, shows promise

as a viable environmental, technical, and economic option

for extreme HP/HT applications. A field trial in an HP/HT

exploration well in tightly regulated Hungary validatedthe performance and environmental advantages of thenew aqueous-base fluid. In this well, which targeted a tight

gas reservoir, static BHT was expected to exceed 170° C

(356° F) with shut-in pressure greater than 10,000 psi.

HP/HT Mud ChallengesThe industry has long sought a water-base mud (WBM)

that would mimic, or at least approach, the higher per-

formance of an oil-base fluid in HP/HT applications. Dis-persed water-base drilling fluids, typically formulated with

water, bentonite, and assorted additives to control fluid

loss and provide rheological stability, are the most eco-

nomical and favored aqueous systems. Advancing tech-

nology has made these fluids attractive options for morechallenging applications, such as those requiring the

highest level of engineering control and wellbore stability.

However, designing dispersed WBM for ultra HP/HTapplications has been a formidable exercise.

For example, increasing downhole temperatures tendto thermally degrade the polymers used to control fluid

loss and maintain rheological stability. Under high tem-

peratures, it becomes extremely difficult to control thegelation and the subsequent flocculation of water-base

fluids containing clays and/or drill solids. The issues sur-rounding both thermal degradation and progressively

high gel strengths are magnified with the high fluid den-

sities required to control pore pressure when drillingultra HP/HT wells.

With gelation being an overriding issue with aqueous

fluids in elevated temperatures, chromium-containing

thinners and fluid-loss additives have been used toimprove rheological stability and fluid-loss properties.Chrome lignosulfonates or chrome lignites were pre-

ferred to enhance adsorption onto the clay edges, thus

preventing clay platelets from bonding together. How-ever, a growing number of areas prohibit the inclusion

of toxic, multivalent metals like chrome in drilling fluids,

thus spurring research into the development of chrome-free alternatives.

A number of additives, including lignosulfonates, mixed with more environmentally acceptable metal ions have

been investigated with varying results. While both mixed

titanium/zirconium lignosulfonate salt and zirconium cit-

Jorge Fernandez and Steve Young, M-I SWACO

This table shows the final HP/HT water-base drilling fluid formulation to be used in Hungary field trial and testing results. (Image cour-

tesy of Schlumberger Ltd.)

Chrome-free WBM a viable option

for ultra-HP/HT applicationsEngineering drilling fluids for ultra HP/HT applications, particularly in sensitive ecosystems,

can be a daunting proposition.



DRILLING AND

COMPLETION FLUIDS

rate were shown to be reasonably effective in controlling

high-temperature gelation at temperatures to 204° C

(400° F), neither proved as effective as chrome lignosul-

fonate at higher temperatures.Chemically, synthetic low molecular-weight anionic

polymers were shown to function similarly to lignosul-fonates in effectively neutralizing the positive charges on

the clay edges to prevent flocculation. Subsequent workexamined synthetic polymers, copolymers, and terpoly-

mers for use as stable rheological and fluid-loss control

additives at higher temperatures.From a fluid-loss perspective, synthetic polymers,

including the high-molecular weight vinyl sulfonatecopolymers used in geothermal wells in the mid-1980s

have demonstrated the most promise. However, a more

effective alternative was needed that would likewise resist contaminants, while at the same time control rheology,

and remain stable at extremely high temperatures with-out promoting gelation or progressive gel structure. Con-

sequently, a research program was initiated to develop a

fluid system that would equal the performance of a

chrome-containing HP/HT water-base mud.

Testing protocol, resultsExtensive development and laboratory evaluation of both

fluid-loss control polymers and thinners/deflocculants was conducted on a 15.0 lb/gal (1.8 sg) drilling fluid

dynamically aged at 250° C (482° F).The general specifications defined the performance of

the ideal fluid as one having a plastic viscosity (PV) of less

than 30 cP, a 6 rpm reading between 7 and 10, an HP/HTfluid-loss filtrate of less than 20 mL at 149° C (300° F), and

500 psi differential pressure on hardened paper. The rhe-ological properties would be measured at 66° C (150° F).

At the onset, a benchmark formulation employing

chrome lignite was prepared to compare the effectivenessof the subsequent chrome-free deflocculants developed.

Both the mixing and addition conditions were establishedand controlled to optimize performance and ensure a

sound comparison between the various formulations.

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DRILLING AND

COMPLETION FLUIDS

Unconventional shale plays are becoming an increas-

ingly important and abundant part of domestic and

global production, which greatly increases the need for

more environmentally conscious solutions for flowbackand produced water. Concerns about the potential for

groundwater contamination and wastewater disposal

have only strengthened the need for careful selection of

more environmentally friendly fracturing chemicals.

A prime consideration for any oil and gas producer is to

find the most efficient means of minimizing the impact of

its daily operations on surrounding ecosystems.

Traditional methods have called for operators to pur-

chase chemicals from the pumping service. Sold as part

of an overall program, these systems are designed to fit a

wide range of applications. More and more, companies

are looking for tailor-designed chemical programs that provide higher efficiencies with better safeguards to the

local environment.

Taking a natural lineOne way to alleviate much of the controversy surround-

ing fracing operations in the world’s burgeoning shale

market is through extensive planning and analysis to

engineer fluid programs on a play-by-play basis.

Multi-Chem’s NaturaLine products are engineered

and assessed with environmental protection as a primeconsideration. The company’s main objective is to

develop technology and chemistries that provide lower

toxicity, reduce exposure, and consequently reduce the

environmental risks of production and completion

chemicals. The company has found a niche in its chemi-

cal design process that gives operators an opportunity to

partner in the process of achieving goals for both pro-

duction and environmental stewardship.

“Multi-Chem’s customers have been actively looking for

ways to reduce their environmental footprint for years,”

said Danny Durham, vice president of technology. “Sev-

eral customers came to us and requested chemicals that would reduce both safety and environmental hazards. We

then developed the product line to be proactive to have a

Tayvis Dunnahoe, Senior Editor

Unconventional resources benefit

from custom chemical regimesFrac fluid designed in play-specific programs can increase operations

throughout the life-of-well cycle.



full suite of frac additives that would reduce risk in the

field. We created a set of standards that served as a rank-

ing system for Safety and Environmental Risk. We sharethis ranking system with our customers so that they can

continually choose products for their operation based onthe environmental needs of that area and on the safety

standards of their organization.”The company’s frac fluid additives are evaluated on

safety, toxicity, biodegradation, and bioaccumulation.

With improvements in biodegradation and reducedbioaccumulation tendencies in the aquatic environ-

ment, this chemical system greatly reduces the potentialfor exposure over the products’ total lifetime. Operators

can select chemicals that have improved exposure pro-

files over more traditional chemistries. Continual evalua-tion gives operators a consistent and comprehensive

basis to consider both toxicity and environmental healtheffects when making informed chemical selections for

their production and completion operations.

“From both a performance and environmental stand-point, it is important to use the right product versus just

traditional chemistries,” Durham explained. In the caseof sulfate reducing bacteria (SRB) formation and gassouring control in fracs it is critical for environmental

and safety reasons to use environmentally consciouschemistries and to have a product that performs well in

reducing dangerous hydrogen sulfide gas later in the

life of the well. An example is that some companies useoxidizing agents (like bleach, chlorine, dioxide, etc.)

for SRB control in fracs. “The use of these agents with

organic materials in fresh, produced, and flow back water for SRB control has a two-fold negative effect in

that it does not provide long term SRB control in the

formation. This allows for greater risk of hydrogen sul-fide formation, and there is the risk of producing chlori-

nated hydrocarbons including carcinogenic andmutagenic compounds,” Durham said.

During the evaluation process, Multi-Chem’s technicalexperts evaluate the production or fracturing challenge

and recommend the most effective products and solu-

tions to meet the need. All recommended productsreceive a ranking based upon carefully selected environ-

mental and health-based criteria. This information is provided to customers along with pertinent technical and

cost performance information. Customers can then inde-

pendently evaluate and select the products that bothdemonstrate a commitment to environmental product

stewardship in their communities and best meet theiroperational needs.

The goal is to use frac additives and processes that

fully utilize flowback and produced water and maximize water management efforts. These solutions can be

used throughout the entire fracturing process andcan enhance production operations as well. The com-

pany’s process provides operators with a basis for system-

specific frac or production solutions that can offer duediligence to communities, regulators or partners in envi-

ronmental protection. The product selection processcan be tailored to include both Multi-Chem’s Natura-

Line criteria and customer-based standards and require-

ments as requested.

From practice into action

Within the Marcellus, Multi-Chem recently was chal-

lenged to control bacteria and scaling issues with anenvironmentally conscious process while the operator

effectively fractured the formation up to 2,100 m (7,000

ft). The company had been deployed by a customer forsome time when it introduced its NaturaLine process.

DRILLING AND

COMPLETION FLUIDS

Outstandin or

eth n

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The decision was made to use the system in subsequent

projects. The chemicals being used were B-8642 and

S-2510 T, which were proving to be very effective in con-trolling targeted bacteria issues and scaling problems.

Multi-Chem and the customer set out to find a more

environmentally responsible solution. The operator was

fracing using flowback water as well as make-up water that

was proving to be highly contaminated with SRB and acid

producing bacteria (APB). The waters also were showing

potential to precipitate scale.

As is standard practice, Multi-Chem obtained samples

of the water to be used for fracturing and ran standard

tests to confirm that the waters being used contain SRBs

and APBs. Specific biocide testing was carried out on a

full suite of products using SRB and APB cultures. Oneof the NaturaLine biocides was deemed an effective

candidate based on an environmentally focused ranking

system. This was done by leveraging a new, exclusive

chemistry to Multi-Chem rather than increasing activity

level and pumping a more concentrated biocide. Simi-

larly, the scale inhibitor was selected based on its environ-

mental ranking through the company’s ranking process.

The biocide was pumped using a Multi-Chem frac truck

on location, as was the scale inhibitor. The company

pumped the biocide at less than half of the original rate

being used. The scale inhibitor was pumped at the same

rate as before, achieving the same results with a moreenvironmentally conscious approach.

Chemicals are typically a small line item on a bill from

pump companies. For this reason, operators often opt

to purchase chemicals from pump companies to avoid

having additional vendor on location. If an operator

chooses to use a specialty chemical company, a cus-

tomized chemical program is developed for that particu-

lar operating environment.

“With a NaturaLine customized chemical program,

Multi-Chem reviews local environmental standards, char-

acteristics of that particular formation, and operational

goals of that customer. Specialty chemical solutions,including NaturaLine products, can have a major impact

on an operator’s bottom line,” Durham said. When appli-

cable, a surfactant is recommended that can increase

initial production of the well. Friction reducers, when

selected and applied correctly, can reduce surface treat-

ing pressures needed to frac the reservoir, therefore

reducing the amount of horsepower needed. If an

operator selects the appropriate bacteria and scale

solutions up front can reduce the amount of preventive

maintenance to equipment that will be needed through-

out the production phase.

EPmag.comREAD MORE ONLINE

There is more

to the story…

Innovation

has

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name:

Vicinay R5

The

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quality,

developed b

y

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the result

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to p

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innovat ive solut ions.

This

qualit

y

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her res i s tance than chains in R4 and

i ts w e i

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ht is more than

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The

me c h a n i c a l propert ies obtained

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The

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UNCONVENTIONAL

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of US shale plays. W i t h more than 300 wells

the p

lay and

with

al most 6 million barrels of oil and condensat e be i ng

produced

in

2010

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Energy

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y

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TURED LUNCH

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obert M. Gates served as the 22nd Secretary of Defense (

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) and s the only Secretary of Defense in

istory asked to

remain

inoffice by anewly-elected

President President Barack

Obama

is

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hth president

W.

On his

ast

day n office,Dr.Gates was awarded he Presidential

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INVESTMENTS

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Two GREAT WORKSHOPS OCTOBER 1OT H

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CN ` T CRMAKCR



DOWNHOLE SYSTEMS

AND SOLUTIONS

Artificial lift technology has long been an essential

part of the oil and gas production process, with the

vast majority of wells around the world benefiting fromartificial lift in various forms. Electrical submersible

pumping (ESP) systems have played a significant role,enhancing output for more than 70 years.

Overall demand for products and services that

enhance oil recovery is expected to grow significantly,driven by an expected decline in production from exist-

ing wells (at roughly 6% annually) and the increasing

complexity of developing new reserves.ESP deployment is one of the fastest growing seg-

ments in the industry, with an estimated 120,000 systemsin operation today. For an increasing number of oil

wells, the technology is the only viable artificial lift

option. The technology will be paramount in helpingproducers meet the rising global demand for hydrocar-

bons, as maturing fields are expected to account for

more than 70% of global oil production output by 2012.

Such technology is required to perform in increas-ingly challenging conditions – fields are being devel-oped where the wells are deeper and operating at

higher temperatures and pressures; operators are enter-

ing more remote locations and setting up operations inmore harsh environments; and crude oils with higher

viscosities, higher volumes of entrained sands, and solidsin more corrosive conditions are being produced using

ESP systems.

ESPs have become a vital part of E&P’s advance intothe deepwater and subsea environment as the industry

seeks to maximize production of these frontier reserves.

In fact, ESPs make up the biggest area of expected mar-ket growth for artificial lift technology.

Improving reliabilityExtending the run life between incidences of mechani-

cal or electrical failure on these systems remains a key focus. Operators want as little nonproductive time as

possible.ESP systems have become the focus of a strong and

coordinated technology push by both suppliers and

operators as they research and develop new ways tomeet the needs of the expanding application envelope.

The expectations placed on ESP performance are

growing rapidly, and manufacturers have responded

with major enhancements such as improved metallurgy,motors that can operate at higher downhole tempera-tures, more efficient pumps, and greater gas handling

capability. ESPs now are more capable of operating over

extended ranges and at higher tempera-tures, encompassing almost all current pro-

duction conditions.The vast majority of ESPs are deployed

onshore and have an average a run-life of

between two and three years, but ESP sys-tems are not confined to land operations.

They are being deployed in subsea applica-

tions with ever-increasing stepouts and waterdepths.

There are around 80 subsea ESP systemsinstalled worldwide, predominantly in the

North Sea and China. To put the offshore

ESP market into perspective, it is estimatedthat there are approximately 120,000 ESPs

operating onshore in any single year.

According to Ben Gould of Baker Hughes,presenting at the 2011 Offshore Technology

Conference in Houston, for most companiesan ESP with a service life of two to three

Mark Thomas, International Editor

This figure shows a schematic

of the ESP system (right) in a

vertical boosting station,

installed on Shell’s Perdido

development in the GoM.

(Image courtesy of Baker

Hughes Inc., FMC Technolo-

gies, and Shell)

Pump up the volumeNothing is artificial about ESP technology’s ability to enhance production.



years is considered acceptable. “While most operators will ask for

longer run lives, when they weigh that against the additional cost

of procuring such a system, the economics will not justify the

added expense.

“However, when we look at the offshore, and particularly the

subsea environments, the economics drastically change. The cost

of an ESP system is relatively small versus the cost of a workover, so

the additional upfront cost associated with a higher-end ESP

becomes less significant.”

Pushing the limitsThe technology involved in the design, engineering, and deploy-

ment of ESP systems also has changed dramatically in recent years,

driven by operators asking suppliers to push the equipment

toward its operational limits and at the same time asking for

longer run lives.

This is not to say that ESPs cannot run longer – one onshore sys-

tem in the US ran for a reported 24 years, while an ESP in the

North Sea achieved nearly 20 years. But the average in the North

Sea is approaching four years of operation.

Many of the subsea wells are equipped using redundant systems,

meaning there are two ESP systems installed in the well, usually one in oper-ation and one on standby.

Gould pointed to one of the most recent advancements in this dual-ESP

approach where the ESPs are separated by a packer between the two systems.

“The idea of having the ESP systems stacked on top of each other allows for

the units to be installed in a smaller wellbore. It also means that the control

lines and motor lead extension can be protected from damage during run-

ning in the hole by installing them in the can and not having them rub

against the annulus during installation.”

Having two ESP systems in the same wellbore has its advantages, including

a longer run time. The well can continue to produce when a workover is

planned while also allowing the workover to be carried out in conjunction

with other work rather than having to mobilize a rig for a solitary pull.Several studies have shown an interesting advance in the technology

involving a combination of an in-well ESP system working in tandem with a

seabed boosting system, where the ESP would only have to move the fluid to

the sea floor and then let the seabed boost system provide the added pres-

sure to move the fluid to the host production facility. This would allow the

well to be drawn down to maximum capacity for the longest length of time

to maximize the well’s productivity.

“To date this has only been done for a few wells because most of the subsea

wells are capable of free-flowing to the seabed boost system so the in-well ESPs

are typically not required. There are several projects in the planning phases

that will use both an in-well ESP and a seabed boosting system,” Gould said.


DOWNHOLE SYSTEMS

AND SOLUTIONS

The Baker Hughes dual subsea ESP bypass system will be used on the Big

Foot field in the deepwater GoM. The system allows for reservoir access

and the ability to switch between ESPs without intervention. (Image cour-

tesy of Baker Hughes)

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“The industry will continue to deploy subsea ESP sys-

tems in shallow to medium water depths and will con-

tinue to learn from these installations. Approximately 40

seabed boosting systems have been successfully deployedin up to 2,400 m (~8,000 ft) water depth. Some have

direct vertical access and the ability to be pulled andinstalled without a rig, but the majority of them are

deployed in areas where a rig will have to be used inorder to work on the systems.”

William Milne, director of business development, Arti-

ficial Lift at Baker Hughes, described the offshore deepwater and subsea environment as the fastest-growing

market in artificial lift systems, with predicted growth of more than 500% over the next 10 years.

“We are collaborating with major operators to help

them come up with artificial lift solutions for a numberof projects globally to economically produce from deep

reservoirs,” he said. “This will require step changes incapability and an innovative approach to the develop-

ment of key technologies. It is critical to evaluate

designs from a system point of view in the subsea deep-

water environment – taking into account anything that could impact the performance and longevity of the pro-

duction solution.”The company also was involved early in the process

with Shell, receiving a contract to help the operator with

innovative enhanced run-life 1,600 hp ESP systems forits Perdido ultra-deep project in the Gulf of Mexico

(GoM), where the ESPs were installed inside 107-m

(350-ft) caissons installed in dummy wells in the seaflooras part of a subsea boosting system to help pump around

125,000 b/d of liquids to the field’s spar platform.

“Operators would like us to put more and more horse-power in the well to increase productivity and reduce

associated well costs,” Milne said. “We are also working in

partnership to enhance reliability. It’s a question of accel-erating the development program to match the ambitions

of the operators.”Efforts such as these are pushing the technology enve-

lope for ESPs. Testing and development of such tech-


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nologies takes time, a substantial amount of money from both sides, and

plenty of cooperation.

The longevity of any ESP system depends on a full understanding of the

environment that the unit will be exposed to and how it will be operated.Other run-life factors include proper qualification, testing, and selection of

materials including elastomers and metals, and the pump stage design.

Impressive resultsCombined efforts are producing some impressive results. Baker Hughes

noted that improved ESP technology and manufacturing controls have

extended ESP run times for critical well applications when announcing amajor award in the GoM.

The contract awarded by Chevron will supply ESP systems for the opera-tor’s Big Foot development project. The ESP systems and production pack-

ers will be run in seven producing wells, plus mud line packers for three

injection wells.This award marked the first deployment of ESP systems inside the well-

bore in the deepwater GoM. The systems will be placed at a true verticaldepth of approximately 4,900 m (~16,000 ft).

Big Foot is in 1,600 m (~5,200 ft) water depth in the Walker Ridge area and

is being developed via an extended tension-leg platform with an onboarddrilling rig and production capacity of 75,000 b/d of oil and 25 MMcf/d of

gas. Deployment of the ESP systems is scheduled to begin in 2014.The 1,200 hp dual ESP systems will be among the highest horsepower in-

well systems ever deployed in an offshore environment. The ESP systems are

deployed on dual bypass systems, allowing for reservoir access and the abil-ity to switch between ESPs without intervention.

“Longer term, the experience and knowledge gained from Big Foot canpotentially be applied to other developments in the deepwater market to

extend field productivity,” said Richard Williams, GoM president for Baker

Hughes. Another deepwater project in the Campos basin offshore Brazil saw one

of Baker’s ESPs set a run-life record of more than 1,360 days of continuousoperation in more than 1,350 m (4,430 ft) water depth after being installed

and starting up in the summer of 2007.

This beat a previous record of about 1,300 days for a subsea ESP comple-tion in shallower waters and is clear evidence of the increasing run times

being achieved by the industry.

Remaining challenges Although ESP systems are suited for the environments they will encounter

in extreme water depths and temperatures, there are technology challengesremaining.

Currently, penetrator systems and wet mate connectors that allow

cables to pass through the wellhead are being developed for the higherpressures that the ESP systems might be exposed to, and elastomers

required in the system need to be developed to withstand the higher tem-peratures that may be present. There also is an expectation of run-lives

of up to 10 years, which is currently beyond today’s average, making ESP

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UNCONVENTIONAL:

GRANITE WASH

6EPmag.com | August 2011

efforts to exploit the play and potentially discover new

fields, Keller noted separately in a 2010 webinar hosted

by Hart Energy’s UGCenter.com .Considering its variability, the Granite Wash may be an

unconventional wild card, but its merit as a premier

hydrocarbon resource play in the heart of E&P friendly

communities continues to draw both oil- and gas-lever-aged companies.

Chasing liquidsSince the play was tapped more than 50 years ago, more

than 4,200 wells have been completed in various Granite Wash reservoirs, which have produced a high volume of

hydrocarbons over the years. While exploiting the Washhas proven to be well worth the effort in areas that con-

tain significant gas-in-place, interest in the longtime tar-

get has gone through cycles.Earlier wells were aimed at deeper Morrow and

Hunton vertical targets, which yielded huge quantities

of producible gas. With advances in horizontal drilling

techniques driving the recent uptick in unconventionalE&P, enthusiasm has piqued and players are now pony-ing up for more oil-prone and liquids-rich gas targets in

the 257-km (160-mile) long, 48 km (30-mile) wide area.

Adding to its appeal, the play has a strong NGL andoil component within the Upper Granite Wash zones,

although upper and lower zones can vary wildly in oiland gas pay quality. This saturation of liquids makes it

one of the more attractive and economic unconven-

tional plays today as ethane prices trend higher and theoil commodity reigns supreme.

In early 2010, nearly 60% of the economics of Granite

Wash wells derived from their liquids content. Today,Granite Wash wells continue to exhibit encouraging

results, and drilling and completion costs continue torange anywhere from US $5 to $7 million.

Among the top Granite Wash operators are US inde-

pendents Chesapeake Energy Corp., Forest Oil Corp., Apache Corp., Penn Virginia Corp. and SM Energy Co.

As activity in the region accelerates, the Granite Wash

also can be viewed as a midstream infrastructure oppor-tunity. Gas gathering and treatment and processing serv-

ices are expected to continue experiencing rapid growthas operators struggle to harness new take-away capacity

to move mounting gas and liquids production to eitherthe Conway or Mont Belvieu hubs in Kansas and Texas,respectively.

ONEOK Partners of Tulsa, for example, plans tospend up to $240 million by 1H 2012 on midstream

projects in the Granite Wash and nearby Cana-Wood-

ford shale plays. Citing increasing liquids growth in themidstream, Eagle Rock Energy Partners LP plans to

forge ahead as a leading Granite Wash player with

significant investment in the pipeline.CEO Joseph Mills said at the National Association of

Publicly Traded Partnerships MLP Investor Conference

As of March 2011, the highest rate Granite Wash

wells to come onstream were all in Wheeler County,

Texas. The top five wells include:

• Linn Energy’s 50-1H Black, which produced at an

initial rate of 60.2 MMcfe/d (6,700 bbl/d of con-

densate and NGLs and 27 MMcf/d of natural gas);

• Forest Oil Corp.’s 2012H Frye Ranch, which pro-

duced at an initial rate of 39.83 MMcfe/d (3,455

bbl and 19.1 MMcf/d);

• Devon Energy Corp.’s 2012H Bach and 6H-9, which

produced at initial rates of 37.75 MMcfe/d (325bbl and 35.8 MMcf/d) and 33.8 MMcfe/d (300 bbl

and 32 MMcf/d), respectively; and

• Newfield Exploration Co.’s 7H McCoy 27, which

produced at an initial rate of 36.4 MMcfe/d (1,900

bbl and 25 MMcf/d).

Privately held Greenwood Village, Colo.-based

Cordillera Energy Partners III recently completed a

series of Granite Wash producers. The company and

wholly owned subsidiary Granite Operating oper-

ate 20 horizontal Granite Wash wells in six separate

benches in the play.

In June 2011, the company reported three hori-

zontal Des Moines producers in the Anadarko Basin.

In the Section 1, Block 2, B&B Survey, in the Stiles

Ranch field area of Wheeler County, the #5HB Dob-

son – a 16,849-ft well (12,600 ft TVD) fracture-stimu-

lated in 12 stages – flowed 16.7 MMcf of gas and 540

bbl of condensate during a 24-hour sales period.

The #2042HB Byrd in Section 42, Block A-3, H&GN

Survey, A-8798, flowed gas at an initial rate of 10.4

MMcf/d with 395 b/d after it was drilled to 17,364 ft

(13,120 ft TVD). And the #5-6HC Sayre Ranch in Sec-

tion 5-12n-26w flowed 5.27 MMcf and 170 b/d fromthe Granite Wash B bench after a 12-stage fracture

stimulation. The 16,845-ft Reydon field well has a

3,781-ft lateral extending northward to a true verti-

cal depth of about 12,800 ft.

Cordillera has three horizontal rigs dedicated to

drilling additional Granite Wash targets in Wheeler

and Hemphill counties, Texas, and Roger Mills

County, Okla.

Source: IHS Inc.; Cordillera Energy Partners III



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in June that much of the

Houston-based MLP’s focus

will be on the Granite Wash.“This is an area that we think

we can spend $50 to $100 mil-

lion per year for the next twoto four years building addi-

tional processing,” he said,adding that Eagle Rock has

one of the best gathering footprints in the play, particu-

larly in the Texas Panhandle.

Linn Energy LLCUpstream MLP Linn Energy LLC, also based in Hous-

ton, has zeroed in on what it considers to be a cash cow

in terms of encouraging operating results, a gamechang-ing organic growth opportunity, and quick pay out:

acquiring and reworking mature assets.The Granite Wash is one such area in the Midconti-

nent where the company is maximizing this strategy and

horizontal drilling technology has significantly improved well results and returns.

According to Linn, the high concentration of liquids

in the Granite Wash makes it one of the most economicplays in the US. Here, the company cites an ROR close

to 70% at an oil price around $90/bbl and more than80% at $100/bbl.

The company entered the Granite Wash in mid-2007

after it purchased 38,000 net acres in the trend as part

of a $2.05 billion Midcontinent package from Dominion

Resources Inc. It now holds nearly 170,000 gross acres in

the prolific play.Linn announced in a recent investor presentation that

it had identified some 200 high-potential, low-risk hori-zontal drilling locations in the Texas Panhandle Granite

Wash alone.

In 2010, Linn drilled eight locations in the play andhad initial production ranging from 18.5 to 60.2

MMcfe/d.The company’s second

operated well drilled in

the Greater Stiles Rancharea, where it has a large

concentrated acreage

position, reported an ini-

tial production rate of more than 60 MMcfe/d.CEO and president Mark

E. Ellis believes the Black

50-1 well is the highest initial production rate

reported in the Granite

Wash trend.“The liquids content of

more than 6,700 bbl/drepresents more than

65% of the production

stream,” he said.LINN is currently run-

ning a four-rig drillingprogram focused on the

Texas Panhandle portion of the Granite Wash, where

the company plans to drill 35 horizontal wells in 2011. At the end of 1Q 2011, the company had 15 operated

horizontal wells and 10 nonoperated wells producing.

Initial production rates from the operated wells aver-aged approximately 21 MMcfe/d, exceeding Linn’s

expected average initial production rates of 15MMcfe/d. At the end of 1Q 2011, LINN also had 10

additional operated wells and eight additional nonoper-ated wells drilling, completing or awaiting completion.

The company is on pace to complete two to three new

operated horizontal wells each month throughout 2011

and believes the high concentration of liquids in theGranite Wash will continue to be a core component of

its organic growth.

Newfield Exploration Co.Houston-based Newfield Exploration Co. is one of the

most active operators in the Granite Wash play and con-

tinues to see strong returns from its upstream assets,

Newfield Exploration and

Linn Energy have significant

upside in the Granite Wash

play and are actively bring-

ing top producers online

using advanced horizontal

drilling technology.


Linn has identified around 200

horizontal drilling locations in

the Texas Panhandle Granite

Wash region and is running a

four-rig drilling program.



UNCONVENTIONAL:

GRANITE WASH

which the company said stack up very favorably in its

portfolio. Newfield’s inventory consists of 300 locationson which it has identified around 30 prospective target

zones from the liquids-rich Marmaton to the dry-gas

Atoka. So far it has successfully tested 10 of these geo-logic intervals.

From an initial entry in 2002 via the acquisition of EEX Corp., Newfield drilled around 140 vertical wells

before taking on its first horizontal test in late 2008 in

the Stiles Ranch asset – the company’s largest producingGranite Wash field and one of the most prolific in the

play.

The #27-7H well came online in December 2008 at aninitial rate of 1,900 bbl/d of condensate and 25 MMcf/d

of gas and averaged 27.1 MMcfe/d during its first 60days of production.

Since transitioning to a horizontal strategy, Newfieldhas drilled 40 wells with an average 24-hour initial rateof 16 MMcfe/d. It currently averages 175 MMcfe/d

from a position that encompasses more than 44,000 net acres in the play.

Over the last year, Newfield added 13,000 net acres

in the Granite Wash, most of it in the core area of Wheeler County. Through 2011, the company intends

to keep four rigs running in the play and expects to

drill between 28 and 35 wells this year to meet targetedproduction growth of more than 20%.

Newfield’s focus will remain on the wet Marmaton sec-tions of the play, which promises returns in the 25%

range at $5 gas and $75 oil and greater than 30% at today’s oil prices, said Danny Aguirre, investor relations

lead. Since 2009, it has completed 21 wells in the high

Btu Marmaton formations with gross 24-hour IP ratesaveraging 17 MMcfe/d.

Recent Marmaton completions include the Dupont1-1H and the Britt Ranch G44W-14H, each initially pro-

ducing at a gross rate of 22 MMcfe/d.

Meanwhile, Newfield continues to hone in on its hori-zontal drilling technique in the Granite Wash. A “best

in class” 1,433-m (4,700-ft) lateral well was drilled and

cased in 25 days, according to the company’s 1Q 2011financial and operating results.

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This year has seen a climate of optimism grow through-

out the oil and gas industry. The year began withindustry leaders upbeat about prospects for the sector,

with capital expenditure expected to increase and the

resumption of many projects that were previously deferred due to the oil price slump. Investment is pour-

ing into many capital-intensive projects across the globe.

This welcome resurgence in levels of activity in the oiland gas sector has had a beneficial flow on effect on the

remotely operated vehicle (ROV) market. The oil andgas sector is the largest single market for the ROV indus-

try, with underwater vehicles currently being used for a

wide spectrum of activities across all life-of-field phasesin the offshore arena: the drilling and development of

wells; installation and construction of production facili-

ties; inspection, repair, and maintenance (IRM); and

decommissioning. It follows, therefore, that the fortunesof ROV manufacturers and contractors is intrinsically linked to those of the wider energy industry.

The increasingly optimistic outlook is, of course,

linked to the spectacular recovery in oil prices witnessedover the last year. Levels of development spending and

activity in the oil and gas industry are overwhelmingly

congruent with oil prices. The relationship can be seen

as relatively simple: A high oil price leads to increasedspending and development, while low prices tend to

depress activity. Therefore, any recovery in oil prices

witnessed throughout the last year bodes well forROV demand.

ROV demand trends upwardIt is against the backdrop of high oil prices and opti-

mistic spending plans that Infield Systems predicts thisupturn will continue, with an increase in overall ROV

demand over the next five years of 43% in comparisonto the previous five-year period. This is equivalent to

demand for more than 1.25 million ROV days between

2011 and 2015.This demand will be shaped by a number of key

areas that will combine to propel demand upward dur-

ing this period. Companies have to move into deeper

water to find new sources of hydrocarbon production.The extreme nature of deep water increases the impor-tance of the role that ROVs play in drilling support and

new installations. At the same time, existing oil and gas

infrastructure is subject to more exacting IRM routinesin which ROVs perform many pivotal tasks.

In recent years, the trend of increasingoffshore development in oil and gas has led to

many operators growing their work class fleets

to meet demand. The worldwide fleet of light,medium, and heavy work class ROVs servicing

global energy requirements totaled 887 ROVs at

the end of 2010, with approximately 210 of thesefalling into the light work class category suitable

for inspection duties. The remaining 667 mediumand heavy work class vehicles tend to be electro-

hydraulic and have a higher power rating than

the smaller light work class units.The largest operator in the market, Oceaneer-

ing, has expanded its fleet from approximately

100 ROVs in 2000 to more than 250 in 2010 – arise of more than 150%. This number includes a

rise of almost 50% from the 170 ROVs the com-pany operated in 2005. Other operators have

Jamie Balmer, Infield Systems

Historic oil price (yearly average) vs. ROV demand from 2006-

2011(estimated). (Image courtesy of Infield Systems)

Investment resurgence

buoys ROV marketDemand growth will be strongest in North America, Africa, and Latin America.


ROV/AUV



made similar, if less prolific, investments in new vehiclesin recent years. Fugro, for example, has increased the

number of ROVs it operates by around 116% over five

years to a fleet totaling 130 in 2010.The lull in ROV demand seen in 2009 and 2010 had

the effect of stymieing growth in operator fleets some-

what over this period. The downturnin demand coincided with a high

number of ROVs in the market, whichled to a drop in utilization rates

among some of the large operators.

Infield predicts that any slack inregional markets will be squeezed by

the increasingly robust demandexpected through 2011 to 2015.

Deep and ultra-deepwater activity will be an important source of demand for ROVs in the coming

years. A large proportion of expectedgrowth in deepwater activity will be

concentrated in Africa and Latin

America, where rises in ROV demandof 126% and 157% are forecast

respectively until 2015. Nigeria and Angola in West Africa and Brazil in

Latin America will be largely responsi-

ble for such increases in demand.

Brazil, in particular, exemplifies thenature and profile of deepwaterdemand.

New deepwater discoveries in areas

such as the Santos and Campos basinsoffshore Brazil have led to significant

development in the past five years.This activity has made Brazil a major

center for ROV operations and com-

panies. Large-scale offshore projectshave drawn the big fish of the ROV

world in great numbers. Mostly oper-

ating out of Brazil’s oil capital, Macae,companies such as Subsea 7, Fugro,

DOF Subsea, and Oceaneering haveestablished new bases in the region in

the last five years.There has been a flurry of large

orders and contracts. Last year Petro-

bras awarded a contract in excess of US $400 million to Subsea 7 for the

provision of ROVs and interventiontooling services on up to 30 drilling

rigs. This in turn spawned an order

for UK-based manufacturer SMD for between 20 and 30

work class ROVs. Fugro, which has approximately 14%of its global fleet in the country, has a number of

drilling rig support contracts with Petrobras as well as asignificant presence in the IRM market. Oceaneeringhas around 35 ROVs in the country.


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Inspection is vital to ensuring safe transfer of hydrocar-

bons and continued integrity of subsea pipelines. Envi-

ronmental factors acting on pipelines can threaten

integrity by moving and bending the lines, and waves can

cause scouring that can create long free spans where the

pipeline is not sufficiently supported. Additional damage

can be caused by ship’s anchors being dropped and by trawling in areas where commercial fishing activities take

place. Pipeline integrity must be carefully monitored to

ensure that this sort of damage does not advance to the

point of compromising safe transfer.

Historically, pipeline inspections have been performed

primarily by acoustic sensors on towfish. The development

of ROVs allowed inspections to move to another level and

added the possibility of using cameras as inspection sen-

sors. Today, both towfish and ROV-based inspection are

common, but the industry has not stopped investigating

ways to improve the inspection process. R&D efforts have

gone into developing autonomous underwater vehicles(AUVs) that can be used as pipeline inspection tools.

In a recent inspection carried out in the Hjelte fjord

near Bergen, Norway, Kongsberg Maritime carried out the

world’s longest multisensor AUV pipeline survey.

AUV inspectionThe milestone AUV pipeline inspection took place

between February 9 and 11, 2011, offshore mid-Norway.

The subject of the inspection was the Troll I and II

pipelines, which move hydrocarbons produced

offshore to the onshore Mongstad oil refinery.

The HUGIN 1000 AUV, operated from the Royal Nor- wegian Navy vessel HNoMS Måløy , was equipped with an

advanced suite of Kongsberg imaging equipment includ-

ing the high-resolution interferometric synthetic aper-

ture sonar (HISAS) 1030, the EM3002 multibeam echo

sounder (MBES), and an optical camera with LED light-

ing. The instruments were used to inspect approxi-

mately 30 km (18.6 miles) of subsea pipeline in an

8-hour, two-pass mission.

Executing the surveySeveral pipelines were present on the seafloor, some-

times crossing each other via buried sections. During the

first pass in the inspection process, when the primary

pipeline’s position is determined with high accuracy

(to get close enough to use camera and high-res MBES

on the second pass), the pipeline tracking software man-

aged to re-acquire the correct pipeline after a buried

crossing. This was possible because the tracking function

keeps track of several pipelines and chooses the one best

matching criteria.

HISAS was critical to the inspection. SAS systems are

superior to conventional systems because the resolutionof the images produced does not degrade with range.

The HISAS 1030 typically produces better than 3 cm by 3

cm image resolution out to 300-m (984-ft) range. Inter-

ferometric technology sets it apart from other SAS sys-

tems in that it

provides full-

swath bathyme-

try and

increased

immunity to

conditions that

traditionally have been con-

sidered difficult

for SAS, like

crab angles and

platform move-

ment. The

HISAS 1030

Even Børhaug and Per Espen Hagen,

Kongsberg Maritime

AUVs take on pipeline inspectionAdvanced technology enables the world’s longest multisensor AUV pipeline inspection.

ABOVE: The first 8-hour

mission is indicated by the

green line. (Images cour-

tesy of Kongsberg Mar-

itime) RIGHT: This single

3-megapixel camera

image was taken at an

altitude of 4.6 m (15 ft) at

2 mm by 2 mm resolution.


ROV/AUV



mounted on a HUGIN AUV achieves a full survey area

coverage rate of more than 2 sq km/hr.

Typically a HUGIN AUV performs a detailed seabed

survey in shallow or deep water with a standard geophysi-cal survey suite. The pipeline inspection carried out on

the Troll I and Troll II lines introduced a new way of fully autonomously achieving detailed digital still imagery of

an underwater pipeline by using interferometric SAS,pipeline tracking software, an MBES, and a high-resolu-

tion still camera in a two-pass mission.

In the first pass, side-scan data from the HISAS 1030sonar were used to detect and track the pipelines in real

time using PipeTracker software, which was developedin a collaborative effort with the Norwegian Defence

Research Establishment (FFI) in a project funded by

the Norwegian Research Council. The software runsas a plug-in module in the standard HUGIN payload

system and was used in this application for pipelinedetection and for tracking extracted pipe-like features

in the sonar images with a high degree of robustness

toward false detections.The HUGIN 1000 control system uses identified

pipeline tracks to position the vehicle at an optimalrange for HISAS imaging. The entire process is fully

automated inside the AUV and requires no operator

intervention.In the second pass, the AUV followed the pipeline

tracks identified in the first pass at low altitude andinspected the pipelines using the EM 3002 multibeam and

the optical camera. The recorded HISAS 1030 data were

post-processed into high-resolution (4 cm x 4 cm) sonarimages and bathymetry maps of the pipeline. The maps

combined with the optical images and the multibeam datarecorded in the second pass gave a detailed view of the

pipeline surroundings as well as the pipeline itself. The

complete procedure was repeated the next day over thesecond pipeline in another 8-hour, two-pass mission.

Both pipelines were surveyed at a constant speed of 4knots and at 4 m to 25 m (13 ft to 82 ft) altitude, depend-

ing on the sensor in use. Water depth ranged from 180m to 560 m (590 ft to 1,837 ft).

The greater speed of the HUGIN 1000 compared to

that of an ROV meant that 60 km (37 miles) of pipelinecould be inspected in a little more than 16 hours during

the two passes. The stability of the HUGIN platform and

the ability to simultaneously operate both at high speedand at low altitude resulted in an efficient survey with

clear images from the onboard optical camera.Kongsberg’s REMUS family of AUVs also can perform

visual pipeline inspections and pipeline surveys when

equipped with high-frequency sidescan sonar, a multi-

beam, and camera. This means the REMUS 100 AUV,used for deployment in shallow water, and REMUS 600

AUV, used for operation in depths to 600 m (1,968.5 ft),

are viable low-logistics tools for pipeline inspections. Forpipeline inspection and surveys in depths greater than

600 m, HUGIN AUVs offer long endurance and swap-

pable batteries, resulting in high operational efficiency with few launch and recovery cycles and fast topside

turnaround time. In addition, the AUV can be equipped with the HISAS 1030 from Kongsberg, providing

unmatched sonar image resolution throughout the

entire sensor swath.

The road ahead

With this survey successfully completed, there are now

opportunities for the technology to be used on pipelineinspection in and around oil and gas fields, for initial

baseline pipeline inspection surveys and follow-on sur-

veys after hurricanes, and for environmental monitoringpipeline inspection surveys.

EPmag.com

READ MORE ONLINE

There is more

to the story…

EXPR

Expro

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new

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techWATCH

The best well results are achieved through optimum

well placement and flow monitoring. Although the industry has invested heavily in develop-

ing ways to improve recovery, the fact is that in most operations more than 60% of the hydrocarbons are left in the ground. A better sense of well performance allows

for improved production management.

A new approachThe Production Profile Predictor Method (3PM), arecently patented reservoir and wellbore surveillance

technology, allows well performance to be accurately monitored by determining the depletion of each column

of fluids in the reservoir draining into the wellbore.

The 3PM approach can be used on any well type from

vertical to horizontal, including subsea wells, producingin steady-state gas and at least one liquid phase. The well

also can have one or more mid-production depths (com-

mingled production well). This process allows the wellto be analyzed flowing into a manifold, along with other

wells, without either surface or downhole fluids flow rates measuring devices.

For well analysis, 3PM requires:

• Two measured steady-state pressures taken either at the wellhead or from a downhole pressure gauge;

• Estimates of fluids flow rates at each of the two pres-

sure tests;• Black oil PVT (pressure, volume, temperature) data;

and

• Well geometry data.The method determines whether or not the pressures

are steady-state. Each of the measured pressure values

is at a different total fluids flow rate from the well. Theaccuracy of the results is independent of the depth of

pressure measurements. Fluids flow rate estimates arerequired to decrease the computing time for a 3PM

analysis. These estimates do not affect the accuracy of the computed flow rates at each pressure test.

How it worksIn a test that illustrates how 3PM works, two meas-

ured steady-state pressures (PWH1 and PWH3) arerepresented as Test 1 and Test 3 at the wellhead. GLR

represents gas-liquid ratio. Test 2 is not necessarily

representative of the well being analyzed. It has theaverage wellhead pressure and average fluids flow

rates of Test 1 and Test 3.

From the wellhead +30.5 m (100 ft, arbitrarilychosen) to mid-production depth D1, analysis of the

difference of the pressure gradient change betweenTest 1 and Test 2 and the pressure gradient change

between Test 2 and Test 3 shifts from a maximum at

the wellhead +30.5 m to a minimum at mid-produc-tion depth D1. To identify mid-production depth D1

(where fluids flow rates change) 3PM determines,

from the wellhead to the wellhead +30.5 m, the maxi-

The two measured steady state pressures (PWH1 and PWH3) are repre-

sented as Test 1 and Test 3 at the wellhead. GLR represents gas-liquid

ratio. Test 2 is not necessarily representative of the well being analyzed.

It has the average wellhead pressure and average fluids flow rates of

Test 1 and Test 3. (Images courtesy of Production Testing Services)

New production profile predictormethod determines well performanceCurrent technologies that measure downhole fluid rates all suffer froma fluids fall-back problem in addition to inherent inaccuracies. A newapproach eliminates these problems and the measurement costs.

Brian H. Samaroo, Production Testing Services



mum difference of the pressure gra-dient change between Test 1 and

Test 2 and the pressure gradient

change between Test 2 and Test 3.

This maximum difference is

found using unique accurate liquid

flow rates for each test and varying

the approximate gas flow rates for

each test to obtain the maximum

difference between the measured

steady state pressures of Test 1 and

Test 3. The methodology identifies

this maximum difference using any multiphase flow correlation and

black oil PVT models.

To calculate unique accurate liq-

uid flow rates and approximate gas flow rates (depend-

ing on the multiphase flow correlation and black oil

PVT models used) for each test and an accurate mid-

production depth, the difference of

the pressure change between the tests is accurate and

unique for all three tests. This is the case from the well-

head up to mid-production depth D1 with the pressure

for Tests 1 and 3 both at depth D13.

Given the accurate measured steady-state pressures at the wellhead for all three tests and the accurate pressure

for both Tests 1 and 3 at depth D13, the accurate pres-

sure profiles for all three tests can be determined from

the wellhead to mid-production depth D1. Assuming the

measured pressures are accurate, if a maximum differ-

ence described cannot be obtained, either one or both

of the measured pressures are in transient flow. This is

evident from transient flow conditions producing each

measured pressure with a different mid-production

depth.

In general this process of obtaining a maximum differ-

ence to determine the results of accurate liquid flow rates and pressure profiles for all three tests is repeated

from mid-production depth D1 to D1 +100 ft to mid-

production depth D2 through the sequence up to the

deepest mid-production depth.

ResultsThe 3PM well analysis delivers valuable information. It

identifies the total accurate liquid and approximate gas

flow rates from all columns of fluids draining into the

wellbore. This is particularly useful in subsea wells that

cannot be individually tested for total fluids flow rates. It

also accurately measures the depth interval of each

column of fluids draining into the wellbore.

This result is obtained for any such column using an

equivalent U-tube effect from basic physics. One side

of the U-tube (the source) is a column of fluids flowing

in a porous medium from the top of the gas column to

the bottom of the water column, both of any radial

extent. The other side is the wellbore, also of any ID,

with pipe flow. The two sides are connected through theperforations. From the bottom of the water column to

the top of the gas column, the difference between the

pressure in the column and the pressure in the wellbore

decreases due to less driving force needed up the well-

bore. For there to be steady-state flow in the wellbore,

there has to be an abnormal pressure profile in the well-

bore within the column compared to that above and

below the column. This is due to the influence of flow

of the column in the porous medium, the source. This

new phenomenon occurs regardless of the orientation

of the U-tube, from vertical to horizontal, and improves

current well performance determination. Accurate mid-production depth is provided within

each column described. For each mid-production

depth, there are accurate liquid and approximate gas

flow rates for all three tests, so water or gas coning can

be determined. The approximate Productivity Index

(PI) or potential to flow for each fluid type produced

also is provided for each mid-production depth. The

measured depth intervals of wellbore fluids entry is

graphically displayed, as are the measured depths where

there are wellbore restrictions (such as wax or paraffin

or hydrate buildup) or ID increases.

techWATCH

This image illustrates the U-tube effect.



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Built on a PCI Express x16 Gen2 platform, the display wall controller boards are supported by a new PowerDeskEdge Overlap feature that facilitates multiprojector soft

edge blending by duplicating the GPU’s output edgesand allowing up to 24 projector edges to physically

overlap one another from a single system. The high-

performance board’s design has universal input channelsupport, enabling Mura MPX customers to capture up to

four 1920 x 1200 digital or analog video signals per board

from a variety of devices and display them anywhere onthe unified multiprojector display. www.matrox.com .

Chemical resistant coating takes the heatNansulate EPX insulation, corrosion prevention, chemi-

cal, and flame-resistant coating was created by IndustrialNanotech Inc. to insulate both metal and nonmetal

surfaces around 205°C (400°F). The durable two-part epoxy formula’s applications include steam and chilled

water pipes, boilers, valves, heat exchangers, tanks,

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acids, bases, and fuels and can be easily applied with atexture sprayer, trowel, or stiff brush while equipment is

in-service. www.nansulateindustrial.com .

Proppant storage silo reduceswellsite carbon emissionsHalliburton’s new proppant storage silo addresses two crit-

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carbon emissions from oilfield operations.The SandCastle PS-2500 unit saves on-site storage space

by using a smaller pad size for fracturing operations andtransitioning from a horizontal position to an operating

vertical position using its own solar power gener-ation. This latter component enables it to bypass

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silo’s integrated weighing system. Total working volume is 2,500 sacks (250,000 lb), and proppant

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Next-gen kickover tool enhancestrouble-free gas lift

Wireline Engineering has introduced downholetechnology that enhances the efficiency of gas lift

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failure risks in high deviation wells where the gas lift

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enabling gas lift valve retrieval at the first attempt, thecompany said. The first successful application was com-

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the East Shetland Basin of the UK North Sea, in 186 m(~600 ft) water depth. www.wireline-engineering.com .

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South America

Repsol Sinopec strikes Campos oil

Repsol Sinopec and partners Statoil and Petrobras havemade an ultra-deepwater oil discovery in the presalt

Campos basin. The 1-REPF-11A-RJS well, 190 km (118miles) off the coast of Rio de Janiero, encountered good

quality oil, the Spanish-Chinese operator said. The

exploratory well, informally know as Gávea, was drilledby Stena Drilling’s Stena Drillmax I drillship in 2,708 m

(8,885 ft) water depth and reached a final depth of

6,851 m (22,477 ft). The find is the most significant made in the presalt area of the Campos basin, according

to Repsol Sinopec, although no reserve estimates wererevealed at press time.

Statoil success with Peregrino sidetracks

As part of the first phase of development, Norway’s Sta-

toil has completed both sidetracks at its Peregrino South

well immediately adjacent to the newly opened Pere-

grino field –the company’s largest heavy oil field and

largest operated international field – offshore Brazil.

The wells were drilled by the Fred. Olsen semisub-mersible rig Blackford Dolphin . Estimates for recoverable

volumes in Peregrino South are pegged between 150and 300 MMboe.

OGX’s Waikiki a winner

Brazilian operator OGX has concluded the drilling

of horizontal well OGX-9-44HP-RJS targeting the Waikiki accumulation. A drill stem test has identified

“excellent production conditions” and potential of 40,000 b/d of oil with an oil gravity of approximately 23°

API. The well is in Block BM-C-39 in the Campos basin

and is expected to be part of OGX’s second productionproject in the basin. A complex process of selective acid-

ification was used in eight well intervals, permitting bet-

ter stimulation of the 1,063-m (3,488-ft) horizontal wellextension and maximizing oil flow, OGX said.

Falklands find achieves commercial flow rates

Rockhopper Exploration’s latest appraisal offshore the

Falkland Islands in the South Atlantic has flowed at com-mercially viable rates. The 14/10-05 well (Sea Lion discov-

ery) flowed at a stabilized rate of 5,508 b/d, achieving amaximum flow rate of 9,036 b/d during testing. The

PL033 area’s water depth approaches 550 m (1,804 ft),meaning the operator could opt for either fixed or float-ing production platform development options. Diamond

Offshore’s Ocean Guardian semisubmersible rig will move

on to drill well 14/10-6, the third appraisal probe in theharsh-environment North Falkland basin.

Africa

Mozambique appraisal under way

Anadarko has initiated appraisal drilling using the Fred.

Olsen Belford Dolphin drillship on the deepwater Barquen-tine gas discovery in the Rovuma block offshore Mozam-

bique, according to partner Cove Energy. The rig will drillthe Barquentine-2 well approximately 4 km (2.5 miles)

southeast of the discovery well, followed by the Barquen-

tine-3. The initial appraisal program including flow testingand core analysis will focus on proving sufficient resources

in the Oligocene gas reservoirs of the Windjammer/Bar-quentine discovery area to lay the foundations for a first

EPmag.com

READ MORE ONLINE

For additional

information on

these projects

and other globaldevelopments:

Workers on the Peregrino A platform’s drillfloor. (Photo courtesy

of Øyvind Hagen/Statoil ASA)


internationalHIGHLIGHTS




LNG train. Acquisition of 3-D seismic over some 4,448 sq

km (1,717 sq mile) of the Rovuma block is now complete.Final results are expected in 4Q 2011.

Senegal-Guinea Bissau wildcat spudded

UK-based Ophir Energy has started drilling the Kora-1

wildcat deepwater well in the AGC Profond PSC adminis-tered by the Agence Gestion de Co-operation between

Senegal and Guinea Bissau, the joint commission set up

by the Senegal and Guinea-Bissau governments to admin-ister the maritime zone between the two jurisdictions. The

Kora prospect is approximately 280 km (174 miles) south-

southwest of Dakar in 2,700 m (8,858 ft) water depth.

TGS swims with Dolphin off NW Africa

TGS and Dolphin Geophysical plan to jointly acquire,

process, and market multiclient 2-D seismic data along

Northwest Africa. The survey will total 25,000 km(15,534 miles) of long-offset seismic data. At press time,

approximately 10,000 km (6,214 miles) of data had beenacquired along the Northwest African Passive Margin

using the M/V Artemis Atlantic seismic vessel. The data

will be available in late 2011. According to TGS, the fullprogram is expected to be completed in 2012.

Cobalt to kick off Angolan wells

In late June, Houston-based Cobalt Energy was notified

that Diamond Offshore’s Ocean Confidence drilling rigpreviously under assignment to Total offshore Angola

would be returned to Cobalt for its planned Block 21

drilling activities. Cobalt’s drilling program calls for twopresalt deepwater exploration wells – the Bicuar-1 and

Cameia-1. Additionally, the company expects to executethe production-sharing agreement for its 40% working

interest and operatorship of Block 20 offshore Angola in

early 3Q 2011.

Europe

New FPSO to anchor in West of Shetlands

Operator BP and partners Shell, Hess, Murphy Petro-leum, Statoil, and OMV plan to upgrade production and

subsea facilities at the Schiehallion and Loyal oil fields

in the West of Shetlands with a £3 billion (~US $4.8 bil-lion) reinvestment. In a project known as Quad 204, the

joint venture will replace the area’s existing floating pro-duction, storage, and offloading (FPSO) vessel with a

new FPSO vessel in 2015. The 270-m (886-ft) long and

52-m (171-ft) wide vessel will be able to process andtransport up to 130,000 b/d of oil and store more than

1 MMbbl. The subsea facilities also will be upgraded and

replaced for 2016 production.

Norwegian Sea prospect bears oil and condensate

Statoil and partners Det Norske and Svenska have

proven oil and condensate in the Norwegian North

Sea’s Krafla West prospect, 26 km (16 miles) southwest of the Oseberg South field. The discovery well found

hydrocarbons in two columns with a total thickness of 300 m (984 ft). Preliminary calculations indicate the

find could contain 12.6 to 37.7 MMboe. Through the

discoveries of Krafla and Krafla West – both drilled by Diamond Offshore’s Ocean Vanguard – Statoil said it has

proven reserves of 50 to 75 MMboe. The Krafla discover-

ies were the first wells drilled in the license and may betied back to the Oseberg area’s existing infrastructure.

TGS adds Adriatic Sea data

Spectrum has reprocessed approximately 9,000 km

(5,592 miles) of regional 2-D seismic data from theItalian sector of the Adriatic Sea on a multiclient basis.

The original surveys were acquired by the Italian govern-ment as part of a study to highlight the Adriatic Sea’s

hydrocarbon potential. The majority of production in

the region is from Pliocene-age gas fields, many of which have multi-Tcf reserves. Deeper potential from

the area has yet to be fully explored. A number of undrilled structures have been identified by thereprocessed data, according to TGS.

Middle East

CNPC nears Iraq Phase 1 project completion

CNPC has completed construction of the first phase of the Al-Ahdab oil field in Iraq, on which it began work in

2009 after renegotiating its previous development deal.

The Asian NOC said it hopes to pump 110,000-130,000

The Kora-1 prospect is the first well to be drilled in the deepwa-

ter AGC area. (Image courtesy of Ophir Energy plc)




b/d of oil from the field, which holds estimated reserves

of 1 Bbbl. Completion of the first phase, with a capacity

of 60,000 b/d, is ahead of schedule, according to CNPC.

The field is the first new oil capacity building project inIraq in 20 years.

Central Asia

Reliance finds gas off India’s east coast

Indian energy conglomerate Reliance Industries hasdiscovered gas at its operated exploration well KG-D9-A2

within the deepwater D9 license off India’s east coast,according to UK-based partner Hardy Oil and Gas.

The Dhirubhai-54 discovery well was drilled to a total

depth of 4,881 m (~16,000 ft) with the objective of exploring the play fairway in the early and late Miocene

Channel Levee Complex in 2,700 m (8,860 ft) water

depth. Three sand reservoirs with a gross thickness of22 m (72 ft) were encountered and evaluated by wire-

line MDT. The D9 license in the Krishna Godavari basinoffshore India covers approximately 8,695 sq km (3,357

sq miles).

Pacific Rim

Coastal hits Bua Ban pay dirt offshore ThailandCoastal Energy has hit additional oil pay on the BuaBan North B field offshore Thailand. The Bua Ban

North B-08 well was drilled to 1,800 m (5,900 ft) TVD

and encountered 28 m (92 ft) of net pay. The well, anappraisal of the B-03 discovery well on the easternmost

fault block of the field, further confirms the Miocenetrend in the Songkhla basin. The B-07 water injection

well also was drilled to establish the oil/water contact

in the field at 1,166 m (3,824 ft). According to Coastal,a mobile offshore production unit will be installed

on the Bua Ban North B field once the drilling rig

is off location.

String of oil discoveries prove up Parsons

Beach Energy has encountered a 6-m (20-ft) oil column

at the Parsons-5 development well in the Cooper Basin

Western Flank onshore Australia. This is Beach’s fifthsuccess in its PEL 92 drilling program, which includes

an additional two undrilled wells. The Parsons-5, whichfound oil in the Namur sandstone reservoir, is expected

to be tied in to the Parsons oil facility during the second

half of the year. Preliminary work suggests the Parsons well results, in addition to continued strong production

performance, will result in a reserve increase of morethan 800,000 bbl from the field, Beach said.

North America

Canada-Nova Scotia offers deepwater parcels

The Canada-Nova Scotia Offshore Petroleum Board(CNSOPB) has issued Call for Bids NS11-1, consisting

of eight deepwater parcels offshore Nova Scotia. The

board will only accept bids from companies that havehad experience drilling exploration wells in more than

800 m (2,625 ft) water depth during the last 10 years.

According to the CNSOPB, the parcels are in a geologi-cal region that contains many large undrilled structures

that could trap oil or gas. The bid due date is Jan. 10,2012.

Cobalt lines up GoM wildcat duo

Cobalt Energy expects to begin exploration drillingon its North Platte-1 wildcat in the US Gulf of Mexico

(GoM) later this year. The company formally submittedthe North Platte-1 application to drill (APD) in June

and, at press time, was awaiting a Coast Guard Certifi-

cate of Compliance for the ENSCO 8503 drilling rig, which is expected to be obtained after the rig is

inspected following its return from French Guianain 3Q 2011. Cobalt also resubmitted the Ligurian-2

APD June 9. If the BORMRE approves the Ligurian-2

APD prior to the ENSCO 8503’s return and spud of theNorth Platte-1, Cobalt will first drill the Ligurian-2.

The ENSCO 8503 ultra-deepwater semisubmersible rig is

expected to begin drilling for Cobalt in the GoM in late 2011.

(Image courtesy of Ensco plc)



Online Registration

and

Ho

using begins

6

Jul

y

2011

1

Icebreaker/Exposition

Don

't miss

the opening of the exhibit

floor

on Sunday,18

September.

1Applied Science Education

Program

Join San Antonio natives

,

Celina and Marina Suarez as the

speak about

their discovery

of

a

new

species

of

dinosaur

,

now

named

for

them,

rom io-iiam

on Wednesday,

21

September.

1

SEG Forum

A distinquished panel will discuss the "Frontiers in

Exp loration

,

Geograp

hics

,

Technology,

and Business

'

on Monday,

19

September.

•

More

than

600 oral & poster

presentations

• Over

8

,

000 industry

professionals

•

More

than 300 companies

exhibiting

• Cutting-edgesessions

&

workshops

•

Networking events

E

201

En Finwin

9

from innovation

r

9Y

Society of Exploration Geophysicists International Exposition and

81st

Annual Meeting

Henry B.

Gonzalez

Convention

Center

•

18-23

September

2011

San Antonio

,

TX USA

1

Golf

Tournament

La

Cantera Golf

Club

,

Saturday,

17

September

(

Icebreaker

Sunday,

i8

September

1

Exhibition

Sunday-Wednesday,l

8-21 September

1

Technical

Program

Monday-Friday,

1

9-23

September

1

SEG

Forum

Monday, 19

September

1

Challenge

Bowl

Monday,1

9

September

1Ap p

lied

Science

Education Program

Wednesday, 2 1 September

1

Wednesday

Night

Celebration

Wednesday,21 September

1w.

,

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t

?

i•

r

l

L A

L

vvv

+\

W



Edward “Ted” Beaumont

(left), senior geologist atSM Energy, has been elected

AAPG president for 2012-13.

Adnan Shihab-Eldin

(left) and Claude

Mandil (right) have

joined the SBC

Energy Institute.

Range Resources president

Jeffrey L. Ventura (left) will

assume the additional role of CEO in 2012, at which time

CEO John H. Pinkerton will become

executive chairman.

John Meaden is now COO of NCS

Survey, an Acteon company.

McDermott International has named

Jack McCormack EVP and COO.

Gene Rice has taken the reins as techni-

cal director, rig repairs, at McDermott’s Altamira, Mexico, fabrication facility.

CTAP LLC plans to open a Midconti-

nent sales office in Oklahoma City led

by Mike Booth in 3Q 2011.

Lloyd’s Register Americas has consoli-

dated five businesses to a new regional

HQ in Houston, Texas.

ADVERTISER INDEX

on theMOVE


Baker Hughes Incorporated . . . . . . . . 11

Cameron . . . . . . . . . . . . . . . . . . . . . . . . . 9

CDI Seals . . . . . . . . . . . . . . . . . . . . . . . . 28

CNPC Greatwall Drilling Co. . . . . . . . . 24

Cudd Energy Services . . . . . . . . . . . . . 20

Deep Casing Tools . . . . . . . . . . . . . . . . 63

Dragon Products, Ltd. . . . . . . . . . . . . . .41

E&P . . . . . . . . . . . . . . . . . . . . . . . 60, 78, 84

Emerson Process Management . . . . . . 7

Escondido Resources II . . . . . . . . . . . . 71

Expro Group . . . . . . . . . . . . . . . . . . . . . 75

Frontier Energy Group, Inc. . . . . . . . . 64

Fugro . . . . . . . . . . . . . . . . . . . . . . . . 35, 73

Fugro Jason . . . . . . . . . . . . . . . . . . . . . . 53

GE Oil & Gas . . . . . . . . . . . . . . . . . . . . IFC

GE Energy . . . . . . . . . . . . . . . . . . . . . . . 33

GEA Westfalia Separator Group . . . . . 45

GEFCO . . . . . . . . . . . . . . . . . . . . . . . . . 58

Halliburton . . . . . . . . . . . . . . . . . . . . . . 26

Halliburton Landmark

Software & Services . . . . . . . . . . . . . . . 4

IHS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Independent Petroleum

Association of America . . . . . . . . . . . 49

McJunkin Redman . . . . . . . . . . . . . . . . . 17

M-I Swaco . . . . . . . . . . . . . . . . . . . . . . . . 2

National Oilwell Varco . . . . . . . . . . . . . 19

Nachurs-Alpine . . . . . . . . . . . . . . . . . . . 55

OTC Brasil . . . . . . . . . . . . . . . . . . . . . . IBC

P2 Energy Solutions . . . . . . . . . . . . . . . 69

Petris . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Precision Geophysical . . . . . . . . . . . . . 51

Schlumberger . . . . . . . . . . . . . 3, 65, OBC

Society of Exploration Geophysicists . . 90

Society of Petroleum Engineers . . . . . 37

Stallion Oilfield Services . . . . . . . . . . . 68

TGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Vicinay Cadenas, S.A. . . . . . . . . . . . . . 59

Weatherford International, Ltd. . . . 22, 23

Group PublisherRUSSELL LAAS

Tel: 713-260-6447

[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]

Advertising Sales RepresentativeHENRY TINNE

Tel: 713-260-6478

[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 77057Tel: 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

Ellis Williams, Jr., a leading designer of

oilfield equipment, passed away on July 1.

A Texas registered engineer since 1961,

Williams was the founder of Ellis Williams

Co. (EWCO and EWECO); designed

mud pumps for Emsco, Ideco, Brewster,

Skytop, LeTourneau, and Weatherford; and

authored numerous patents and specifica-

tions for API.

In Memoriam

E

P



According to recent US Energy Information Adminis-

tration (EIA) estimates, the production of naturalgas from shale formations now accounts for 23% of total

onshore domestic natural gas production. EIA also now

estimates total technically recoverable natural gas fromUS shale at 862 Tcf – a mind-boggling total that has the

potential to enhance energy security and drastically reduce domestic emissions of greenhouse gas.

As citizens of Pennsylvania, Texas, and other states

know, with shale plays come job creation, investment,tax revenue, and economic development. Generations

of Americans have wondered what it would be like to

have the energy resources of Saudi Arabia. Is it possi-ble for the US to squander this opportunity?

The recent shale boom has been made

possible by technological advancements inthe decades-old method of hydraulic

fracturing. Hydraulic fracturing involves

injecting water (typically 99.5% of thesolution), sand, and fracing fluids into

deep geological formations of reservoirrock to create small cracks that allow

natural gas to flow into the wellbore. While fracing has long been regulated

by state agencies, concerns about fracing

have now become a cause célèbre for theenvironmental community and the media. Most

of the claims revolve around potential risks to drinking

water. And yet, underneath the hype lies the fact that hydraulic fracturing in shale occurs at depths thousands of

feet below where usable groundwater is likely to be found.Undaunted by the lack of any documented groundwater

contamination from fracing, multiple Federal efforts are

under way to examine the safety of the hydraulic fractur-ing process, including EPA’s study on the method, which

is not scheduled to be completed until 2014, and a review

by the US Department of the Interior of potential furtherpermitting requirements for fracing on Federal lands.

In addition, recent attention has fallen on the USDepartment of Energy (DOE) where Secretary Chu has

been charged by President Obama with establishing a sub-

committee to examine fracing issues and identify both

immediate and long-term steps that can be taken toimprove the safety and environmental performance of the

fracing process. How can the DOE help ensure continuedshale gas production while providing increased assurance

to the public on environmental safety?

First, increased disclosure of the chemicals contained infracing fluid has been a major focus of the environmental

community and regulators. Industry has responded tothese concerns by participating in the creation of Frac-

Focus – a joint project of the Ground Water ProtectionCouncil and the Interstate Oil and Gas Compact Com-mission. FracFocus is an online registry through which

operators can publicly disclose the chemicals used in

fracing. Montana and Texas already have concluded that local operators can meet their regulatory requirements

by using FracFocus, and other states may soon follow.DOE can lead this effort by recommending to

the President that FracFocus become the

basis for state disclosure requirements. A second major focus of the DOE sub-

committee has been the development

of best practices within the industry tobetter prevent accidents and ensure

appropriate standards are upheld. Onthis issue, DOE can look inward by rec-

ommending to the President that exist-

ing interstate nonprofit entities – someof which were established with DOE funds

– be strengthened. Organizations such as theGroundwater Protection Council and the Inter-

state Oil and Gas Compact Commission are:

• Already engaged in ensuring best practices within theindustry;

• Much more nimble and able to react to ongoing tech-nological developments; and

• Better able to adjust recommendations to account for

local and regional factors.These recommended steps can go a long way toward

achieving President Obama’s aim of increasing energy

security, growing the economy, and ensuring that gas pro-duction is accomplished in a manner that protects public

health and the environment.

Technological achievements combined with naturalresources have given this country a great gift. It is one that

should be gratefully – and responsibly – accepted.

Getting to ‘yes’ on shale gasUS shale gas reserves are enormous, but development hinges on resolvingenvironmental concerns.

Jason B. Hutt, Bracewell & Giuliani LLP

lastWORD

Concernsabout fracing

have now becomea cause célèbre forthe environmentalcommunity and

the media.



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Revista E&P - Agosto 2011

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