revista e&p - diciembre 2011

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76 REGIONAL REPORT: INDIA

ASSET INTEGRITY MANAGEMENT

Root cause identificationmitigates equipment failures

Asset performance managementcreates long-term value

Combine operations, engineeringto achieve asset integrity

EXPLORATION MILESTONES

Explorers innovate

DRILLING REVIEW

Drilling environments benefitfrom improved technology

PRODUCTION SUCCESSES

Production milestones revealan expanding universe

SPECIAL REPORT: DUG EAGLE FORD

South Texas holds hidden reserves

OFFSHORE 2012: THE YEAR AHEAD

Offshore tide on the rise

IndustryPULSE:New technologiesstave off Peak Oil

False pessimistic predictions regarding the future ofoil production have been around since the mid-1850s. Though reserves numbers continue to grow,the hue and cry of Peak Oil continues to entanglegovernment agencies, geologists, and moneymen.

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

DECEMBER 2011VOLUME 84 ISSUE 12

A HART ENERGY PUBLICATION www.EPmag.com

COVER STORY

30Five industry experts predict

the advances and innovations

expected in the coming year.

Gearing upfor 2012

8

WorldVIEW:

Independent looks eastfor the Eagle FordA small company has big ideas when it comes tochasing the Eagle Ford shale into Louisiana.

10

Unconventional:Fayetteville shale gasstill a hot commodity

All may be quiet on the dry gas front, but recentresults from the Fayettevilles first mover show that

this shale gas play is still paying dividends andhas growth potential to boot.

42

44

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4/91

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AS I SEE IT

Its time for the industry to occupy shale development 7

MANAGEMENT REPORT

Water management trends toward reuse 14

DIGITAL OIL FIELDInnovative software takes on riser design, analysis 19

EXPLORATION TECHNOLOGY

Flying nodes shift marine seismic paradigm 25

WELL CONSTRUCTION

Pollution is lost profit 27

PRODUCTION OPTIMIZATION

Its time to boldly go 29

TECH WATCH

Closed-loop drilling scalability provides options 78

TECH TRENDS 80

INTERNATIONAL HIGHLIGHTS 82

ON THE MOVE/INDEX TO ADVERTISERS 85-86

LAST WORDUK Government Ring Fence Expenditure Supplement First response to bad policy? 88

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, PO Box 5020, Brentwood, TN37024. Address all non-subscriber correspondence to E&P, 1616 S. Voss Road, Suite 1000, Houston, Texas 77057; Telephone: 713-260-6442. All subscriberinquiries should be addressed to E&P, 1616 S Voss Road, Suite 1000, Houston, TX 77057; Telephone: 713-260-6442 Fax: 713-840-1449; custserv@hartener-

gy.com. Copyright Hart Energy Publishing, LP, 2011. Hart Energy Publishing, LP reserves all rights to editorial matter in this magazine. No article may be repro-duced or transmitted in whole or in parts by any means without written permission of the publisher, excepting that permission tophotocopy is granted t o 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 A very active 2011 paves the way for an equally success-

ful 2012 as operators continue their push into new plays with new technologies. (Inset

photos courtesy of Ken Childress Photography/Ensco, TGS-NOPEC, and Baker Hughes;

cover design by Laura J. Williams)

COMING NEXT MONTH While the industry continues to fund vital R&D efforts, E&Peditors have

looked outside the industry for potential transfer technologies to add to the mix, presenting them along-

side oil and gas industry efforts in the Technologies to Watch feature. This issue also investigates new ways

to manage cost and risk and looks at advances in seismic processing and interpretation, ways to man-

age HP/HT drilling operations, and the latest in surface production systems. Floating production takes

center stage in the offshore feature, and regional highlights include the hot Permian Basin in the US as

well as China. As always, while youre waiting for the next copy of E&P, remember to visit EPmag.com

for news, industry updates, and unique industry analysis.

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ONLINE CONTENT DECEMBER 2011

PREMIUM CONTENT Subscribe @ EPmag.com/explorationhighlights

Linc reports 124-m shale zone at South Australia siteAn exploration well by Linc Energy Ltd., the #1-Arck, has struck a124-m (~400-ft) shale zone in South Australias Arckaringa basin.The discovery is in the PEL 122 permit area.

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SPE: Nanotechnology in theoil patch: A realistic dream

By Rhonda Duey, Senior Editor

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Oxy builds on IT base, createsdigital wireless canopy

By Scott Weedan, Senior Online Editor

Oxy continues to benefit from its IT operations

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READTHELATESTEPmag.com

INDUSTRYNEWS

Offshore Sri Lanka gas discoveryfirst for nationAn offshore Sri Lanka gas discovery in theMannar basin in the Gulf of Mannar hasbeen reported by Edinburgh, Scotland-

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Much of todays energy reporting labels fossil fuelsusage as unsustainable. Fossil fuels are finite and irre-

placeable, and their combustion emits the greenhousegases (GHGs) that are adversely changing our climate. Thefuture availability of petroleum is of particular concernbecause oil has constituted a leading 35% of the worldsenergy supply for decades. Despite claims to the contrary,however, oil and gas production have not hit their peak.

The heart of the misperceptionThe main reason for misconceptions about fossil fuelavailability is reliance on analytical techniques that fail toappreciate oil as an economic commodity powered by theconstant advance of technology. Many predictions fall

short because they focus on reserve years or the provedrecoverable reserves divided by the annual consumptionrate. Proved reserves can grow over time, however, andestimates of the recoverable resource change as newinformation is acquired through drilling, production,and technological and managerial development.

Another factor that affects perception is that oilcompanies adopt short- to mid-term planning hori-zons. Exploration is costly, so there is no economicincentive to look for resources that will not beneeded for many decades. This is why the knownreserves numbers of so many

producers frequently fallwithin the range of a fewdecades, regardless of howmany years have passed or howmuch of the resource already has beenproduced. In fact, due to the irreversiblenature of an oil projects large invest-ment outlays, it is more constructivefor companies to err on the sideof caution and underinvest inE&P until new information aboutfuture market conditions arrives.

The constant advance of technologyAvailability of natural resources like oil can be visualizedas a pyramid that has a smaller volume of high-quality,easier-to-extract resources at the top, and a larger vol-ume of lesser quality, harder-to-extract resources at thebottom. Over time, resources near the top of the pyra-

mid are consumed, and development of those fartherdown the pyramid begins. The resource pyramid offersa framework for comprehending the enormity of theworlds oil endowment it illustrates why so much oilis still available.

The price of extraction increases as producers go loweron the pyramid, but technologies tend to reduce thesecosts over time. For example, the IEA states that new sub-sea oil production techniques can further decrease theproduction costs and make a considerable number ofnew fields economically profitable. Estimates indicatethe world has used just 8% (1 Tbbl) of the 9.6 Tbbl

resource base of conventional oil and 3 Tbbl of uncon-ventional crude oil.

Energy forecasters today have no way to predicthow fast new technologies will evolve. Oil and servicecompanies develop technologies because demand isever-growing, and there are stiff penalties for getting

it wrong. An industry rule of thumb, forinstance, estimates the cost of drilling a

deepwater dry hole is approxi-mately US $100 million.

New technologies enhance thediscovery process, reduce explo-

ration failures, and help com-panies better integrate dataand information to more effi-

ciently manage assets. Producers cannow produce several oil fields from

a single platform, and with eachupgrade in performance and effi-

ciency, fewer wells are needed torecover more resources. TheUS Department of Energy

notes, If Alaskas PrudhoeBay oil field was opened with

December 2011 | EPmag.com8

industryPULSE

New technologies stave off Peak OilFalse pessimistic predictions regarding the future of oil production have been around sincethe mid-1850s. Though reserves numbers continue to grow, the hue and cry of Peak Oil con-

tinues to entangle government agencies, geologists, and moneymen.

Jude Clemente, Energy Analyst and

Technical Writer, Homeland Security Department,

San Diego State University

The resource pyramid concept

Better quality

resource

Increasing cost

of extration

Highly concentratedEasy extraction/access

Low concentration

Difficult extraction/access

8% of the oil resource

pyramid

Over time, resources near the top of the pyramid

are consumed, and development of those farther

down the pyramid begins.


10/91EPmag.com | December 2011 9

todays technology, its footprint would be almost a third ofits current size.

Emerging technologies and innovative processes con-tinually blur the line between conventional and uncon-ventional energy resources. Much offshore production

was deemed unconventional and too expensive only afew decades ago. Since then, drilling, exploration, andproduction techniques have improved considerably,and sophisticated rigs can tap deep, huge reservoirsundreamed of 25 years ago. Today 30% of all oil comesfrom offshore wells.

Completed in 1986, Shells Mensa field in the Gulf ofMexico at more than 1,500 m (5,000 ft) water depth setthe threshold at the time for ultra-deepwater production.Today, the term ultra-deep means drilling in more than3,000 m (10,000 ft) water depth. IHS CERA reports globaldeepwater capacity is more than 5 MMb/d, up from 1.5

MMb/d in 2000.Technological breakthroughs can occur in a remarkably

short period of time. Just a few years ago, US gas produc-tion was assumed to have peaked, but advancements inhydraulic fracturing and horizontal drilling have createda shale gas boom that has transformed the domestic pro-duction outlook. Companies now are looking to exportexcess supply.

Without drilling a single new well or making a new dis-covery, oil supplies could expand dramatically. At leasttwo-thirds of the oil in a reservoir often is left behind afterprimary, secondary, and tertiary operations because it is

too difficult or expensive to extract. The Reservoir Engi-neering Group estimates that a 10% boost in the globalrecovery rate would translate to an additional 1.4 Tbbl ofreserves, doubling what we have today.

Changing economicsAs oil becomes harder to find and produce, its price willincrease, triggering key supply and demand responses.Higher prices typically result in more investments thatincrease productive capacity and supply, especially bymaking unconventional projects more cost-effective.

During the oil price peak in July 2008, for instance,

the US rig count was at its highest level since1985, and higher prices prompted the uptick inglobal oil discoveries in the 2000s against the

1990s. On the demand side, higher oil pricescurtail consumption by restraining economicgrowth and encouraging lifestyle changes to con-serve or substitute fuel. When world oil pricesaveraged $92 in 2008, demand dropped for thefirst time since 1983.

Even under the IEAs 2010 optimal policy pro-jection for renewable energy (450 Scenario), where oildemand unrealistically peaks before 2020, oil is still a pre-dominant source of energy, supplying 26% of the worldsenergy in 2035.

The economics that reign in the oil industry, however,

are the marginal costs of production, or the expense ofextracting an extra barrel of crude. The EIAs 2011Financial Reporting System analysis concludes thatworldwide lifting costs fell from about $7/boe in 1980 toless than $5/boe in 2005. Finding costs also substantiallydeclined until the early 2000s, when an upward trend wasgained, mostly due to a jump in E&D expenditure and arevision in reserves. In practice, finding costs are the ratioof E&D expenditures to proved reserve additions over aspecified period of time. Today, a more favorable coststructure is beginning to reemerge.

The EIA reports worldwide upstream costs (finding plus

lifting) decreased 16% to $29.30 from 2007-2009 com-pared to 2006-2008. And IHS Herold reports that despitea 40% cut in E&P capital spending in 2009, oil reservesgrew 3%. E&P expenditures were up more than 10% in2010 and are expected to increase by about the sameamount in 2011.

Although oil is an exhaustible resource, the question ofhow much longer the worlds supply will remain sufficientis too ambiguous for anyone to answer.

Evidence indicates recent price levels above $100/bblrepresent a contrived, not an actual, supply scarcity ashortage price without a shortage of in-ground resources.

With supply a function of price and technology, new playsand more intense development of existing reservoirs,allied with cost saving and innovative technologies, areoffsetting resource depletion. Beyond the healthy stockof reserves, evolving economies of scale and new infra-structure also will shift todays massive unconventionalresource into tomorrows conventional supply category.

Looking forward, the resource pyramid reveals the worldis not running out of oil, but producers and consumers arelikely entering a new era of less stable costs.

References available

EPmag.comREAD MORE ONLINE

There is moreto the story

Salient oil reserves and production data, 1980-2010.

Data Point 1980 1990 2000 2010 Increase

World Reserves (Bbbl) 670 1016 1106 1383 106%

World output (MMb/d)* 63 65 75 82 30%

World R/P ratio (years) 29 43 41 46 59%

* Crude oil, shale oil, oil sands, and NGLs (Source: BP Statistical Review of

World Energy 2004 and 2011)


11/91

Independent looks east

for the Eagle FordA small company has big ideas when it comes to chasing the Eagle Ford shale into Louisiana.

When industry people hear the term Eagle Fordshale, they are not likely to think of Louisiana.

This hot play has South Texas on fire as companiesrush to exploit its gas and oil riches. But tiny Indigo II

Minerals LLC is convinced that the geology does notchange much at the Texas/Louisiana border.

Bill Pritchard is the chairman and CEO of Indigo.His ambition is to be successful enough in Louisiana tosinglehandedly rename the play from the TuscaloosaMarine shale (TMS) to the Louisiana Eagle Ford shale.

The company got its start by putting together a min-eral position, a deal made possible by the exchange ofRoy O. Martin Lumber Co.s mineral rights for an equityposition in the company. Yorktown Partners, Indigosfinancial partner, matched the valuation of the mineralsin cash.

We started with about 475,000 mineral acres in thestate of Louisiana because Roy Martin was the largestprivate landowner in the state, Pritchard said. The com-pany went on to sell 90,000 Haynesville shale acres toEncana Corp. Currently, it has about 450,000 lease andmineral acres split between the Austin chalk andLouisiana Eagle Ford.

The company developed an interest in the lattershydrocarbon potential in 2008 based on an old well thathad good shows in the lower Eagle Ford shale intervalbetween the Austin Chalk and the Edwards limestone, inthe same location relative to the Edwards shelf margin

as in South Texas. Pritchard said the name of the well,the Martin Timber #1, caught his companys attention.

When they drilled that well, the mud was cut 2pounds, which was pretty substantial, he said. Theyswabbed in oil, cored, and found fractured shale withlime interbeds. And they had to do some control drillingto mud up and get through that interval. These weregood signs to us.

Continued study revealed that many of the wells inthat area, most drilled in the 1970s and 1980s, hadencountered similar drilling issues with that interval,he added.

Based on this infor-

mation, Indigo beganleasing additionalacreage in mid-2010;between its mineralfee and the leases itacquired, the company

had put together some 255,000 net acres by mid-2011. Itspent about US $5 million to drill, core, and test a verticalwell at the end of 2010.

Were the first company to actually have drilledand conducted modern testing through the interval,Pritchard said. More recently the company has drilled

a horizontal well that it planned to frac and test inNovember.

Mirror imagesWhile different companies have different names for theshale on the east side of the Texas/Louisiana border,Pritchard said the shale he has been drilling and coring isalmost a mirror image of the South Texas Eagle Ford. Onthe Texas side of the border, the Harris delta slides downwest of the Sabine uplift, depositing clay and silt betweenthere and the San Marcos arch. To the west of that is therich organic shale of the Eagle Ford.

On the Louisiana side, similar sediments are trappedbetween the Sabine uplift to the west and the La Sallearch to the east.

Many geologists argue that the shale of interest inIndigos acreage is actually the TMS, but Indigos geo-logical interpretation shows the Lower Tuscaloosa sandsthat underlay the TMS pinching out as the play headswest onto the Sabine uplift. In Indigos area, the highresistivity streak at the base of the Eagle Ford liesdirectly on top of the Edwards lime.

I think the two plays are fundamentally different,he said. The rock were drilling is more calcitic and

Bill Pritchard, chairman

and CEO of Indigo.

(Image courtesy of

Indigo II Minerals LLC)

Rhonda Duey, Senior Editor


worldVIEW


12/91


13/91December 2011 | EPmag.com12

worldVIEW

has less clay content. Its more similar in depositionalenvironment to what you see in South Texas. As youmove further east, it transitions, and by the time you

cross the (Mississippi) river, youre in a different deposi-tional setting.

Drilling also is easier to the west. Pritchard said com-panies chasing the TMS have encountered drilling prob-lems, while both Indigos vertical test well and itshorizontal well were drilled on time and budget with nodifficulties. Meanwhile, Indigo engineers had concernsabout the Lower Tuscaloosa deltas, largely water-bearingsands beneath the TMS that could present the potentialto frac into water below the zone of interest.

So far the company is encouraged by the testing it hasdone on the vertical well. The production test shows 45

to 50 API oil with 1,450 Btu and 10 gal/Mcf of naturalgas liquids. Regional geological work indicates that theshale is more brittle in the western area, coincident withIndigos acreage.

To say the play is underexplored is an understatement Indigos two wells are the only new wells to have beendrilled in the area in the last 30 years. And that uncer-tainty does cause Pritchard some concern.

We worry about the number of frac stages, theproper fluids, drilling costs, all the same things you

worry about in most of these plays, he said. These arepretty capital-intensive deals. Were very well capitalized,but these plays really need big balance sheets.

The history of just about every one of these plays isthat it takes $100 or $200 million to figure out what worksand what doesnt work. At some point were going toneed more dollars to help us figure this thing out.

Our concern is, did we trade good rock mechanicsfor per acre recoverable hydrocarbons? Were going tofind out when we complete our horizontal well.

A little helpToward that end, Indigo is actively seeking a joint venture(JV) partner, either a company that would operate futuredevelopment or a pure financial partner to help develop

its entire 255,000-acre position, where only 11 leasescover 200,000 acres in the play. Pritchard said the benefitsto a potential partner include a large acreage positionand confirmed Louisiana Eagle Ford potential, including:

A favorable geologic setting, Good reservoir attributes, Drillable and fracable rock, High-quality hydrocarbons, Repeatable; and predictable drilling inventory.There is potential for costs to decrease while esti-

mated ultimate recoveries and30-day production numbers

increase, Pritchard said.Indigo has friendly landown-

ers, often not the easiest thingto find in a shale play. Twolandowners account for165,000 of its acres, and oneof them sits on the companysboard of directors.

While Pritchard feels confi-dent that Indigos acreage isin the sweet spot of the play,there is no jealousy toward

other players who also areintrigued by the possibilities.The rising tide floats allboats, right? Pritchard said.

Were really rooting forDevon and others in theeastern part of the play.If Devon drills a 500,000-bbl EUR well, well rebrandeverything as the TuscaloosaMarine shale, effectiveimmediately.

Deposition during the Middle Cretaceous period left organic shale deposits in Louisiana as well

as Texas. (Map courtesy of Indigo II Minerals LLC)


14/91

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15/91

The largest environmental concern related to hydraulic

fracturing is water use. With millions of gallons at stake

for each horizontal lateral, pressure on water resources is

felt both by the industry and by the general public.

For most regions, water quality is a hot-button topic. In

areas such as South Texas and Oklahoma, severe droughtcan amplify pressures on water demand. Awareness of

these concerns has been the impetus for most of the major

shale players adopting reuse as a means of keeping cost at a

minimum, ensuring water is always available, and harmo-

nizing their efforts to protect the natural environment.

Historically, most frac jobs were performed with fresh-

water. It was once thought that high levels of constituents

such as chlorides were an impedance to successful deploy-

ment of fluids. Reuse technology spawned from the need

to treat frac flowback at the surface for additional jobs.

Treatment was expensive, and the outcome of using

treated water was unknown.In 2010, Cabot Oil & Gas in a joint effort with Superior

Well Services and Kroff Well Services Inc. completed theworlds first frac job using 100% treated flowback water in

Susquehanna County, Pa., in the eastern Marcellus shale.

At the time, the well registered among the highest produc-

ers in the same geology and geographical region. Today,

reuse technology has advanced almost to the point of

common practice.

Beginning this year, major players including Chevron,

Atlas, and Range Resources committed to reusing 90% of

their water by year-end 2011. This number was increased

to 100% for 2012.As reuse technology has become more common, cost

has significantly gone down. In addition to saving time

and capital, companies are finding it much more feasible

from an environmental perspective to reuse water than to

release it.

Benefits of analysisIn its ongoing effort to advance water reuse in North

American shale plays, Kroff Well Services has pursued data

acquisition for water quality both before and after frac

deployment in a number of regions.

The companys database contains analyses from morethan 5,000 prefrac samples and about 7,000 post-fracsequential flowback samples. This information is in addi-

tion to produced water analysis from aging wells in the

vicinity, according to Dave Grottenthaler, general

manager, Kroff Well Services. We are sampling

water in all the basins, he said.

Part of the interest in water reuse is generated

from the lack of water resources in many areas.

Most operators are paying to dispose of spent

water, Grottenthaler said. Why not just keep it

and safely reuse it?

Well configuration and the close proximity of later-als in todays shale gas environment are highly con-

ducive to water treatment and reuse. In addition to

access, the company has been successful in delineat-

ing focused examples of water quality in most of the

major shale plays.

Analysis began in the Marcellus, where Kroff has

been most active, but the range of information is

expanding to plays such as the Haynesville and

Eagle Ford, among others. Water samples are col-

lected for every 500 bbl of flowback and fully ana-

lyzed. You end up with a county-by-county analysis

Water management

trends toward reuseCurrent technology gives operators the capacity to reuse water rather than release it.

Tayvis Dunnahoe, Senior Editor


managementREPORT

Variability of dissolved constituents is shown for each shale. This knowl-

edge allows the operator to more effectively reuse water and adjust the

frac fluid design strategy. (Images courtesy of Kroff Well Services Inc.)


16/91

Ole Performan ce

Email: downhole@novc

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The advancement of offshore field developments into

increasingly deeper water, coupled with the progres-

sively more stringent safety requirements being placed

on operators, has made the role of high-quality software

in underpinning the engineering design and analysis

process critically important. Todays engineers rely onanalytical capabilities to provide confidence in their

designs and keenly desire a user-friendly interface to

facilitate optimum productivity in relation to model

creation and refinement.

Challenging the status quoExisting software products used in the offshore industry

broadly fall into two distinct categories, general pur-

pose finite element packages and specialized tools tai-

lored specifically toward the industry. While the former

are undoubtedly powerful and all-encompassing, the

myriad modeling options presented to the engineermake using these tools overly complicated, and efficient

use of the software typically requires significant experi-

ence on the part of the engineer. Dedicated tools, on

the other hand, rarely achieve an optimal balance

between advanced analytical capabilities and user

interface versatility.

The need for a better tool designed specifically for

oil and gas operations was the catalyst behind recent

improvements to a software product developed by MCS

Kenny, Wood Group Kennys riser engineering and soft-

ware solutions company.

Flexcom 8 is the companys next-generation riserdesign and analysis software that delivers a step-change

in how riser engineering design and analysis is per-

formed. The enhancements provided by this new ver-

sion lead to a better design that supports the industrys

increasing focus on improved process safety, better pre-

dictability, and greater knowledge of utilization and

integrity during operations.

Interface technologyThe new user interface has been created using the

latest software development technologies, including

.NET Framework and Windows Presentation Founda-

tion (WPF). The .NET Framework is an integral Win-

dows component that supports the development of the

most recent generation of applications. It includes alarge library of functions and supports several program-

ming languages, which allows developers to combine

their own source code with the existing framework in an

integrated development environment. WPF is a graphi-

cal system produced by Microsoft for rendering user

interfaces in Windows-based applications. At its core

lies a resolution-independent, vector-based rendering

engine that is designed to take advantage of modern

graphics hardware. Using these leading-edge technolo-

gies facilitated the development of the next-generation

user interface.

EPmag.com | December 2011 19

digitalOIL FIELD

Innovative software

takes on riser design, analysisImproved modeling leads to better riser design.

Aengus Connolly, MCS Kenny

Flexcom 8 bridges the gap between finite element analysis and

specialized industry tools. (Images courtesy of MCS Kenny)


21/91

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Flexcom 8 represents a fully integrated engineering environment, with

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tional model.Data specification is aided by useful input prompts, helpful tooltips,

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each analysis, informing the user of successfully completed runs and

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26/91

In recent years, seabed nodes have entered the tech-

nology spectrum as an alternative to towed streamer

and ocean-bottom cable (OBC) operations. As with any

new technology, they have their pros and cons.

The pros include true coupling with the seafloor,

which allows for the measurement of shear waves, which

streamers cant accomplish. Nodes also offer advantages

over ocean-bottom cables in that theyre not tethered

together and can therefore manage rougher topogra-phy and be used in a sparser spread for wider coverage.

But they have their disadvantages as well. They are

orders of magnitude more expensive than streamer sys-

tems and require ROVs to place them on the seafloor,

which creates logistical issues.

The techniques we currently use, however

sophisticated they are and however fast they

progress, will not be scalable to large-

scale, routine deployment, said Dirk

Smit, chief scientist-geophysics for Shell.

The cost may be too high, the logistics

may be too involved, and sub-ice acquisi-tion will be difficult or impossible.

But above all, our commercial models

to acquire data using OBC or nodes are also

inadequate, he said. At the moment,

theres no such thing as group or multi-

client shoots because the technology

costs are too high.

Toward that end, Shell partnered with

a company called GO Science, which

had developed the Ring Hydro-Vessel Agent Under-liq-

uid Vehicle. This vehicle, looking like part of the cabin

of an airplane, has two thrusters that propel it throughthe water, can travel up to 8 knots on battery power, and

can organize itself into a swarm with up to 2,500 units

in a coordinated autonomous group.

Each vessel can get an orientation relative to the

swarm by using a compass, inertial sensors, and acoustic

signals and by a surface coordinator that uses GPS for

navigating to the preplanned position.

What the basic package lacks is a seismic sensor, and

Shell was happy to oblige by adding geophones that can

be towed behind the vehicle, placed on the seafloor, left

to record data, and moved to the next location without

direct intervention.

To Smit, the system has the potential to solve a host of

marine seismic problems. What you really need is lower

costs and higher efficiency rates, he said. Sec-

ondly, you would like to get many more meas-

urements at the same time. The density of

the nodes needs to improve, and you

would like to be able to deploy them

over large areas. This requires deploy-

ment models that are fundamentally of

much lower cost.And you would like to do this in a

shorter time frame. These flying nodes

would help achieve that.

He added that Shell invests in novel

concepts to be able to simultaneously

shoot seismic with lots of source vessels

without degrading the data in particular

for time-lapse seismic. This, together with

low-cost sensor deployment, will establish

a breakthrough and hopefully lead to a commoditiza-

tion of ocean floor seismic and possibly replace

streamer seismic acquisition.Shell plans to test the concept in earnest for a few

months, but Smit says so far it is performing to expecta-

tions. The company is currently seeking partners to

help commercialize the technology. We didnt invest in

this because we didnt believe in it, he said. The prob-

lem were trying to solve is not unique to Shell, and

hence we are happy to partner

with others.

For more information, visit

Goscience.co.uk.

Flying nodes shift

marine seismic paradigmLow-power autonomous nodes could revolutionize ocean-bottom seismic.

Read more commentary at

EPmag.com

RHONDA DUEYSenior Editor

[email protected]

25

explorationTECHNOLOGY

EPmag.com | December 2011

The flying node sensor is being

developed to commoditize

seafloor seismic operations.

(Image courtesy of GO Science)


27/91

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wellCONSTRUCTION

According to Raymond Roccon, director businessdevelopment, Tetra Technologies, Inc., Fracing

doesnt need to be a dirty word.Its true, the issue is polarized politically, but from

the well construction point of view the industry hasnever operated more cleanly, nor has it ever beenmore environmentally conscious.

Forget about simple concerns about being green.

Today, the rapid pace of drilling in North Americanshale plays has developed a number of trends thatnot only are decreasing the industrys environmentalfootprint, but are saving operating companies coldhard cash.

Roccon was among the speakers who presented atan environmental workshop that was organized inconjunction with Hart Energys DUG East conferenceheld in Pittsburgh, Pa., Nov. 15, 2011.

Today, fracing operations generally are carried outusing frac water pits as opposed to multiple tanks.These are double lined, double welded, and are

specifically designed to avoid communicationwith groundwater. Environmentallysound and easily mitigated onceoperations cease, the modern fracjob improves safety and long-term profitability. First-genera-tion slickwater frac jobs typicallyused trucks to supply vastamounts of water, Roccon said.This created a large footprint.

Reduced truck traffic ensures asmaller footprint. Process

improvements also includewater reuse technology, whichis impacting hydraulic fracturingin a big way. Designing systems tocontain, treat, and reuse both flow-back water and produced water in somecases is adding more to the bottom line forcompanies that considered water as an afterthoughtjust a few short years ago.

It is in the best interest of any company to considerthe natural environment when operating on site, but

these process improvements often require investment especially in areas like water treatment, where spentwater is now being disposed.

A common myth among detractors is that oil andgas companies rarely invest money in protecting theenvironment. Experts, however, disagree. The indus-try is getting safer and safer, said Todd Perry, princi-pal and senior geologist, PPM Consultants. The USproduces around 5.6 MMbbl/d of oil and 75.4 Bcf/dof gas with an annual spill incident rate of less than0.01%. This success is due in large part to the nearly

US $5 billion per year spent by the industry tostay in compliance with regulations,

Perry said.The fact is that companies are

realizing real profit by minimiz-ing their exposure to environ-

mental risk. Simple improvementssuch as pad drilling, unifying water

management systems, reclaim-ing and reusing water, andperforming these tasks onlocation are all contributing

to the bottom line.Perry quoted legendary

brewer Peter Coors as saying,Find pollution or waste and you

have found something you paid forbut cant sell. Youve found ineffi-

ciency Fundamentally allpollution is lost profit.

This comment speaks to thecore of production issues,Perry said.

Pollution is lost profitTechnology toes the line between environmental stewardship andprofitability in todays shale gas industry.

Read more commentary at

EPmag.com

TAYVIS DUNNAHOESenior Editor

[email protected]



29/91

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Gearing up

for 2012Five industry experts predictthe advances and innovations

expected in the coming year.

Technology is the mainstay of theoil and gas industry, so it is no surprise thatR&D budgets continue to be heavily funded in 2012.

Most of the dollars going into technology develop-

ment will target subsea, automation, floating produc-

tion innovation, and unconventionals.

With the rapid escalation in shale development

and the growing interest in unconventional oil and

gas, it is a fair guess that 2012 will bring with it a con-

tinued industry focus on developing technologies

around hydraulic fracturing, horizontal drilling and

completions, reservoir monitoring, and water treat-ment. Shale gas reserves are so enormous that they

are likely to be the focus of E&P activity for decades.

While onshore shale developments gain ground,

the fact remains that 30% of the worlds oil is pro-

duced from offshore wells. According to Infield Sys-

tems, although the shallow-water sector is dominant

today, the global deepwater market is the fastest

growing sector of the offshore oil and gas industry,

with subsea technology and floating production the

biggest contributors to growth.

Deep water will see US $225 billion in investmentfrom 2011 through 2015 according to Douglas-

Westwood, whose analysts predict a significant

portion of the capex will go to presalt developments

offshore Brazil, subsea installations, and floating

production installations.

The future will bring with it new approaches to

recruiting and higher investment in employee reten-

tion. Collaboration will become more important,

with additional remote monitoring centers being

established as operations move into more remote

and harsh environments. And continued changeswill take place in the ways people communicate,

with social networking tools growing in popularity

and application.

In general terms, it is risky to make a forecast, but

this did not deter members of the E&PAdvisory Board

from accepting the challenge of making predictions

about where the oil and gas industry is going as a

new year approaches.

The pages that follow contain their take on what is

in store for the E&P industry in 2012.


32/91

Automation is thename of the gameNo longer constrained to drillpipe-handling,automation is poised to pervade every facet

of well construction and production.

The future of the E&P industry may benefit from a wave

of fresh thinking regarding the role of automation.

Why? The answer is better control of oilfield operations.

Individuals with vision have already determined that

many oilfield tasks can be done repeatedly and reliably

by automated systems. This does not mean drilling rigs

are going to resemble automobile assembly lines staffed

with robots that perform all well construction tasks.

However, success with automated pipe-handling tools

has spurred engineers to examine every aspect of well

construction to see where automation makes sense.And the result is surprising.

Where automation worksMany oilfield well construction operations are repetitive.

Since the vast majority of well construction tasks are

well understood, a worker who is relieved of personally

supervising every single task can address extremely

complex operations by using sensors to measure all key

parameters of the task, only acting when alerted to an

exception. Taking this idea one step forward, it is easy to

imagine how judicious measurement of dynamic param-

eters can lead to the ability to predict problems beforethey occur simply by monitoring trends and noting devi-

ations from the acceptable performance envelope.

This was the subject of the Drilling Systems Automa-

tion Technology (DSAT) workshop conducted at the

Society of Petroleum Engineers Annual Technical Con-

ference and Exhibition held recently in Denver, Colo.

Representatives of operating companies, as well as

service and supply companies, presented tasks being

automated today along with their ideas of what might be

automated in the future. An analogy from the aviation

industry illustrated how much initial pilot training is

performed using sophisticated simulators for each type

of aircraft in the fleet and able to create a realistic simu-

lation of any type of in-flight emergency.A Weatherford engineer kicked off the discussion

with a plan to add quality and repeatability to reentry

jobs. Using tools and personnel available today, simula-

tors have been deployed worldwide to train field crews.

Since many dynamic parameters occurring during reen-

try are presented simultaneously, field crews can be over-

whelmed with information. When the majority of tasks

are automated, however, the eyes of the crew can be

focused continuously on the remaining critical items,

ensuring those things are addressed correctly.

A representative from Baker Hughes explained how,

through automation, production packers can be safelyand correctly deployed in the most high-profile wells

offshore Sakhalin Island, Siberia. Technology that uses

an air hammer is used to communicate with downhole

tools by knocking in code on the tubulars at the surface.

This technique is particularly effective when operating

in long lateral sections where other means of communi-

cating with the completion string are impaired.

A presenter from Halliburton revealed several exam-

ples where automation has been successful in improving

efficiency and quality of downhole operations. Starting

with real-time operations centers (RTOC), the company

can perform increasingly complex tasks with fewer peo-ple. Through concentration of expertise, the RTOCs

allow the company to concentrate the most experienced

technical minds to each challenge, while simultaneously

providing a rich, experiential, risk-free training environ-

ment in which to develop new talent. Halliburton is con-

sidering bringing automation to MPD, running and

testing completions, well cementing operations, and

stimulation treatments.

The speakers agreed that downhole tool modeling

and automating must be done under downhole condi-

tions to be successful. And all of the participants agreed

that unless great care is taken, measurements can givefalse positive results, completely negating any advantage

gained from automation.

Schlumbergers presentation focused on examples of

how the company studies a job by breaking down each

task and considering it for potential automation. The

first example was automated handling of perforating

guns at the surface. It is standard practice today to clear

the drill floors red zone when arming a gun, but new

techniques create a safer environment through automa-

tion of arming, deploying, and disarming guns without

human intervention.


COVER STORY:

EXPERTS PREDICT

Industry ExpertDick Ghiselin, P.E.



Schlumberger also is studying intelligent well services

with the goal of automating them, particularly while

running in the completion string simultaneously with

control lines and electrical conductors. Sand controlmedia deployment also is under consideration for some

automation. Control of fluid, unexpected fluid loss or

influx, and equivalent circulating density are being stud-

ied as well.

In addition, a new initiative that enables logging-while-

producing is under way. Different from the familiar pro-

duction logging tool strings, this procedure uses robustaccurate downhole temperature and pressure gauges.

According to Schlumberger, the possibilities are endless

for achieving improved efficiency through automating

key tasks without jeopardizing operational integrity or

safety. The company has identified many automationapps that can be introduced just like the popular

smart-phone apps.

Introducing a back to the basics approach, Shell says

it can eliminate such rig icons as the Marsh Funnel and

the mud balance by introducing continuous measure-

ments of mud properties that can instantly indicate a

downhole influx or fluid loss. In addition, eliminating

drill bit vibration could significantly improve drilling

efficiency and bit longevity.

Intelligence improves efficiency

Wrapping up the conference, Chairman John DeWardttalked about a recent project where the act of driving a

downhole milling operation using a variable speed drive

enabled the operator to smooth out the operation, mak-

ing a 50% improvement in milling efficiency. DeWardt

said the industry needs to determine what can be doneto deploy effective automation tools and techniques and

when they can be reasonably implemented. Some of the

critical items to be decided include:

The human factor how much can we automate

without incurring risk?

What constitutes acceptable risk in our industry?

What will be the perceived value of automation byeach stakeholder?

What is the implication of variable drivers? Should

we strive for a perfect solution for one well or a less

than perfect solution that fits all wells?

This conjures up a vision of the automated rig of thefuture that is allegedly populated by two creatures a

human and a dog. The dogs role was to keep the human

from touching anything, and the humans role was to

feed the dog. Humorous perhaps, but the consensus of

the participants in the 2011 DSAT was clear automation

is coming, and those adopting it will benefit from greatly

improved operating efficiency and safety, which will be

achieved by focusing workers attention on the excep-

tions while the robots take care of the routine tasks.

COVER STORY:

EXPERTS PREDICT

Although drilling operations are unlikely ever to resemble assem-

bly line operations, many drilling activities will be automated in

the near future.


34/91

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38/91EPmag.com | December 2011 37

subject matter experts across many wells or fields.Real-time support tools also play a role in improving

drilling efficiency. The tools can be used to update

predrill models as new information becomes available,such as models for hydraulics, torque and drag, or porepressure. Artificial intelligence tools also are being usedto increase predictability and diagnosis of upcominghazards. Statistical tools are being employed to improveoperations efficiency, such as the time required to makea trip or make a connection.

Recent technical papers prove this approach is payingdividends. In an SPE paper presented earlier this year, theauthors demonstrated how techniques dependent on real-time decision-making facilitated the reduction in days todepth for developing areas in land drilling. Another paper

discussed how real-time technologies are supporting largescale-drilling operations that use mature commercialproducts built on the WITSML standard.

The final hurdleDespite the successes, the final hurdle for ensuringeffective real-time decision-making is cultural change.

Using real-time technologies can greatly shorten thetraining time for new engineers by exposing themto simultaneous drilling operations from a numberof rigs. And it can leverage the experience of scarcesubject matter experts across many wells or fields.But unless this new way of making decisions isembraced both in the office and at the well site,the initiative will fail.

As the use of real-time technologies grows, the advan-tages it brings are becoming evident. Collaboration hasresulted in lower costs, intelligent solutions, increasedefficiency, and improved drilling performance. This

shift in the industry will continue as more companiesembrace this use of technology.

COVER STORY:

EXPERTS PREDICT

Unconventionalresources moveto center stageUnconventional resource development couldrevitalize the US economy.

O

ver the last 30 years, US petroleum imports have

grown from less than 30% of consumption toalmost 60%, with imported petroleum products totalingUS $252 billion in 2010. Petroleum imports account forabout half of the US trade deficit. Booming productionfrom unconventional resources has the potential to dra-matically improve the balance of trade, strengthen the USdollar, and create jobs. Just as oil from the North Seahelped pull Britain out of the deep recession of the early1970s, production from unconventional tight resourcescould promote an economic renaissance in the US.

When I was evaluating natural gas markets for Mobilin the 1990s, the US was viewed as an unattractive mar-

ket because of the persistent gas bubble and associatedlow prices. In the early part of the last decade, after thegas bubble burst, companies were competing to get per-mission to build LNG receiving terminals in the US (oreven in Mexico with the goal of pipelining the gas toCalifornia).

How times have changed!I heard recently that the shale gas boom and the asso-

ciated collapse in US natural gas price has led one com-pany to consider building a liquefaction terminal in theUS to export natural gas to markets where the gas pricesare higher.

Impact on peopleShale gas and its liquid equivalent, shale oil/tight oil,are dramatically changing the business environment. Anew trend is emerging with majors opening large newoffices outside of Houston, closer to the gas shale and

tight oil plays. And a greater diversity of work locationsis just a tiny slice of the significant changes that willresult from the unconventional plays.

If hydraulic fracturing with water remains an essentialcomponent of these unconventional plays, operators willneed to provide full life cycle water management. Waterusage and disposal has generated widespread commu-nity concerns. If water cannot be recycled, there aremany potential sources of friction with local communi-ties. The large volumes of water needed could impactother water users in the system. Disposal also is fraughtwith issues.

Industry Expert

Eve Sprunt2006 President of the

Society of Petroleum Engineers



People who do not benefit directly from the new activity

will be susceptible to manipulation by groups that object

to all forms of extraction and use of fossil fuels. To secure

work permits, oil and gas companies could find them-selves engaging in considerably more public outreach andeducation than ever before. One thing that particularly

irritates those who oppose the oil and gas industry is that

these new plays lower the price of oil and gas making it

harder for alternative energy supplies to compete.

A change in technology, workforceSeismic technology is the workhorse for determining sub-

surface structures and delineating traps. Geochemists

provide guidance on source material and source rock

maturation. But no one ever really thought about how

the hydrocarbons migrated out of the impermeableshale source rocks to fill the reservoirs. Subsurface

expertise is essential in extending unconventional

resource play concepts to new geographic regions and

new formations. In shale gas and tight oil plays the search

is not so much for structures as sweet spots. Part of the

challenge is that it is not clear which attributes are most

critical for economic production using current technol-

ogy. Earth scientists and petroleum engineers must assessa large number of poorly understood factors. While there

may be sufficient information about a few of these playsto develop them manufacturing style, identifying new

plays requires a broad experience. The demand for sea-

soned subsurface experts comes just as the big crew

change is under way. This is not a case of training the

new recruits on how to do things, but rather having peo-

ple with the experience to develop new methodologies.

Worldwide, companies are scrambling to quickly assess

vast areas. Some non-seismic sensing technologies may

emerge to join seismology as standard components of

the explorationists tool kit.Gas shale and tight oil plays have brought petroleum

industry operations to new areas around the world and

reinvigorated production in other areas. As shale devel-

opment expands, it will elicit even more change.

COVER STORY:

EXPERTS PREDICT

Challengingenvironmentswill demandbetter contract

managementContracts refine focus on risk, particularly

for high-cost deepwater projects.

The oil and gas industry is still recovering from the

greatest global economic shock of more than 75

years. While a mood of cautious optimism has emerged,

economic uncertainty remains. In todays business envi-

ronment, conditions remain challenging for many, and

managing risk remains at the top of every organizations

agenda. The industry should expect a renewed and

expanded regulatory focus on safety and environmental

risk preparedness and mitigation. This will only high-

light the need for companies to be more vigilant in

anticipating threats and managing todays business risks.

In such an environment, prudent risk managementpractices will necessitate additional management

scrutiny for critical contract issues and practices.

Managing and determining riskContract risk can be managed and mitigated to a large

degree with proper planning. Preplanning is vital to a

successful project and becomes increasingly important

as projects get bigger and more complex. The oil and

gas industry must properly preplan high-cost develop-

ments, and a solid execution strategy is absolutely neces-

sary to mitigate the many risks associated with executing

complex megaprojects or billion-dollar projects withmultiple interfaces and significant challenges.

Preplanning means performing activities such as the

conceptual, pre-FEED, and FEED phases of a project that

deliver significant benefit-to-cost results. These activities

ensure solid strategies are created for the execute or

EPCI (Engineer, Procure, Construct, and Install) phase,

allowing projects to proceed according to plan and to

achieve budget, schedule, and performance goals.

With poor preplanning, projects tend to move prema-

turely into the execute phase, putting all goals at risk.

Projects cannot get it right by starting with a poorly

Industry Expert

Christopher M. Barton

KBR


40/91



amount that bears some relationship to the contractors

gross margin on the project.

Contractors will accept certain carve-outs from a total

liability cap; these carve-outs are typically limited to lia-bilities covered by project insurance, but uncapped lia-

bilities are not acceptable to most prudent contractors.

Indemnities are another issue. Contractor indemnities

must be limited to the life of the construction project

plus one or two years and limited to:

Third-party personal injury and death caused by the

contractors negligence or fault;

Intellectual property infringement resulting from

services or materials supplied by the contractor;

Payment of employee compensation and payroll

taxes;

Subcontractor and supplier liens provided the con-tractor has been paid by the customer; and

Fines and penalties for violations of law.

Contractors are not insurance companies and can

only be expected to provide indemnification with

respect to matters within their control.

Where risk of loss is concerned, contractors want to

assume only risks they can control and manage, prefer-

ring to limit liability for physical loss or damage during

construction either to the proceeds of the customers

all-risk insurance above some reasonable deductible or,

alternatively, for the contractor to

furnish t

revista e&p - diciembre 2011

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