Winter 2012/2013

Downhole Debris Recovery

Asphaltene Science

Fishing Techniques

Carbon Capture and Storage

Oilfield Review

13-OR-0001

Widely recognized in some quarters as a means to reduce carbon dioxide [CO2] emissions to the atmosphere, the practice of carbon capture, utilization and storage remains largely unfamiliar to the general public. The utilization component of the technology is familiar to those who have worked in enhanced oil recovery (EOR) operations, but the concept of deep-well injection and storage of dense-phase CO2 is unknown to many regulators, elected officials and the population at large. In addition, these practices pres-ent many unanswered questions, including those address-ing how such practices affect the environment and personal property or whether current understanding of the science also predicts future CO2 storage behavior.

As a consequence, the road to popular acceptance and widespread use of carbon capture and storage (CCS), inde-pendent of the oil field, requires that demonstration field tests be performed over time. It is also imperative that findings from those tests be presented honestly and clearly to the community. Proving the capacity for safe CO2 stor-age and containment and the effectiveness of geologic res-ervoirs and seals may be accomplished through the development of test projects that are scalable to the vol-umes of CO2 emitted from commercial power plants. Early projects such as those in Japan, Germany and Australia injected up to about 100,000 metric tons [110,000 tonUS] of CO2 using truck or pipeline delivery.

However, larger demonstration projects require pipeline delivery of CO2 to an injection well at rates of about 0.25 to 1 million metric tons [0.28 to 1.1 million tonUS] or more per year. The objective of these larger projects is to create a CO2 plume in a target formation that may be monitored effectively through well logging, chemical sampling, pres-sure and temperature monitoring, geophysical surveying and other means.

In the US, the US Environmental Protection Agency under the Underground Injection Control program, is pro-mulgating regulations and associated guidance for the new Class VI operational classification. The US Department of Energy has had a program of multiple field tests and dem-onstrations in place since 2003 under the Regional Carbon Sequestration Partnership program, with several demon-stration projects currently underway, including the 1 mil-lion metric ton demonstration at Decatur, Illinois, USA, described in this issue (see “CO2 Sequestration—One Response to Emissions,” page 36).

Regional geologic screening followed by careful site characterization and selection constitute the foundation of safe and effective CO2 storage. The objectives in this explo-ration process are to find a porous and permeable reservoir and a competent reservoir seal. Geophysical tools provide

The Future of CCS

1

the initial look at a subsurface volume, while drilling, logging and coring confirm expectations of a suitable reservoir-seal system.

Project operators and technical staff members have gained considerable knowledge from the demonstration projects underway today and have shared much of this knowledge through conferences and peer reviews. However, as regulators ask future-oriented questions about reservoir simulation, groundwater flow modeling and other predictive approaches, the industry will need a compre-hensive knowledge-sharing framework that will answer such questions and allow larger, commercial-scale projects to proceed.

The public also has a role in the future of CCS, but in some instances, project developers have not gained the community’s confidence. There is an ongoing need for open and complete communication with the general public in a way that understandably conveys the technical basis for CCS. This consideration should not be overlooked during project development and operation.

Although the portfolio of projects is not as diverse today as may have been envisioned five years ago, the next generation of projects—associated with hydrocar-bon production, power generation and natural gas pro-cessing—is being developed now. Implementation of CCS in saline reservoirs is still in its infancy, but the results to date are encouraging.

Oil and natural gas production industry technologies and the experience of its personnel are essential for the suc-cess of CO2 injection and storage projects. Successful dem-onstration projects will apply and even advance oilfield industry technologies, and knowledge acquired during project development and ongoing monitoring must be transparent to the public. This transparency will gain the confidence of stakeholders outside the industry and is key to ensuring the popular understanding that CCS is a viable tool for climate change mitigation.

Robert J. FinleyDirector, Advanced Energy Technology InitiativeIllinois State Geological SurveyChampaign, Illinois, USA

Robert J. Finley is a Director of the Advanced Energy Technology Initiative with the Illinois State Geological Survey in Champaign, Illinois, USA. He has worked in reservoir development for unrecovered oil and natural gas, with coalbed methane and tight gas sandstone reservoir development in Texas and the Rocky Mountains in the US and in reservoir development for carbon sequestration in the Illinois basin. Robert earned a BS degree from City University of New York, an MS degree from Syracuse University, New York, USA, and a PhD degree in geology from the University of South Carolina, Columbia, USA.

www.slb.com/oilfieldreview

Schlumberger

Oilfield Review

1 The Future of CCS

Editorial contributed by Robert J. Finley, Director, Advanced Energy Technology Initiative, Illinois State Geological Survey

4 Specialized Tools for Wellbore Debris Recovery

Wellbore completion operations often generate downhole debris, including sand, perforating gun residue and metal particulates. In addition, drillers frequently discover assorted nuts, bolts, tools and other materials that have been acciden-tally dropped in the wellbore. Unless these materials are removed, optimal well productivity may be compromised. This article describes new tools and techniques for efficient wellbore debris recovery.

14 Revealing Reservoir Secrets Through Asphaltene Science

By combining downhole fluid analysis with advances in asphaltene science, oil companies are gaining a better understanding of reservoir architecture. Downhole analysis of asphaltenes—the heaviest components of petroleum—can help geoscientists determine asphaltene concentration gradients, which in turn, can help operators ascertain the presence of sealing barriers and assess the communication and equilibrium of fluids in complex reservoirs. Examples from the Gulf of Mexico and the Middle East show how com-panies are using asphaltene gradient techniques to learn more about reservoir connectivity and fluid distribution.

Executive EditorLisa Stewart

Senior EditorsTony SmithsonMatt VarhaugRick von Flatern

EditorRichard Nolen-Hoeksema

Contributing EditorsDavid AllanGinger OppenheimerRana RottenbergDon Williamson

Design/ProductionHerring DesignMike Messinger

Illustration Chris LockwoodTom McNeffMike MessingerGeorge Stewart

PrintingRR Donnelley—Wetmore PlantCurtis Weeks

Oilfield Review is published quarterly and printed in the USA.

Visit www.slb.com/oilfieldreview for electronic copies of articles in English, Spanish, Chinese and Russian.

© 2013 Schlumberger. All rights reserved. Reproductions without permission are strictly prohibited.

For a comprehensive dictionary of oilfield terms, see the Schlumberger Oilfield Glossary at www.glossary.oilfield.slb.com.

About Oilfield ReviewOilfield Review, a Schlumberger journal, communicates technical advances in finding and producing hydrocarbons to employees, customers and other oilfield professionals. Contributors to articles include industry professionals and experts from around the world; those listed with only geographic location are employees of Schlumberger or its affiliates.

On the cover:

Carbon sequestration is one approach to managing greenhouse gas emissions. Here, a derrickman handles drillpipe as a rig captures cores of the Maquoketa Shale in Illinois, USA. The shale is a containment barrier within the Illinois Basin–Decatur Project carbon sequestra-tion verification well. During construction of a verification well in the nearby Illinois Basin Carbon Capture and Sequestration project (small inset), all casing strings are cemented to the surface. Verification wells are equipped with monitoring systems to track carbon dioxide as it is being injected underground during carbon sequestration operations. Rig photographs by Daniel Byers for the Midwest Geological Sequestration Consortium.

2

Winter 2012/2013Volume 24Number 4

ISSN 0923-1730

49 Contributors

51 Coming in Oilfield Review

52 New Books

54 Defining Testing: Well Testing Fundamentals

This is the eighth in a series of introductory articles describing basic concepts of the E&P industry.

56 Annual Index

3

26 Landing the Big One—The Art of Fishing

Second only to blowouts, one of the worst situations a driller may encounter is the loss of equipment downhole. Fishing—the art of recovering lost, damaged or stuck objects from the borehole—draws on the experience, imagination and innovation of the fishing expert. This article describes tools and strategies developed for dealing with items lost in the wellbore.

36 CO2 Sequestration—One Response to Emissions

One response to concerns that human activity is influencing climate has been to remove the CO2 from emissions created when carbon-based fuels are burned and sequester it deep underground. Upstream oil industry experts are uniquely qualified to manage the selection, construction and monitor-ing of these complex injection projects.

Hani Elshahawi Shell Exploration and Production Houston, Texas, USA

Gretchen M. Gillis Aramco Services Company Houston, Texas

Roland Hamp Woodside Energy Ltd. Perth, Australia

Dilip M. Kale ONGC Energy Centre Delhi, India

George King Apache Corporation Houston, Texas

Advisory Panel

Editorial correspondenceOilfield Review 5599 San FelipeHouston, TX 77056United States(1) 713-513-1194Fax: (1) 713-513-2057E-mail: editorOilfieldReview@slb.com

SubscriptionsCustomer subscriptions can be obtained through any Schlumberger sales office. Paid subscriptions are available fromOilfield Review ServicesPear Tree Cottage, Kelsall RoadAshton Hayes, Chester CH3 8BHUnited KingdomE-mail: subscriptions@oilfieldreview.com

Distribution inquiriesTony SmithsonOilfield Review12149 Lakeview Manor Dr.Northport, AL 35475-3850United States(1) 832-886-5217Fax: (1) 281-285-0065E-mail: DistributionOR@slb.com

Oilfield Review is pleased to welcome Hani Elshahawi to its editorial advisory panel. Hani is Deepwater Technology Advisor at Shell in Houston. Previously, he led FEAST, Shell’s Fluid Evaluation and Sampling Technologies Center of Excellence, where he was responsible for the planning, execution and analysis of global high-profile formation testing and fluid sampling operations. With more than 25 years of experience in the oil industry, he has worked in both service and operating companies in more than 10 countries in Africa, Asia, the Middle East and North America and has held various positions in interpretation, consulting, operations, marketing and product development. Hani has lectured widely in various areas of petrophysics, geosci-ences and petroleum engineering, holds several patents and has written more than 100 technical papers. He was the 2009–2010 president of the SPWLA and a distinguished lecturer in 2010 and 2011. Hani attained a BS degree in mechanical engineering and an MS degree in petroleum engineering from The University of Texas at Austin.

4 Oilfield Review4 Oilfield Review

Specialized Tools for Wellbore Debris Recovery

In the late 1700s, Giovanni Battista Venturi, an Italian physicist, described a

reduction in pressure when fluid flows through a restriction. Now, engineers

are using this principle to design specialized wellbore cleaning systems capable

of performing critical debris recovery operations in some of the world’s most

challenging subsurface environments.

Brian CollGraeme LawsM-I SWACOAberdeen, Scotland

Julie JeanpertRavenna, Italy

Marco SportelliEni SpA E&P DivisionRavenna, Italy

Charles SvobodaMark TrimbleM-I SWACOHouston, Texas, USA

Oilfield Review Winter 2012/2013: 24, no. 4. Copyright © 2013 Schlumberger.For help in preparation of this article, thanks to Kenneth Simpkins, M-I SWACO, Houston.FRAC-N-PAC, PURE and QUANTUM are marks of Schlumberger. HEAVY DUTY RAZOR BACK CCT, MAGNOSTAR, RIDGE BACK BURR MILL, WELL PATROLLER and WELL SCAVENGER are marks of M-I SWACO LLC.

Debris removal is a vital step in assuring the suc-cess of drilling or completion operations. Debris removal involves the extraction of “junk” and unwanted materials from a borehole or com-pleted wellbore. Junk typically consists of small pieces of downhole tools, bit cones, hand tools, wireline, chain, metal cuttings from milling oper-ations and an array of other debris. Although not generally considered junk, sand and other mate-rials used during completion, stimulation and production operations often require removal from the wellbore prior to production.

Because there are many types of debris, engi-neers have developed a variety of tools and tech-niques to facilitate debris removal from a wellbore. This article focuses on the postdrilling phase of well construction and issues related to ridding the borehole of relatively small fragments of debris such as metal cuttings, perforating gun debris, small hardware and sand. The article begins with a discussion on the sources of small debris and then reviews various techniques avail-able to remove these materials from the wellbore. Case studies demonstrate how operators are applying these new technologies in a variety of completion environments to reduce risks, mini-mize downtime and improve well productivity.

Sources of Small DebrisThe drill floor is a busy place, providing numer-ous opportunities for small items to inadvertently fall into an open hole. In deepwater operations, the surface opening at the riser pipe may have a diameter of 1 m [3 ft], creating opportunities for larger items to fall to the depths.

Debris is also generated downhole by various well operations. Often, drillers must mill hard-ware such as packers, liner tops and equipment within the wellbore (above).1 Metal cuttings from these operations are among the most common type of debris found downhole. Circulation of drilling, milling or completion fluid transports much of the metal debris to the surface. However, some metal cuttings may still be left in the hole, frequently in locations that cause problems dur-ing the completion or production process.2

1. Milling is the process of using a downhole tool to cut, grind and remove material from equipment or tools in the wellbore. Successful milling operations require selection of milling tools, fluids and techniques that are compatible with the fish materials and wellbore conditions.

2. Connell P and Haughton DB: “Removal of Debris from Deepwater Wellbores Using Vectored Annulus Cleaning Systems Reduces Problems and Saves Rig Time,” paper SPE 96440, presented at the SPE Annual Technical Conference and Exhibition, Dallas, October 9–12, 2005.

> Typical junk mill. Junk mills are designed to grind any type of material encountered downhole, including bit cones, drillpipe, bridge plugs or other objects. Wear pads provide stabilization while the mill is grinding. Drillers deploy a variety of grinding faces or tool configurations, depending on the type of material to be milled.

Wear pad

Grinding face

Winter 2012/2013 5Winter 2012/2013 5

6 Oilfield Review

During well completion, cased wells may be perforated using an array of specialized explo-sive charges mounted on perforating guns. When perforating guns are fired, shaped charges pierce the casing, cement sheath and formation. A shot density of 33 shots/m [10 shots/ft] across a producing zone may create hundreds of perfo-ration tunnels; this perforation process gener-ates a considerable amount of metal and formation debris that needs to be cleared from the wellbore.

Historically, fragments from explosive charges, the casing, the cement and the forma-tion were left in perforation tunnels, which may cause a reduction in production efficiency. Postperforation analysis often showed that many perforation tunnels were plugged and nonpro-ductive. Developments in perforating technol-ogy, such as the PURE perforating system for clean perforations, in conjunction with shaped charges that generate minimal debris, allow engineers to reduce this type of perforation tun-nel damage.3 Although less debris remains in the perforation tunnels using these techniques, more debris may be deposited in the wellbore, potentially fouling latching mechanisms on retrievable bridge plugs or impeding the perfor-mance of completion hardware.

Certain materials are sometimes deliber-ately introduced into the wellbore, only to be removed during subsequent cleanout opera-tions. Stimulation operations typically use sand to cover the top of temporary packers and open perforations to protect them from damage while drillers work in other locations within the well-bore (left). Once these operations are complete, the sand must be removed before production can commence. Other stimulation activities, such as those used in conjunction with the FRAC-N-PAC proppant exclusion system, inten-tionally place sand and synthetic proppant in the wellbore to aid production.4 In all cases, excess sand and proppant must be removed prior to producing a well.

Regardless of precautions taken to keep a wellbore and associated production equipment free of debris, unwanted materials often find their way to problematic locations and increase the risk of damaging completion equipment, reducing production efficiency and jeopardizing the long-term viability of a well.5

Complexity of DesignOil and gas wells are becoming more complex and expensive to construct. To drill wells char-acterized by remote locations, deepwater set-tings or great drilling depths, operational spread rates often reach US$ 1 million per day. In the face of such increasing complexities and to hold costs down, operators must make criti-cal drilling and completion decisions. Risk analy-sis costs, as a result, are now considered on a per minute basis, rather than per day.

With wellbore geometries and completion designs becoming increasingly sophisticated, engineers recognize that risk management, improved efficiency and optimized production may require removal of debris that might have once been considered inconsequential. Even small amounts of debris have the potential to limit production and cause completion failure. Junk and small debris may create difficulties when operators run long and complex comple-tion assemblies in deep and deviated wellbores. In advanced completion designs—such as those with production sleeves that selectively isolate producing intervals—small debris, including metal fragments and sand, may plug or other-wise render production sleeves difficult to access or operate.

Wells with tortuous trajectories are hard to clean using conventional methods. Determining optimal circulation rates is difficult when engi-neers must consider varying deviation, equivalent circulating density (ECD) limitations, telescop-ing casing sizes and pump capacity limitations (next page, top left). Even modest circulation rates, in combination with viscous fluids, risk lost circulation from elevated ECDs. These complex well environments demand new approaches.

3. Bersås K, Stenhaug M, Doornbosch F, Langseth B, Fimreite H and Parrott B: “Perforations on Target,” Oilfield Review 16, no. 1 (Spring 2004): 28–37.

4. Gadiyar B, Meese C, Stimatz G, Morales H, Piedras J, Profinet J and Watson G: “Optimizing Frac Packs,” Oilfield Review 16, no. 3 (Autumn 2004): 18–29.

5. Haughton DB and Connell P: “Reliable and Effective Downhole Cleaning System for Debris and Junk Removal,” paper SPE 101727, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Adelaide, South Australia, Australia, September 11–13, 2006.

6. Visual Physics, School of Physics, University of Sydney, Australia: “Fluid Flow, Ideal Fluid, Bernoulli’s Principle,” http://www.physics.usyd.edu.au/teach_res/jp/fluids/flow3.pdf (accessed September 16, 2012).

> Protecting open perforations. To isolate open perforations, which may be damaged by debris from ongoing well operations in zones above the perforations, drillers place sand on top of a temporary packer. After operations in the upper zone are completed, the sand and debris from uphole are removed from the top of the packer; the packer is then released and retrieved from the wellbore.

Perforating gun

New perforations

Sand

Temporary packer

Openperforations

Winter 2012/2013 7

Old Concept—New ApplicationOne approach to overcoming the risks of high circulation rates—the venturi vacuum—has existed for centuries. In the late 1700s, Giovanni Battista Venturi, an Italian physicist, described the effect that came to be named after him. He and Daniel Bernoulli, a Swiss mathematician who worked in fluid mechanics, are known for discoveries that led to the development of the

venturi vacuum pump. Engineers and develop-ers have used the venturi vacuum pump design in many applications, from fluid mixing systems to health care and home maintenance equip-ment such as the common garden hose sprayer. Today, engineers are applying this fundamental principle—the venturi effect—to design spe-cialized wellbore cleaning systems capable of performing debris removal operations in diffi-cult subsurface environments.

The venturi effect can be described as a jet-induced vacuum. The laws of fluid dynamics described by Venturi and Bernoulli dictate that flow velocity increases with a constriction of the flow path diameter, satisfying the principle of continuity, while a corresponding decrease in pressure occurs, satisfying the principle of con-servation of mechanical energy. A concurrent drop in localized static pressure creates a vac-uum (above).6

Venturi vacuum systems have numerous advantages over conventional mechanical pumps. Conventional mechanical vacuum systems typi-cally have moving parts that can be troublesome: Valves may become stuck, intake filters may become clogged and motors are subject to failure. Venturi pumps, by contrast, have few or no moving parts and thus require little maintenance.

Debris from the DeepRecently, engineers have used venturi vacuum pumps to remove debris from difficult-to-reach and problematic areas of wellbores. Multiple designs have been developed, each with unique features to meet an array of operational require-ments. Several service companies, including M-I SWACO, a Schlumberger company, offer downhole debris recovery tools based on the ven-turi effect; some are configured to be used on coiled tubing and others to be used on conven-tional workstrings.

The WELL SCAVENGER tool offers a modular design that provides application flexibility. The upper module contains a single-nozzle fluid-driven engine designed on the venturi principle. Pressure from surface pumps generates an effi-cient, localized reverse-circulation flow that achieves optimal lifting velocities without high

, Annular flow rate and cleaning capacity. Most wells use consecutive strings of casing, with each subsequent string smaller in diameter than the previous one, creating a telescoping effect. In offshore deepwater wells, multiple strings of casing are required to control subsurface pressure and formation stress. The ability to move debris from the bottom of the hole to the top by circulation alone is a function of the fluid’s carrying capacity and is directly affected by the fluid’s annular velocity and viscoelastic properties. However, as the fluid moves uphole, its velocity slows with each increase in casing size and effective hydraulic diameter. This places greater demand on the viscosity characteristics of the fluid to carry debris. Compensating for loss of carrying capacity by increasing the viscosity or velocity of the carrier fluid may result in increased equivalent circulating density, which places greater hydraulic force on the formation and may promote lost circulation. Achieving satisfactory carrying capacity uphole while keeping the well within ECD limitations downhole is the driller’s challenge. Because of this problem, debris removal by conventional methods can be difficult.

36 in.

28 in.

22 in.

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Flow

Cement

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16 in.

135/8 in.

95/8 in.

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113/4 in.Incr

easi

ng h

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> Venturi effect. As fluid passes through a flow constriction at high velocity, it generates a localized pressure drop, thus creating suction, which can be harnessed to vacuum debris.

Fluidinput

Fluidoutput

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Suction

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8 Oilfield Review

Engine module

Debris-screening

module

Debriscollection

modules

Filtrationscreen

Low pressurearea generated bythe venturi effect

Jet

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down the tool

Reverseflow

Conventionalflow

Engine

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Debriscollection area

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pump rates. This reverse flow causes debris to flow up the inside the lower tubular and into the collection chambers before it reaches the ferrous collection chamber and then flows through the filtration screen (left). The basic three-module system can be augmented with an array of ancil-lary tools such as the MAGNOSTAR magnet assembly, WELL PATROLLER downhole filter tool, RIDGE BACK BURR MILL device and single action bypass sub (SABS) to expand the scope of work (next page).

Because debris removal tools are often deployed in brine fluids that inherently have lim-ited solids carrying capacity, conventional tech-niques typically require high circulation rates or viscous carrier fluids to lift debris into capturing baskets or chambers. These measures are not nec-essary with the WELL SCAVENGER tool. When perforations are open and subject to lost circula-tion or damage, when pressure sensitive downhole hardware is in place or when surface equipment limitations make it impossible to achieve high pump rates, the newer generation tools, such as the WELL SCAVENGER device, offer engineers a significant advantage. M-I SWACO engineers use proprietary flow regime software to determine the surface pump rate required to recover the expected debris without affecting downhole hard-ware or open perforations.

Depending on the volume of debris antici-pated, engineers configure one or more debris collection modules at the lower end of the work-string. Each module is designed with a debris col-lection area, a flow diverter and an inner flow tube equipped with an internal centralizer to provide strength and stability. The inner flow tube provides the path for the reverse flow, and the diverter encourages debris to fall out of the fluid and into the collection area as the fluid flows through each chamber.

The screening unit is fitted above the debris collection modules and below the engine. Fluid flows up through the tool, passes over a magnet assembly and then through a filter before exiting the tool. The screen and magnet assemblies are internally centralized for stability in deviated wells. After cleanup, or when the system becomes filled or plugged, the SABS tool can be opened, allowing higher annular circulation rates, which help clean residual debris located above the tool. The WELL SCAVENGER tool is able to remove a wide variety of debris types from wellbores, including milling debris, bit teeth and cones, sand, small hand tools and debris from perforat-ing guns.

>WELL SCAVENGER tool module configuration. Fluid flowing through the WELL SCAVENGER engine (top left) takes the following path: Fluid flowing from the surface through the jet (downward green arrow) generates a low-pressure zone. The vacuum effect resulting from this localized pressure drop causes fluid and debris to be pulled up through the WELL SCAVENGER tool and then through the center of the engine (upward red arrow). The fluid passes around the perimeter of the engine, reverses direction proximal to the jet (curved red arrows) and then flows out of the tool (black arrows). Upon exiting the tool, a portion of the fluid travels up the hole to the surface (upward green arrows), while the remainder travels back.

Prior to reaching the engine, debris-laden fluid passes through the lower collection chamber (right). Once inside the tool, moving debris interacts with the tool’s deflector elements, promoting settling into collection chambers. When one chamber is full, the debris flows to subsequent chambers. As debris-laden fluid passes up through the WELL SCAVENGER tool, not all debris settles in the collection chambers. Some debris passes on to the screening module, where a magnet assembly attracts and collects ferrous materials; the fluid then passes through a filter that removes residual nonferrous materials.

Winter 2012/2013 9

At the surface, safe handling of the recovery tools loaded with debris is essential, especially when they have been exposed to zinc bromide and other completion fluids characterized by elevated HSE risks. To address these concerns, the WELL SCAVENGER tool modules are fitted with sealed lifting caps designed to contain recovered materials during tool extraction at the surface.

Sand and Gun Debris RemovalOperators typically set temporary bridge plugs above productive zones while performing opera-tions such as reperforating upper zones. In addi-tion, sand or ceramic proppant is typically placed on top of temporary plugs to provide additional protection to upward facing latching mechanisms that release and retrieve the temporary plugs.

In 2011, Eni SpA used QUANTUM gravel-pack BA packer plugs to carry out multizone gravel-pack completion operations in a series of wells in the Adriatic Sea offshore Italy. After the plugs were set, drillers spotted sand on top of each one to protect the plugs from gun and formation debris generated while perforating the zone above. On completion of perforating operations,

>Wellbore cleanup tools. The MAGNOSTAR tool is a magnet assembly that collects ferrous debris as the debris stream passes the tool. The vanes on the magnet assembly housing create a flow area for fluid bypass around the tool while providing standoff from the casing wall. The WELL PATROLLER tool is a downhole filter device that runs in the cleanup string. This device helps clean the wellbore when running in the hole. The tool then filters any remaining debris from the annulus through a wire screen filter as the assembly is pulled from the hole. The RIDGE BACK BURR MILL tool is a casing cleanup tool for perforated casing or liners. The tool removes perforation burrs to ensure unrestricted passage of completion equipment downhole. Users have the ability to turn off the RIDGE BACK BURR MILL after the milling and cleaning operation is complete. The driller circulates an actuation ball down to the tool; the ball shifts an internal support sleeve to remove the expanding force on the milling ribs. The single action bypass sub (SABS) allows drillers to boost the flow velocity in a casing string above a liner or casing crossover. The tool is run in the hole with its circulating ports in the closed position (second from right). The driller drops an actuation ball to open the circulating ports (right). This action redirects and reverses fluid flow from down the toolstring to bypass the string, thus removing flow restrictions, allowing an increase in pump rate and establishing higher annular velocity. To close the ports, the driller drops a second actuation ball.

Fluidflowpath

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Ports closed Ports open

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10 Oilfield Review

the WELL SCAVENGER tool was run in the hole and successfully cleaned the sand and the gun debris from the top of each packer.

M-I SWACO engineers in Aberdeen worked with Schlumberger engineers in Ravenna, Italy, to carefully plan each completion. The operator used 1.3 g/cm3 [10.8 lbm/galUS] of calcium chloride [CaCl2] completion fluid in the wellbore and spotted 20 liters [5.3 galUS] of 2.7-g/cm3 [22.5-lbm/galUS] ceramic proppant on top of each temporary packer prior to perforating shal-lower zones. The first well, which was vertical, was perforated with 39 shots/m [12 shots/ft] (above).

After each zone was perforated, the driller ran a WELL SCAVENGER tool and washover shoe in the hole to remove excess ceramic proppant and clear the packer retrieval latching mechanism.

On the first run, the top of the debris was located with the WELL SCAVENGER tool; no cir-culation was initiated, thus allowing the wash-over shoe to slide over the debris and land on the

packer plug. The sand and debris were success-fully removed and the temporary plug retrieved without incident. However, to reduce the risk of the tool becoming stuck in the sand or damaging the packer, engineers chose to initiate circula-tion approximately 30 m [100 ft] above the antici-pated top of the sand pill on future runs.

In each well, after positioning the washover shoe on the packer plug, the driller circulated one and one-half to three annular volumes to assist in overall debris cleanout. The WELL SCAVENGER tool cleared each sand pill in an average of 25 minutes. Based on total nonfer-rous debris recovery, 16 kg [35 lbm] wet weight, or approximately 65% of the ceramic sand, was pumped through the filter screen and out of the wellbore. Gun debris and larger sand particles were retained in the collection chambers, and ferrous materials were collected on the filter module magnet assembly (below). The crews handled, cleaned, inspected and prepared

debris chambers for rerun in subsequent bot-tomhole assemblies (BHAs).

Similar operations were conducted on two subsequent wells; the third well was deviated 24°. Using the WELL SCAVENGER tool, drillers successfully removed the sand and the gun debris in all 12 runs, allowing each packer to be retrieved without incident.

Debris in Pressure Sensitive Areas Accumulations of sand and other small debris on top of packers can make the packers difficult to retrieve. Similarly, these materials can inter-fere with the operation of other downhole mechanical hardware such as formation isolation valves (FIVs). Because these valves are pressure activated, debris removal techniques must ensure minimal localized pressure changes. The WELL SCAVENGER single-nozzle venturi engine provides debris removal at low circulation rates, thus minimizing pressure changes near an FIV. In a typical FIV cleanup operation, the BHA com-prises WELL SCAVENGER system components and one or more complementary wellbore cleanup tools such as the MAGNOSTAR tool and the WELL PATROLLER tool (next page, left).

In 2012, a major international operator in the UK sector of the North Sea planned a targeted cleanup above an FIV. Conventional tools that require high flow rates may cause problems when they clean the area near the FIV. These conditions increase the risk of accidental valve actuation or damage to components of the com-pletion assembly.

For optimal tool performance, the bullnose on the bottom of the WELL SCAVENGER tool should be placed 0.3 to 1 m [1 to 3 ft] above the FIV actu-ation ball. In this case, a 7 1/8-in. landing sub achieved this spacing, thus reducing the risk of damage to the FIV from accidental contact.

In this operation, the WELL SCAVENGER tool was run in the hole until the bullnose was approximately 6 m [20 ft] above the FIV actua-tion ball. The driller began pumping at a prede-termined rate of 4 bbl/min [0.6 m3/min] while slowly running the tool in the hole. When the bullnose was approximately 0.75 m [2.5 ft] above the FIV actuation ball, the engineer increased the pump rates slightly to 6 bbl/min [0.95 m3/min], which ensured optimal cleaning around the FIV ball area without risking damage to the downhole hardware.

After pumping for 30 minutes, the rig crew retrieved the tool to the surface. The debris cham-bers had collected a total of 11.8 kg [26 lbm] of

Depth, topZone Depth, base Zone length Shots

1,782 m [5,846 ft]1 1,794 m [5,886 ft] 12 m [39 ft] 472

1,640 m [5,381 ft]2 1,648 m [5,407 ft] 8 m [26 ft] 315

1,522 m [4,993 ft]3 1,546 m [5,072 ft] 24 m [79 ft] 964

1,471 m [4,826 ft]4 1,480 m [4,856 ft] 9 m [30 ft] 354

> Collecting wellbore debris in the Adriatic Sea. The WELL SCAVENGER magnet assembly attracts ferrous debris, which has circulated up through the WELL SCAVENGER tool (A). Ceramic debris (B) and perforating gun residue (C) were recovered from the debris collection chambers.

A B

C

> Intervals perforated in an Adriatic Sea well.

Winter 2012/2013 11

assorted nonferrous debris consisting mainly of sand and small pieces of rubber. Crews recovered an additional 0.91 kg [2 lbm] of ferrous debris from the internal magnet section of the tool.

The operator originally intended to operate the FIV within a relatively short period after cleanup. However, the well was temporarily sus-pended. Although final confirmation of cleanup cannot be verified until the valve is operated, the successful placement of the WELL SCAVENGER tool close to the FIV, combined with the amount of debris recovered, implied a successful opera-tion. The company intends to return to this well in the near future.

Gravel-packed wellbores, particularly those with low reservoir pressure and that are subject to lost circulation, may also be easily damaged by debris removal techniques. Sand and other small debris may accumulate inside the gravel-pack screens and impede production. In recompletion operations, operators often need to remove these materials from the inside of delicate screens to improve production rates.

For completion engineers, the inability to cir-culate completion brine in low-pressure reser-voirs limits debris recovery options. One of the unique features of the WELL SCAVENGER tool is its ability to recover downhole debris at low cir-culation rates, making it an ideal solution for these difficult applications.

This was precisely the situation in 2012, when an operator working on the North Slope of Alaska, USA, needed to recomplete an openhole gravel-packed well that began experiencing production declines. Engineers theorized that sand building up inside the gravel pack screens was choking off production. But when the well was reentered, low reservoir pressures resulted in loss of returns as workover crews attempted to circulate with 1.02-g/cm3 [8.5-lbm/galUS] filtered water. Engineers at M-I SWACO recommended cleaning the 9 5/8-in. casing to the top of the gravel-pack assembly at around 4,300 ft [1,300 m] and then running the WELL SCAVENGER assembly into the openhole gravel-pack assembly to clean out debris to a total depth of approximately 5,000 ft [1,500 m].

To protect the openhole gravel pack while cleaning and logging the upper 95/8-in. casing, a temporary packer was placed just above the lower completion assembly. Next, 1,000 lbm [454 kg] of sand was placed on top of the packer to protect the release mechanism from falling debris during upper casing cleanout. After the casing was cleaned and the well logged, the sand was circulated to the surface and the temporary packer was successfully retrieved.

The M-I SWACO crew ran WELL SCAVENGER tools in the hole at 3 ft/min [1 m/min] while pumping at 4 bbl/min [0.6 m3/min] (above). Surface pump rates were maintained at the low

> Configuring the WELL SCAVENGER tool for formation isolation valves debris removal. Tools may be configured to clean in sensitive areas near FIVs. In this case, a WELL PATROLLER tool, MAGNOSTAR magnet assembly and SABS tool were run above the WELL SCAVENGER tool to ensure debris removal from the wellbore. A no-go locator limits downward movement of the workstring into the completion assembly.

Debris collection chambers

SABS tool

Workstring

No-golocator

Wash pipe

Mule shoe

WELL PATROLLERtool

WELL SCAVENGERengine and debris-screening module

MAGNOSTARtool

> Cleaning the inside of gravel-pack screens. The WELL SCAVENGER assembly is configured to run inside gravel-pack screen assemblies. Four debris collection chambers and 21 joints of workstring are assembled below the engine; these components are small enough to be inserted inside the gravel-pack screen assembly. In this case, the engine and debris collection chambers sit above the top of the gravel-pack screens during debris removal. After the tool removes the debris, the driller pulls the tool assembly to the liner top and the SABS tool is opened, which allows increased annular circulation rates and ensures that any residual debris in the annular space is removed to the surface.

Workstring

SABS tool

Debris collection chambers

21 joints of workstring

Mule shoe

WELL SCAVENGERengine and debris-screening module

12 Oilfield Review

end of the tool’s optimal range, minimizing loss of returns. After the driller circulated down each stand, the pump rates were increased to 7 bbl/min [1.1 m3/min] for five minutes. The tool reached the targeted depth in one run. The workover crew

recovered 14.5 lbm [6.6 kg] of formation sand, rubber and metal debris from the gravel-pack screens (below). Following successful debris recovery from inside the gravel-pack screens, the operator continued well recompletion operations.

Milling Debris RemovalDrillers use milling techniques for various well operations such as cutting windows in casing, smoothing burrs and edges on the top of tools and grinding plugs and packers into small pieces so that they can be circulated out of the wellbore.

In 2010, a major operator working in the Gulf of Mexico planned to remove a cast-iron bridge plug (CIBP) from the wellbore. Before the CIBP could be milled, the operator had to remove 200 ft [60 m] of cement that had been placed on the top of the plug. The driller ran into the hole with an 81/2-in. roller cone bit and located the top of the cement at approximately 800 ft [240 m]. During drilling operations, a bit cone was lost in the hole.

The driller pulled the damaged bit from the hole and then ran back in with a mill but was unable to grind up the errant bit cone. To minimize additional lost rig time, the operator sought a solution that could remove the bit cone and mill the CIBP in a single trip. M-I SWACO engineers recommended the WELL SCAVENGER tool with a special BHA to meet the company’s objectives in a single trip.

The BHA comprised two pieces: a washover shoe—dressed with a smooth exterior, rough interior and rough leading edge—and a wash pipe extension dressed with two rows of finger baskets. Cable fingers were inserted to help cap-ture the bit cone. The BHA allowed 16.5 ft [5 m] between the bottom of the WELL SCAVENGER tool and the leading edge of the shoe.

The driller tripped into the hole and located the top of the CIBP, broke circulation and began milling the plug. Operating the mill at 80 rpm, the fishing supervisor milled the CIBP in about five hours with 1,000 to 6,000 lbf [4,450 to 26,700 N] of weight on the tool and 1,000 to 3,000 lbf.ft [1,356 to 4,067 N.m] of torque. When the total interval of 2.0 ft [0.6 m] was milled, the rig crew pulled the BHA to the surface. The tool had collected between 12 and 15 lbm [5.4 and 6.8 kg] of metallic debris. Larger items that could not enter the WELL SCAVENGER tool were found inside the cable fingers and below the finger bas-ket. These included the bit cone, cone rings, packer rubber and other CIBP components. Based on the amount of accumulated material, technicians determined that most of the debris had been removed from the wellbore.

Despite the inferior lifting properties of the seawater-base drilling fluid used in the wellbore, the WELL SCAVENGER debris recovery system removed the bit cone and debris associated with milling the CIBP. Drillers successfully tripped into the hole and retrieved the remaining tool elements with no interference from debris or junk, thus avoiding the cost of additional trips.

> Assorted debris removed from the depths. Drillers sealed the WELL SCAVENGER debris chambers as the tool was removed from a well on the North Slope of Alaska. When opened later at the M-I SWACO facility, the four collection chambers contained various materials, including a mix of formation sand, rubber pieces and ferrous material. A pen, not retrieved from the hole, illustrates relative size.

Recovered Debris Close-Up View

Winter 2012/2013 13

Removing Stuck PackersDrillers and engineers make every effort to mini-mize operational risks. Despite these efforts, drillstrings become stuck, completion assemblies fail to reach their objectives and junk winds up in the wellbore. A major operator working on the North Slope of Alaska recently experienced such an event.

While the operator was running a packer in 9 5/8-in. casing, the packer set prematurely at 8,184 ft [2,494 m]. Previously, the operator had set a packer with a stinger assembly attached at approximately 10,100 ft [3,078 m]. Once the stuck packer was drilled out, the wellbore had to be cleaned down to the top of the deeper packer before the driller could resume further recomple-tion operations.

Debris removal was complicated by the well’s 80° deviation from approximately 2,500 ft [762 m] to total depth. After a competitor’s boot basket retrieval tool yielded very little debris in two runs, engineers from the M-I SWACO specialized tools group in Alaska and Houston recommended a specially modified BHA combined with the WELL SCAVENGER tool and several high- capacity MAGNOSTAR tools.

The BHA included 90 ft [27 m] of wash pipe, a HEAVY DUTY RAZOR BACK CCT casing scraper, the MAGNOSTAR tools, the WELL SCAVENGER tool and the SABS circulating sub. After the tools reached a depth of 6,200 ft [1,890 m], a large accumulation of debris on the lower side of the wellbore hindered progress. Through continuous circulation and near-constant pipe movement, the driller was able to push the tool assembly to 6,280 ft [1,914 m]. The tools were then pulled from the hole. Once the tools were on the surface, technicians recovered 184 lbm [83 kg] of ferrous debris from the MAGNOSTAR tools (above).

While technicians cleaned the MAGNOSTAR tools, the driller ran back into the hole with a com-petitor’s boot basket fishing tool and magnet assembly. When the tool was pulled from the hole, technicians recovered a packer slip and 20 lbm [9 kg] of ferrous debris. A second run of the WELL SCAVENGER assembly included three MAGNOSTAR tools. This run yielded an additional 287 lbm [130 kg] of ferrous debris on the MAGNOSTAR tools and 1,033 lbm [469 kg] of sand and silt along with 168 lbm [76 kg] of ferrous debris recovered from the WELL SCAVENGER tool collection chambers.

A final run made with the three MAGNOSTAR tools yielded an additional 145 lbm [66 kg] of fer-rous debris. After clearing most of the debris from the wellbore, the driller was able to run in the hole with a polish mill to clean the lower packer bore. M-I SWACO tools removed a total of 1,817 lbm [824 kg] of ferrous and nonferrous debris from the wellbore.

Rapidly Evolving Tool DevelopmentComplicated completions, complex borehole con-figurations and high rig-time costs are leading engineers to identify new applications for the WELL SCAVENGER assembly and associated debris removal tools. Because of new debris recovery tools and techniques, drillers are now better able to remove materials intentionally placed downhole or items accidentally lost in the wellbore. Tool combinations are evolving to address a broader array of completion and debris recovery needs. The evolution in debris recovery tool designs is reducing risks, cutting costs and improving well productivity.

Ongoing design work further enhances the range and scope of debris recovery tools used at great depths. Given the increasing cost of rig time, especially in deepwater settings, engineers are focusing on the development of systems that allow debris recovery to be combined with other well operations in a single tool run. For example, field tests have shown that debris recovery and milling tools can be combined with packer retrieval hard-ware to deburr casing perforations, recover the generated debris and remove a temporary packer all in a single tool run, thus improving operational efficiency and reducing costs. Other develop-ments are underway to help operators recover debris in low-pressure, lost circulation environ-ments, setting the bar for successful completions in increasingly challenging situations. —DW

> Recovering ferrous debris. The vanes of the MAGNOSTAR tool are covered with ferrous debris, which has been recovered from the well after milling operations. Debris removed from the tool (inset) is laid out for inspection on the drill floor. A ruler, not recovered from the borehole, shows the scale of the debris.

14 Oilfield Review

Revealing Reservoir Secrets Through Asphaltene Science

Downhole fluid analysis of the heaviest components of petroleum can help unlock

information about reservoir structure. Understanding how asphaltenes associate in

oil columns permits scientists and engineers to use asphaltene concentration

gradients to determine the presence of sealing barriers. Production results have

confirmed the validity of this approach, which is being extended to address the

structure and dynamics of fluids in complex reservoirs.

A. Ballard AndrewsOliver C. MullinsAndrew E. PomerantzCambridge, Massachusetts, USA

Chengli DongHani ElshahawiShell Exploration and ProductionHouston, Texas, USA

David PetroMarathon Oil CorporationHouston, Texas

Douglas J. SeifertSaudi AramcoDhahran, Saudi Arabia

Murat ZeybekDhahran, Saudi Arabia

Julian Y. ZuoSugar Land, Texas

Oilfield Review Winter 2012/2013: 24, no. 4. Copyright © 2013 Schlumberger.For help in preparation of this article, thanks to John Mainstone, The University of Queensland, Brisbane, Australia.InSitu Fluid Analyzer, LFA and MDT are marks of Schlumberger. INTERSECT is a joint mark of Schlumberger, Chevron and Total.

Long before scientists grappled with the heaviest component of petroleum—asphalt—humans were putting it to use. In the ancient world, Babylonians used asphalt as mortar, and Egyptians employed it for mummification.1 Asphalt’s ability to preserve and bind has been carried through the intervening centuries to a host of current applications that include paving, roofing, waterproofing and insulation.

In the oil field, the utility of asphalt is less clear. Asphaltenes, the primary component of asphalt, tar or bitumen, can create flow assur-ance problems in the formation, production tub-ing and pipeline.2 Additionally, crudes with high asphaltene levels are less valuable on world mar-kets; their hydrogen deficiency limits their yield of liquid hydrocarbons and their sulfur and metal content creates problems for refining.3

1. Yen TF and Chilingarian GV (eds): Asphaltenes and Asphalts, 2. Amsterdam: Elsevier Science BV, Developments in Petroleum Science, 40B, 2000.

2. Kabir CS and Jamaluddin AKM: “Asphaltene Characterization and Mitigation in South Kuwait’s Marrat Reservoir,” paper SPE 80285, presented at the SPE Middle East Oil Show and Conference, Bahrain, February 20–23, 1999.

3. Allan D and Davis PE: “Refining Review—A Look Behind the Fence,” Oilfield Review 19, no. 2 (Summer 2007): 14–21.

4. Elshahawi H, Mullins OC, Hows M, Colacelli S, Flannery M, Zuo J and Dong C: “Reservoir Fluid Analysis as a Proxy for Connectivity in Deepwater Reservoirs,” Petrophysics 51, no. 2 (April 2010): 75–88.

5. This classification is typically labeled a SARA analysis—saturates, aromatics, resins and asphaltenes. For more: Akbarzadeh K, Hammami A, Kharrat A, Zhang D, Allenson S, Creek J, Kabir S, Jamaluddin A, Marshall AG, Rodgers RP, Mullins OC and Solbakken T: “Asphaltenes—Problematic but Rich in Potential,” Oilfield Review 19, no. 2 (Summer 2007): 22–43.

6. Black oil is used in reservoir modeling to describe oil in place. The conventional black oil model uses three components: water, oil and gas. For more on black oil modeling: Huan G: “The Black Oil Model for a Heavy Oil Reservoir,” paper SPE 14853, prepared for presentation at the SPE International Meeting on Petroleum Engineering, Beijing, March 17–20, 1986.

7. Mullins OC: The Physics of Reservoir Fluids. Sugar Land, Texas, USA: Schlumberger, 2008.

Zuo JY, Freed D, Mullins OC, Zhang D and Gisolf A: “Interpretation of DFA Color Gradients in Oil Columns Using the Flory-Huggins Solubility Model,” paper SPE 130305, presented at the CPS/SPE International Oil and Gas Conference and Exhibition, Beijing, June 8–10, 2010.

> Reservoir gradients. Measurements on a condensate oil from a reservoir in Norway show that the formation pressure and temperature at the gas/oil contact zone lie on an equation of state (EOS)–generated bubblepoint line dividing the liquid and two-phase regions. Composition data on reservoir fluids from this field show large gradients. Composition gradients in the reservoir depend on fluid conditions, and as the reservoir temperature and pressure approach the bubblepoint line and critical point, large composition gradients develop.

Pres

sure

, bar

Temperature, °K

Increasingcompositiongradients

Liquid VaporTwo-phase region

700600500400300200100

100

200

300

400

500

0800 900

Formation conditionsCritical point

BubblepointDewpoint

Winter 2012/2013 1515

The high cost of offshore operations and the trend toward deeper wells worldwide have renewed the imperative for understanding reser-voir fluids at a molecular level. Operators can no longer afford to view reservoirs as homogeneous tanks of oil and gas. In addition to knowing fluid composition, they must also be able to assess res-ervoir connectivity, particularly when costs dic-tate a limited number of wells. Imaging and pressure surveys are often insufficient to com-pletely assess oil drainage patterns, so operators are turning to downhole fluid analysis (DFA) and asphaltene science to better understand reser-voir structures.4

In the recent past, operators characterized oil in reservoirs with a few parameters such as specific gravity, gas/oil ratio (GOR) and a simple chemical classification of the bulk oil.5 However,

DFA measurements on oil columns from around the world reveal that reservoir fluids present a much more complex picture, both vertically in the oil column and laterally across the field. Such results, coupled with decades of analytical research, are yielding a more complete picture of asphaltene physical forms in the reservoir. These research advances explain how and under what conditions asphaltenes associate with each other and allow all components of the reservoir fluid mix—gas, liquids and solids—to be described by equations based on thermodynamic principles. The end result of this work enables use of pre-dicted and observed asphaltene concentration gradients to confirm or disprove fluid drainage connectivity in an oil column.

This article focuses on new asphaltene sci-ence and covers its origins, development and uses. Cases from deepwater Gulf of Mexico and

Middle Eastern fields illustrate how these devel-opments are helping oilfield scientists and engi-neers learn more about connectivity in reservoirs and the distribution of gases, liquids and solids in the fluids contained therein.

Reservoir Fluids—A Complex PictureA beaker of petroleum on a laboratory bench or an open hatch on a stock tank presents a decep-tively simple view of underground fluids—that an entire reservoir consists of only black oil and gas.6 Fluid property gradients, where present because of reservoir conditions, may appear to affect only the GOR. However, this view is inaccurate because at actual reservoir conditions, composi-tion gradients can exist not only for the GOR, but also for asphaltenes and the individual compo-nents of the oil (previous page).7

N

16 Oilfield Review

Asphaltenes in petroleum have been a focus of study by oilfield engineers and scientists for decades. Much about asphaltenes has seemed complex and inconclusive. Interest in these compounds has taken on several dimensions over time. In the early years of the industry, downstream research was centered on optimiz-ing uses for the asphalt by-products from refin-ing operations. In the last half of the twentieth century, that focus turned toward efficient con-version of heavy ends and their asphaltene com-ponent as refiners sought to maximize the production of transportation fuels. In upstream exploration and production, the focus on asphaltenes has almost always been on mitigat-ing and avoiding their negative impacts. These impacts include formation plugging because of precipitation and the effects of high viscosity during production and transportation (below).8 However, new science developed over the last

decade has shown that asphaltene gradients in the reservoir can provide valuable insights about reservoir structure.

Asphaltenes found in reservoir fluids are a complex molecular mixture of particles colloi-dally suspended in oil that have no single chemi-cal identity. They are usually defined as a solubility class—that is, those molecules that are insoluble in n-heptane but soluble in toluene. Asphaltene molecules are typically condensed aromatic rings that can contain heteroatoms such as nitrogen and sulfur as well as metals such as nickel and vanadium. Almost every chemical property of asphaltenes has been the subject of significant debate, except for their elemental composition. An early controversy centered on the nature of the covalently bound chemical groups versus those that are associated in noncovalent aggre-gates.9 The wide range of molecular weights obtained at that time—1,700 to 500,000 g/mol—

was attributed to varying aggregate sizes. Over the last decade, research on asphaltenes has encompassed multiple branches of analytical chemical science to produce a much clearer pic-ture of asphaltene properties and how individual asphaltene molecules associate to form larger particles (above).10

Downhole Fluid AnalysisDownhole fluid analysis helps scientists and engi-neers examine reservoir fluids in their native environment. The DFA concept has evolved from a technique for fluid identification via openhole sample acquisition to a means of analyzing reser-voir fluids and their spatial variations at forma-tion conditions in real time. The concept is simple: Following drilling, a cylindrical sampling and analysis module is lowered into a well on wireline, and fluids are collected from the forma-tion. This tool, the MDT modular formation

8. Mullins, reference 7. Edgeworth R, Dalton BJ and Parnell T: “The Pitch Drop

Experiment,” European Journal of Physics 5, no. 4 (October 1984): 198–200.

9. Dickie JP and Yen TF: “Macrostructures of the Asphaltic Fractions by Various Instrumental Methods,” Analytical Chemistry 39, no. 14 (December 1967): 1847–1852.

10. Mullins OC: “The Modified Yen Model,” Energy & Fuels 24 (January 2010): 2179–2207.

11. Creek J, Cribbs M, Dong C, Mullins OC, Elshahawi H, Hegeman P, O’Keefe M, Peters K and Zuo JY: “Downhole Fluids Laboratory,” Oilfield Review 21, no. 4 (Winter 2009/2010): 38–54.

> Asphaltene viscosity. In 1927, researchers at The University of Queensland, Australia, heated a sample of pitch, or asphalt, and placed it in a funnel that was subsequently sealed (inset ). The asphalt was allowed to settle for three years at room temperature before researchers cut the funnel stem. Since that date, the asphalt has dripped from the funnel, averaging one drop every nine to ten years. In 2002, the ninth drop was starting to form. While the viscosity of heavy oils is not nearly as high as that of asphalt, viscosity rises sharply with increasing asphaltene content. Data on asphaltenes and deasphalted oil from several crudes show a rapid increase in viscosity with rising hexane asphaltene content that spans six orders of magnitude in viscosity. These data are represented by a Pal-Rhodes viscosity model. (Photograph courtesy of JS Mainstone, The University of Queensland).

Hexane asphaltenes, wt %

Visc

osity

, Pa.

s at

60°

C

0 10101

102

103

104

105

106

107

108

109

20 30 40 50

Asphaltenes,deasphalted oilsPal-Rhodes viscosity model

> Asphaltene properties. During the past decade, advances in analytical science have allowed a more consistent picture of asphaltene structure to emerge. Estimates for the mean asphaltene molecular weight have been reduced by several orders of magnitude and are now about 750 g/mol, and the range is significantly tighter. Similarly, scientists now know the median number of fused rings per asphaltene polyaromatic hydrocarbon (PAH) is about seven, with one PAH per molecule dominating. In addition, the number of PAH stacks in an asphaltene nanoaggregate, unknown a decade ago, is one. All of these developments have allowed researchers to establish consistent physical models regarding asphaltene molecules and to show how they associate with one another in reservoir fluids.

Property

Mean asphaltene molecular weight

Number of PAHs per asphaltene

Number of fused rings per asphaltene PAH

Number of PAH stacks in a nanoaggregate

1 to 20

2 to 20

unknown 1

7 (average)

1 dominates

750 g/mol103 to 106 g/mol

Reported Values, 1998 Reported Values, 2009

12. Optical density, measured by MDT spectroscopy, is calculated from the degree of absorption in the visible and near-infrared portion of the frequency band—from wavelengths of about 400 to 2,000 nm. Components of reservoir fluids, such as asphaltenes, have characteristic absorptions in this range that reflect their molecular structures. Optical density gives a dimensionless numerical value to the color characteristics of these fluids. For more on downhole optical density applications: Creek et al, reference 11.

13. Mullins OC, Andrews AB, Pomerantz AE, Dong C, Zuo JY, Pfeiffer T, Latifzai AS, Elshahawi H, Barré L and Larter S: “Impact of Asphaltene Nanoscience on Understanding Oilfield Reservoirs,” paper SPE 146649, presented at the SPE Annual Technical Conference and Exhibition, Denver, October 30–November 2, 2011.

Winter 2012/2013 17

dynamics tester, contains a probe for sampling reservoir fluids and an array of sensors for analyz-ing the sampled fluids on a real-time basis (above). An MDT tool configured for DFA can pro-vide a long list of reservoir data ranging from gen-eral properties such as GOR and pressure and temperature at depth to specific attributes such as density, composition and miscible sample con-tamination by nonaqueous drilling fluids.11 In addition to determining GOR and other proper-ties, the MDT tool uses spectroscopy to measure optical density—essentially oil color—which is directly proportional to asphaltene concentra-

tion.12 Fluid property variations interpreted from DFA measurements made at several depth sta-tions in a well can sometimes indicate nearby sealing barriers (right).13

Identifying compartments in a reservoir is not as challenging as assessing oil drainage connec-tivity within those compartments, especially before production. Static pressure surveys may fail to find hard-to-image sealing barriers before production starts because pressure equilibrium and composition equilibrium are achieved over different time scales. Composition equilibrium is achieved slowly, and the difference between the

>Modular formation dynamics tester. The MDT tool (above) contains a complex array of instrumentation for downhole sampling and analysis. In a typical configuration (right), the MDT tool components include a section for storing samples in addition to an InSitu Fluid Analyzer system and LFA live fluid analyzer system for real-time downhole fluid analysis. Reservoir fluids enter the tool at the formation probe and are pumped in two directions—upward toward the InSitu Fluid Analyzer tool and downward toward the LFA module. The InSitu Fluid Analyzer tool contains two spectrometers and a fluorescence detector for analysis of hydrocarbons, CO2, pH and fluid color; it also contains instruments for measuring density, resistivity, pressure and temperature. Reservoir fluid from the sampling probe that is pumped downward passes through the LFA module. This device employs an absorption spectrometer to quantify and monitor the amount of reservoir and drilling fluids that are present. A gas refractometer (not shown) in the tool differentiates between gas and liquids.

Sample modules

InSitu Fluid Analyzer system

LFA live fluidanalyzer system

Focused probe

Pump 2

Pump 1

> Sealing barriers. Using DFA to reveal the presence of fluid density inversions can sometimes help identify sealing barriers in a reservoir. GOR data for two depth zones in an oil column illustrate this concept. Using GOR as a proxy for density in this column, scientists found a low-GOR, high-density fluid at Point A (left), above a high-GOR, low-density fluid at Point B (right). This finding indicates the possible presence of a sealing barrier between the two zones.

Verti

cal d

epth

, m

GOR, ft3/bbl

Possible sealing barrier

A

B

X,800

X,700

1,000 2,000 3,000 4,000 5,000

X,600

X,500

X,400

X,300

X,200

18 Oilfield Review

time to reach pressure equilibrium and that to reach composition equilibrium for the heaviest fraction of crude can be several orders of magni-tude (above).14 Massive fluid migration in the res-ervoir is required to achieve compositional equilibration, and for this to occur, there must be good reservoir connectivity. In contrast, pressure equilibration can be achieved with very small mass transfer, which can occur through leaky seals. Consequently, pressure equilibration is a

necessary but insufficient condition to establish connectivity in the reservoir.

Nearly equilibrated asphaltene concentration gradients between two zones are indicative of connectivity. However, before that concept can be implemented on a practical basis, it is neces-sary to have a model for asphaltenes that accounts for their thermodynamic characteris-tics and how they associate with each other deep in the reservoir.

Modeling AsphaltenesSince 2000, advances in analytical instrumenta-tion and science have allowed a much clearer picture of asphaltene structure to emerge. Such advances have narrowed the knowledge gap about their properties and have led to a more refined description of asphaltene science as embodied in the modified Yen model.15 This model was later renamed the Yen-Mullins model.16 It envisions asphaltenes in crude oil as existing in three distinct and separate forms—as asphaltene molecules, as nanoaggregates of indi-vidual asphaltene molecules and as clusters of nanoaggregates (below). The number of analyti-cal methods employed over the last decade to resolve the molecular weight, size and aggrega-tion parameters in this model is extensive and includes time-resolved fluorescence depolariza-tion and laser-based mass spectrometry for molecular and aggregate size and weight deter-mination. For most model parameters, such as asphaltene molecular weight, scientists must apply several techniques to reduce the uncertainty.

The asphaltene molecule is at the first level of the Yen-Mullins model. The typical asphaltene molecule consists of several fused aromatic rings with peripheral alkane substituents, often with scattered sulfur and nitrogen heteroatoms. This molecule has a mean molecular weight of 750 g/mol with most of the population ranging from 500 to 1,000 g/mol and a length of about 1.5 nm. In this model hierarchy, the asphaltene

> The Yen-Mullins model of asphaltene nanoscience. At low concentrations—typical in condensates and volatile oils—asphaltenes are predicted to exist as a solution of molecules that measure about 1.5 nm (left). At higher concentrations—found in black oils—asphaltenes are dispersed as 2-nm nanoaggregates (center). At still higher concentrations, such as those found in mobile heavy oils, asphaltenes are dispersed as clusters of 5 nm (right).

Molecule Nanoaggregate Cluster

~1.5 nm ~2 nm ~5 nm

N

> Reservoir equilibration. Reservoir modeling gives insight to the time required to reach equilibration. Modeling of a tilted sheet reservoir with a low-permeability zone in the center shows that fluid composition equilibration—measured by density, methane or heavy fraction— is seven to eight orders of magnitude slower than the corresponding pressure equilibration.

Tim

e to

reac

h eq

uilib

ratio

n, y

ears

Black oil Volatile oil Condensate Gas0

1

101

102

103

104

105

106

107

108

109

PressureFluid density

Methane

Heavy fraction

Winter 2012/2013 19

14. Pfeiffer T, Reza Z, Schechter DS, McCain WD and Mullins OC: “Determination of Fluid Composition Equilibrium Under Consideration of Asphaltenes—A Substantially Superior Way to Assess Reservoir Connectivity than Formation Pressure Surveys,” paper SPE 145609, presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, USA, October 30–November 2, 2011.

15. Mullins, reference 10. Mullins et al, reference 13.16. Sabbah H, Morrow AL, Pomerantz AE and Zare RN:

“Evidence for Island Structures as the Dominant

nanoaggregate is the next structure in size. These particles represent an aggregation of about six asphaltene molecules in a single disordered stack about 2 nm in size. The asphaltenes in nanoaggregates are tightly bound, and exterior alkanes on the nanoaggregate particle project outwardly. The largest particle in the Yen-Mullins model is the cluster, which represents a group of about eight nanoaggregates. Clusters, which are loosely bound, are about 5 nm in size.

Although all of the forms envisioned by the Yen-Mullins model may occur in any oil column, the specific form depends largely on the asphal-tene concentration. In wells that produce volatile oils and condensates with high GOR, the asphal-tene concentration will be less than 0.5 wt % and the asphaltene particles will be 1 to 1.5 nm in size. At higher asphaltene concentrations, such as black oil columns with moderate GOR values, the asphaltene concentration will usually be less than 5 wt % and the asphaltene particles will be principally 2-nm nanoaggregates. In even higher asphaltene concentrations, as seen in mobile heavy oils that have low GOR, asphaltene levels will range from 5 to 35 wt %, with 5-nm clusters as the primary asphaltene particle.

Tar mats may occur in formations with signifi-cant levels of mobile heavy oil and are areas of nearly immobile asphaltenes usually found at the base of an oil column near the oil/water contact. There are two predominant forms of tar mats.17 One type occurs at the base of a mobile heavy oil column as a result of seemingly continuous extension of a large asphaltene concentration and viscosity gradient. The other type of tar mat occurs at the base of a lighter oil column and is discontinuous in asphaltene concentration.

The first type of tar mat results from a subtle destabilization of asphaltenes at the top of the oil column followed by transport of asphaltenes to the base of the oil column to form a mat. The sec-ond type of tar mat may occur when there is a sig-nificant gas charge into the top of a reservoir containing black oil. As the gas diffuses down the column, the GOR increases and causes asphal-tene molecules and nanoaggregates to form clus-ters. These clusters descend ahead of the diffusive gas front, which moves lower in the column with time. When the gas front reaches the bottom of the column, the asphaltenes are expelled from the oil to form the tar mat (above right).18

> Tar mat formation. One mechanism for tar mat formation (top) envisions a stable black oil column (A) in which biogenic methane moves beneath an upper seal (B). As the methane slowly diffuses down the oil column, large GOR and asphaltene gradients are formed (C). These gradients can become large enough that a dense, asphaltene-rich tar mat may form at the bottom of the column (D). A thin section from a tar mat formed at the base of a high- GOR column shows tar on the grains of a cemented sandstone (bottom).

Aquifer Aquifer

Aquifer Aquifer

Black oil column

Methanecharging updip

A B

C D

Methanediffusing downdip

Tar mat

Seal

Tar

Architecture of Asphaltenes,” Energy & Fuels 25, no. 4 (2011): 1597–1604.

17. Mullins OC, Zuo JY, Dong C, Andrews AB, Elshahawi H, Pfeiffer T, Cribbs ME and Pomerantz AE: “Downhole Fluid Analysis and Asphaltene Nanoscience for Reservoir Evaluation Measurement,” Transactions of the SPWLA 53rd Annual Logging Symposium, Cartagena, Colombia, June 16–20, 2012, paper CCC.

18. Zuo JY, Elshahawi H, Mullins OC, Dong C, Zhang D, Jia N and Zhao H: “Asphaltene Gradients and Tar Mat Formation in Reservoirs Under Active Gas Charging,” Fluid Phase Equilibria 315 (February 15, 2012): 91–98.

20 Oilfield Review

Correctly modeling asphaltenes requires a two-pronged approach. The Yen-Mullins model provides the solution to the first challenge—a useful framework for the asphaltene particles that form in an oil column along with estimates of particle size and molar volume. The second part of the problem is to mathematically describe the asphaltene concentration gradients for the vari-ous asphaltene physical states as predicted by the Yen-Mullins model.

In thermodynamic systems, a state variable is a parameter such as temperature, pressure or volume, which depends on the state of the system but not the path used to get to that state. The mathematical equation that relates state vari-ables is called an equation of state (EOS). In 1834, Benoit Paul Émile Clapeyron, a French engineer and physicist, developed the ideal gas law, an EOS that relates pressure, volume and temperature. The ideal gas law is a first-order equation that ignores molecular volumes and forces and is accurate only for weakly interacting gases at moderate conditions. In 1873, van der Waals developed a cubic EOS that approximates the behavior of gases and liquids by taking into account molecular forces and the size of mole-cules. Since that time, many variants of the clas-sic cubic EOS have been developed, and these

equations have been used for decades to model fluid behavior in oil columns. However, using these equations for black oil modeling in reser-voirs containing significant levels of asphaltenes is not satisfactory. Because asphaltenes lack a gas phase or a critical point, they must be treated as a pseudocomponent and handled empirically. Although this approach is adequate to model hydrocarbon gas-liquid equilibria and determine parameters such as GOR, it is inadequate for modeling molecular and colloidally suspended particles such as asphaltenes, asphaltene nano-aggregates and clusters of nanoaggregates.

The need to model solution behavior of mix-tures containing solvents and large molecules such as asphaltenes has existed for decades. Much research in the 1940s focused on the ther-modynamics and solution behavior of polymer compounds and resulted in the Flory-Huggins theory.19 More recently, the Flory-Huggins approach has been used to examine asphaltene instabil-ity.20 Recognizing the need for a first principles approach to describe asphaltene concentration gradients in oil columns, scientists have devel-oped the Flory-Huggins-Zuo EOS for this pur-pose.21 This equation incorporates a gravity term for asphaltenes using their known size. This grav-ity term is essential for modeling asphaltene

gradients. The equation was developed starting with the free energy of a mixture of asphaltenes and solvent as a function of the free energies associated with gravity, solubility and entropy of mixing. At equilibrium, the derivative of the free energy sum is zero, and the solution of the result-ing partial differential equations yields the Flory- Huggins-Zuo EOS. In its original form, this equation expresses the asphaltene concentration gradient as a volume fraction of asphaltenes at various depths in the oil column. Since oil color is directly proportional to the asphaltene concen-tration, the optical density ratio is usually substi-tuted for the volume ratio for a more practical measurement. The resulting equation gives the asphaltene concentration in terms of optical den-sity and is an exponential function of several parameters (above).22

The first term in the Flory-Huggins-Zuo EOS accounts for the effect of gravity and is the most significant term for asphaltenes in an oil column for low-GOR oils (next page, top right). Gravitational effects cause asphaltenes to accu-mulate at the base of a column, although thermal energy counteracts gravity to some extent. This first term expresses gravitational effects as the buoyancy of an object in a liquid—the gravity effect—divided by a function of the tempera-

> Asphaltene equation of state (EOS). The Flory-Huggins-Zuo EOS (top) predicts asphaltene gradients in an oil column. Optical density at two depths is predicted as an exponential function of three terms—gravity, entropy and solubility. The gravity term depends primarily on asphaltene particle size and depth. The entropy term is a measure of molecular randomness and depends on molar volumes. The final term in this equation—solubility—depends on GOR, density and composition.

OD hi( ( optical density at depth hi φa hi( ( asphaltene concentration at depth hi

va asphaltene molar volume

v oil phase molar volume

g gravitational constant

Δρ density difference between asphaltenes and oil phase

T temperature

R ideal gas constant

δa asphaltene solubility parameter

δ oil phase solubility parameter

Fluid color ƒ Gravity term Entropy term Solubility term= +

RTRTexp==

h2 h1

h1h2

vva va va

v – –+φaOD Δρ – gva

δ δ2 2

a – δ δa ––( ( ( (φaOD

( ( ( ( ( (( ( ( (h2 h2 h2

h1 h1

h1

Winter 2012/2013 21

ture—the thermal effect. For large physical forms of asphaltenes, such as clusters found in heavy oils, the gravity term is significant and gives rise to high concentrations of asphaltenes near the base of the oil column.

The remaining two terms in the new asphal-tene EOS are similar to the original Flory-Huggins terms for entropy and solubility. The entropy is stated in terms of ratios of molar vol-umes of asphaltenes and solvent at two depths. The entropy effect tends to randomize the asphaltene distribution and counteract gradi-ents, but is usually not large for asphaltenes in crude oils. The other factor in the Flory-Huggins-Zuo EOS that essentially corresponds to the original Flory-Huggins work is the solubility term. For asphaltene gradients, this term is expressed in solubility parameters that are cal-culated from GOR or mass densities. This term accounts for changes of asphaltene solubility in the liquid phase and is important for high-GOR oil that produces a low-density liquid, rich in paraffinic alkanes that decrease asphaltene solubility. For low-GOR oils, however, the solu-bility term is usually not significant.

The end result of this new equation of state for asphaltenes is the prediction of asphaltene concentrations, directly proportional to fluid color, at any depth in the oil column. Almost all of the parameters may be measured or estimated from downhole fluid analysis results of the bulk oil at various depth stations. Those parameters not directly measured—such as the solubility parameters—may be obtained from correlations of known properties.

The only adjustable parameter in the Flory-Huggins-Zuo EOS is the asphaltene molar vol-ume, which is related to particle size. The

particle size cannot be determined directly from the downhole data, but there are other ways to find it. The first method is to tune the unknown size of the asphaltene particles to match the downhole fluid color data from measure ments at different depths. This size is then checked against the Yen-Mullins model particle types to ensure it is within the boundar-ies described by the model. The second method is to assume that heavy ends in the oil column

are either asphaltene molecules, nanoaggre-gates or clusters. In this case, the assumed size is used to predict the downhole asphaltene gra-dients in the oil column, which can be checked against the actual data. If there is consistency, then the data can be used to assess connectivity and other reservoir properties. Analysis of the data may not always suggest a single asphaltene particle type because multiple particle types may be involved (below).

19. Flory PJ: “Thermodynamics of High Polymer Solutions,” Journal of Chemical Physics 10, no. 1 (January 1942): 51–61.

Huggins ML: “Thermodynamic Properties of Solutions of Long-Chain Compounds,” Annals of the New York Academy of Sciences 43, no. 1 (March 1942): 1–32.

20. Buckley JS, Wang J and Creek JL: “Solubility of the Least Soluble Asphaltenes,” in Mullins OC, Sheu EY, Hammami A and Marshall AG (eds): Asphaltenes, Heavy Oils, and Petroleomics, New York: Springer Science+Business Media (2007): 401–438.

21. Zuo JY, Mullins OC, Freed D, Elshahawi H, Dong C and Seifert DJ: “Advances in the Flory-Huggins-Zuo Equation of State for Asphaltene Gradients and Formation Evaluation,” Energy & Fuels (in press).

22. Freed DE, Mullins OC and Zuo JY: “Theoretical Treatment of Asphaltene Gradients in the Presence of GOR Gradients,” Energy & Fuels 24, no. 7 (July 15, 2010): 3942–3949.

Zuo et al, reference 21.

> Gravity effects. The effect of gravity depends on which asphaltene physical form predominates in the well. For a 100-m [328-ft] oil column containing mostly asphaltene clusters (black), gravity effects are large, as evidenced by the dramatic increase of asphaltene content with depth. The intermediate size nanoaggregates (blue) show a much more gradual change, while the asphaltene molecules (red) show only a small change from top to bottom of the column.

Verti

cal d

epth

, m

0 0.2 0.4 0.6 0.8 1.0100

80

60

40

20

0

5.0-nm clusters2.0-nm nanoaggregates1.5-nm molecules

Asphaltene concentration at depthAsphaltene concentration at 100 m

>Multiple particle types. A black oil column that was subjected to a late gas and condensate charge shows evidence that more than one asphaltene particle type is present in the column. Analysis of DFA data using the Flory-Huggins-Zuo EOS indicates that nanoaggregates alone would not account for the increase in asphaltene concentration—as measured by optical density—with depth (left). In this example, the late gas charge destabilized the asphaltenes, causing clusters to form; these clusters settled toward the bottom of the oil column because of gravity (right). The presence of large viscosity and asphaltene gradients characterized this oil column, and production of this well proceeded with no significant problems.

Verti

cal d

epth

, m

Oil c

olum

n

Optical density

Nanoaggregatesand clusters

Nanoaggregates

X,Y00

X,Z00

X,X50

X,Y50

X,Z500 0.5 1.5 2.51.0 2.0 3.0

EOS modelsDFA data

Nanoaggregate Cluster

22 Oilfield Review

Downhole fluid analysis, the new Yen-Mullins model and the Flory-Huggins-Zuo EOS can be used together to model asphaltene gradients in actual oil columns. The first step is the use of DFA to give experimental data on asphaltene concentration via fluid color, GOR and other physical parameters at several depth stations in a well. The Yen-Mullins model then provides a physical picture of the asphaltene entities that may be present and allows the operator to make reasonable assumptions on particle size. That size is then used in the Flory-Huggins-Zuo EOS to predict the asphaltene con-centration gradient in the well. If this gradient matches the experimental data, it can be used to further assess reservoir connectivity. This analysis is not a mere curve-fitting exercise. The matching of sizes computed by the new EOS and the Yen-Mullins model gives the operator confidence that the system is in equilibrium.

Asphaltene Science and Complex ReservoirsAn example from a complex field in the Gulf of Mexico illustrates how asphaltene science is used in answering practical questions. This field, operated by Marathon, included an area produc-

ing intermediate-GOR black oil that consisted of six sand layers spanning 1,000 ft [300 m] of depth and intersected by multiple wells.23 The chal-lenge for the operator was to develop an accurate description of reservoir fluid properties and understand connectivity among the various sand layers. The reservoir fluids were analyzed by mul-tiple methods. DFA was employed using the MDT tool both to gather real-time information and obtain samples for further PVT analysis in the laboratory. Using advanced gas chromatographic analysis, the operator also performed geochemi-cal fingerprinting on collected samples. Although the data covered multiple wells in the area of interest, not all analyses were performed at all depth stations; the most complete dataset came from two wells in one of the sands. These data and their analyses show how connectivity ques-tions can be viewed through the lens of the new asphaltene science.

Prior to use of asphaltene gradients to give clues to connectivity in a reservoir sand layer, operators often used data from bulk oil sampling and formation pressure at several depths to make judgments on connectivity. Data on GOR, stock-

tank oil density and formation pressure from the two Marathon wells spanning about 500 ft [152 m] of depth in Sand A show differences that suggest barriers to connectivity. In particular, the pressure gradients from the two wells do not appear to coincide, which is indicative of a seal-ing barrier. However, these differences may reflect either measurement imprecision or differ-ences in the way the data were collected (above).

> Fluid properties and formation pressure in a field in the Gulf of Mexico. DFA data on GOR (left) and density (center) from two wells in Sand A show variability that lies either within or very close to the measurement error bands; scientists can draw no definitive conclusions about connectivity. Data on formation pressure (right) show a difference between the two wells, suggesting a potential for a sealing barrier. However, since the pressure measurements on the two wells were conducted on different wireline runs, and the runs used different pressure gauges, assessment of connectivity using pressure was also inconclusive.

1,000 1,100 1,200 X,200

Verti

cal d

epth

, ft

Fluid GOR, ft3/bbl Stock-tank oil density, g/cm3 Formation pressure, psi

X,275 X,3501,300 0.85 0.86 0.87 0.88 0.89 0.90 X,000

X,050

X,100

X,150

X,200

X,250

X,300

X,350

X,400

X,450

X,500

Well 5 WaterWell 1

23. Dong C, Petro D, Latifzai AS, Zuo J, Pomerantz AE and Mullins OC: “Evaluation of Reservoir Connectivity from Downhole Fluid Analysis, Asphaltene Equation of State Model and Advanced Laboratory Fluid Analyses,” paper SPE 158838, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 8–10, 2012.

24. Resins are a solubility class similar to asphaltenes and are typified by polyaromatic hydrocarbon molecules.

25. Elshahawi H, Ramaswami S, Zuo JY, Dong C, Mullins OC, Zhang D and Ruiz-Morales Y: “Advanced Reservoir Evaluation Using Downhole Fluid Analysis and Asphaltene Flory-Huggins-Zuo Equation of State,” prepared for presentation at the SPWLA 54th Annual Logging Symposium, New Orleans, June 22–26, 2013.

26. The ability to absorb light and then fluoresce is characteristic of some light oils. Like optical density, fluorescence intensity is dimensionless. For more: Creek et al, reference 11.

Winter 2012/2013 23

Using these data, Marathon engineers found it difficult to determine whether Sand A is hydrauli-cally connected between Wells 1 and 5.

In addition to these fluid properties and for-mation pressures, the operator also obtained downhole optical density measurements at sev-eral depth stations for the two wells in Sand A (above). The agreement with the Flory-Huggins-Zuo EOS model indicates that the asphaltenes in the two wells are in equilibrium as 2-nm asphaltene nanoaggregates; this analysis pre-dicts connectivity in Sand A between the two wells. Similar analyses of other sand layers in this field did not show equilibrium in some cases, prompting the operator to conclude that there was no connectivity between those sands. Actual field production data confirmed all asphaltene analysis–based predictions regard-ing connectivity between sands.

The new science on asphaltenes can also be useful in analyzing lighter oils and even conden-sates that contain essentially no asphaltenes but have heavy resins.24 A well in the Gulf of Mexico, operated by Shell, illustrates this concept.25 The light oil column from this well has virtually no asphaltenes and a large GOR variation: from 4,000 ft3/bbl [720 m3/m3] at the top of the column to 2,600 ft3/bbl [463 m3/m3] at a depth 440 ft [134 m] below it.

> Fluid optical density in Sand A. The operator obtained reservoir fluid optical density measurements at several DFA depth stations for wells that penetrated Sand A. These data, which showed a smooth increase with depth, fit the Flory-Huggins-Zuo EOS prediction using 2-nm nanoaggregates as the asphaltene particle state.

0 0.1 0.2 0.3 0.4 0.5Ve

rtica

l dep

th, f

tOptical density

X,000

X,050

X,100

X,150

X,200

X,250

X,300

X,350

X,400

X,450

X,500

Well 5 WaterWell 1 EOS model

The operator had to contend with three issues: Describe the compositional variation of the bulk oil in terms of GOR and other parame-ters, identify the gradient of the heavy compo-nents in the volatile oil and decide if the production zone was connected. To answer these questions, Shell obtained DFA data at five depth stations from the top to the bottom of the oil col-umn. GOR and other properties were analyzed using a traditional cubic EOS in conjunction with established correlations. Results from this work were tuned to experimental data to give a satis-factory fit. Shell engineers found it difficult, how-ever, to quantify optical characteristics of the oil in this column to answer questions about the heavy-end gradient and connectivity.

In most crude oils, optical densities offer good sensitivity for measuring the relative concentra-tion of heavy ends. However, for nearly colorless oils, such as this Shell light oil, optical density is not sensitive enough, especially at very high GOR levels and low heavy-end concentrations. The dif-ference between colorless oils that have 100% light transmission and almost colorless oils that have 99% light transmission is difficult to discern using only optical density. Fluorescence inten-sity, however, is applicable to this type of sample and may be correlated directly to the fraction of heavy resin or asphaltenes.26 In this case, both optical methods were used to give a complete color description of the resin concentration gra-dient with depth (below). Because of the small

Verti

cal d

epth

, m

Fluorescence intensity

Optical density

540

500

460

420

380

340

0

0 0.04 0.08 0.12 0.16 0.20 0.24 0.28

0.30.20.1

Optical densityFluorescence intensity

EOS model

> Optical gradients in a light oil column. Shell engineers used fluorescence intensity and optical density to measure the concentration of heavy molecules in an oil column from a well in the Gulf of Mexico. Application of the Flory-Huggins-Zuo EOS to these DFA data with a 1-nm particle size is a good fit and indicates the heavy resin molecules in the column are in equilibrium. The color characteristics of this light oil are similar to those observed in prior work in which the source of the blue color was identified as the five-ring PAH perylene (inset). If the properties for perylene are used in the EOS for these data, the calculated size of the heavy resin is 0.96 nm, suggesting that the source of the color in this oil column is perylene-like molecules.

24 Oilfield Review

1-nm resin particle size, the gravity term in the Flory-Huggins-Zuo EOS is also small, and the expression is dominated by the GOR effect on the solubility term. The equilibrium distribution of resin molecules indicates that this oil column is connected, as confirmed by subsequent produc-tion data. These results suggest that this approach is useful not only for black oils but also light oils and rich gas condensates. Extending this methodology to mobile heavy oil in a large Middle Eastern field completes the picture.

A large anticlinal oil reservoir operated by Saudi Aramco has proved challenging to describe by conventional modeling.27 The low GOR oil col-umn in this field is stratified and is characterized by black oil at the crest and mobile heavy oil below it, with a tar mat above the oil/water con-tact at the bottom. Although the black oil portion is manageable from a production viewpoint, the asphaltene concentrations in the mobile heavy oil increase sharply with depth, and the oil reaches a viscosity of about 1,000 cP [1,000 mPa.s] just above the tar mat. Conventional PVT model-ing does not account for these viscosity gradient observations, and the existence of these discrete zones represents major challenges in developing

production plans. Saudi Aramco engineers turned to asphaltene science to help them under-stand and model the compositional gradients in this reservoir.

DFA and laboratory data on the different com-position zones in this reservoir were obtained from eight wells around the circumference of the field (above). The data show that the top and majority of the column is black oil with less than 5 wt % asphaltenes and little concentration gradi-ent with depth. This is consistent with an interval containing mostly 2-nm nanoaggregates. The next portion of the column is mobile heavy oil with an asphaltene content ranging from 5 to 35 wt % asphaltenes. Using the Yen-Mullins model as a guide, scientists determined that mobile heavy oil with this range of asphaltenes should exist primarily as 5-nm clusters (next page). The tar mat with an asphaltene concentration greater than 35 wt % is at the bottom of the oil column. Asphaltene concentrations in the tar mat are irregular with depth, indicating that this zone is not equilibrated. The tar mat and heavy oil sec-tions of this reservoir resulted from gravitational accumulation of asphaltenes at the base of the oil column, possibly from a late gas charge.

The combination of the detailed DFA data on asphaltene concentrations and viscosity, coupled with the agreement with the asphaltene science, is important in describing this complex reservoir. These data on viscosity, connectivity and location of the tar mat have a significant impact on pro-duction planning for this field.

Determining oil drainage patterns and con-nectivity in a specific area is an important out-come but is only the beginning for asphaltene science. Going from black oil, characterized by a few simple properties, to oil columns and reser-voirs with detailed compositions is one part of that frontier—but there are other possible direc-tions as well.

New FrontiersFew compounds among the thousands found in crude oil have evoked as much interest and avoid-ance as asphaltenes. In the past, asphaltenes often meant operating problems for producers and difficulties for refiners because of their high molecular weight, high viscosity, plugging char-acteristics and high levels of molecular contami-nants. Scientists and engineers, long fascinated by these heavy molecules, have persevered in their attempts to understand and characterize them. The result is a new branch of asphaltene chemistry that is changing the ways in which sci-entists view connectivity of oil columns within the same reservoir. Through the use of advanced sampling and analysis techniques such as DFA, scientists are able to extend these new ways of looking at asphaltenes from single wells to adja-cent wells and reservoirs. The next step is to extend that view across entire producing basins.

Proper incorporation of diverse phenomena, such as large GOR variations, pressure gradients, asphaltene gradients and the presence of tar mats, will aid operators in field development and planning. At the current stage, these analyses apply to oil columns and reservoirs at equilib-rium. Extending this type of analysis to the fac-tors causing a reservoir to be out of equilibrium allows the theory to be applied to a wider range of situations, as has been shown in deepwater wells in the Gulf of Mexico.28

> Downhole fluid analysis testing. Characterization of this Middle East reservoir was accomplished by analysis of samples from eight wells around its periphery. DFA and oil samples provided useful data on the black oil and mobile heavy oil zones, while data on the tar mat zone were obtained through core analysis.

WellBlack oilHeavy oilTar matWater

27. Seifert DJ, Zeybek M, Dong C, Zuo JY and Mullins OC: “Black Oil, Heavy Oil and Tar in One Oil Column Understood by Simple Asphaltene Nanoscience,” paper SPE 161144, presented at the Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, November 11–14, 2012.

28. Zuo et al, reference 18.29. Edwards DA, Gunasekera D, Morris J, Shaw G, Shaw K,

Walsh D, Fjerstad PA, Kikani J, Franco J, Hoang V and Quettier L: “Reservoir Simulation: Keeping Pace with Oilfield Complexity,” Oilfield Review 23, no. 4 (Winter 2011/2012): 4–15.

Winter 2012/2013 25

In addition to advancements in understand-ing equilibrium, ascertaining connectivity and predicting oil column gradients, the new asphal-tene science has spawned unexpected and poten-tially useful applications for other areas such as enhanced oil recovery. For some time, scientists and engineers have known that asphaltenes have certain interfacial characteristics that are simi-lar to those of naturally occurring surfactants. For example, asphaltenes can alter the balance between oil-wet and water-wet zones in a reser-voir. Because mixed wettability zones may contain nearly one half of field reserves in large Middle East reservoirs, the capability of asphaltenes to change wettability could result in large increases in recovery.

Another branch of work on asphaltenes applies to viscosity and its prediction. Large vis-cosity gradients are a natural consequence of the asphaltene concentration gradient. The ability to predict gradients in asphaltenes and viscosity for oil columns brings up an interesting possibility.

Advanced reservoir simulators—such as the INTERSECT reservoir simulator—now use clus-ters of parallel computers to solve the thousands of equations necessary to model and predict the properties of an entire field.29 These equations simulate the material, energy and property bal-ances for small cubic reservoir sections—called cells—as a function of time and position in the reservoir. Cell size in these simulators has contin-ued to decrease as computational power has increased, and modern simulators now handle cells as small as 50 m [164 ft] in the large reser-voirs of the Middle East. Geoscientists hope to merge the new asphaltene science and gradient predictions with reservoir simulation so that asphaltene and viscosity predictions are made for the entire field—vertically and horizontally. These new reservoir simulators not only model field composition and properties but also include modules for field management and facilities planning. The ability to make good predictions for asphaltene gradients would be an additional step in optimizing field development.

Future possibilities for applying fundamental knowledge about asphaltenes abound. Knowing more about property and asphaltene gradients throughout oil fields will not only aid operators in making better decisions about field development, but may yield benefits in areas as diverse as res-ervoir connectivity, viscosity gradients and enhanced oil recovery. —DA

>Mobile heavy oil characterization. Application of the Flory-Huggins-Zuo EOS for asphaltenes to the mobile heavy oil data (left) yields a cluster size of 5.2 nm, confirming the expected size of 5 nm. For this mobile heavy oil zone, EOS gravity is the only term needed to describe the six-fold variation in asphaltene content over the periphery of this field. The photograph shows a mobile heavy oil in the laboratory.

Verti

cal d

epth

, ft

Asphaltene, wt %

Mobile heavy oil

Tar mat

Black oil

Y,100

Y,150

X,900

X,950

Y,050

X,800

X,850

X,700

X,750

Y,2000 5 10 20 30 4015 25 35 45

Y,000

EOS modelLaboratory data

Tar mat

40 45

26 Oilfield Review

Landing the Big One—The Art of Fishing

Drillers often refer to tools and equipment left in the borehole as “lost.” In reality,

these items have been misplaced thousands of feet below the surface. Removal

of these objects from the wellbore has challenged drillers since the earliest days

of the oil field.

Enos JohnsonHobbs, New Mexico, USA

Jimmy LandMark LeeHouston, Texas, USA

Robert RobertsonStavanger, Norway

Oilfield Review Winter 2012/2013: 24, no. 4. Copyright © 2013 Schlumberger.For help in preparation of this article, thanks to Michael Muhlherr and Eric Wilshusen, Houston; and Torodd Solheim, Stavanger.FPIT is a mark of Schlumberger.

In the oil field, a fish is any item left in a wellbore that impedes further operations. This broad defi-nition encompasses every variety of drilling, log-ging or production equipment, including drill bits, pipe, logging tools, hand tools or any other junk that may be lost, damaged, stuck or other-wise left in a borehole. When junk or hardware blocks the path to continued operations, these items must first be removed from the hole through a process known as fishing.

The origins of this term are attributed to the early days of cable-tool drilling, in which a cable attached to a spring pole repeatedly lifted and dropped a heavy bit that chiseled away at the rock to create a wellbore. When the cable parted, drillers attempted to retrieve the cable and bit from the bottom of the hole using an improvised hook lowered on a length of new cable hung from the spring pole. Experts in the art of retrieving junk from the subsurface became known as fish-ermen. Over the years, their services have become highly sought after, and the art of fishing has grown to fill a specialized niche within the well services industry.

All manner of equipment may fail, become stuck, need replacement or otherwise require retrieval from a wellbore. Fishing operations may be needed at any point during the life of a well—from drilling through abandonment. During the drilling phase, most fishing jobs are unexpected and are often caused by mechanical failure or by sticking of the drillstring. Sticking may also occur during wireline logging or testing operations.

Later, during the completion phase, operations may be thwarted by a variety of problems, includ-ing stuck perforating guns, prematurely set pack-ers or failed gravel pack screens. After a well has been put on production, fishing operations may be scheduled as part of the overall process of maintaining, replacing or recovering downhole equipment and tubulars during workover or abandonment procedures. In many fields, the workover process entails cleanout or retrieval of tubing that has sanded up after years of produc-tion, thus prompting a fishing job at the outset of operations. During abandonment, operators often try to salvage downhole tubulars, pumps and completion equipment before plugging the well. Even the fishing equipment may become stuck, necessitating revision of the original fish-ing strategy. In the oil field, no operation, it would seem, is exempt from the possibility of fishing.

Statistics from the mid-1990s indicate that fishing operations accounted for 25% of drilling costs worldwide.1 These days, fishing can fre-quently be avoided or sidestepped using other, more cost-effective options. For instance, mod-ern drilling technology, such as rotary steering, is creating a shift in fishing strategies by influenc-ing the economics used to determine whether to fish, to buy the stuck equipment, known as the fish, and sidetrack, or to junk and abandon (J&A) the hole.

Each fishing situation—planned or unplanned, openhole or cased, coiled tubing or wireline—is unique, and each presents its own set of conditions

1. Short JA: Prevention, Fishing, and Casing Repair. Tulsa: PennWell Publishing, 1995.

2. A dogleg is an abrupt turn, bend or change of direction in a wellbore and can be quantified in degrees or degrees per unit of distance.

3. Drilling fluid pressure can erode a wellbore to create a washout and it can erode drillpipe to create a hole, which is also termed a washout.

Winter 2012/2013 2727

and problems for which a retrieval solution must be adapted. Within this wide-ranging topic, this article focuses primarily on fishing techniques used during drilling; variations on these tech-niques have been adapted for cased hole, coiled tubing, wireline and workover applications. The article outlines common processes that may lead to the loss of equipment downhole and describes some of the tools and techniques devised in response. It also discusses strategies for deciding how long to pursue fishing operations and closes by discussing a program that trains new fishing personnel in the skills needed to continue the recovery of lost items from the wellbore.

Root CausesMost fishing jobs may be traced to one of three basic causes: human error, faulty equipment or wellbore instability. Nearly everything that goes into the hole can become a fish. Under the wrong circumstances, any object smaller than the bowl diameter of the rotary table master bushing can be lost downhole (right). Hand tools, chains and flashlights have made their way from the drill floor into the wellbore, as have pieces of tongs, slips and other items that can junk a hole. Fortunately, most drilling crews are alert to such dangers, which are preventable through scrupu-lous attention to housekeeping and maintenance practices on the drill floor.

Downhole, mechanical failure of the drill-string can turn a routine drilling operation into a fishing job. Modes of failure are manifold. Tubulars—drillpipe, casing or tubing—may col-lapse, burst, part or twist off (right). The drill bit may break apart. A tool joint may simply come unscrewed from the drillstring, or the pipe may become stuck. Each case produces a different type of fish, which in turn dictates how the fish-ing job will be conducted.

Although pipe failure may not be common, avoiding this problem ranks as a top priority for drillers. Pipe collapses as a result of excess exter-nal pressure, bursts from too much internal pres-sure, parts when subjected to excess tension or twists off because of too much torque. The industry has instituted various practices to reduce the risk of drillstring failure, beginning with inspection of tools, pipe and threads for wear and corrosion before they go into the hole, followed by careful use of pipe handling equipment and avoidance of excess torque during makeup.

In today’s high-angle wells, pipe wear can be accelerated by sharp changes in trajectory. Sharp turns impose alternating bending stresses on the pipe as it works through a dogleg.2 In addition,

high-angle wells are often beset by hole cleaning problems. To prevent cuttings from packing off around the drillstring, the driller may resort to high rotation and circulation rates to clean the wellbore. Such practices, however, increase the

likelihood of creating a hole, or washout, in the drillstring itself.3 When a drillstring washout develops before the well has been cleaned out, the operator must choose between continuing to circulate the wellbore clean or attempting to trip

>Master bushing. The master bushing transmits power from the rotary table to the kelly bushing to spin the drillstring. The master bushing lies flush with the drill floor (photograph), and any item that passes through its bowl may become a fish.

Bowl

> Drillstring failure. Excessive torque can cause a drillstring to part downhole. Here (left), the drillpipe has twisted off beneath the tool joint. Even thick-walled drill collars may be subjected to wear and fatigue (above).

28 Oilfield Review

out of the hole. Continuing to circulate runs the risk of enlarging the washout and weakening the drillstring; pulling out before the wellbore is clean runs the risk of sticking the pipe.4

To prevent pipe collapse, drillers keep the pipe filled with mud to offset external hydrostatic pressure of the mud in the annulus. They monitor makeup torque, hydraulics, rotary speed, weight on bit and hook load to avoid exceeding drill-string design limits. When tubulars do fail, they often produce a jagged, irregular length of pipe, which the fishing expert must contend with.

The drill bit is another common fish. Bits are engineered to withstand the rigors of weight, tor-sion and abrasion; nevertheless, drillers must be attentive to weight on bit, rotary speed, drilling fluid hydraulics, solids control, formation charac-teristics and time on bottom to prevent excessive bit wear and associated problems. Occasionally, a bit may seize up and break apart, leaving bit cones, bearings and teeth downhole (above). Although small, these components are hard and robust, and typically must be recovered to pre-vent damage to new bits or other equipment sub-sequently run in the hole.

Tool joints sometimes back off, or come unscrewed, from the drillstring. This develop-ment may occur when insufficient torque is applied as one joint of pipe is made up to another, or when the drillstring spins counter to its normal clockwise rotation. However, worn or

damaged pipe threads may also be a culprit; this problem can be avoided in part through careful handling of tool joints during makeup on the drill floor and by monitoring vibration and rotary speed while drilling to minimize stress on the drillstring.

Sometimes, the fault is traced back to manu-facturing controls, as one operator discovered. Having set a liner, the driller ran the bit to the top of cement. Although the topdrive stalled several times while drilling out the liner shoe, the driller was able to continue some 150 m [490 ft] beneath the shoe before observing erratic torque readings at the drill floor console. Later, approximately 5.5 kg [12 lbm] of steel shavings, circulated to surface in the drilling fluid, were recovered from the shale shaker screens and ditch magnets, pro-viding confirmation to the driller that there was a problem downhole.5

As the driller pulled out of the hole, the oper-ator ordered junk baskets and a junk mill dis-patched to the wellsite. (Upon its arrival, the junk mill was rejected for lack of proper inspec-tion certification; the operator chose not to risk compounding the problems downhole.) The driller ran in the hole with a bit and junk basket, drilling slowly for 3 m [10 ft] before readings of normal parameters confirmed that the hole was free of junk. Several more kilograms of metal cut-tings were recovered when the basket was pulled out of the hole, along with more at the ditch mag-nets. Further investigation revealed that the pipe threads on the liner shoe connection were not designed to withstand the same torque loads as those on the liner string. The operator concluded that back torque produced by stalling of the top-drive probably caused the left-hand thread of the liner shoe to break loose.

A large number of fishing jobs are instigated by sticking of the drillstring (next page). Many such incidents are caused by unstable forma-tions; others are related to drilling practices:• Loose or unconsolidated formation sands or

gravels can collapse into the borehole and pack off the drillstring as supporting rock is removed by the bit. Schists, laminated shales, fractures and faults also create loose rock that caves into the hole and jams the drillstring.

• In regions where tectonic stresses are high, rock is being deformed by movement of the Earth’s crust. In these areas, the rock around the well-bore may collapse into the well. In some cases, the hydrostatic pressure required to stabilize the hole may be much higher than the fracture initiation pressure of exposed formations.

• Mobile formations—typically salt or shale—can behave in a plastic manner. When compressed

by overburden, they may flow and squeeze into a wellbore, thereby constricting or deforming the hole and trapping the tubulars.

• Overpressured shales are characterized by for-mation pore pressures that exceed normal hydrostatic pressure. Insufficient mud weight in these formations permits the hole to become unstable and collapse around the pipe.

• Reactive shales and clays absorb water from the drilling fluid. Over time—ranging from hours to days—they can swell into the wellbore.

• Drillstring vibration may cause caving of the well-bore. These cavings pack around the pipe, causing it to stick. Downhole vibration is controlled by monitoring parameters such as weight on bit, rate of penetration and rotary speed, which can be adjusted from the driller’s console.

• Differential sticking presents a common prob-lem downhole. It happens when the drillstring is held against the wellbore by hydrostatic overbal-ance between the wellbore pressure and the pore pressure of a permeable formation. This problem occurs most commonly when a station-ary or slow-moving drillstring contacts a perme-able formation, and where a thick filtercake is present. Depleted reservoirs are the primary culprit for differential sticking.

• Keyseating takes place when rotation of the drillpipe wears a groove into the borehole wall. When the drillstring is tripped, the bottomhole assembly (BHA) or larger-diameter tool joints are pulled into the keyseat and become jammed. A keyseat may also form at the casing shoe if a groove is worn in the casing or the cas-ing shoe splits. This problem normally occurs at abrupt changes in inclination or azimuth, while pulling out of the hole and after sus-tained periods of drilling between wiper trips. Wireline logging tools and cables are also sus-ceptible to keyseating.

• Undergauge holes may develop while drilling hard, abrasive rock. As the rock wears away the bit and stabilizer, the bit drills an undergauge, or smaller than specified, hole. When a subse-quent in-gauge bit is run, it encounters resis-tance in the undergauge section of hole. If the string is run into the hole too quickly or without reaming, the bit can jam in the undergauge sec-tion. This problem may occur when running a new bit, after coring, while drilling abrasive formations or when a PDC bit is run after a roller cone bit.

• Cement blocks can pack off the drillstring when hard cement around the casing shoe breaks off and falls into the new openhole interval drilled out from under casing.

> Bit components. Bit cones, nozzles and other pieces of junk are typically small enough to be retrieved by a magnet or junk basket.

4. Eck-Olsen J and Foster BM: “Backing Off a Free Drillstring: Planning and Execution on a World-Class ERD Well,” paper SPE/IADC 104478, presented at the SPE/IADC Drilling Conference, Amsterdam, February 22–24, 2007.

5. Ditch magnets are strong magnets placed in the flowline to collect metallic debris from the drilling fluid as the mud is circulated to the surface.

6. Ali A, Blount CG, Hill S, Pokhriyal J, Weng X, Loveland MJ, Mokhtar S, Pedota J, Rødsjø M, Rolovic R and Zhou W: “Integrated Wellbore Cleanout Systems: Improving Efficiency and Reducing Risk,” Oilfield Review 17, no. 2 (Summer 2005): 4–13.

Winter 2012/2013 29

• Uncured, or green, cement may trap a drill-string after a casing job. When the top of cement is encountered while tripping in the hole, a higher than expected pressure surge may be generated by the BHA, causing the cement to set instantaneously around the BHA.

• Collapsed casing occurs when pressures exceed the casing collapse pressure rating or when

casing wear or corrosion weakens the casing. The casing may also buckle as a result of aggressive running practices. These conditions are typically discovered when the BHA is run in the hole, only to hang up inside the casing.

• Hole cleaning problems prevent solids from being transported out of the wellbore. When the cuttings settle at the low side of deviated wellbores, they form layered beds that may

pack around the BHA. Cuttings and cavings may also slide down the annulus when the pumps are turned off, thus packing around the drillstring. These problems are frequently caused by low annular flow rates, inadequate mud properties, insufficient mechanical agi-tation and short circulation time.6

> Sticking mechanisms. The driller must avoid or contend with a variety of potential problems in order to reach TD.

Differential Sticking

Geopressured ZoneUnconsolidated Zone Fractured or Faulted Zone

Undergauge HoleKeyseating

Reactive FormationMobile Formation

Collapsed Casing Junk

Wellbore GeometryPoor Hole Cleaning

Cement Problems

Drillstring Vibration

30 Oilfield Review

Indications that a fish might be lost downhole are usually seen on the drill floor as sudden changes in drilling rate, mud pressure, hook load or rotary torque; these changes typically spur a trip out of the hole. The condition of the last joint of pipe to clear the rotary table tells the drilling crew most of what they may have already sus-pected. A jagged joint of pipe, paired with an accurate pipe tally, tells the driller not only that the pipe has parted, but also how much pipe remains in the hole. By contrast, a damaged bit indicates that a few small metal pieces remain in the hole.

Tools of the TradeThe type of fish and the downhole conditions dic-tate the fishing strategy. Numerous innovative tools and techniques have been developed for retrieving pipe, downhole components and mis-cellaneous junk from the wellbore. Most fishing tools fit into one of five categories:• Junk baskets catch small objects or pieces of

debris that are too heavy to circulate out of the hole.

• Milling tools grind down the upper surface of an object.

• Cutting tools sever pipe. • External catch tools retrieve fish by engaging

the outer surface of the fish.• Internal catch tools engage the inner surface of

the fish. The solution to any fishing problem depends

on where the fish is, how it came to be there, its condition, its dimensions and its orientation

within the wellbore. The orientation and size of the borehole are also critical; these parameters can limit the type and diameter of the retrieval equipment and restrict the space available for maneuvering retrieval equipment over the fish. A large-diameter wellbore, however, may make it difficult to locate the top of the fish.

To devise a fishing program, the operator must know the exact size and shape of the fish. Lack of correct dimensional data can doom a fishing job. For this reason, company representa-tives require each item that goes into the hole to be accurately drawn, then strapped with a mea-suring tape for length and calipered for breadth.

If the driller is not sure what type of junk must be retrieved, the drilling crew may run an impression block in the hole to ascertain the position and shape of the top of a fish (below left). Impression blocks have a short, tubular steel body fitted at the lower end with a block of soft material—typically a lead insert. The tool is lowered on the end of the fishing string until it makes contact with the obstruction. Some impression blocks have a circulation port for pumping drilling fluid to clean the top of the fish before the block sets down on it. The weight of the fishing string helps press the lead against the top of the fish, creating an impression; the driller or fishing expert carefully studies this impression when the block reaches the surface. This prelimi-nary information helps the operator determine the depth of the fish and the type of fishing equip-ment to deploy. Impression blocks can also be run on slickline, which is much faster than run-ning in on drillpipe; however, there are weight and size limitations for this method.

Small pieces of junk or debris, such as hand tools, bit cones or pipe-tong dies, can be retrieved with a junk basket or junk magnet. Junk baskets are available in a variety of con-figurations, each taking a different approach to recovering lost items.

To retrieve small pieces of junk from the bot-tom of a well, fishermen sometimes use a core-type junk basket. By slowly cutting a core from the formation, this device recovers the junk along with the core. This operation is often employed in soft to medium-soft formations.

Boot baskets, used in drilling and milling operations, catch debris that is too heavy to be circulated out of the hole. These baskets are run as close as possible to the bit or mill and are sometimes run in tandem to increase junk retrieval capacity. The boot basket is used at the bottom of the hole and relies on circulating mud to carry the junk off-bottom. Because the annu-

lus is wider above the junk basket, the annular mud velocity decreases, and as a result, the junk settles out of suspension and lands inside the basket (above).

A jet junk basket produces a circulating force that is capable of lifting stubborn items such as chain from the bottom of the hole. These baskets use ports near their base to produce a reverse circulation that forces the material up through the center of the basket. The jet junk basket can be run in cased or open hole to retrieve small debris from the wellbore and is effective in verti-cal or horizontal applications (see “Specialized Tools for Wellbore Debris Recovery,” page 4).

Junk magnets are used to retrieve ferrous debris such as bit cones, bearings, milled cut-tings and pins that may be hard to retrieve using other methods (next page, top left). These tools have a highly magnetized internal pole plate within a nonmagnetic body. Junk magnets are also typically run in advance of diamond bits to remove debris that could damage the bit.

If the junk is not fully recovered, the opera-tor may elect to run a used bit and attempt to drill and wash past the fish. Should this strategy fail, the junk can be broken into smaller pieces using a junk shot or a mill. A junk shot is a shaped charge, designed to direct its energy

> Impression block. If there is any uncertainty about what type of object must be retrieved, the operator may first run an impression block in the hole. This device uses an insert of soft lead, which provides a surface on which to obtain an impression of the top of the fish.

Lead insert

> Boot basket. Circulation of drilling fluid lifts the junk off-bottom. Beneath the tool joint, mud velocity decreases as the annulus grows wider. This decrease in mud velocity allows the junk to settle into the basket opening.

Basket opening

Winter 2012/2013 31

downward to break up the object. A more con-ventional approach is to grind the object using a concave mill (below). The concavity of the mill helps to center the junk beneath a thick cutting surface of tungsten carbide that breaks the junk into smaller pieces, which can then be washed or circulated for capture by junk baskets above the mill.

Mills are available in a range of configura-tions for use in various applications (right). They are often used to dress the top of the fish to accommodate a fishing tool, but some are also used to grind float collars, bridge plugs and retainers. The debris produced through milling is then picked up by magnets or junk baskets or cir-culated from the well. Techniques for Larger Fish

Retrieving large fish, such as drillpipe or collars, requires a different approach. Many of these jobs start with the assumption that any pipe left in the hole will likely become stuck. With no mud circu-lating around the fish, cuttings can settle around the pipe or the formation might pack off, which will restrict further movement. Thus, when a drillstring gets stuck, twists off or backs off, the recovery plan typically involves freeing the fish.

When fishing for pipe, the basic strategy involves running jars and an overshot into the hole, latching onto the fish, jarring the pipe free and then pulling the fish out of the hole. However, no fishing job is typical and no job is that easy; the top of the fish may be damaged, requiring a mill to dress the fish, or the fish may be difficult to engage, requiring several attempts to latch onto it.7 Furthermore, each of the basic steps above encompasses a number of procedures.

When a drillstring becomes stuck, the driller usually activates downhole jars to free the pipe through percussive force.8 In the case of differen-tial sticking, the operator typically orders a pill—a special blend of surfactants, solvents or other compounds—to be pumped downhole to help free the pipe from differential sticking. The driller pumps this spotting fluid downhole to pen-etrate and break up the filtercake along the pipe and reduce the area of pipe subjected to sticking. This helps decrease the force required to move the pipe and free the drillstring. The likelihood that this approach will remedy the problem decreases rapidly with time, so once a drillstring

> Junk magnet. This type of magnet is used to retrieve small pieces of ferrous material from the hole. Some junk magnets have circulating ports that enable cuttings to be washed away from the junk.

Magnets

> Junk mill. A slight concavity to the face of the mill helps to center the junk beneath the cutting surface so it can be ground into smaller pieces.

> Downhole milling tools. Mills come in a variety of sizes and configurations. The taper mill (top) is designed for milling through tight spots and cleaning out collapsed or deformed tubulars. A pilot mill (center) may be employed to mill sections of tubular junk or to dress casing prior to installing a casing patch. The larger milling blades are guided by the small central pilot at the front of the tool. The string taper mill (bottom) may be used for cleaning out damaged tubulars and is also recommended for removing keyseats in open hole. Tapering at the top and the bottom of this mill allows it to ream in both directions.

Taper Mill

Pilot Mill

String Taper Mill

7. Adkins CS: “Economics of Fishing,” Journal of Petroleum Technology 45, no. 5 (May 1993): 402–404.

8. For more on jars: Costo B, Cunningham LW, Martin GJ, Mercado J, Mohon B and Xie L: “Working Out of a Tight Spot,” Oilfield Review 24, no. 1 (Spring 2012): 16–23.

32 Oilfield Review

is stuck, it is essential to spot the fluid as quickly as possible. While the spotting fluid is working, the operator usually starts planning the fishing job and mobilizing equipment and personnel.

If the spotting fluid does not free the pipe, the operator may elect to sever the pipe and pull out of the hole to prevent sticking farther up the hole. The goal is to part the drillstring at the greatest depth possible and thus recover the maximum amount of pipe. The first step in this process, however, is to determine the uppermost depth at which the pipe is stuck. In accordance with Hooke’s law, when a drillstring is subjected to pull or torsion within its elastic limits, the pipe deforms linearly. Such behavior can be used to calculate how much free pipe remains above the stuck point.

The operator typically calls for an FPIT free-point indicator tool to precisely measure pipe stretch and torque. The FPIT device is lowered on wireline through the center of the drillpipe, then anchored in place as a given amount of force is applied to the pipe. FPIT strain gauges sense changes in torque and tension as the drillstring is subjected to rotation or pull, respectively. The stretch produced by this force is a function of the length of free pipe, the elasticity of the steel and its cross-sectional area. The tool should detect no tensile load or rotation when positioned below the stuck point.

If circulation is established, the FPIT device may be pumped down the center of the drillpipe; otherwise, the operator might resort to coiled

tubing or a wireline tractor to convey the tool downhole.9 Once the free point has been estab-lished, the same conveyance method is used to lower any tools needed to sever the pipe. Parting the drillstring involves either unscrewing—back-ing off—the drillpipe downhole or cutting it.

Backing off the pipe is the least drastic mea-sure and leaves a threaded pipe connection at the top of the fish. Before unscrewing the pipe downhole, the driller must apply left-hand torque to the drillstring. The torque is worked downhole by reciprocating the pipe as the torque builds up. A string shot, consisting of a length of detonation cord, is lowered through the drillpipe to the depth opposite a tool joint above the free point. Upon detonation downhole, explosive pressures enlarge the thread in the box end of the tool joint and the left-hand torque unscrews the threaded connection to back off the pipe. The process may be repeated to force the pipe loose.

If the pipe cannot be unscrewed, a variety of methods may be employed to cut the pipe. A chemical cutter is a wireline tool that utilizes a propellant and reactant to create a series of closely spaced holes in the pipe. The holes weaken the pipe sufficiently to pull it apart. This method requires no application of torque on the drillstring and produces little burring and swell-ing of the pipe, thus obviating the need for mill-ing. Another wireline device, an explosive cutter, sends out a 360° radial explosive jet to sever the pipe. Some explosive cutters leave a smooth cut, but others produce a flared edge that must be dressed with a mill to accommodate subsequent retrieval operations. A third method uses mechanical pipe cutters, which are lowered on washpipe to the desired depth. Hydraulic pres-sure forces the cutter arms against the inside of the pipe. The cutting surfaces are dressed with crushed tungsten carbide to sever the pipe as the tool rotates slowly inside the pipe.

Having separated free pipe above the stuck point, the driller trips out of the hole. The fishing expert will be on the drill floor to examine the last joint of pipe when it is brought to surface. The condition of that joint dictates the course of the ensuing fishing job.

Catching OnThe two methods most commonly employed to retrieve a fish are the external catch and the internal catch. The dimensions of the fish and its orientation with respect to the wellbore deter-mine which approach is used.

The external catch is provided by a box tap or an overshot. The box tap uses a tapered thread to screw over the top of the fish (left). Typically

used to engage ragged, parted pipe, this tool is slowly rotated as it is lowered onto the fish. The bottom lip of the tool is often dressed with hard metal or crushed tungsten carbide to aid in cut-ting a thread into the surface of the outer diam-eter of the fish.

The overshot is designed to engage, pack off and retrieve parted drillpipe or drill collars (above). A tapered helical bowl within the over-shot houses a grapple used to grip the outside of the fish. As the overshot is lowered toward the top of the fish, the driller circulates mud while reciprocating the fishing string to clean the top of the fish and flush out the inside of the overshot.

Before engaging the fish, the driller records fishing string weight and torque. After washing over the top of the fish, the driller slowly lowers the overshot until a slight reduction in weight indicates it has landed on top of the fish. The overshot guide slides over the top of the fish as the driller slowly lowers and rotates the overshot. By turning to the right, the grapple opens to engage the fish. Upward pull, with no rotation, will cause the grapple to retract inside the tapered bowl, thus constricting around the fish. With the top of the fish gripped firmly inside the overshot, the driller pulls the fishing string and fish out of the hole.

> Box tap. This device is designed to externally engage and retrieve tubulars that cannot be rotated. It uses a tapered wicker thread sized to fit over the top of the fish.

> Overshot. The overshot is divided into three segments. The top sub connects the overshot to the workstring. The bowl has a tapered helical design to accommodate a grapple, which holds the fish in place. The guide helps position the overshot onto the fish.

Top sub

BowlGrapple

Guide

9. For more on downhole conveyance methods: Billingham M, El-Toukhy AM, Hashem MK, Hassaan M, Lorente M, Sheiretov T and Loth M: “Conveyance— Down and Out in the Oil Field,” Oilfield Review 23, no. 2 (Summer 2011): 18–31.

Winter 2012/2013 33

Overshots can be fitted with a variety of grap-ples, control packers and accessories, with some strong enough to accommodate backoff and jar-ring operations. A common accessory is a mill guide, installed at the base of the overshot to grind away flared or jagged edges of the fish to permit passage into the grapple. The mill acces-sory makes it possible to dress off and engage the fish in one trip. Fishermen deploy another basic but useful device when the wellbore is enlarged or washed out near the top of the fish. The wall hook guide is attached to a bent joint of pipe or a hydraulic knuckle joint to sweep a washed-out section of hole (above). Once the overshot has passed the top of the fish, the string is slowly rotated until the rotary torque indicates that the fish has been hooked. The torque is held while the string is elevated. When the torque decreases, the fish slips into position for engage-ment by the overshot.

Although the basic overshot has changed very little over the past few decades, it continues to be used to great effect. An operator in New Mexico,

USA, had to contend with a downhole pipe failure in a well. During drilling of a 7 7/8-in. hole, a joint of 6 1/8-in. drill collar twisted off, leaving behind a parted drill collar and the BHA. While pulling out of the hole, the operator called on Schlumberger

fishing services to retrieve the remaining drill-string from the hole. The fishing expert made up a fishing string consisting of drillpipe, drill col-lars, a jar, a bumper sub and an overshot (above). The driller ran the fishing string in the hole and

>Wall hook guide. If the hole size is much greater than the fish diameter, the overshot may pass alongside the fish, rather than engaging it. This condition forces the fishing specialist to install a wall hook guide to ensure alignment of the fish with the overshot.

> Fishing string. A basic fishing string, with jar and overshot, was used in a well in New Mexico to retrieve a fish after it twisted off from the rest of the drillstring.

Drillpipe

Drill collars

Jar

Overshot

Drill collars

Bumper sub

Twistoff

Bit

34 Oilfield Review

succeeded in reaching the top of the fish. After the overshot engaged the twisted off collar, the fisherman noted an increase in weight as the driller slowly pulled on the fishing string. Once the fishing specialist was assured that the over-shot had latched onto the fish, the driller tripped out of the hole and laid down the fish for exami-nation on the pipe rack. There, the operator attributed the problem to pipe fatigue.

If the orientation or condition of the fish will not permit use of an overshot, then the fisher-man must resort to an inside catching device to engage the fish. Variations on the inside catch-ing device include the pin tap, taper tap and spear (above).

A pin tap is used with a fish that has been backed off from the string of pipe. This leaves a box tool joint facing upward so it can be engaged by the tap.

A taper tap provides an internal catch on tubulars that have a restricted internal diameter. It has a long tapered profile and is used to cut new thread while screwing into the top of the fish. This tool is run in the hole to the top of the fish and then rotated to engage the threads. It is normally used in conjunction with a safety joint, which provides a means of detaching the work-string from the fish in the event that the work-string becomes stuck.

A spear uses an internal grapple, or slip, that expands to grip against the inside wall of the pipe as the driller pulls out of the hole. The tool is made up on the end of the workstring then low-ered through the top of the fish. When the fishing expert determines that the spear is positioned deep enough within the fish, the workstring is rotated to engage the grapple. A straight pull,

with no further rotation, wedges the grapple against the pipe as the driller retrieves the work-string and fish from the hole. Some spears come with accessories such as mills, which are placed at the base of the spear to grind away jagged edges or other obstructions.

Another basic tool deployed inside tubulars may need to be run to open the way for further fishing. The casing swage is used to restore dented, buckled or collapsed casing to nearly its original shape and diameter (below). The swage relies on mechanical force supplied by down-hole impact equipment such as a bumper sub or drilling jar to open casing obstructions. Incremental sizes allow swaging to repair vari-ous degrees of casing collapse. This tool is fre-quently run before production equipment is deployed to ensure that tools will pass cleanly through the casing.

> Internal catch devices. Pin taps (left) are used to make up to a box tool joint when retrieving a tubular fish that is restrained from rotation. One-piece taper taps (center) are constructed with a fine thread form that enables the tap to work as a threading tool. Flutes in its threading give it a cutting edge to assist in tapping into the fish. The fishing spear (right) provides engagement over a large area of pipe to minimize distortion of the fish.

Grapple

Pin Tap

Fishing Spear

Taper Tap

Bullnosenut

> Casing swage. The conical shape of the swage enables operators to restore deformed casing to nearly its original size and shape.

Economic ConsiderationsThe decision to fish—or not—must be weighed against a need to preserve the wellbore, recover costly equipment or comply with regulations. Each choice is fraught with its own costs, risks and repercussions. Before committing to a spe-cific course of action, the operator must consider a number of factors: • Well parameters: proposed total depth, current

depth, depth to top of the fish and daily rig operating costs

Winter 2012/2013 35

• Lost-in-hole costs: the value of the fish minus the cost of any components covered by tool insurance

• Fishing costs: daily fee for fishing expertise and daily rental charges for fishing tools and jars

• Fishing timetable: time spent mobilizing fish-ing tools and personnel, estimated duration of the fishing job and the probability of success.

Cost usually dictates the maximum duration of the fishing job. Thus, a shallow hole with little rig time and equipment invested will probably war-rant a minimal expenditure in fishing time. By contrast, when the lost equipment represents a large capital investment, more time and expense are justified. Some operators mandate that once fishing costs reach about half the cost of kicking off and redrilling, then fishing operations should be abandoned in favor of sidetracking.10

Various formulas and proprietary programs have been developed to help operators determine how much time should be spent trying to retrieve a fish (above right). Experience has shown that the probability of successful retrieval diminishes rapidly with time. This conclusion tends to pro-vide an incentive for starting fishing operations as soon as possible, with the assurance that beyond a certain point, the chances of catching the fish become nil. When it comes to fishing for stuck pipe, for example, many operators draw the line at four days, including time spent working the pipe or spotting pills.

If the decision is to abandon the fish, the operator must then decide whether to J&A the hole, complete the well above the fish or side-track around it. In the case of junking and aban-doning the well, the operator’s geoscientists may be able to find value in the data obtained from the well, which may influence subsequent decisions regarding whether or not to drill an offset well.

Some wells encounter productive horizons on their way to deeper pay zones. If reserves in shal-lower horizons are sufficient to justify comple-tion, the operator may decide to forgo pursuit of deeper pay when faced with a fishing job; instead, the company can abandon the deep hole and set pipe in the shallower pay. This option will be impacted by the replacement cost of the equip-ment left in the hole, the probability of its recov-ery, the cost of the shallow completion and the amount of reserves in the shallow zone.

Another option is to sidetrack. In addition to accounting for the cost of equipment left in the hole, the operator should weigh the following: • the cost and time required for shipping a whip-

stock, drilling motor or other equipment used to sidetrack the well

• the cost of setting cement plugs down to the kickoff point, setting time and tripping in prep-aration to sidetrack

• the cost of drilling from kickoff point to TD• the probability of getting stuck in the same

interval again.In certain areas, an operator may find that fish-

ing is more expensive than sidetracking, or that the latter may have a more reliable outcome. For openhole jobs, setting a cement plug and whip-stock may be an attractive alternative to days of nonproductive time. This option is not popular in all regions, however, and demand for fishing may actually see a resurgence in some areas.

Training for the FutureFishing expertise is hard won, gained primarily through on-the-job exposure to a myriad of challeng-ing operational situations in difficult wellbores. Currently, the “great crew change” is sweeping a number of experienced fishing hands into retire-ment, thus reinvigorating the imperative to train more fishing specialists. In response, Schlumberger has instituted a training program for fishing crews. The curriculum is designed to develop students’ fishing skills and sharpen their technical knowl-edge; the curriculum is supplemented by actual field operations to strengthen proficiency.

The program provides progressive exposure to a wide range of tools and fishing techniques. With a prerequisite that ensures all trainees are famil-iar with the tools used in their region of opera-tions, the first-level course provides field specialists and field engineers with hands-on

training that concentrates on shop assembly and disassembly, supplemented by classroom instruc-tion and rig-site training.

The trainees are then assigned to the field to a number of fishing, wellbore departure and well abandonment jobs before they become eligible for the next step in their development. These jobs are carried out by experienced personnel with the trainee assisting.

The second level of training goes into greater depth on fishing techniques and is supplemented by case studies. The trainees conduct job planning exercises based on actual fishing jobs. They design a complete BHA for the job and present their plans to the class for evaluation and brainstorming. Following this class, the trainees continue their field training and conduct a number of solo jobs before moving on to the next level.

The final level of training focuses on the man-agerial side of fishing and remediation to train personnel for supervisory roles. Such training is vital to the future of the oil patch, because as long as downhole equipment or wellbores fail, fishing expertise will be in demand. —MV

> Basic fishing equation. This formula is used to determine the optimal number of days to fish, based on economics.

= number of days allocated for fishing

= value of the fish

= estimated cost of sidetracking the well

= daily fishing tool rental and personnel charges

= daily rig operating cost.

Df

Vf

Cs

Cf

Cd

where

,Df = (Vf + Cs) / (Cf + Cd)

10. Muqeem MA, Weekse AE and Al-Hajji AA: “Stuck Pipe Best Practices—A Challenging Approach to Reducing Stuck Pipe Costs,” paper SPE 160845, presented at the SPE Saudi Arabia Section Technical Symposium and Exhibition, Al-Khobar, Saudi Arabia, April 8–11, 2012.

36 Oilfield Review

CO2 Sequestration—One Response to Emissions

That human activity is having a deleterious effect on the Earth’s natural heating and

cooling cycle is widely accepted by the scientific community. However, how humans

can and should respond is far less certain. One approach now being demonstrated at

the field scale around the world—carbon capture, utilization and storage—removes

carbon dioxide from emissions sources and seals it beneath the Earth’s surface.

Ahsan AlviEric H. BerlinJim KirkseyChampaign, Illinois, USA

Bill BlackDavid LarssenBurnaby, British Columbia, Canada

Michael Carney Houston, Texas, USA

Ethan ChaboraRichmond, California, USA

Robert J. FinleyHannes E. LeetaruIllinois State Geological SurveyChampaign, Illinois

Scott MarstellerAnchorage, Alaska, USA

Scott McDonaldArcher Daniels Midland CompanyDecatur, Illinois

Ozgur SenelSugar Land, Texas

Valerie SmithWesterville, Ohio, USA

Oilfield Review Winter 2012/2013: 24, no. 4. Copyright © 2013 Schlumberger.For help in preparation of this article, thanks to Tony Booer, Abingdon, England; Robert J. Butsch, Houston; Daniel Byers and Scott Frailey, Illinois State Geological Survey, Champaign, Illinois; Marcia Couëslan, Calgary; Lori Gauvreau, Oslo, Norway; and Dwight Peters, Sugar Land, Texas.ECLIPSE, EverCRETE, Petrel, RSTPro, RTAC and Westbay are marks of Schlumberger.

Most scientists have concluded that Earth’s natu-ral temperature fluctuations are distorted by man-made greenhouse gases (GHGs), particu-larly carbon dioxide [CO2]. These greenhouse gases enter the atmosphere as a by-product of industrial activity (below).1 In 2010, the Intergovernmental Panel on Climate Change (IPCC) set a target to limit global temperature increase to 2°C [3.6°F] above the preindustrial average.2 The panel proposed to accomplish this goal by limiting the growth of GHG concentra-

tions in the atmosphere to between 445 and 490 parts per million (ppm) CO2 equivalent. At the end of 2010, concentrations had grown from preindustrial concentrations of about 270 ppm to 390 ppm.3 However, limiting GHG concentra-tions by focusing on the source—carbon-fueled human activity—presents significant challenges. According to the IPCC data, emissions from exist-ing infrastructure account for 80% of the CO2 allowed by the cap.4 Therefore, as the world’s population and carbon fuel–based economies

> Emissions and temperature. Anthropogenic CO2 emissions (blue) have substantially increased during the past 160 years, leading to a significant increase in atmospheric concentrations of the gas. Associated with this increase have been higher than expected annual positive temperature anomalies (red) leading to higher temperature increases than would be projected using historical mean temperatures. [Adapted from Global CCS Institute: “The Global Status of CCS: 2011,” http://cdn.globalccsinstitute.com/sites/default/files/publications/22562/global-status-ccs-2011.pdf (accessed August 23, 2012).]

400

380

360

340

320

300

280

260

240

220

2001850 1870 1890 1910 1930

Year1950 1970 1990 2010

0.6

0.4

0.2

0.0

–0.2

–0.4

–0.6

–0.8

–1.0

Atm

osph

eric

CO 2, c

once

ntra

tions

, ppm

Glob

al te

mpe

ratu

re a

nom

aly,

°C

Temperature

CO2

Winter 2012/2013 3737

continue to grow, many consider capping emis-sions to be synonymous with capping economic growth—a trade-off few political leaders are will-ing to make.

Staying below the CO2 cap through the use of alternative energy sources alone has thus far proved an unlikely solution. Today, solar, wind and other renewable sources are able to supply

only a small fraction of the world’s energy demands. Nuclear energy, while technically mature and economically viable, has become politically unpalatable worldwide since a 2011

Industrial users

CO2

Greenhouse gas emissions

Greenhouse gas e

missions

Green

hous

e gas

emiss

ions

CO2

Seal

CO2 displaces methane from coal.

Seal

Seal

Seal

CO2 displaces trapped oil for enhanced oil recovery.

CO2 is stored in saline formations.

Enha

nced

oil

recov

ery

Oil

CO2

Ethanol plants Cement and steel refineries

CO2 capture

G

Electricity generation

Food productsCOCOCOCOCOCO aaaaaa ttptptptptptpptppp

CO2 is stored in depleted oil and gas reservoirs.

1. For more on consensus among leading scientific bodies on global climate change: Union of Concerned Scientists: “Consensus on Global Warming,” http://www.ucsusa.org/ssi/climate-change/scientific-consensus-on.html (accessed August 17, 2012).

2. The IPCC sets the beginning of the industrial age at around 1850 as fossil fuel usage began to rise dramatically and fossil fuel quickly became the most commonly used fuel.

3. Moomaw W, Yamba F, Kamimoto M, Maurice L, Nyboer J, Urama K and Weir T: “Renewable Energy and Climate Change,” in Edenhofer O, Pichs-Madruga R, Sokona Y, Seyboth K, Matschoss P, Kadner S, Zwickel T, Eickemeier P, Hansen G, Schlomer S and von Stechow C (eds): IPCC Special Report on Renewable Energy Sources and Climate Change Mitigation. New York City: Cambridge University Press (2011): 161–207.

4. International Energy Agency: World Energy Outlook. Paris: International Energy Agency, 2011.

38 Oilfield Review

earthquake and tsunami destroyed a nuclear power plant in Fukushima, Japan. Consequently, the vast majority of the world’s growing appetite for energy in the foreseeable future will be satis-fied by traditional fossil fuel sources.

Given this reality, it is clear that the world’s demand for energy and its environmental con-cerns are not likely to be reconciled through reduced emissions alone. One solution to this apparent impasse may lie not in reducing emis-sions, but instead in preventing the most signifi-cant GHG component—CO2—from entering the atmosphere by removing it from emissions as they are created.

The process of carbon capture, utilization and storage (CCUS) removes CO2 gas from emissions, dehydrates and purifies it and compresses it to a liquid state. The liquid CO2 is then transported to wellheads or other locations for use in enhanced

oil recovery projects, injected deep into the Earth to be stored for millennia or utilized as feedstock in chemical manufacturing.5 For the upstream oil and gas industry, the transport and storage seg-ment of the process is a familiar one. For decades, engineers have been designing subsurface injec-tion systems for formation pressure mainte-nance, gas storage, enhanced oil recovery and disposal. This article examines how upstream oilfield expertise, methods and technologies are being applied to CO2 geologic storage.

Resource Governments worldwide are concerned with cap-turing CO2, separating it from stationary point source emissions and storing it (above). To that end, they are seeking realistic estimates of poten-tial carbon dioxide storage resources. In the US and part of Canada, these approximations are

supplied by the US Department of Energy (DOE) through the creation of Regional Carbon Sequestration Partnerships (RCSPs).6 The DOE sought to determine available underground space for CO2 sequestration by considering three types of formations—oil and gas reservoirs, saline formations and unminable coal deposits.

The resulting resource estimates represent the fraction of pore space volume in sedimentary rocks that is accessible to injection and available for CO2 storage. Potential resources were screened using the following criteria:• isolation from shallow groundwater, producible

hydrocarbons, other strata, soils and atmosphere• gravity segregation• maximum allowable injection pressure• caprock or seal capillary entry pressure• displacement efficiency.7

> Overview of large-scale injection projects (LSIPs) around the world. According to the Global CCS Institute annual survey undertaken in 2011, 74 LSIPs around the world are in varying stages of planning and completion. LSIPs are defined as those that involve the capture, transport and storage of CO2 at a scale of not less than 800,000 metric tons (Mg) [882,000 tonUS] of CO2 annually for a coal-based power plant and not less than 400,000 Mg [441,000 tonUS] of CO2 annually for other emission-intensive industrial facilities such as natural gas–based power generation. Projects in the first three columns denote LSIPs in planning stages. The Identify column represents those on a developer’s short list of options that are undergoing concept and site screening studies. Those in the Evaluate column are further refined and in prefeasibility, cost and site assessment studies. Those in the Define column are being examined for technical and economic viability. Projects in the two columns on the right are active projects. Those in the Execute column are in the final stages of design, organization, construction and commissioning. Those in the Operate column are in full operation mode per regulatory compliance requirements. [Adapted from the Global CCS Institute: “The Global Status of CCS: 2011,” http://cdn.globalccsinstitute.com/sites/default/files/publications/22562/global-status-ccs-2011.pdf (accessed August 23, 2012).]

Identify

1

1

1

0

4

0

1

0

8

30

25

20

15

10

5

United States

Europe

Australia and New Zealand

Canada

China

Middle East

Other Asia

Africa

Total

Num

ber o

f pro

ject

s

Evaluate

8

9

5

2

2

1

1

0

28

Define

9

9

0

4

0

2

0

0

24

Execute

3

0

1

2

0

0

0

0

6

Operate

4

2

0

1

0

0

0

1

8

Total

25

21

7

9

6

3

2

1

74

Winter 2012/2013 39

Engineers assessed oil and gas reservoirs at the field level based on the volume of oil and gas that has been or can be produced and based on the assumption that the volume could be replaced by an equivalent volume of CO2. Saline forma-tions and unminable coal deposits were assessed at the basin level.8

Saline formations consist of brine-saturated porous rock capped by one or more regionally extensive low-permeability rock formations. Saline formations assessed for storage by the US DOE and the RCSPs were restricted to those with the following characteristics:• pressures and temperatures able to keep the

CO2 in a dense liquid phase• a suitable seal system able to limit vertical flow

out of the reservoir• hydrogeologic conditions able to isolate the CO2.

Unminable coal deposits were limited to those areas containing water with a total dis-solved solids concentration greater than 10,000 ppm. Depending on the geothermal and geopres-sure gradients in a coal formation, gaseous CO2

adsorption may be possible down to a depth of only about 900 m [3,000 ft].9 At greater depths, liquid-phase CO2 may enter the solid coal and change its properties, swelling the coal matrix, and causing injectivity problems.10 Additionally, injection may cause closure of coal cleats, reduc-ing permeability.11

The methodology developed for the estima-tion process for all three types of environments is based on volumetric methods, in situ fluid distri-butions and fluid displacement processes. Such methods assume an open system in which in situ fluids are displaced from the formation by the injected CO2. The primary constraint on pore space available for CO2 is based on displacement efficiencies rather than on pressure increases.

There is a great degree of uncertainty associ-ated with US DOE estimates of storage volume available in saline formations because of the sparsity of well data. In the oil and gas industry, the designation of a formation as a resource indi-cates a lack of data and a level of uncertainty about the presence, size or recoverability of spe-cific hydrocarbon deposits. As more data are gathered through exploratory and delineation wells, increased certainty allows the operator to change the play classifications from possible to probable to proved developed producing (PDP) reserves. These well-defined classifications are used globally, including by the US Securities and Exchange Commission, to assess company assets for public accounting purposes.

Engineers evaluating porous and permeable zones may use a similar system to classify a car-bon capture and storage (CCS), or sequestration, resource (above).12 Moving a resource from the

PDP classification to storage capacity—the CCS equivalent of reserves—requires greater cer-tainty about formation properties. The operator must determine the rate at which the formation

5. Although the term storage is often used to denote the possibility the CO2 will be retrievable for future use and the term sequestration is used to indicate permanent isolation of the gas, the two terms are often used interchangeably.

6. The US Department of Energy (DOE) has created seven regional partnerships made up of state agencies, universities, private companies, national laboratories and nonprofit organizations to establish technology, infrastructure needs and regulations for CCS.

7. Bachu S: “CO2 Storage in Geological Media: Role, Means, Status and Barriers to Deployment,” Progress in Energy and Combustion Science 34, no. 2 (2008): 254–273.

8. Litynski J, Deel D, Rodosta T, Guthrie G, Goodman A, Hakala A, Bromhal G and Frailey S: “Summary of the Methodology for Development of Geologic Storage Estimates for Carbon Dioxide, Appendix B,” in US DOE National Energy Technology Laboratory (NETL) (ed): Carbon Sequestration Atlas of the United States and Canada, 3rd edition, Washington, DC: US DOE NETL, (November 2010): 136–159.

> Proposed classification system. In an effort to establish a common framework for dividing CCS resources into classifications, scientists have suggested adapting analogous ones used by the E&P industry. The proposed framework is divided into three phases that correspond to resource classes: the exploration phase (bottom), in which prospective resources are comparable to prospective storage resources; site characterization (center), in which contingent resources are comparable to contingent storage resources and an implementation phase (top), in which reserves are comparable to storage capacity. Each resource class is then further divided into project status subclasses to show project maturity. For example, the exploration phase is divided into subsets that include comprehensive evaluation processes for classification comparable to those performed by E&P engineers for site screening, site selection and initial characterization processes. (Adapted from Rodosta et al, reference 12.)

Reserves

Implementation

Site Characterization

Exploration

Storage Capacity

E&P Resource Classifications Proposed CCS Resource Classifications

On production

Approved for development

Justified for development

Active injection

Approved for development

Justified for development

Development pending

Development unclarified or on hold

Development not viable

Development pending

Development unclarified or on hold

Development not viable

Prospect

Lead

Play

Potential subregions

Selected areas

Qualified site(s)

Contingent Resources Contingent Storage Resources

Prospective Resources Prospective Storage Resources

Project subclass

Potential subregions

Selected areas

Qualified site(s)

Evaluation process

Site screening

Site selection

Initial characterization

Prospective Storage Resources

Potential subregions

Selected areas

Qualified site(s)

Prospective Storage Resources

9. Bachu S, Bonijoly D, Bradshaw J, Burruss R, Holloway S, Christensen NP and Mathiassen OM: “CO2 Storage Capacity Estimation: Methodology and Gaps,” International Journal of Greenhouse Gas Control 1, no. 4 (2007): 430–443.

10. Metz B, Davidson O, deConick HC, Loos M and Meyer L (eds): Carbon Dioxide Capture and Storage. Cambridge, England: Cambridge University Press (2005), http://www.ipcc.ch/publications_and_data/publications_and_data_reports.shtml (accessed July 10, 2012).

Injectivity is the maximum rate and pressure at which fluids can be pumped into the formation without fracturing it.

11. Coal cleats are natural fractures in coal beds.12. Rodosta TD, Litynski JT, Plasynski SI, Hickman S,

Frailey S and Myer L: “US Department of Energy’s Site Screening, Site Selection, and Initial Characterization for Storage of CO2 in Deep Geological Formations,” Energy Procedia 4 (2011): 4664–4671.

40 Oilfield Review

can accept injected CO2, the pressure necessary for safe injection and the ultimate volume that may be stored. To determine these parameters, the operator must drill wells to obtain data on the porosity and permeability of the formation that is the target for CO2 injection. The equiva-lent of the oil and gas PDP classification for car-bon storage may be thought of as proved developed storage capacity.13

Before the wells are drilled, a site must be selected using specific criteria that often differ from oilfield practices. Among the parameters sought for CCS well injection sites is proximity to the source, which may allow the operator to dis-pense with the cost of building pipelines. In con-trast to the oil industry, CCS operators seek areas

with minimal penetrations into the zone of inter-est. Though this reduces offset well data that are valuable to engineers for selecting oil and gas well drilling sites, for injection purposes, a lack of well-bores through the storage formation minimizes the potential for leaks through the caprock seal. Similarly, geoscientists seek formations that are below any other mineral- or hydrocarbon-bearing zones to discourage future drilling through the storage formation.

When considering potential CCS formations, geoscientists favor formations with a combina-tion of porous and permeable reservoirs, effective trapping mechanisms and an overlying caprock seal. They also look for indications that the tar-geted zone has experienced minimal prior tec-tonic activity, thus reducing the likelihood of

fault-induced pathways through which injected CO2 may migrate from the injection formation.

As opposed to hydrocarbon reservoirs and gas storage facilities, four-way closure for a potential sequestration site is not a prerequisite. The ideal reservoir may also be one with minimal regional dip with low saline fluid flow. Modeling has shown that over long periods of time—hundreds of years—CO2 migrates very slowly and stabilizes over time in formations under these conditions as new residual CO2 saturation is created and dis-solution in brine occurs.

CapacityUpgrading a resource to a capacity designation may be difficult. CCS resources are often in regions with little or no oil and gas activity or may lack data with which to characterize the formation. Conclusions about the proposed resource are usually derived initially from logs, core data and 2D seismic lines. In many cases, the data pertain to offset wells that are many kilometers away.

Early characterization of prospective injection zones helps predict formation injection rates, pressures and containment capacity. Geoscientists first interpret available seismic data to answer questions about the formation’s seal, thickness, porosity and optimal injection intervals and the presence of faults. They also attempt to resolve additional parameters such as the following:• location with respect to state borders, town-

ships, nature preserves, local gas and oil fields, potable water, porosity window and legacy wells

• regional formation dip• appropriate depth for sequestration in a dense

phase• proximity of CO2 source to injection well• secondary seals and reservoir heterogeneity.

A product of the geoscientists’ efforts is often a geocellular model of the reservoir (above left). Reservoir engineers use these basic models to run flow simulations to further understand a for-mation’s injectivity, reservoir capacity, potential subsurface movement of injected CO2 and pres-sure response.

The knowledge gained from flow modeling often generates a round of new questions for geo-scientists, especially about the relationship between CO2 plume migration and permeability.14 Modeling the migration of the CO2 once it enters the formation is critical to accurately predict the behavior of injection zones for both sequestration and EOR projects. A key parameter for the model is residual CO2 saturation in the brine-saturated

> Geocellular modeling. Geocellular models are used to simulate and predict well performance for CCS injection projects. With limited data, engineers may be able to develop a simulation model of a proposed CCS storage area. This model assumed only broad indicators, with the reservoir as a set of dipping flat layers (top). Engineers then may draw on petrophysical analyses of a proposed site, data from nearby wells (INJ1B, INJ2B, INJ3B, INJ4B, INJ5B, INJ6B), seismic data and new surface interpretations to develop a more realistic structural model. The engineers apply their findings to an advanced geostatistical prediction of the interpreted depositional facies model of an open marine to nearshore fluvial–tidal delta–shallow shelf distribution (bottom).

5,6006,0006,4006,8007,2007,6008,0008,4008,8009,2009,600

10,000

Dept

h, ft

2,260,000State Plane Coordinate System 1927 (SPCS 27) location, ft

2,270,000 2,280,000 2,290,0002,220,000 2,230,000 2,240,000 2,250,000 2,300,000

INJ3BINJ4B

INJ5B

INJ6B INJ2B

INJ1B

Winter 2012/2013 41

rock.15 Prior to CO2 injection, engineers derive this value in the laboratory by analyzing rock properties and interactions between the forma-tion fluid and CO2 to build predictive equations.

Once injection has begun, engineers may use time-lapse sigma logging measurements in both injection and observation wells to determine res-ervoir saturation, lithology, porosity and borehole fluid profiles.16 Such was the case for the Frio Brine Pilot Project site near Houston, which is managed by the Bureau of Economic Geology at the Jackson School of Geosciences, The University of Texas at Austin. The project engineers used the RSTPro reservoir saturation tool on wireline to verify laboratory-based CO2 saturation values.

Project engineers presented a Schlumberger Carbon Services petrophysics team with two challenges: measure the CO2 saturation in the formation fluid at its maximum level during injec-tion and measure the residual CO2 saturation in the reservoir after the plume had expanded within the target injection formation. Wells avail-able for taking measurements included an obser-vation well and an injection well downdip 100 ft [30 m] away.

Engineers ran a baseline log on both wells before injection. Repeat logs were run immedi-ately following breakthrough at the observation well and then again two days after, one month after and nine months after injection was halted. The resulting data allowed geoscientists to com-pare in situ saturation measurements with lab-oratory and modeled measurements.17

Resource to Capacity Numerous regions in the US and elsewhere have been identified as having CCUS potential. In the Illinois basin in the US, the Cambrian-age Mt. Simon Sandstone was identified as a poten-tially suitable formation for CO2 storage. It is an areally extensive saline reservoir that overlies a Precambrian granitic or rhyolitic basement and is overlain by the Eau Claire Shale—a low-per-meability formation comprising shale, siltstone and tight limestone.18

The decision to develop the Mt. Simon Sandstone in a demonstration of CCS technology was made easier by the fact that Illinois has some of the largest gas storage facilities in the US. For more than 50 years, predominantly near the large Chicago metropolitan area in the northern end of the state, utility companies have been using natural gas stored in the upper zones of the Mt. Simon Sandstone, which extends across nearly the entire state and parts of

Indiana and Kentucky (above). Consequently, the overlying seal and the injectivity and reser-

voir continuity of the upper 200 to 300 ft [60 to 90 m] of the sandstone are understood. However,

13. Frailey SM and Finley RJ: “Classification of CO2 Geological Storage: Resource and Capacity,” Energy Procedia 1, no. 1 (February 2009): 2623–2630.

14. Plume migration is the vertical and horizontal extent to which the injected CO2 has spread through the formation.

15. As CO2 spreads through the connected pore space, small droplets disassociate and become disconnected from the main body of the CO2 plume. These droplets become immobilized in the pores. This residual trapping is a significant mechanism in retaining CO2 in the storage formation.

>Mt. Simon Sandstone. The Mt. Simon Sandstone is the thickest and most widespread saline reservoir in the Illinois basin. It covers two-thirds of the state of Illinois, and extends into Indiana and Kentucky. The estimated CO2 storage capacity of the Mt. Simon Sandstone is 11 to 151 billion Mg [13 to 166 billion tonUS]. Several layers of shale above and below serve as impermeable caprocks to hold the CO2 in place. The upper sections of the Mt. Simon Sandstone have been used for gas storage for many years. (Map courtesy of the Midwest Geological Sequestration Consortium.)

I N D I A N A

I L L I N O I S

K E N T U C K YLess than 500500 to 1,0001,000 to 1,5001,500 to 2,000Greater than 2,000Illinois basin outline

Mt. Simon Sandstonethickness in feet

DecaturChampaign

Chicago

0 75 150 km

0 50 100 mi

16. A pulsed neutron capture tool may be used to measure the rate at which thermal neutrons are captured by the formation. This measurement is called the macroscopic capture cross section, or sigma.

17. For more on the Frio Brine Pilot Project: Bennaceur K, Gupta N, Monea M, Ramakrishman TS, Randen T, Sakurai S and Whittaker S: “CO2 Capture and Storage—A Solution Within,” Oilfield Review 16, no. 3 (Autumn 2004): 44–61.

18. US DOE NETL: “Midwest Geological Sequestration Consortium—Development Phase–Large Scale Field Test,” http://www.netl.doe.gov/publications/factsheets/project/Project678_4P.pdf (accessed July 10, 2012).

42 Oilfield Review

when a well was drilled deeper, to the basement, the lower zones of the Mt. Simon Sandstone were found to have porosity as high as 30% with

permeability up to 1,000 mD. The familiar upper zones average around 100 mD. Additionally, the Mt. Simon has at least three sealing formations between it and the surface and is a continuous 1,500-ft [460-m] thick, clean sandstone.

To demonstrate the feasibility of long-term CO2 geologic storage, and to change the classification of the Mt. Simon from resource to capacity, the Illinois State Geological Survey (ISGS), with fund-ing from the US DOE to the Midwest Geological

Sequestration Consortium, is leading the Illinois Basin–Decatur Project (IBDP) with Archer Daniels Midland (ADM) Company, Schlumberger Carbon Services and other partners. The IBDP started in December 2007 when funding was first received and began injection operations in November 2011. The project captures CO2 from the fermentation process, which is used to produce ethanol at the ADM corn processing plant in Decatur, Illinois. The compressed and liquefied

> CO2 injection well. The IBDP injection well was constructed using engineering techniques that are typical for such wells. All casing strings are cemented to the surface. Additionally, specific storage formations and intervals are selected because they are bounded above and below by impermeable zones. In the case of the IBDP injection well, the caprock is the Eau Claire Shale and the lower boundary is Precambrian rock. The impermeable Maquoketa and New Albany shales above the Eau Claire are considered secondary and tertiary boundaries, respectively. The injection well uses 20-in. surface casing, 13 3/8-in. intermediate casing and 95/8-in. production casing set through the sandstone and a 41/2-in. injection tubing set into a packer above the perforations. The bottom 1,947 ft [593 m] of the production casing and all the injection tubing are chrome to resist corrosion.

Surface casing

Shallow water

New Albany Shale

Eau Claire Shale

Maquoketa Shale

St. Peter Sandstone

Mt. Simon Sandstone

2,088 to 2,214 ft

5,047 to 5,545 ft

2,611 to 2,817 ft

3,270 to 3,477 ft

5,545 to 7,051 ft

Precambrian

Intermediatecasing

Productioncasing

Productioncasing

Casing shoeat 7,219 ft

Tubing

Packer

> Verification well. To monitor the progress of the CO2 plume though formations, CCS projects may include a verification well (left ). Engineers install monitors (not shown) at many levels along the verification well borehole; this 3D array of measuring and sampling points accurately assesses where injected fluids are going. In the IBDP verification well, real-time temperature and pressure sensors take measurements at 11 ported locations along the wellbore. Mandrels with sampling points are collocated with these sensors; reservoir fluids may be captured through these ports at reservoir conditions and brought to the surface via a slickline tool (right ). The well is completed with 133/8-in. surface casing, 95/8-in. intermediate casing and 51/2-in. production casing, including 2,213 ft [675 m] of chrome set into the Precambrian rock below the Mt. Simon Sandstone. A string of 27/8-in. tubing is run from the surface to 4,747 ft [1,447 m]. To resist corrosion, 21/2-in. stainless steel tubing is set from 4,747 to 7,126 ft [1,447 to 2,172 m].

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Winter 2012/2013 43

CO2 is then transported to and injected into the Mt. Simon Sandstone at depths of around 7,000 ft [2,100 m]. The IBDP is one of a series of such proj-ects within the US DOE RCSP program to demon-strate that CO2 can be successfully and securely stored over extended periods using best engineer-ing and geologic practices and that projects can be performed in the best interests of local and regional stakeholders.19

The IBDP site selection was the result of a combination of suitable geology and relatively low-cost CO2 supply, which have helped create numerous projects in the area. A second proj-ect—the Illinois Industrial Carbon Capture and Sequestration (IL-ICCS) project—is also in Decatur. IL-ICCS project partners are the same as the IBDP partners with the addition of nearby Richland Community College; the proj-ect is funded by the American Recovery and Reinvestment Act (ARRA) of 2009.

Emissions from ethanol production at the ADM plant are typically 99% pure CO2 saturated with water vapor at 80°F [27°C] and just above atmospheric pressure. Capturing CO2 is therefore easier and less costly than when the process is applied to more-complex emission compositions such as those from coal-fired plants in which the cost of isolating CO2 using current technology may reduce plant efficiency by a quarter to one-third. Additionally, the IBDP injection, monitoring and verification wells are on ADM property at the proj-ect site in Decatur, which minimizes pipeline con-struction costs and allows implementation of extensive environmental monitoring.

The IBDP captures CO2 at the ADM facility and dehydrates and compresses it to 1,400 psi [9.6 MPa] at the wellhead. The consortium began injecting 1,100 tonUS/d [1,000 Mg/d] of this liq-uid-phase CO2 with a goal of injecting a total of 1.1 million tonUS [1 million Mg] over three years.20

Developing the IBDPDuring project planning stages, using regional geology, a 2D seismic line and logs from two wells 38 mi [61 km]northeast and 50 mi [80 km] south of the intended injection well site, ISGS and Schlumberger Carbon Services geoscientists cre-ated an initial geologic model with the Petrel E&P software platform. From this model, reser-voir engineers created a flow model using ECLIPSE reservoir simulation software.

Schlumberger Carbon Services was responsi-ble for managing the drilling and completion of the injection, verification and geophone wells for the project. Well completion design choices such

as perforation intervals, tubular and wellhead size were based on the injection rate and pres-sures calculated by early reservoir modeling. Because additional data to refine these models could come only from drilling and testing wells in the area, injection rates were estimated and wells were designed with a significant safety factor.

Project engineers drilled an injection well in 2009 (previous page, left). Later that year, a 3D seismic survey was conducted. In 2010, the verifi-cation well was drilled 1,000 ft [300 m] to the north and petrophysical logs and core data were acquired (previous page, right). A geophysical well to monitor formations above the Eau Claire Shale was completed with geophones cemented outside the casing every 50 ft [15 m] along the openhole section (right).

As part of the sequestration containment process to prevent CO2 from breaching the cap-rock sealing formation, each casing section of any well penetrating a storage zone must be cemented all the way back to the surface. This requirement creates challenges for drilling and completion engineers. The hydrostatic pressure created by a full column of cement in the pro-duction string–formation annulus may create pressures along the wellbore, which may result in lost circulation events.

This issue arose during drilling of the IBDP injection well when engineers encountered a lost circulation zone in a carbonate formation above the Eau Clair Shale. Traditional lost circulation countermeasures did not resolve the problem.21 When drilling conventional wells, engineers often accept the loss of drilling fluids to thief zones long enough to drill past them and set pipe. In this case, however, they knew that this practice would not be a solution. While cement tops behind casing are typically far below the surface, each casing string of a CCS well must be cemented to the surface. The lost circulation zone, therefore, must be made strong enough to support a full annulus of cement.

Engineers solved the lost circulation problem by placing a dispersed cement slurry across the weak zone, allowing some cement to enter and set up in the formation matrix. They then drilled through the newly created cement plug, leaving a section of cement-lined wellbore across the lost circulation zone that was able to withstand the hydrostatic pressure created by a full column of cement used for the production string.

A more daunting problem for CCS well con-struction is that CO2 can cause cement to

degrade through the process of carbonation, which occurs when traditional portland cement is exposed to CO2.22 To counter this threat, the drilling team used EverCRETE CO2-resistant cement. During laboratory experiments that included exposing the cement to liquid-phase CO2 under downhole conditions, the cement showed no signs of failure. EverCRETE cement was circulated down the injection string behind

19. Rodosta et al, reference 12.20. US DOE NETL: “Midwest Geological Sequestration

Consortium—Development Phase,” http://www.netl.doe.gov/technologies/carbon_seq/refshelf/project%20portfolio/2009/Partnerships/Development/Midwest%20Geological%20Carbon%20Sequestration%20 Consortium%20Phase%20III.pdf (accessed August 1, 2012).

21. For more on lost circulation: Cook J, Growcock F, Guo Q, Hodder M and van Oort E: “Stabilizing the Wellbore to Prevent Lost Circulation,” Oilfield Review 23, no. 4 (Winter 2011/2012): 26–35.

22. Carbonation occurs when carbon dioxide penetrates the cement and alters its composition. For more on carbonation of cement: Kayser A, Knackstedt M and Ziauddin M: “A Closer Look at Pore Geometry,” Oilfield Review 18, no. 1 (Spring 2006): 4–13.

> Geophysical well. A geophysical well includes geophones cemented in place within the well’s tubing-openhole annulus. The bottom of the geophysical well is shallower than the sealing formation. With these geophones in a geophysical well and an injection well, engineers can use microseismic monitoring software to locate subterranean sounds to within about a 90-ft [27-m] radius sphere. The well includes 91/4-in. surface casing and 31/2-in. tubing from the surface to 3,498 ft [1,066 m] inside 3,500 ft [1,067 m] of 81/2-in. open hole.

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44 Oilfield Review

a lead slurry of standard portland cement. The top of the EverCRETE cement was 750 ft [230 m] above the intermediate casing shoe, ensuring that CO2 would not come in contact with the vulnerable conventional cement.

Measuring Progress The verification well is equipped with a Westbay multilevel groundwater characterization and monitoring system. Developed for groundwater monitoring, the system can measure fluid pres-sure, collect fluid samples and repeatedly per-form hydraulic testing from multiple zones in a single well. For the IBDP project, the system was configured for deeper applications and for moni-toring CO2 storage. It allows engineers to collect fluid samples at formation pressure and to moni-tor real-time pressure and temperature data from multiple zones before and after CO2 arrives at the verification well. At the IBDP well, engi-neers are using the reconfigured Westbay system to monitor 11 intervals, and the data are used to support simulation models of CO2 movement through the Mt. Simon Sandstone.

The monitoring device consists of a multi-packer tubing completion string installed inside cemented and perforated casing. The tubing string has 27 packers to isolate selected seg-ments of perforated and blank casing. Each zone has a measurement port that is accessed by a wireline-deployed probe that measures fluid pressure and collects fluid samples.

Thirteen probes measure pressure and tem-perature at 11 perforated zones, at one quality assurance zone to identify any breaches of packer integrity and at one zone to monitor internal tub-ing pressure. The probes are connected through a common slim cable to a data logger interface at the surface. Technicians remove the wireline string of pressure probes from the tubing string for sampling and then reinstall it to continue monitoring until the next sampling operation.

Before a series of sampling operations, engineers run a wireline RSTPro log to determine which zones have CO2. Samples are collected only from zones where CO2 has not arrived. The sampling process includes a standard sequence of steps that provides repeatability for later time-series evaluation of fluid-chemistry data. A selected volume of fluid is purged from the tar-geted sampling zone, and formation fluid is col-lected using a sampler probe and canisters. The canisters are sealed to preserve the fluid at res-ervoir conditions and retrieved to the surface. Laboratory technicians remove the fluid from

the canisters using a pressure-controlling appa-ratus that preserves the integrity of the sample. The chemical analysis typically includes dis-solved anions, cations and gases.

The project is equipped with RTAC real-time acquisition and control software that uses a supervisory control and data acquisition (SCADA) system for interfacing with numerous tools and equipment. The RTAC system also includes a secure web-based data visualization and archive interface, which may be used in stan-dard modules or customized for specific pur-poses. For the IBDP wells, the RTAC system is configured to be accessible to project stakehold-ers who wish to remotely monitor injection and other relevant well data (next page).

Injection began in November 2011 and geosci-entists offered a wide range of predictions about initial formation response. Engineers included provisions for venting CO2 to the atmosphere in the event the formation did not immediately take the volumes of gas captured. Extra pump capacity at the ADM plant was also available should injec-tion pressure need to be higher than initially predicted. However, neither contingency was required because injection rates were higher and pressures required were below those predicted by the model.

Refining the ModelsWith wells drilled and injection underway, reser-voir engineers and geoscientists obtained data to update Petrel models and optimize the next step in the operation. For example, to ensure injection capacity and optimize plume geometry, engineers designed the completions after drilling and log-ging the injector well. Using the updated models, engineers then designed water injection and fall-off tests that represented downhole conditions. Data from those tests were used to calibrate the models to reevaluate and verify the completion strategy. After the verification well was drilled and logged, geoscientists used the new data to update predictive models.

A team of reservoir engineers, petrophysicists and geoscientists identified the locations of sam-pling and measurement zones in the verification well using information from the updated model. Sensitivity analyses were carried out at different stages to understand what new data were needed.

Engineers and geoscientists began to accu-mulate large amounts of data with the com-mencement of injection at the IDBP and began studying the models in anticipation of the IL-ICCS project. The injection operations are scheduled to begin early in the third and final

year of injection into the IBDP well. Spinner data were used to detect flow distribution between perforations in the injection well. RSTPro well logs were used to gather CO2 saturation data around the injection and verification wells. Data from the IBDP well included the real-time injec-tion rate and injection bottomhole pressure (IBHP) using a downhole gauge placed about 600 ft [180 m] above the perforations. Data were also gathered using the Westbay monitoring sys-tem, which measured real-time pressures at spe-cific zones in the verification well located 1,000 ft north of the injection well. Five of the 10 Westbay zones were used for model calibrations.

Using ECLIPSE reservoir simulation software, engineers ran reservoir simulations that included the CO2STORE module, which was developed to model CO2 storage in saline formations.23 Using the model, engineers considered three phases: a CO2-rich phase, an H2O-rich phase and a solid phase. The static geologic model included the entire Mt. Simon Sandstone and the overlying Eau Claire Shale.

This model covers a 40-mi2 [104-km2] area and was represented with a 1,298- × 1,308- × 534-cell grid with average cell size of 150 ft × 150 ft × 3.5 ft [46 m × 46 m × 1 m]. The horizontal cells of the geologic model were downscaled from 150 ft to 50 ft [15 m] around the wellbore for better reser-voir model resolution there. In the far-field region, horizontal cells were upscaled from 150 ft to 1,500 ft [460 m]. Vertical resolution of the geologic model was maintained in the lower 700 ft [210 m] of the reservoir where CO2 was expected to remain. In the upper section of the model, the vertical dimension of the cells was decreased to 75 ft [23 m]. The resulting cellular model was repre-sented by a high-resolution 143- × 143- × 143-unit grid locally refined around the injector.

The porosity within the injection interval ranges from 8% to 26%. The temperature and pressure gradients of approximately 1°F/100 ft [1.8°C/100 m] and 0.45 psi/ft [10.2 MPa/km] were based on in situ measurements made after drill-ing the IBDP wells. The formation pressure gradi-ent in the lower half of the Mt. Simon Sandstone is slightly higher than a typical freshwater gradi-ent because of the high-salinity water present in this part of the reservoir, which ranges from 179,800 ppm to 228,000 ppm total dissolved solids based on analysis of actual formation fluid sam-ples recovered during the drilling of the injection well. Another governing parameter used in the reservoir simulation was the fracture pressure gradient of the lower Mt. Simon Sandstone, which

Winter 2012/2013 45

was demonstrated by a step rate test in the injec-tion well to be 0.715 psi/ft [16.2 MPa/km].

For the reservoir simulations, the bottomhole injection pressure (BHIP) was allowed to reach up to 80% of the fracture pressure in the IDBP well. The BHIP in the IL-ICCS injection well will be allowed to reach 90% because of its planned higher injection rate. During the course of the simulation, CO2 is injected into the IBDP well for two years at 1,100 tonUS/d [1,000 Mg/d], followed by one year of dual injection of 1,100 tonUS/d into the IBDP well and 2,200 tonUS/d [2,000 Mg/d] into the IL-ICCS well. Injection continues for four years into the IL-ICCS well at 3,300 tonUS/d [3,000 Mg/d]. At the end of this 7-year injection period, a 45-year postmonitoring period was simu-lated to understand the long-term behavior of the CO2 plumes and the reservoir pressure within the injection zone.

In both wells, injection is confined to the lower part of the Mt. Simon Sandstone because it is the most porous and permeable. In the case of the IBDP well, reservoir engineers used the exist-ing perforated interval of 55 ft [16.8 m] in the simulation. For the IL-ICCS well simulation, they used the 330-ft [100-m] perforation interval of the completion plan.

23. For more on simulations: Edwards DA, Gunasekera D, Morris J, Shaw G, Shaw K, Walsh D, Fjerstad PA, Kikani J, Franco J, Hoang V and Quettier L: “Reservoir Simulation: Keeping Pace with Oilfield Complexity,” Oilfield Review 23, no. 4 (Winter 2011/2012): 4–15.

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. Real-time data. With RTAC real-time acquisition and control software, project stakeholders were able to monitor the injection rates measured downhole (top). Real-time downhole pressures recorded in the injection well (center) confirm that targeted injection rates were achieved. Westbay measurements from 11 perforated zones along the verification well (bottom) reported real-time downhole pressures. That pressure changes are seen only in Zones 1, 2, 3 and 4, indicates that CO2 has not risen above Zone 4.

46 Oilfield Review

The team calibrated the site model using data obtained during the first four months of the IBDP injection period. The engineers input the IBDP injection rate into the simulation to calculate the pressures at five zones at the verification well. The simulated pressures were comparable to the observed pressures. Engineers concluded that res-ervoir permeability and skin were the main param-eters impacting injection pressure calibration,

thus were used as fitting parameters. Engineers used spinner data from a wireline production log to determine the proportion of total CO2 injection entering each of the sets of perforations in the injection well. These data, along with the simula-tion, allowed engineers to fine-tune skin values at respective perforations and calculate permeability to match IBHP (above).

Engineers used RSTPro well logs to estimate the location, saturation and thickness of the CO2 column around the injection and verification wells. This information helped engineers fine-tune the endpoints of relative permeability curves, which govern CO2 and brine flow in the reservoir. Using the calibrated model, engineers ran a predictive simulation to evaluate the devel-opment of the plume and its pressure during the course of the injection program.

> Simulation validation. The data used for the IBDP bottomhole pressure calibration process were obtained during the first four months of injection. To calibrate the reservoir model, engineers fed the observed injection rate into the simulator, which predicted injection bottomhole pressures. The simulated pressures (top, black) were then compared to the observed pressures (green). Once the injection bottomhole pressure was calibrated, simulated pressures at five zones at the verification well were fine-tuned by calibrating the vertical and horizontal permeability ratio (kv /kh) of the tight sections and compressibility of the reservoir rock (bottom). Zones 2 and 3 are in direct communication with injection well perforations, thus show immediate pressure responses. Reservoir engineers have determined that flow barriers between Zones 2 and 3 and between Zone 4 and the zones above it prevent vertical flow. As a result, the matches between simulated and observed pressures in 4, 6 and 7 are more apparent than in Zones 2 and 3.

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Winter 2012/2013 47

Based on the simulation, the CO2 plume resulting from injection into the IL-ICCS well will interact with the IBDP well plume. Because the injection interval is near the base of the Mt. Simon Sandstone, and CO2 is less dense than the native brine, the CO2 flows upward from the injection interval. As it rises, CO2 saturation increases below the lower-permeability intervals within the Mt. Simon Sandstone. This pooling causes the CO2 to spread laterally beneath the lower-permeability strata, which results in slow growth of the plume. The lower-permeability strata within the Mt. Simon Sandstone limit the ultimate vertical migration of CO2 through the injection zone. As a consequence, simulation shows that after five years of continuous injection through the IL-ICCS well and 45 years of shut-in, the CO2 is expected to remain well within the lower half of the Mt. Simon Sandstone (right and next page).

CCS in the Long TermWhen combined, the two projects at ADM will have injected more man-made CO2 into geologic storage than any project has pumped elsewhere in the US. The lessons learned from these two projects have significant implications for treating emissions from the burning of fossil fuels.

The two Illinois projects will help determine how large amounts of anthropogenic CO2 behave in the Mt. Simon Sandstone, which has the poten-tial to hold billions of tons of CO2. Because the formation stretches across three states beneath some of the largest coal plants and industrial installations in the US, and because it is in the midst of coal-dependent Midwestern states, a siz-able portion of CO2 generated in the US can be transported to the region and stored there; these advantages make CCS commercially viable in the US.

The IBDP and IL-ICSS have been and are being constructed to meet specifications of the US Environmental Protection Agency’s newly created Underground Injection Control Class VI injection well guidelines. Under the new well classification, operators must closely monitor how an under-ground CO2 plume moves in porous rock. To com-ply, scientists at the Illinois State Geological Survey, in Champaign, are testing equipment that has never been used with carbon sequestration; such equipment includes seismic sensors to cre-ate a detailed image of the CO2 plume.

The two demonstration projects in Illinois will answer numerous questions about the viability of CCUS. Simultaneous injection of the two projects will provide crucial information that will help sci-entists understand how two underground CO2

plumes interact with each other. This information is important for the viability of future projects because large power plants will require multiple injection wells to manage the CO2 they generate.

Additionally, data from the Illinois projects will resolve questions about geologic storage

safety and sustainable injection rates that have caused government policy makers to hesitate funding large-scale CCUS projects. If those ques-tions can be addressed, the US will be able to take advantage of storage capacity from 11 iden-tified deep saline formations with an estimated

> Year 1. Map view (top) and cross-sectional view (bottom) of the IBDP CO2 model-predicted footprints of the pressure front and the plume after one year of injection into the IBDP well indicate that the CO2 remains at or near perforation depth. The green bar represents the designed perforation interval for the IL-ICCS injection well.

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48 Oilfield Review

storage capacity for 100% of projected US surplus CO2 from emissions for 100 years.24

Even as debate over anthropogenic climate change seems to be waning, public concerns have arisen about the environmental impact of CCUS. Large-scale projects, such as the IBDP, the IL-ICCS and others now underway may alleviate some of those concerns. If so, CCUS technology

may offer at least a partial solution to govern-ments caught in a seemingly irreconcilable posi-tion that, on the one hand, concedes that human activities are indeed aggravating climate change, but on the other hand, admits that curbing those activities is politically difficult. —RvF

> Year 3. Map view (top) shows the predicted pressure fronts at the start of the third and final year of injection. The CO2 plume footprints of the IBDP injection well remain deep in the Mt. Simon Sandstone (bottom). This coincides with the first year of injection into the IL-ICCS well where the plume footprint also remains at perforation depth.

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> Year 18. Eighteen years after injection began into the IBDP well, models predict the CO2 plume footprint, as seen in cross-sectional view (bottom), will remain contained well below the base of the Eau Claire Shale. Simulators predict the pressure front will dissipate in Year 8, measured from the beginning of injection into the IBDP well.

24. Szulczewski ML, MacMinn CW, Herzog HJ and Juanes R: “Lifetime of Carbon Capture as a Climate-Change Mitigation Technology,” Proceedings of the National Academy of Sciences 109, no. 14 (April 3, 2012): 5185–5189.

Contributors

Winter 2012/2013 49

Ahsan Alvi has been a Project Manager with Schlumberger Carbon Services in Champaign, Illinois, USA, since 2011. Previously, he was a drilling optimiza-tion engineer. Ahsan received a bachelor’s degree in civil engineering from the University of Illinois at Urbana-Champaign.

A. Ballard Andrews, a principal scientist at Schlumberger-Doll Research in Cambridge, Massachusetts, USA, specializes in optics, photonics, laser applications, infrared thermography, spectros-copy and asphaltene science. He earned a PhD degree in condensed matter physics from The University of Texas at Austin, USA, and conducted postdoctoral research at Los Alamos National Laboratory, New Mexico, USA. He later worked for Brookhaven National Laboratory in Upton, New York, USA, on computational scientific visualization and X-ray microtomography. Ballard has published more than 50 articles in physics, chemistry and energy journals and coauthored a chap-ter in Handbook of Physics and Chemistry of the Rare Earths. He has presented at more than 35 confer-ences and has 16 patents granted or filed. His current interests include downhole gas compositional analysis.

Eric H. Berlin is a Project Manager with Schlumberger Carbon Services in Champaign, Illinois. He has held various positions with Schlumberger since 1981 in Illinois, California and Ohio, USA. Eric attained a BS degree in geoengineering from the University of Minnesota Institute of Technology, Minneapolis, USA.

Bill Black is a Senior Hydrogeologist and Westbay* Sales and Marketing Manager for Schlumberger Water Services in Burnaby, British Columbia, Canada; he has worked with the Westbay system for more than 34 years. His technical interest lies in groundwater behavior, and his current projects include demonstrat-ing the value of Westbay technology for environmental monitoring of unconventional resource developments such as oil shale, oil sands, shale gas and coal seam gas. Bill received a BSc degree in geological engineer-ing from the University of British Columbia in Vancouver, Canada.

Michael Carney is the North America Subsurface Technical Manager for Schlumberger Carbon Services in Houston; he leads a team of petrotechnical experts in geology, geophysics, petrophysics and reservoir and production engineering. He joined Schlumberger in 1991 as the district geologist for most of sub-Saharan Africa in Port Gentil, Gabon, and was then the data center manager in Luanda, Angola. In the US, he has served in several positions, including management and technology development. He has recently been focus-ing on production and reservoir optimization and per-manent downhole sensing. He serves as a coleader of the production and completions engineering commu-nity and of the Schlumberger sensor technology spe-cial interest group. Michael earned a BSc degree in geological engineering from the Colorado School of Mines, Golden, USA.

Ethan Chabora is a Reservoir Engineer for Schlumberger Geothermal Services in Richmond, California; his focus is resource assessment and reser-voir optimization for clients such as geothermal power operators and project investors. He began his career with Schlumberger Wireline in 2000 as a field engineer and has since held the roles of general field engineer, engineer in charge and project manager with Schlumberger Carbon Services. Ethan received a BA degree in physics from Cornell University in Ithaca, New York, and an MS degree in petroleum engineering from Stanford University, California.

Brian Coll is the Business Support Manager for New Technologies with M-I SWACO LLC, a Schlumberger company. Based in Aberdeen, he works in the Wellbore Productivity Segment with a focus on the WELL SCAVENGER† tool and other new tools under develop-ment. He joined the oil industry in 1997 as a field engi-neer for Gyrodata Ltd, running gyroscopic and magnetic measurement tools to obtain high-accuracy directional wellbore surveys in Europe, North Africa, the Middle East and Asia. He served as Gyrodata oper-ations coordinator for Saudi Arabia, Kuwait and Bahrain followed by operations manager in Kalimantan, Indonesia. Brian joined SPS International in 2006 as product support engineer to oversee the development of the CENTURION circulating valve, which evolved into the WELL COMMANDER† tool. Following the acquisition of SPS by M-I SWACO in 2006, he became business development manager for new technology and conducted market research, field trials, data collection and analysis and global introduc-tion and offered training and support for the WELL COMMANDER tool.

Chengli Dong is a Senior Fluid Properties Specialist with the Shell FEAST (Fluid Evaluation and Sampling Technologies) team in Houston. Before moving to Shell, he was a reservoir domain champion for Schlumberger. He has been a key contributor to the development of downhole fluid analysis (DFA) mea-surements and their applications in reservoir charac-terization. He conducted extensive spectroscopic studies on live crude oils and gases and led the devel-opment of interpretation algorithms for the DFA tools. In addition, he has extensive field experience in design, implementation and analysis of formation test-ing jobs. He has published more than 50 technical papers, holds nine patents and nine filed patents and has one trade secret award. Chengli holds a BS degree in chemistry from Beijing University and a PhD degree in petroleum engineering from The University of Texas at Austin.

Hani Elshahawi is Deepwater Technology Advisor at Shell in Houston. Previously, he led FEAST, the Shell Fluid Evaluation and Sampling Technologies Center of Excellence, where he was responsible for the plan-ning, execution and analysis of global high-profile for-mation testing and fluid sampling operations. With more than 25 years of experience in the oil industry, he has worked in both service and operating compa-nies in more than 10 countries in Africa, Asia, the Middle East and North America and has held various positions in interpretation, consulting, operations, marketing and product development. Hani has lec-tured widely in various areas of petrophysics, geosci-ences and petroleum engineering, holds several patents and has written more than 100 technical papers. He was the 2009–2010 president of the SPWLA and an SPWLA distinguished lecturer in 2010 and 2011. Hani attained a BS degree in mechanical engi-neering and an MS degree in petroleum engineering from The University of Texas at Austin.

Robert J. Finley is a Director of the Advanced Energy Technology Initiative with the Illinois State Geological Survey in Champaign, Illinois. He has worked in reser-voir development for unrecovered oil and natural gas, with coalbed methane and tight gas sandstone reser-voir development in Texas and the Rocky Mountains in the US and in reservoir development for carbon sequestration in the Illinois basin. Robert earned a BS degree from City University of New York, an MS degree from Syracuse University, New York, and a PhD degree in geology from the University of South Carolina, Columbia, USA.

Julie Jeanpert, based in Ravenna, Italy, began her career in the oil industry in 1998 as a gas pipeline con-struction project engineer for Gaz de France. In 2001, she joined Schlumberger as stimulation and sand con-trol engineer. Currently, she is a Technical and Sales Engineer for sand control and matrix acidizing in Continental Europe. Her technical expertise is in sand control pumping and downhole tools in cased hole or openhole completions, matrix acidizing of sandstones and carbonates, water shutoff and fracturing. Julie has a degree in mechanical engineering from Ecole Nationale Supérieure des Arts et Métiers, Paris, and obtained a master’s degree in natural gas engineering from Ecole Nationale Supérieure des Mines de Paris.

Enos Johnson is a District Manager in Hobbs, New Mexico, in charge of Schlumberger fishing and reme-dial services. He coordinates fishing and reversing jobs on drilling and workover rigs operating in New Mexico and West Texas. Enos has worked in the oil field since 1969; his career has taken him from the tool shop to the rig floor and on to operations and sales.

Jim Kirksey has worked for Schlumberger for 31 years and is currently Well Engineering Manager for Carbon Services North America in Champaign, Illinois. He has served in many management and technical positions. Jim holds a BS degree in petroleum engineering from Mississippi State University, USA.

50 Oilfield Review

Jimmy Land is a Business Director for Schlumberger fishing and remediation services. He has a background in drilling and production support and more than 30 years of oilfield experience, 20 of which was in senior operations management. Jimmy has a BA degree from McMurry University, Abilene, Texas.

David Larssen is a Geotechnical Engineer with Schlumberger Water Services in Burnaby, British Columbia, Canada. Before beginning his career with Schlumberger in 1986, he was an engineering consul-tant specializing in hydrogeology. He has authored sev-eral publications on advanced groundwater instrumentation and is the senior technical expert on application of the Westbay system. David obtained a BS degree in geotechnical engineering and hydrogeol-ogy from the University of British Columbia, Vancouver.

Graeme Laws is the Director of the Specialized Tools Technology Centre for M-I SWACO in Aberdeen. In 1975, he began as a cementing engineer in the North Sea and held field positions in various locations work-ing with a range of downhole tool systems, including drillstem testing, gravel packing and tubing-conveyed perforating. He began his management career in Brunei in 1983 working with Baker Hughes Sand Control. He ran and managed liner hanger systems in the North Sea with Nodeco Limited and then became director of the company. Graeme joined SPS International in 1999 and worked in various technical management positions; he was a technical director when M-I SWACO acquired SPS in 2006. He has con-tributed to the design of several downhole tools, including the WELL SCAVENGER tool.

Mark Lee, based in Houston, is the Director for Career Development and Training with Schlumberger. He joined the company in 2009 and has been in the oil industry for 38 years. Mark previously worked for Weatherford International as the country business manager of North Africa and for Baker Hughes as a field engineer. Mark has a BS degree in engineering from Louisiana Tech University, Ruston, USA.

Hannes E. Leetaru is a Senior Petroleum Geologist at the Illinois State Geological Survey in Champaign, Illinois. His focus is the geology and geophysics of the subsurface in relation to carbon sequestration activi-ties at the Illinois Basin–Decatur Project. He is also the Principal Investigator for a US Department of Energy–funded study on the carbon sequestration potential of the Cambrian and Ordovician strata in the Illinois and Michigan basins in the US. He has worked as a petroleum geologist with Getty Oil Company and Union Pacific Resources in Houston and was involved in exploration and development projects in the East and West Texas basins and the Hugoton Embayment in Kansas, USA. Hannes, who has pub-lished numerous industry papers, received a BS degree from the State University of New York at Fredonia, an MS degree from Syracuse University, New York, and a PhD degree from the University of Illinois at Urbana-Champaign, all in geology.

Scott Marsteller joined Schlumberger in 1989 as a wireline field engineer in south Texas. Since then, he has held many positions in sales, marketing and opera-tions management in the US. He recently served as the Illinois basin projects manager in Champaign, Illinois, managing the Illinois Basin–Decatur Project from the planning phase through CO2 injection. He is currently a Marketing Manager for Schlumberger in Anchorage. Scott attained a BS degree in mechanical engineering from Rose-Hulman Institute of Technology, Terre Haute, Indiana, USA, and an MBA degree from Erasmus University, Rotterdam, the Netherlands.

Scott McDonald is Director of Biofuels Development for Archer Daniels Midland (ADM) Company in Decatur, Illinois. His responsibilities include identifi-cation and development of projects and novel product applications that will expand the use of biofuels and bio-based products into the marketplace. He leads the biofuels technical services team. Prior to joining ADM, he was the commercial trading manager for Total, where his responsibilities included trading and risk management for feed and finished product streams for the company’s US refining and petrochemical assets. His 20-year career has included trading and risk man-agement, business development, economics and plan-ning, fuels formulation and unit process design, startup and operation. Scott has a BS degree in chemi-cal engineering from The University of Texas at Austin.

Oliver C. Mullins, a chemist, is a Science Advisor to executive management in Schlumberger. He is the pri-mary originator of downhole fluid analysis for forma-tion evaluation. For this, he has won several awards, including the SPE Distinguished Membership Award and the SPWLA Distinguished Technical Achievement Award; he has been a distinguished lecturer four times for the SPWLA and SPE. He authored the award- winning The Physics of Reservoir Fluids: Discovery Through Downhole Fluid Analysis. Oliver also leads an active research group in petroleum science. He has coedited three books and coauthored nine chapters on asphaltenes and 195 publications. He coinvented 81 allowed US patents, is Fellow of two professional societies and is Adjunct Professor of Petroleum Engineering at Texas A&M University, College Station.

David Petro is a Senior Technical Consultant at Marathon Oil Corporation in Houston; he has more than 32 years of experience in the oil and gas industry. During the past 17 years, he has worked on reservoir characterization and implementation of deepwater Gulf of Mexico projects. David has coauthored many papers on reservoir evaluation and performance.

Andrew E. Pomerantz is the Geochemistry Program Manager at Schlumberger-Doll Research in Cambridge, Massachusetts. His research focuses on the development of novel techniques to characterize the chemical composition of kerogen and asphaltenes, including methods in mass spectrometry, X-ray spec-troscopy and infrared spectroscopy. That molecular information is used to understand fundamental physi-cal and chemical processes in petroleum such as asphaltene compositional grading and storage and transport in shales. Andrew, who has coauthored 40 publications, received a PhD degree in chemistry from Stanford University, California.

Robert Robertson has been a Schlumberger Global Product Engineering Advisor since 2011. Based in Stavanger, he has more than 25 years of fishing and remedial experience as a fishing tool supervisor, senior well specialist, operations supervisor and operations manager in every part of the world. In his current posi-tion, Robby is responsible for product development, reliability and technical follow up of the fishing and remedial product line with an emphasis on global plug and abandon technology.

Douglas J. Seifert is a Petrophysical Consultant with Saudi Aramco in Dhahran, Saudi Arabia. He works as the Petrophysics Professional Development Advisor in the Upstream Professional Development Center, where he oversees the Petrophysics curriculum and develop-ment of petrophysicists within Saudi Aramco. He specializes in real-time petrophysical applications and pressure testing and fluid analysis. He previously worked for Pathfinder Energy Services, Maersk Olie og Gas, Halliburton and Texaco. Doug is the President of the Saudi Arabia Chapter of SPWLA and also serves on the SPWLA Technology Committee. He holds a BS degree in statistics and an MS degree in geology from The University of Akron, Ohio.

Ozgur Senel has been a Reservoir Engineer with Schlumberger Carbon Services in Sugar Land, Texas, since 2008. He is responsible for analyzing field data, creating and calibrating reservoir models, simulating CO2 injection, predicting and optimizing CO2 plume development and optimizing well sizing, completions and injection programs for carbon capture and storage (CCS) projects in the US and Canada. In addition, he manages surface facilities–flow assurance projects. Ozgur has a BS degree in petroleum engineering from the Middle East Technical University, Ankara, Turkey, and an MS degree in petroleum engineering from Texas A&M University, College Station, where he is a PhD candidate in petroleum engineering.

Valerie Smith is a Reservoir Geophysicist with Schlumberger Carbon Services in Westerville, Ohio. Before obtaining her current position, she worked for West Virginia University, Morgantown, USA, as a research assistant. Valerie attained a BA degree in physics from the State University of New York at Potsdam, a BS degree in geology from West Chester University of Pennsylvania, USA, and an MS degree in geology from West Virginia University.

Marco Sportelli joined Eni SpA as a completion super-visor on offshore rigs in 1986. He then became Drilling and Completion Superintendent and has held that position since 1999. His expertise is in development and workover in the depleted gas fields of the Adriatic Sea. Marco has extensively used dual selective sand control completions. He is based in Ravenna, Italy.

Winter 2012/2013 51

An asterisk (*) is used to denote a mark of Schlumberger. A dagger (†) is used to denote a mark of M-I SWACO LLC, a Schlumberger company.

Charles Svoboda is the Director of Business Development for M-I SWACO wellbore productivity in Houston. He began his career with Halliburton and transferred to M-I SWACO, formerly IMCO Services, in 1984 and has held operational and technical positions in the drilling fluids and wellbore productivity seg-ments since that time. His focus is on developing and commercializing technologies pertaining to comple-tion fluids, reservoir drill-in fluids, breakers, special-ized tools and filtration. Charles received a bachelor’s degree in civil engineering in 1982 from the University of Illinois, Urbana-Champaign.

Mark Trimble began in the oil industry as a rough-neck on the drill floor and then progressed to a driller position. In 1980, he joined Baker Oil Tools, where he worked for 10 years as a field technician running downhole completion and remedial tools. He left the industry for 18 years; when he returned in 2008, he started at M-I SWACO as a technical service engineer focusing on designing, recommending and writing procedures for downhole cleanup tools pri-marily in deepwater and extended-reach applications. Since 2010, he has been a Business Development Manager. Based in Houston, Mark promotes and con-ducts training and support for new technology for cleanup tools worldwide.

Murat Zeybek is a Schlumberger Reservoir Engineering Advisor and Reservoir and Production Domain Champion for the Middle East area and is based in Dhahran, Saudi Arabia. He works on analysis and interpretation of wireline formation testers, pres-sure transient analysis, numerical modeling of fluid flow, water control, production logging and reservoir monitoring. He is a member of the technical editorial review committee for SPE Reservoir Evaluation and Engineering and served as a committee member for the SPE Annual Technical Conference and Exhibition. He also served on the industrial advisory committee for the petroleum engineering department at King Fahd University of Petroleum and Minerals, Dhahran. Murat holds a BS degree from Istanbul Technical University, Turkey, and received MS and PhD degrees from the University of Southern California in Los Angeles, all in petroleum engineering.

Julian Y. Zuo is currently a Scientific Advisor and Interpretation Architect for a next-generation formation testing and sampling tool at the Schlumberger Houston Pressure and Sampling Center in Sugar Land, Texas. He has been working in the oil and gas industry since 1989. Recently, he has been leading the effort to develop and apply the industry’s first simple Flory-Huggins-Zuo equa-tion of state for predicting compositional and asphal-tene gradients to address concerns such as reservoir connectivity, tar mat formation, asphaltene instability, flow assurance and nonequilibrium with late gas charg-ing. He has coauthored more than 150 technical papers for journals, conferences and workshops. Julian holds a PhD degree in chemical engineering from the China University of Petroleum in Beijing.

Well Placement and Completion Evolution. The advent of new LWD tools and measurements has led to changes in the way some operators approach drilling horizontal wells. New tools are able to detect boundar-ies in the formation away from the borehole and in front of the drill bit, resulting in an improvement in well placement techniques. In addition, tools have been developed that accurately image borehole details and identify naturally occurring fracture networks. Engineers use these data to create effective completion designs. This article presents some of the technologies and pro-cesses that are making these changes possible.

Coming in Oilfield Review

Evaluation While Drilling. Motivated by environ-mental, health and security reasons, scientists have spent years developing alternatives to radioisotope-based logging tools. Through the use of pulsed-neu-tron generators that have replaced chemical sources in other logging tools, engineers have developed a radioisotope-free gamma-gamma density measure-ment. This innovation allows operators to deploy a full suite of LWD tools that have no chemical sources.

Wireline Formation Testing. Wireline-conveyed fluid sampling tools enable operators to capture and analyze reservoir fluids faster than ever before. Until recently, however, use of these formation testers was limited by some types of formations and the flow regimes of certain fluids or required an extended period of time on station to capture clean samples. A new design has overcome these challenges and, in so doing, greatly expanded the realm of wireline formation testing.

Oilfield Review52

52 Things You Should Know About GeophysicsMatt Hall and Evan Bianco (eds)Agile LibrePO Box 336 Mahone Bay, Nova Scotia B0J 2E0 Canada2012. 132 pages. US$ 19.00ISBN 978-0-9879594-0-9

The editors, geoscience consultants who specialize in subsurface problems, pulled together a collection of one- to two-page essays written by prominent petroleum geoscientists. The essays range from general philosophy to detailed tips for interpreting seismic data to career advice.

Contents:

• Fundamentals: Basics; Mapping

• Concepts: Geology; Analogs

• Interpretation

• Powertools: Attributes; Ninja Skills

• Pre-Stack: Rock Physics; Pre-Stack; Processing

• Quantitative: Mathematics; Analysis

• Integration: Teamwork; Workflow

• Innovation: History; Innovation; Technology

• Skills: Learning; Career; Managing

This is a short book full of wisdom for both young and experienced geophysicists. . . . The authors are to be commended at attempting this book and managing to get a distin-guished list of contributors.Bartel DC: “Book Review,” The Leading Edge 31,

no. 12 (December 2012): 1520.

The Carbon Crunch: How We’re Getting Climate Change Wrong and How to Fix ItDieter HelmYale University Press302 Temple StreetNew Haven, Connecticut 06511 USA2012. 304 pages. US$ 35.00ISBN: 978-0-300-18659-8

In our commitment to understanding climate change, Dieter Helm, professor of energy policy at University of Oxford, England, argues that we have failed to tackle the issue of global warming and advocates for a rethinking of energy policies. Included in this argument is a suggestion of a broad transition from coal to gas to electrification with a focus on the economics of new technologies.

Contents:

• Part One: Why Should We Worry About Climate Change?: How Serious Is Climate Change?; Why Are Emissions Rising?; Who Is to Blame?

• Part Two: Why Is So Little Being Achieved?: Current Renewables Technologies to the Rescue?; Can Demand Be Cut?; A New Dawn for Nuclear?; Are We Running out of Fossil Fuels?; A Credible International Agreement?

• Part Three: What Should Be Done?: Fixing the Carbon Price; Making the Transition; Investing in New Technologies

• Conclusion

• Endnotes, Bibliography, Index

Helm superbly articulates why some of the alternate energy sources touted as solutions (such as wind power) aren’t cost efficient, and how countries claim to have reduced harmful carbon emissions only by increasing carbon imports that don’t add up to a net reduction. This intelligent though depressing tome should inform future debates.

“Book Review,” Publishers Weekly (September 3,

2012), http://www.publishersweekly.com/978-0-

300-18659-8 (accessed January 14, 2013).

The heart of Mr Helm’s book is an examination of the economics of renewable energy. . . . [R]eaders will get a cogent account of how self-defeating current global climate-change policies are turning out to be.

“Climate Change: How to Fix It,” The Economist

(October 20, 2012), http://www.economist.com/

news/books-and-arts/21564815-climate-change-

needs-better-regulation-not-more-political-will

(accessed January 14, 2012).

An optimistically levelheaded book about actually dealing with global warming.

“Book Review,” Kirkus (September 13, 2012),

https://www.kirkusreviews.com/book-reviews/

dieter-helm/carbon-crunch/ (accessed

January 4, 2013).

The Face of the Earth: Natural Landscapes, Science, and CultureSueEllen Campbell with Alex Hunt, Richard Kerridge, Tom Lynch, Ellen Wohl and othersUniversity of California Press2120 Berkeley WayBerkeley, California 94704 USA2011. 334 pages. US$ 27.95 ISBN: 978-0-520-26927-9

Author and editor SueEllen Campbell, a professor of English, examines Earth’s landscapes through both scientific and cultural lenses by weaving science, cultural myth, literary studies and personal experience. Accounts by Campbell as well as scientists and other writers explore, explain and chart humankind’s interdependence with and mark on the natural world.

Contents:

• Landscapes of Internal Fire: On the Spot: Over a River of Lava; Imagining the Interior; On the Spot: At the Edge of an Overthrust Belt; Mundus Subterraneus; On the Spot: Among the Aeolian Islands; The Globe, Tectonic Plates, and Mountain Building; On the Spot: Along the Disturbance Gradient; Volcanoes and Their Eruptions; On the Spot: Along the Chaitén Volcano; Hot Springs and Geysers

• Climate and Ice: On the Spot: Up and Down the Himalaya; How the Climate Works; The Ghosts of Climates Past; Our Ice Age; Landscapes Shaped by Ice; On the Spot: In the Channeled Scablands; Ice-Age Humans; On the Spot: On the Arctic Tundra; The Little Ice Age, Glaciology, and the Sublime; On the Spot: Toward a Glacier’s Edge; The Story Now

• Wet and Fluid: On the Spot: In the Rocky Intertidal Zone; The Water Cycle; On the Spot: Along a Rain Forest Stream; The Moving Waters of Rivers; The Dream of Water in Deserts; The Slow Water of Wetlands; On the Spot: At the Bog on Céide Fields; Peat, Mires, Bogs, Fens; On the Spot: At Wicken Fen; Marshes and Swamps; Wet/Dry; On the Spot: At the Billabong

• Desert Places, Desert Lives: On the Spot: Down a Desert River Canyon; Dry, Hot, Windy, and Dusty; On the Spot: In Jabal Aja; What We See; On the Spot: In the Chihuahuan Desert; Clever Plants; On the Spot: In the Red Center; Clever Creatures; On the Spot: In the Negev Desert; The Human Desert

• The Complexities of the Real: Underfoot; On the Spot: In Antarctica’s Dry Valleys; Oceans of Grass; The Shapes of Complexity; On the Spot: On the Chalk Downs; Evolving Together . . .; On the Spot: In the Tallgrass Prairie; . . . And Moving Apart; On the Spot: On the Tibetan Plateau; Among Trees; On the Spot: In a Eucalypt Forest; Zooming In; Return to Wonder

• Epilogue: In a High Flower Meadow

• Sources, Contributor Biographies, Index

Campbell and her colleagues draw on a scholarship model that employs the collaborative research-team approach . . . typical of the sciences. . . . The result is masterful: a hugely ambitious, necessary, articulate, and generous intellectual undertaking, executed with scholarly exactitude and lyrical beauty.

Dodd E: “Book Review,” Ecozon@: European

Journal of Literature, Culture and Environment 3,

no. 2 (Autumn 2012): 212.

. . . readers will encounter nature writing that rivals Annie Dillard’s fiction, combined with personal responses to the environmental state of our earth’s natural landscapes and practical suggestions that offer hope in the face of overwhelming issues like climate change.

White K: “Countering Crisis with Action: Voices

for the Earth,” ForeWord Reviews 15, no. 1

(Winter 2012): 23.

NEW BOOKS

Winter 2012/2013 53

Parameter Estimation and Inverse Problems, Second EditionRichard C. Aster, Brian Borchers and Clifford H. ThurberAcademic Press, an imprint of Elsevier225 Wyman StreetWaltham, Massachusetts 02451 USA2012. 376 pages. US$ 99.95ISBN: 978-0-12-385048-5

This textbook explores classical and Bayesian approaches to linear and nonlinear inverse theory problems and also looks closely at computational, mathematical and statistical issues related to their application to geophysi-cal problems. A companion website features computational examples for the exercises in the book.

Contents:

• Introduction

• Linear Regression

• Rank Deficiency and Ill-Conditioning

• Tikhonov Regularization

• Discretizing Inverse Problems Using Basis Functions

• Iterative Methods

• Additional Regularization Techniques

• Fourier Techniques

• Nonlinear Regression

• Nonlinear Inverse Problems

• Bayesian Methods

• Epilogue

• Appendices, Bibliography, Index

As is true of the original, the book continues to be one of the clearest as well as the most comprehensive elementary expositions of discrete geophysical inverse theory. It is ideally suited for beginners as well as a fine resource for those searching for a particular algorithm that could be brought to bear on a particular inverse problem. . . . All examples in the book are beautifully illustrated with simple, easy to follow ‘cartoon’ problems, and all painstakingly designed to illuminate the details for a particular numerical method.

Treitel S: “Review,” The Leading Edge 31, no. 7

(July 2012): 860.

To Forgive Design: Understanding FailureHenry PetroskiThe Belknap Press ofHarvard University Press79 Garden StreetCambridge, Massachusetts 02138 USA2012. 432 pages. US$ 27.95ISBN: 978-0-674-06584-0

By surveying some of the world’s infamous engineering failures, the author reveals the interconnectedness of technology and culture and explores the larger context in which accidents occur. Petroski explains how even simple technologies are embedded in cultural and socioeconomic constraints, complications and contradictions and demonstrates how dangers may emerge from complexity.

Contents:

• By Way of Concrete Examples

• Things Happen

• Designed to Fail

• Mechanics of Failure

• A Repeating Problem

• The Old and the New

• Searching for a Cause

• The Obligation of an Engineer

• Before, During, and After the Fall

• Legal Matters

• Back-Seat Designers

• Houston, You Have a Problem

• Without a Leg to Stand On

• History and Failure

• Notes, Illustrations, Index

Despite the book’s meanderings and repetitions, there is much to learn from it. . . . The most brilliantly explained engineering failure concerns the ocean-bed blowout involving the Deepwater Horizon oil rig in 2010. Petroski’s exposition is immensely detailed and benefits from being linear in its narrative. This section of the book is exemplary in its remorseless exfoliation of the technical and commercial reasons for the incident.

Merrick J: “Book Review,” The Independent

(May 19, 2012), http://www.independent.co.uk/

arts-entertainment/books/reviews/to-forgive-

design-understanding-failure-by-henry-petroski-

7763597.html (accessed September 5, 2012).

Ignorance: How It Drives ScienceStuart FiresteinOxford University Press198 Madison AvenueNew York, New York 10016 USA2012. 195 pages US$ 21.95ISBN: 978-0-199-82807-4

The author posits that in science and research, knowledge follows ignorance, rather than the other way around. Firestein argues that ignorance is the force that propels scientists and researchers. The book includes four case histories that illustrate how individual scientists use ignorance to direct their research.

Contents:

• A Short View of Ignorance

• Finding Out

• Limits, Uncertainty, Impossibility, and Other Minor Problems

• Unpredicting

• The Quality of Ignorance

• You and Ignorance

• Case Histories

• Coda

• Notes, Suggested Reading, Index

An excellent read, Ignorance would be a fine companion text for potential scientists at the beginning of their studies. . . . Firestein’s short account may even make you embrace your ignorance, wearing it like a badge of honor. You may gradually become more and more ignorant as you read, and you will enjoy the journey. Ignorance in this telling is truly bliss.

Cerf M: “Known Unknowns,” Science 336,

no. 6087 (June 15, 2012): 1382.

To show how scientists depend on ignorance, Dr. Firestein has written a short, highly entertaining book aimed at nonscientists and students who want to be scientists. . . . Dr. Firestein . . . celebrates a tolerance for uncer-tainty, the pleasures of scientific mystery and the cultivation of doubt.

Blakeslee S: “To Advance, Search for a Black Cat

in a Dark Room,” The New York Times (June 18,

2012), http://www.nytimes.com/2012/06/19/

science/ignorance-book-review-scientists-

dont-care-for-facts.html?_r=0 (accessed

December 27, 2012).

Wild Hope: On the Front Lines of Conservation SuccessAndrew BalmfordUniversity of Chicago Press1427 East 60th StreetChicago, Illinois 60637 USA2012. 264 pages. US$ 26.00 ISBN 978-0-226-03597-0

As the title suggests, Balmford offers hope that our natural environment is in recovery, not on its way to disaster. Organized geographically, the book highlights the people who are discover-ing and generating new ideas to make conservation a success. Balmford recognizes the difficulties and chal-lenges of conservation but offers solutions and accounts of citizens, governments and corporations working together to implement such solutions.

Contents:

• The Glass Half Empty

• Guarding the Unicorn: Conservation at the Sharp End

• Ending the Woodpecker Wars

• Problem Plants, Politics, and Poverty

• Rewilding Goes Dutch

• Seeing the Good from the Trees

• The Greening of a Giant

• Fishing for a Future

• The Glass Half Full

• Appendix: Stemming the Loss (Or What We Can All Do to Save Nature)

• References

. . . there is a kind of genius in [the book’s] opacity and simplicity that sets it apart from bibliographic congeners in the genre of conserva-tion writing. Science plays a critically important role in framing the dia-logue for how and where we manage ecosystems. Balmford makes this clear. . . . Balmford’s vague, but sincerely impassioned, response makes more neurons fire in the region of the heart than in the head. Nonetheless, perhaps that is just the muscle needed for protecting nature.

McCauley D: “Nature—Half Lost or Half Saved?,”

Science 337, no. 6101 (September 21, 2012): 1455.

Oilfield Review54

DEFINING TESTING

Well and formation tests, which entail taking measurements while flowing fluids from the reservoir, are conducted at all stages in the life of oil and gas fields, from exploration through development, production and injection. Operators perform these tests to determine whether a formation will pro-duce, or continue to produce, hydrocarbons at a rate that gives a reasonable return on further investments. Operators also use test data to determine the limits of the reservoir and to plan the most efficient methods for producing wells and fields.

During testing, operators measure formation pressure, characterize the formation fluids and reservoir and determine permeability and skin—dam-age to the formation incurred during drilling or other well operations. Data that indicate how the formation reacts to pressure increases and decreases during a test can also reveal critical information about the reservoir.

Well and formation tests are also primary sources of critical data for reservoir models and are the principal means by which engineers confirm or adjust reservoir model parameters. Engineers use these models to under-stand how reservoir fluids, the formation and the well interact and use that knowledge to optimize completion and development strategies.

Operators assess the production potential of wells through several test methods, singularly or in combination. They may choose to perform a pro-duction well test in which the well is flowed through a temporary comple-tion to a test separator (right). Or they may use a wireline formation tester (WFT) to capture fluid samples and measure pressure downhole at the zone of interest. Engineers sometimes perform both types of tests.

During production well tests, technicians flow reservoir fluids to the sur-face through a drillstring or a drillstem test (DST) string. Packers isolate the zone to be tested while downhole, or surface equipment provides well control. The well is flowed at different rates through a choke valve that can be adjusted to control the flow rate precisely.

Reservoir fluids produced to the surface are sent directly to holding tanks until test operators determine that contaminants such as drilling flu-ids are eliminated, or at least minimized, from the flow stream. After cleanup, flow is redirected to a test separator where bulk fluids are divided into oil, gas and water, and any debris, such as sand and other material, is removed. The three fluid phases are measured and analyzed separately. Operators may opt to obtain additional reservoir and fluid flow data by simultaneously running production logging tools into the well on wireline. These tools measure the downhole flow rate and fluid composition and can indicate which zones are contributing to the total flow.

During well tests, reservoir fluids are produced to the separator at vary-ing rates according to a predetermined schedule. These tests may take less than two days to evaluate a single well or months to evaluate reservoir extent. Test types include buildup, drawdown, falloff, injection and inter-ference. For most tests, engineers permit a limited amount of fluid to flow from or into a formation. They then close the well and monitor pressures while the formation equilibrates.

Buildup tests are performed by shutting in the well after some period of flow to measure increase in bottomhole pressure (BHP). By contrast, for

drawdown tests, engineers open the well after a specified shut-in period to observe BHP decrease. During injection tests and falloff tests, fluid is injected into the formation, and BHP, which increases as a result, is moni-tored. The well is then shut in and the ensuing decreasing BHP is recorded. Interference tests record the pressure changes in adjacent wells when the test well pressure is changed. The time it takes for changes in the test well to affect pressure at the observation well gives engineers an indication of the size of the reservoir and flow communication within it.

Engineers analyze responses to pressure change schemes using pres-sure transient analysis, a technique based on the mathematical relation-ships between flow rate, pressure and time. The information from these analyses helps engineers determine the optimal completion interval, pro-duction potential and skin. They can also derive average permeability, degree of permeability heterogeneity and anisotropy, reservoir boundary shape and distance, and initial and average reservoir pressures.

Engineers use specific variations on well buildup and drawdown tests to evaluate gas wells. During a backpressure test, a well is flowed against a specified backpressure until its BHP and surface pressures stabilize—an indication that flow is coming from the outer reaches of the drainage area. An isochronal test is a series of drawdowns and buildups. Pumping rates vary for each drawdown, while subsequent buildups continue until the well

Well Testing Fundamentals

Oilfield Review Winter 2012/2013: 24, no. 4. Copyright © 2013 Schlumberger.

Rick von FlaternSenior Editor

Safety valve Coalescing plates Gas lineMistextractor

Effluentinlet

Water-levelcontroller and float

Water line

Weir plate Vortex breaker

Oil line

Oil-levelcontrollerand float

Conventional Separator

Inlet breaker Deflector plate Foam breaker

> Test separator. Separators are designed so that produced fluids enter the vessel, where they are retained long enough for the oil to separate and float to the top of the water. This process is enhanced by deflector plates that slow flow velocity and by coalescing plates that gather oil into large droplets. Once the oil and water have separated, the oil then flows over a weir into a separate section of the vessel while water remains in the original compartment. Mechanical water- and oil-level controller arms, with attached floats lifted by the rising fluid, trigger valves (not shown) that release oil and water along their respective flowlines. When the fluids reach prescribed levels, the controllers cause the release of gas or air pressure with actuation of pneumatic valves. Mist extractors remove oil droplets from the gas phase before gas exits through a valve at the top of the vessel and passes through an orifice plate meter (not shown) for measurement. Safety valves allow gas to escape into the atmosphere rather than overpressure the vessel.

Winter 2012/2013 55

reaches its original shut-in pressure. A modified isochronal test—in which drawdown and buildup periods are of equal duration—may also be used.

Based on data from these tests, engineers are able to determine produc-tion potential, skin and absolute open flow (AOF)—the theoretical rate at which the well would flow if backpressure on the sandface, or the borehole wall, were zero. Operators use AOF as the basis for calculations to deter-mine the relationship between backpressure settings and flow rates of the well.

Rather than use well tests, operators may opt to evaluate their wells using WFTs that include a quartz pressure gauge and a fluid sampling tool placed across a production interval (above). During these formation tests, reservoir fluids are pumped or flowed into the WFT through a probe inserted into the formation or between packers set above and below the sampling site.

The reservoir fluids, which may be contaminated with drilling fluid, are first flowed or pumped through flowlines in the tool into the wellbore while the contamination level decreases. Once engineers determine that the

formation is delivering minimally contaminated reservoir fluids, they redi-rect flow to sample chambers within the tool. The chambers are retrieved to the surface and transported to laboratories for analysis.

Scientists also use downhole fluid analysis (DFA) to monitor the sam-pling process. Using optical spectroscopy, or the recorded light spectrum, engineers identify in real time the composition of fluids as they flow into the tool; this method also reveals critical data about the reservoir without wait-ing for laboratory tests to be completed. Additionally, the DFA measure-ments confirm that the sample is uncontaminated and eliminate uncertainties associated with fluid transport and laboratory reconstruction of in situ conditions necessary for fluid analysis. Technicians also use DFA data to identify gas/oil ratios, relative asphaltene content and water frac-tion in real time.

A variety of well and formation test schemes are performed throughout the stages in the life of a well or field. At the exploration stage, operators may use well tests to simulate production after a well is completed to estab-lish production potential and reserves estimates. In addition, capturing large fluid samples at the surface gives experts an opportunity to perform laboratory measurements on the reservoir fluids.

Well tests at the exploration stage also allow operators to determine if low flow rates are affected by skin or are the result of natural permeability of the reservoir. Armed with the knowledge of either situation, engineers can then take appropriate actions, plan treatments that may be necessary once production commences or decide to abandon the project for economic reasons. For instance, well tests can be used to estimate reservoir size, which allows operators to abandon a small reservoir that will not be eco-nomical despite high initial flow rates.

During the field development stage, well tests help indicate wells that may require stimulation treatments. Using well test data, engineers predict induced or natural fracture length and conductivity. They can then estimate productivity gains that may be realized from a stimulation treatment. In addition, WFTs can be used for pressure testing to determine static reser-voir pressures and to confirm fluid contacts and density gradients. This information helps analyze communication within the reservoir, tie reservoir characteristics to a geologic model and identify depleted zones.

During the production phase, well tests are aimed at monitoring reser-voirs, collecting data for history matching—comparing actual production with predicted production from reservoir simulators—and assessing the need for stimulation. These tests use a pressure gauge placed at formation depth to collect data during pressure buildup and drawdown.

Well productivity usually diminishes over time, sometimes as a result of formation damage from fines migration—the movement of very small par-ticles through the formation to the wellbore where they fill pore spaces and reduce permeability. Engineers may perform formation tests to predict the likely effectiveness of treatments to remove these fines. The effects of com-pletion choices may also be assessed using formation tests to aid engineers in planning required remedial operations.

Well and formation test data provide operators with information about their new and producing wells that is critical to making near-term opera-tional decisions. But the real power of well test data is their application to construction or correction of reservoir models, which allow operators to make better long-term decisions about their assets.

>WFT sampling. Pistons are driven from one side of the WFT to force a packer assembly firmly against the formation to be tested. At its center, the packer includes a probe that is then extended into the formation to withdraw wellbore fluids. Formation fluids (red arrows) flow into the probe and into flowlines. The fluids are pumped into the wellbore until they are sufficiently free of contamination as determined by downhole fluid analysis (green and brown cylinders). Uncontaminated fluids are directed into storage bottles (orange) where the fluids are kept at in situ conditions. Multiple samples can be taken on one trip into the well. When all tests are completed, the samples are brought to the surface and may be sent to laboratories for advanced testing. A quartz pressure gauge measures and records bottomhole pressures.

Tool pistonPacker assembly

Probe

Quartz pressuregauge

Packer assemblypiston

ARTICLES

Basin to Basin: Plate Tectonics in ExplorationBryant I, Herbst N, Dailly P, Dribus JR,Fainstein R, Harvey N, McCoss A, Montaron B, Quirk D and Tapponnier P.Vol. 24, no. 3 (Autumn 2012): 38–57.

CO2 Sequestration—One Responseto EmissionsAlvi A, Berlin EH, Kirksey J, Black B,Larssen D, Carney M, Chabora E, Finley RJ, Leetaru HE, Marsteller S,McDonald S, Senel O and Smith V.Vol. 24, no. 4 (Winter 2012/2013): 36–48.

Drilling AutomationAldred W, Bourque J, Mannering M,Chapman C, du Castel B, Hansen R,Downton G, Harmer R, Falconer I, Florence F, Godinez Zurita E, Nieto C,Stauder R and Zamora M.Vol. 24, no. 2 (Summer 2012): 18–27.

The Expanding Role of Mud LoggingAblard P, Bell C, Cook D, Fornasier I, Poyet J-P, Sharma S, Fielding K, Lawton L,Haines G, Herkommer MA, McCarthy K,Radakovic M and Umar L.Vol. 24, no. 1 (Spring 2012): 24–41.

Landing the Big One—The Art of FishingJohnson E, Land J, Lee M and Robertson R.Vol. 24, no. 4 (Winter 2012/2013): 26–35.

Logging Through the BitAivalis J, Meszaros T, Porter R, Reischman R, Ridley R, Wells P, Crouch BW, Reid TL and Simpson GA.Vol. 24, no. 2 (Summer 2012): 44–53.

Microbes—Oilfield Enemies or Allies?Augustinovic Z, Birketveit Ø, Clements K,Freeman M, Gopi S, Ishoey T, Jackson G,Kubala G, Larsen J, Marcotte BWG,Scheie J, Skovhus TL and Sunde E.Vol. 24, no. 2 (Summer 2012): 4–17.

Offshore Permanent Well AbandonmentAbshire LW, Desai P, Mueller D, Paulsen WB, Robertson RDB and Solheim T.Vol. 24, no. 1 (Spring 2012): 42–50.

Revealing Reservoir SecretsThrough Asphaltene ScienceAndrews AB, Mullins OC, Pomerantz AE,Dong C, Elshahawi H, Petro D, Seifert DJ,Zeybek M and Zuo JY.Vol. 24, no. 4 (Winter 2012/2013): 14–25.

Seismic Detection of Subtle Faultsand FracturesAarre V, Astratti D, Al Dayyni TNA, Mahmoud SL, Clark ABS, Stellas MJ,Stringer JW, Toelle B, Vejbæk OV and White G.Vol. 24, no. 2 (Summer 2012): 28–43.

Sonic Logging WhileDrilling—Shear AnswersAlford J, Blyth M, Tollefsen E, Crowe J,Loreto J, Mohammed S, Pistre V andRodriguez-Herrera A.Vol. 24, no. 1 (Spring 2012): 4–15.

Specialized Tools for WellboreDebris RecoveryColl B, Laws G, Jeanpert J, Sportelli M,Svoboda C and Trimble M.Vol. 24, no. 4 (Winter 2012/2013): 4–13.

Testing the Limits in Extreme Well ConditionsAvant C, Daungkaew S, Behera BK, Danpanich S, Laprabang W, De Santo I,Heath G, Osman K, Khan ZA, Russell J,Sims P, Slapal M and Tevis C.Vol. 24, no. 3 (Autumn 2012): 4–19.

When Rocks Get Hot: ThermalProperties of Reservoir RocksChekhonin E, Parshin A, Pissarenko D,Popov Y, Romushkevich R, Safonov S,Spasennykh M, Chertenkov MV andStenin VP.Vol. 24, no. 3 (Autumn 2012): 20–37.

Working Out of a Tight SpotCosto B, Cunningham LW, Martin GJ,Mercado J, Mohon B and Xie L.Vol. 24, no. 1 (Spring 2012): 16–23.

EDITORIALS

Drilling Automation: GeneratingGreater Reliability and ProfitabilityFlorence F.Vol. 24, no. 2 (Summer 2012): 1.

Frontier Hydrocarbon Exploration:The Importance of Tectonic ModelsTapponnier P.Vol. 24, no. 3 (Autumn 2012): 1.

The Future of CCSFinley RJ.Vol. 24, no. 4 (Winter 2012/2013): 1.

Offshore Idle Iron: Remains of thePast or Infrastructure of the FutureHopkins H.Vol. 24, no. 1 (Spring 2012): 1.

DEFINING…INTRODUCINGBASIC CONCEPTS OF THE E&P INDUSTRY

Defining Cementing: Well Cementing Fundamentals Nelson EB.Vol. 24, no. 2 (Summer 2012): 59–60.

Defining Perforating: Detonation for Delivery Smithson T.Vol. 24, no. 1 (Spring 2012): 55–56.

Defining Porosity: How Porosity Is Measured Smithson T.Vol. 24, no. 3 (Autumn 2012): 63–64.

Defining Testing: Well Testing Fundamentalsvon Flatern R.Vol. 24, no. 4 (Winter 2012/2013): 54–55.

NEW BOOKS 52 Things You Should Know About GeophysicsHall M and Bianco E (eds).Vol. 24, no. 4 (Winter 2012/2013): 52.

Bacteria: The Benign, the Bad, and the BeautifulWassenaar TM.Vol. 24, no. 2 (Summer 2012): 57.

The Carbon Crunch: How We’reGetting Climate Change Wrong and How to Fix ItHelm D.Vol. 24, no. 4 (Winter 2012/2013): 52.

Climate Matters: Ethics in a Warming WorldBroome J.Vol. 24, no. 3 (Autumn 2012): 62.

The Diffusion Handbook: AppliedSolutions for EngineersThambynayagam RKM. Vol. 24, no. 1 (Spring 2012): 54.

Epigenetics in the Age of Twitter:Pop Culture and Modern ScienceWeissmann G.Vol. 24, no. 3 (Autumn 2012): 61.

Eruptions That Shook the WorldOppenheimer C.Vol. 24, no. 3 (Autumn 2012): 62.

The Face of the Earth: Natural Landscapes, Science, and CultureCampbell S with Hunt A, Kerridge R, Lynch T and Wohl E.Vol. 24, no. 4 (Winter 2012/2013): 52.

Fluid Mechanics, Heat Transfer, and Mass Transfer: Chemical Engineering PracticeRaju KSN.Vol. 24, no. 2 (Summer 2012): 58.

Free Radicals: The Secret Anarchyof ScienceBrooks M.Vol. 24, no. 3 (Autumn 2012): 60.

The House of Wisdom: How ArabicScience Saved Ancient Knowledgeand Gave Us the Renaissanceal-Khalili J.Vol. 24, no. 1 (Spring 2012): 53.

The Idea Factory: Bell Labs and theGreat Age of American InnovationGertner J.Vol. 24, no. 3 (Autumn 2012): 60–61.

Ignorance: How It Drives ScienceFirestein S.Vol. 24, no. 4 (Winter 2012/2013): 53.

Parameter Estimation and InverseProblems, Second EditionAster RC, Borchers B and Thurber CH.Vol. 24, no. 4 (Winter 2012/2013): 53.

The Philosophical Breakfast Club:Four Remarkable Friends WhoTransformed Science and Changedthe WorldSnyder LJ.Vol. 24, no. 1 (Spring 2012): 54.

Principles of Multiscale ModelingE W.Vol. 24, no. 2 (Summer 2012): 57.

The Quest: Energy, Security, andthe Remaking of the Modern WorldYergin D.Vol. 24, no. 1 (Spring 2012): 53.

Reinventing Discovery: The NewEra of Networked ScienceNielsen M.Vol. 24, no. 3 (Autumn 2012): 62.

The Story of Earth: The First 4.5 Billion Years, from Stardust to Living PlanetHazen RM.Vol. 24, no. 2 (Summer 2012): 58.

To Forgive Design: Understanding FailurePetroski H.Vol. 24, no. 4 (Winter 2012/2013): 53.

Turing’s Cathedral: The Origins ofthe Digital UniverseDyson G.Vol. 24, no. 3 (Autumn 2012): 61.

Volcanoes of the World, Third EditionSiebert L, Simkin T and Kimberly P.Vol. 24, no. 2 (Summer 2012): 58.

Waking the Giant: How a ChangingClimate Triggers Earthquakes,Tsunamis, and VolcanoesMcGuire B.Vol. 24, no. 3 (Autumn 2012): 60.

Wild Hope: On the Front Lines ofConservation SuccessBalmford A.Vol. 24, no. 4 (Winter 2012/2013): 53.

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Oilfield Review Annual Index—Volume 24