Oilfield Review Apps

Winter 2014/2015

Fracturing Unconventional Reservoirs

Improved Wireline Logging Cables

Ultradeep Water

Bioturbation

Oilfield Review

SCHLUMBERGER OILFIELD REVIEW

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INTER 2014/2015

VOLUME 26 N

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Oilfield Review AppsThe Schlumberger Oilfield Review app for Android† devices is now available free of charge on the Google Play† store. This new app complements the iPad‡ app, which is available at the Apple‡ iTunes‡ online store. For Android devices, including phones, this is a stand-alone app; accessing content on the iPad and iPhone‡ devices is done through the Newsstand.

Oilfield Review communicates advances in finding and producing hydrocarbons to oilfield professionals. Articles from the journal are augmented on the apps with animations and videos, which help explain concepts and theories beyond the capabilities of static images. The apps also offer access to several years of archived issues in a compact format that retains the high-quality images and content you’ve come to expect from the print version of Oilfield Review.

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Oilfield GlossaryAvailable in English and Spanish, the Oilfield Glossary is a rich accumulation of more than 5,800 definitions from18 industry disciplines. Technical experts have reviewed each definition; photographs, videos and illustrationsenhance many entries. See the Oilfield Glossary at http://www.glossary.oilfield.slb.com/.

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rmThe Last Word

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The current and future state of deepwater exploration and production brings another industry to mind—the space industry. Space exploration projects are expensive and highly complex, and the consequences of failure can be cat-astrophic. The space industry meets these challenges through a management process that integrates planning and execution along with comprehensive cause-and-effect risk management; this systems-based approach utilizes vir-tual simulation and modeling and optimal personnel train-ing programs.

In the E&P industry, geologists and geophysicists create 3D models of exploration prospects. For well construction and field development, the process includes the geome-chanics and drilling engineers. Modeling software, such as the Petrel* family of programs, facilitates this task by incorporating 3D geomechanical stresses and pore pres-sures, which allows drilling engineers to design optimal trajectories that maximize drilling windows.

Conventional drilling engineering relies on past experi-ence and iteration to account for the many variables that impact the well. This can lead to fragmented results, and lessons learned may be quickly outdated or their effective-ness difficult to assess. By contrast, a systems approach attempts to account for all controllable variables to pro-duce desired outcomes such as wellbore assurance and efficient drilling operations. Using simulation programs, engineers can pick an optimal wellbore trajectory and then run “what if” scenarios by varying well construction vari-ables. These iterations also allow engineers to validate the value of introducing new technology.

Operators new to deepwater and ultradeepwater projects soon learn that costs are significantly higher than those of shelf- and land-based projects. Hovering around US$ 1 mil-lion per day, or US$ 11.57 per second, costs are even higher in remote areas that have little infrastructure sup-port. Operators must also consider factors unique to work-ing on the open sea such as the surface and subsurface meteorological uncertainties of sea height, loop currents and hurricanes.

Success in deep water requires improved project plan-ning and execution and a new approach to preparing the next generation of technical experts. Deepwater and ultradeepwater projects, like those in the space industry, involve cross-discipline integration. Incorporating many disciplines under a single workflow captures and accounts for uncertainties and assumptions introduced by each dis-cipline throughout the planning process. Key to this meth-od’s success is the understanding that these uncertainties

Deep Water and Ultradeep Water: Managing Complexity Through Integrated Planning and Execution

1

can be decreased using real-time data to recalibrate the original models.

More attention to detail is required when preparing remote projects than is needed for those in mature deep-water markets. As in the space industry, successful deep-water operational preparedness utilizes a project management (PM) approach. Effective PM organizes a team to work together in a systematic and repeatable man-ner that allows improvements to be captured, replicated and included in productive workflows. The PM approach combines a formalized plan with a risk management sys-tem consisting of measurable components.

Many of the world’s offshore deepwater plays are in the early stages of exploration, and numerous countries are wel-coming international investment for these projects. Operations in emerging deepwater regions must attract the investment dollars and expertise of international operators to help explore and develop offshore acreage. Aware that these projects incur high technical and commercial risk, host gov-ernments often attempt to create an environment with mini-mal geopolitical risk and favorable commercial terms.

In addition to creating new workflows and new technolo-gies, the offshore E&P industry must attract and keep qualified and experienced personnel to service the highly complex deepwater projects of tomorrow. Experts predict the industry will soon have a shortage of experienced tech-nical personnel. The space industry fills its ranks with per-sonnel who possess proven skills and training to meet the requirements of their unique working environments. Offshore personnel also go through a rigorous deepwater certification process, which is validated by qualified experts.

In the quest for energy reserves, the deepwater and ultradeepwater arena continues to offer promise for explo-ration and production. The projects, although complex, can be managed through proper planning and execution meth-ods that ensure a safe, efficient and environmentally responsible outcome.

Chris GarciaSchlumberger Latin America Deepwater AdvisorHouston

Chris Garcia is Latin America Deepwater Advisor for Schlumberger. He began his career with deepwater drilling contractor Zapata Offshore. Since joining Schlumberger in 1987, he has held numerous positions, including deepwater theme manager for the Gulf of Mexico and deepwater business develop-ment manager in Mexico and Latin America. Chris received a BS degree in petroleum engineering from The University of Texas at Austin and is currently pursuing a project management professional certification.

An asterisk (*) denotes a mark of Schlumberger.

71917schD2R1.indd 1 1/21/15 5:58 PM

www.slb.com/oilfieldreview

Schlumberger

Oilfield Review1 Deep Water and Ultradeep Water: Managing Complexity Through Integrated Planning and Execution

Editorial contributed by Chris Garcia, Schlumberger Latin America Deepwater Advisor

4 Unlocking the Potential of Unconventional Reservoirs

A new stimulation technique that promotes the creation of hydraulic fractures through perforations that may have been ineffectively stimulated is helping to improve productivity in unconventional reservoirs. Engineers perform at least two fracturing treatments in an interval; the treatments are separated by a fluid containing a degradable diverting agent. Subsequent fracturing treatments stimulate regions that were bypassed during earlier treatments, thereby enhancing production.

18 Cables and Skates—Improving the Weakest Links

For almost a century, wireline logging has been essential to petrophysical data acquisition. Although new wireline technol-ogies continue to be developed, the basic logging cable design has remained relatively unchanged for decades. Schlumberger engineers recently introduced significant enhancements to cable design and auxiliary logging equipment that is especially useful for logging deepwater and ultradeep wells.

Oilfield Review AUTUMN 14BroadBand Fig OpenerORAUT 14 BRDBD Opener

Executive EditorLisa Stewart

Senior EditorsTony SmithsonMatt VarhaugRick von Flatern

EditorsIrene FærgestadRichard Nolen-Hoeksema

Contributing EditorsErik NelsonGinger Oppenheimer

Design/ProductionHerring DesignMike Messinger

Illustration Chris LockwoodMike 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. Download the free app.

© 2015 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 customers, employees 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:

A machine operator observes a wireline logging cable as it is manufactured at the Schlumberger Houston Conveyance and Surface Equipment Center in Sugar Land, Texas, USA. Straight armor wires enter the device from the right and are shaped before they are wrapped around an inner layer of armor wires. The inner layer (not shown) covers insulated con-ductor wires and has gone through a similar forming process but is wrapped in the opposite direction. A new cable design (inset) includes extruded polymer layers to create cables that resist crush-ing and are less prone to the effects of high tension than were previous- generation cables. (Photograph courtesy of Brian Yu.)

2

www.slb.com/oilfieldreview

Schlumberger

Oilfield Review1 Deep Water and Ultradeep Water: Managing Complexity Through Integrated Planning and Execution

Editorial contributed by Chris Garcia, Schlumberger Latin America Deepwater Advisor

4 Unlocking the Potential of Unconventional Reservoirs

A new stimulation technique that promotes the creation of hydraulic fractures through perforations that may have been ineffectively stimulated is helping to improve productivity in unconventional reservoirs. Engineers perform at least two fracturing treatments in an interval; the treatments are separated by a fluid containing a degradable diverting agent. Subsequent fracturing treatments stimulate regions that were bypassed during earlier treatments, thereby enhancing production.

18 Cables and Skates—Improving the Weakest Links

For almost a century, wireline logging has been essential to petrophysical data acquisition. Although new wireline technol-ogies continue to be developed, the basic logging cable design has remained relatively unchanged for decades. Schlumberger engineers recently introduced significant enhancements to cable design and auxiliary logging equipment that is especially useful for logging deepwater and ultradeep wells.


Executive EditorLisa Stewart

Senior EditorsTony SmithsonMatt VarhaugRick von Flatern

EditorsIrene FærgestadRichard Nolen-Hoeksema

Contributing EditorsErik NelsonGinger Oppenheimer

Design/ProductionHerring DesignMike Messinger

Illustration Chris LockwoodMike 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. Download the free app.

© 2015 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 customers, employees 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:

A machine operator observes a wireline logging cable as it is manufactured at the Schlumberger Houston Conveyance and Surface Equipment Center in Sugar Land, Texas, USA. Straight armor wires enter the device from the right and are shaped before they are wrapped around an inner layer of armor wires. The inner layer (not shown) covers insulated con-ductor wires and has gone through a similar forming process but is wrapped in the opposite direction. A new cable design (inset) includes extruded polymer layers to create cables that resist crush-ing and are less prone to the effects of high tension than were previous- generation cables. (Photograph courtesy of Brian Yu.)

2

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Winter 2014/2015Volume 26Number 4

ISSN 0923-1730

3

34 Beyond Deep—The Challenges of Ultradeep Water

The oil industry is drilling and completing wells in extreme water depths and to very deep drilling depths. Geologic and mechanical complexities, remote locations and new regula-tory requirements combine to create a working environment in which teamwork and technology are crucial for success.

46 Bioturbation: Reworking Sediments for Better or Worse

Bioturbation is the disturbance of sediments or soil by living organisms. Petroleum geologists use bioturbation to recognize key sequence stratigraphic surfaces and infer characteristics of the depositional environment. Bioturbation often affects porosity and permeability. Field examples show that bioturbation, which can be identified in core samples and image logs, can have a significant impact on hydrocarbon production.

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

Andrew Lodge Premier Oil plc London, England

Michael Oristaglio Yale Climate & Energy Institute New Haven, Connecticut, USA

Advisory Panel

Editorial correspondenceOilfield Review 5599 San FelipeHouston, TX 77056United States(1) 713-513-1194Fax: (1) 713-513-2057E-mail: [email protected]

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: [email protected]

Distribution inquiriesMatt VarhaugOilfield Review 5599 San FelipeHouston, TX 77056United States(1) 713-513-2634E-mail: [email protected]

59 Contributors

60 Coming in Oilfield Review

61 Books of Note

62 Defining Intervention: Upstream Maintenance and Repair

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

64 Annual Index

Winter 2014/2015Volume 26Number 4

ISSN 0923-1730

3

34 Beyond Deep—The Challenges of Ultradeep Water

The oil industry is drilling and completing wells in extreme water depths and to very deep drilling depths. Geologic and mechanical complexities, remote locations and new regula-tory requirements combine to create a working environment in which teamwork and technology are crucial for success.

46 Bioturbation: Reworking Sediments for Better or Worse

Bioturbation is the disturbance of sediments or soil by living organisms. Petroleum geologists use bioturbation to recognize key sequence stratigraphic surfaces and infer characteristics of the depositional environment. Bioturbation often affects porosity and permeability. Field examples show that bioturbation, which can be identified in core samples and image logs, can have a significant impact on hydrocarbon production.

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

Andrew Lodge Premier Oil plc London, England

Michael Oristaglio Yale Climate & Energy Institute New Haven, Connecticut, USA

Advisory Panel

Editorial correspondenceOilfield Review 5599 San FelipeHouston, TX 77056United States(1) 713-513-1194Fax: (1) 713-513-2057E-mail: [email protected]

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: [email protected]

Distribution inquiriesMatt VarhaugOilfield Review 5599 San FelipeHouston, TX 77056United States(1) 713-513-2634E-mail: [email protected]

59 Contributors

60 Coming in Oilfield Review

61 Books of Note

62 Defining Intervention: Upstream Maintenance and Repair

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

64 Annual Index

71917schD3R1.indd 3 1/20/15 2:41 AM

4 Oilfield Review

Unlocking the Potential of Unconventional Reservoirs

Hydraulic fracturing treatments are performed to create a highly conductive flow

path from the reservoir to the wellbore. Maximal effectiveness requires stimulating

all perforations in the treated interval. However, achieving such coverage is

challenging in unconventional reservoirs because fracture initiation pressures

can vary widely within the perforated interval. A new fracturing service that employs

a novel diverting agent improves production from established fields and allows

operators to develop areas that previously were not economically viable.

Chad KraemerHouston, Texas, USA

Bruno LecerfAlejandro PeñaDmitriy UsoltsevSugar Land, Texas

Pablo ParraReynosa, Tamaulipas, Mexico

Ariel ValenzuelaPetróleos Mexicanos (PEMEX)Reynosa, Tamaulipas, Mexico

Hunter WatkinsBHP Billiton PetroleumHouston, Texas

Oilfield Review Winter 2014/2015: 26, no. 4.Copyright © 2015 Schlumberger.For help in preparation of this article, thanks to Olga Alekseenko, Novosibirsk, Russia; Anna Dunaeva, Mohan Panga, Dmitriy Potapenko and Zinaida Usova, Sugar Land, Texas, USA.BroadBand Precision, BroadBand Sequence, CemCRETE, ClearFRAC, HiWAY and Mangrove are marks of Schlumberger.

For decades, the oil and gas industry has per-formed hydraulic fracturing to enhance or pro-long well productivity. Without fracturing, producing from many hydrocarbon reservoirs being developed today would not be technically or economically feasible.

During a fracturing treatment, specialized equipment pumps fluid into a well faster than it can be absorbed by the formation, causing pres-sure on the formation to rise until the rock frac-tures, or breaks down. Continued pumping causes the fracture to propagate away from the wellbore, increasing the formation surface area through which hydrocarbons can flow into the wellbore and helping the well achieve a higher production rate than would otherwise be possible. As a result, the volume of produced hydrocarbons increases dramatically, and operators recover their development investment costs more quickly.

Fracturing operations employ two principal substances—proppants and fracturing fluids.1 Proppants are particles that hold the fractures open, preserving the newly formed pathways. Fracturing fluids may be aqueous or nonaqueous and must be sufficiently viscous to create and propagate a fracture and also transport the prop-pant down the wellbore and into the fracture. Once the treatment ends, the fracturing fluid

viscosity must decrease enough to promote rapid and efficient evacuation of the fluid from the well.

Traditional fracturing treatments consist of two fluids. The first fluid, or pad, does not con-tain proppant and is pumped through casing perforations at a rate and pressure sufficient to break down the formation and create fractures.2 The second fluid, or proppant slurry, transports proppant through the perforations into the newly opened fractures. When pumping ceases, the fractures relax, holding the proppant pack in place, and the fracturing fluids flow back into the wellbore to make way for hydrocarbon pro-duction. Ideally, the proppant pack should be free of stimulation fluid residue that can impair conductivity and hydrocarbon production.

For more than 60 years, chemists and engi-neers have sought to develop fracturing fluids, proppants and placement techniques that help produce ideal propped fractures and maximize well productivity. As a result, the chemical and physical nature of fracture fluids has evolved significantly. The industry has developed essen-tially residue-free fluids; an example is the ClearFRAC family of polymer-free fracturing fluids.3 Heterogeneous proppant packs have fur-ther enhanced proppant pack conductivity, exemplified by the HiWAY flow-channel hydraulic fracturing technique.4

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Winter 2014/2015 55

Today’s proppant packs pose little resistance to fluid flow. However, achieving optimal well productivity still requires that the fracturing fluid be able to enter all of the perforations, thereby allowing maximal wellbore access to the region to be stimulated. Failure to do so may leave a large fraction of the reservoir untouched and, consequently, large volumes of hydrocar-bons inaccessible.

Treating all perforations is particularly challenging when stimulating shale formations.5 Most operators produce from horizontal well-

bores that may extend for hundreds of meters through the producing formation. Therefore, to ensure adequate stimulation, completion opera-

tions are performed in steps during which the well is divided into multiple intervals and treated in stages.

1. For more on fracturing fluids and proppants: Gulbis J and Hodge RM: “Fracturing Fluid Chemistry and Proppants,” in Economides MJ and Nolte KG (eds): Reservoir Stimulation, 3rd ed. Chichester, West Sussex, England: John Wiley & Sons, Ltd. (2000): 7-1–7-23.

2. Perforations, holes created in the casing by guns equipped with explosive shaped charges, produce tunnels through the casing and cement sheath to provide communication between the casing interior and the producing reservoir.

3. Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang Y, Krauss K, Nelson E, Lantz T, Parham C and Plummer J:


“Clear Fracturing Fluids for Increased Well Productivity,” Oilfield Review 9, no. 3 (Autumn 1997): 20–33.

4. d’Huteau E, Gillard M, Miller M, Peña A, Johnson J, Turner M, Medvedev O, Rhein T and Willberg D: “Open-Channel Fracturing—A Fast Track to Production,” Oilfield Review 23, no. 3 (Autumn 2011): 4–17.

5. Unconventional formations include those characterized by pores that are insufficiently connected to allow oil and natural gas to move naturally through the rock to the wellbore. Economically extracting hydrocarbons from such formations requires operators to drill horizontal wells through the producing interval and perform hydraulic fracturing treatments, thereby maximizing wellbore access.

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6 Oilfield Review

Operators frequently employ a stimulation method known in the industry vernacular as the “plug-and-perf” technique (below).6 After the wellbore has been drilled, cased and cemented, engineers run a perforating system inside the casing toward the farthest extremity of the well—the toe. A first interval, up to about 100 m [330 ft] in length, is perforated and fractured. Next, the engineers set a plug inside the casing adjacent to the newly fractured interval to isolate

the fractures from the rest of the well. A second stage is then perforated behind the plug, fol-lowed by a second fracturing treatment. This sequence may be performed many times until the entire horizontal portion of the well has been perforated and stimulated.

Traditionally, the length of each perforated interval has been the same throughout the well, and the plugs were equidistant. Such designs are called geometric completions. However, because

shales are usually heterogeneous, engineers have begun using seismic and log data to determine for-mation mechanical properties and productivity potential along the wellbore. Operators then limit perforating and stimulation to potentially more-productive areas, forming optimized perforation clusters. This approach usually reduces the num-ber of stages and plugs, thereby lowering costs without sacrificing well productivity (next page).7 These designs are called engineered completions.

> Plug-and-perf technique. Horizontal wells may extend hundreds of meters away from the vertical section of the wellbore. Most of the horizontal section of the well passes through the producing formation (gray) and is completed in stages. The wellbore begins to deviate from vertical (top left ) at the kickoff point. The beginning of the horizontal section is the heel, and the farthest extremity of the well is the toe. Engineers perform the first perforating operation at the toe (top right ) and follow it with a fracturing treatment (middle left ). They then place a plug (middle right ) in the well that hydraulically isolates the newly fractured rock from the rest of the well. A section adjacent to the plug is perforated (bottom left ); another fracturing treatment follows (bottom right ). This sequence may be repeated until the horizontal section is stimulated from the toe back to the heel. In a final step, a milling operation (not shown) removes the plugs from the well and allows production to commence.

Oilfield Review AUTUMN 14BroadBand Fig 1ORAUT 14 BRDBD 1

Kickoffpoint

Heel Toe

PlugFracturing fluid

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Winter 2014/2015 7

Despite production improvements realized by the optimized cluster technique, fracture initia-tion pressures within an interval may still be highly variable, leading to uneven stimulation among the perforation clusters. Perforations adja-cent to low–fracture gradient rock are preferen-tially stimulated, leaving those in more resistant rock untouched. When conventional fracturing methods are employed, up to 40% of the perfora-tions may fail to contribute to production.8

Schlumberger chemists and engineers inves-tigated the efficiency problem associated with stimulating shale formations with the goal of developing methods that tap elusive hydrocar-bons and improve production results. Their efforts resulted in the development of the BroadBand Sequence fracturing service. This recently introduced service consists of pumping a unique diverting agent into a well between frac-turing treatments.

This article tracks the development of the BroadBand Sequence approach from the labora-tory to its introduction into the oil field. Case histories from the US and Mexico demonstrate the well productivity improvements and cost savings that have been achieved by applying this technique.

Sequenced Fracturing TechniqueThe traditional plug-and-perf completion method features one fracturing treatment, or stage, per

interval. After the treatment, any unstimulated perforations are ignored as the operator pro-ceeds to stimulate the next interval. Under these circumstances, the benefits of performing a sec-ond stage would be limited. The fracturing fluid would take the path of least resistance and flow into previously stimulated perforations.

Schlumberger engineers considered the pos-sibility of following the first fracturing treatment with a pill containing a diverting material that would plug the initially stimulated perforations. They theorized that, during a second fracturing treatment, the fluid would be diverted away from the plugged perforations and into unstimulated perforations, thereby fracturing two distinct regions in an uninterrupted sequence and improving well productivity. However, restoring fluid flow through the initially stimulated perfo-rations would require that the diverting material be degradable and removable.

Using diverting agents is a common practice in other oilfield operations such as matrix acidiz-ing treatments. The agents plug the most perme-able pores in the rock matrix, allowing acid to concentrate on less permeable areas.9 For hydraulic fracturing, the diversion scale is much larger than that for matrix acidizing. The divert-ing agent must be able to plug fractures with near-wellbore widths between about 1 and 6 mm [0.04 and 0.24 in.]. In addition, for logistical

reasons, the volume of the fluid containing the diverting agent must be minimized.

Building on knowledge acquired during the development of CemCRETE concrete-based oil-well cementing technology, the engineers knew that efficient plugging can be achieved when a fluid contains materials with a multimodal par-ticle size distribution.10 For example, a trimodal system may be designed such that the three sizes of the particle groups differ by approximately one order of magnitude. When the particles are mixed together, the small particles fit within the

6. Daneshy A: “Hydraulic Fracturing of Horizontal Wells: Issues and Insights,” paper SPE 140134, presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, USA, January 24–26, 2011.

7. Ajayi B, Aso II, Terry IJ Jr, Walker K, Wutherich K, Caplan J, Gerdom DW, Clark BD, Ganguly U, Li X, Xu Y, Yang H, Liu H, Luo Y and Waters G: “Stimulation Design for Unconventional Resources,” Oilfield Review 25, no. 2 (Summer 2013): 34–46.

8. Miller C, Waters G and Rylander E: “Evaluation of Production Log Data from Horizontal Wells Drilled in Organic Shales,” paper SPE 144326, presented at the SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, USA, June 12–16, 2011.

9. Asiri KS, Atwi MA, Jiménez Bueno OJ, Lecerf B, Peña A, Lesko T, Mueller F, Pereira AZI and Tellez Cisneros F: “Stimulating Naturally Fractured Reservoirs,“ Oilfield Review 25, no. 3 (Autumn 2013): 4–17.

10. Boisnault JM, Guillot D, Bourahla A, Tirlia T, Dahl T, Holmes C, Raiturkar AM, Maroy P, Moffett C, Perez Mejía G, Ramirez Martínez I, Revil P and Roemer R: “Concrete Developments in Cementing Technology,” Oilfield Review 11, no. 1 (Spring 1999): 16–29.

> Comparison of geometric and engineered completions. Geometric completions (Track 5) feature stages of equal length (full lengths of stages not displayed), and perforation clusters are evenly spaced. Engineered completions (Track 4) take reservoir quality (RQ) and completion quality (CQ) into account when determining the locations of perforation clusters. The Mangrove software analyzes the log data and assigns good (blue) or bad (red) ratings for both RQ and CQ (Tracks 1 and 2). The software uses the RQ and CQ grades to further determine a composite score (Track 3). The best locations have good RQ and CQ grades. In this example, Stage 15 of the engineered completion has been designed such that it spans a region with a fairly uniform stress gradient (Track 6). Furthermore, engineers avoided placing perforation clusters at locations where both RQ and CQ grades were bad.


Composite

Completionquality

Reservoirquality

Engineeredcompletion

Geometriccompletion

Stressgradient

12,250 12,300 12,400 12,500 12,600 12,700 12,80012,350 12,450 12,550 12,650 12,750

Track 1

Track 2

Track 3

Track 4 Stage 16

Stage 15 Stage 14

Stage 15

Track 5

Track 6

Measureddepth, ft

Perforation clusters

Completion

Good RQ and good CQ Bad RQ and bad CQ Bad RQ and good CQ Good RQ and bad CQ

Good

Good

Good

Bad

Bad

Bad

Bad

Bad

Bad

Bad

Good

Good

Good

Good

Good

Bad

Bad

Bad

Good

Good

BG BGBB BB BB GGGG GGGB GB GB GB GB GB

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8 Oilfield Review

interstices of the medium-size particles, and the medium-size particles fit within the interstices of the large particles. As a result, a low-permea-bility plug may readily form in a fracture (above).

Using this packing principle, researchers per-formed diversion tests in the laboratory with a simple benchtop device consisting of a syringe connected to a slot whose width could be adjusted between 8 and 16 mm [0.31 and 0.63 in.] (below).11 They placed a screen sieve at the end of the slot with openings that were about 0.5 mm [0.02 in.]

smaller than the diameter of the largest particles but larger than those of the smaller particles. Thus, the slot and screen simulated a perforation tunnel and a fracture entrance.

Engineers varied the sizes and relative con-centrations of the particles. The test slurries, called composite fluids, were prepared from a guar gum solution in water. The solutions con-tained multimodal mixtures of degradable parti-cles whose sizes varied between a few microns and several millimeters.

11. Kraemer C, Lecerf B, Torres J, Gomez H, Usoltsev D, Rutledge J, Donovan D and Philips C: “A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale,” paper SPE 169010, presented at the SPE Unconventional Resources Conference—USA, The Woodlands, Texas, April 1–3, 2014.

12. Chromatography pumps deliver fluids at accurate and precise rates. They are usually employed during high-performance liquid chromatography experiments.

For optimal cleanup after a diversion treat-ment, confining the degradable polymer plug to the near-wellbore region is usually considered the best strategy. Therefore, engineers sought to identify composite fluids that had the ability to plug the screen quickly and minimize the volume of filtrate entering fractures. After determining the most efficient particle size distribution, they learned that the composite fluids needed to con-tain degradable fibers to prevent particle segre-gation or size classification during pumping.

After placement in a fracture, the plugging material must remain intact during the time required to complete a fracturing stage—typi-cally about four hours. To verify that the candi-date compositions met this requirement, engineers built a bridging apparatus that could simulate downhole temperature and pressure conditions (next page, top). The apparatus con-sisted of an accumulator, a chromatography pump and a 3.4-mm [0.13-in.] slot to simulate a fracture.12 Technicians placed the composite fluid in the accumulator and pumped the fluid into the slot until a plug formed. The pump con-tinued to pressurize the system for four hours at 8.3 MPa [1,200 psi]. Engineers attached heating tape around the slot, enabling testing at tempera-tures up to 95°C [203°F].

Most of the composite fluids that efficiently formed plugs during the initial syringe tests also demonstrated good plug stability. Few particles passed through the slot before plug formation, and no plug extrusion took place during the tests. Measurements showed that the permeability of the plugs was often too low to measure.

Having established that the composite fluid plugs were sufficiently resilient to withstand a fracturing stage, engineers needed to ensure that the plugs would degrade and clear the way for unobstructed hydrocarbon production. They were most concerned about the degrada-tion rate of the large polymer particles.

Researchers performed aging tests during which they immersed the multimodal particle mixtures in water and measured polymer degra-dation versus time and temperature (next page, bottom). Complete polymer removal occurred within 10 days at temperatures higher than 90°C [194°F]. In many wellbore scenarios, water avail-

> Fracture diversion concept. A multimodal composite fluid of degradable particles (blue spheres) and fibers forms a plug in a fracture. Ideally, the large particles do not bridge at the perforation entrance but quickly become lodged in the near-wellbore region of the fracture. A low-permeability plug forms as the smaller particles congregate in the interstices of the larger ones.


Particles jamming fracturePerforation

Wellbore

Perforation tunnelCasing

Fracture

> Benchtop device for experiments to optimize the particle size distribution of diverting agents. The apparatus consists of a 60-mL [3.7-in.3] syringe (top) connected to a rectangular slot whose width can be adjusted between 8 and 16 mm [0.31 and 0.63 in.]. The slot is analogous to a perforation tunnel. A sieve (bottom left ), located at the far end of the slot, simulates the fracture entrance. During an experiment, a test slurry, or composite fluid, flows from the syringe into the slot and then through the sieve. Flow continues until the sieve becomes plugged with particles (bottom right ). Technicians measure the volume of filtrate that passed through the sieve before plugging occurred. Low filtrate volumes are preferred. (Adapted from Kraemer et al, reference 11.)

35 mm

8 to 16mm

145 mm

Slot Sieve

Syringe


Sieve

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Winter 2014/2015 9

ability may be limited; therefore, testing also included measuring the effect of the water-to-polymer ratio on the degradation rate. At water-

to-polymer ratios higher than 0.125, complete polymer removal took place within 8 days at 90°C [194°F].

Laboratory testing demonstrated the feasi-bility of using degradable polymer particles for hydraulic fracturing diversion. The next task was

> Diverter plug stability tests. Engineers constructed a laboratory-scale device (left ) for determining whether plugs made from degradable particles could survive for at least four hours under downhole temperatures and pressures. A high-pressure chromatography pump forces composite fluid from an accumulator into a 3.4-mm [0.13-in.] slot that simulates a fracture. After a plug forms in the slot, the pump continues to pressurize the system for four hours at 8.3 MPa [1,200 psi]. The slot is surrounded by heating tape, allowing experiments to take place at temperatures up to 95°C [203°F]. During most tests, few particles exited the slot before a cylindrical plug formed (right ), and no plug extrusion occurred.


Chromatographypump

Heating tape

1 m

20 mm

Accumulator

70 mm3.4 mm

45°

20 cm

> Diverting agent degradation tests. Researchers performed aging tests on diverter materials to evaluate the effectiveness of the treatments. Technicians placed specific amounts of multimodal polymer particles in 100-mL [3.4-oz] bottles filled with water. Next, they sealed the bottles and placed them in ovens at various temperatures. They then measured the amounts of solids remaining in the bottles versus time (left). Complete degradation occurred when 100% of the solids had disappeared. After 10 days, more than 70% of the solids had disappeared at 80°C [176°F]. Complete degradation had occurred within the same time period at 90°C [194°F] and 100°C [212°F]. A second series of tests investigated the effect of limited water availability on polymer degradation (right). Such a condition is possible in many wellbore scenarios such as dry gas wells. Technicians prepared samples at various water-to-polymer ratios, heated them at 90°C and measured the percent degradation after 2, 6 and 8 days. With the exception of the sample that had a ratio of 0.125, complete degradation occurred within 8 days. At present, three versions of the diverting agent exist, applicable across a temperature range between 38°C and 177°C [100°F and 350°F].

90

80

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adat

ion,

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Water/polymerweight ratio

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10 Oilfield Review

to scale up the technology and prove that it could be applied practically and economically in the field.

Designing and Delivering the Composite FluidThe BroadBand Sequence service plugs perfora-tions that were successfully treated during the first fracturing operation. To accomplish this con-sistently, engineers had to determine optimal composite fluid volumes and diverter material concentrations for various downhole scenarios. This task was a major challenge because no practi-cal way exists to duplicate the downhole diversion environment in a laboratory setting. Engineers determined that testing in wells was the only way to proceed.

The Schlumberger researchers presented the BroadBand Sequence concept and laboratory data to several clients who agreed to allow exper-iments in their wells. Client engineers consid-ered the risk low because if a well became plugged during an experimental treatment, the obstruc-tion would be temporary owing to diverter mate-rial degradability. Before field testing could

commence, engineers needed to determine how to prepare and deliver the composite fluid using existing field equipment.

Tests were performed to determine how a homogeneous and stable composite fluid could be mixed using existing equipment and to verify that the pill would remain homogeneous during trans-port from the mixing and pumping equipment to the well. Engineers validated a batch mixing tech-nique using the tubs of standard Schlumberger cementing units. They also discovered that fiber-laden spacer fluids were necessary before and after the composite fluid to maintain pill stability and prevent contamination. Thus, the diverter pill consists of three parts (left).

The particles larger than 4 mm [0.157 in.] were also a major concern for the members of the design team because they were uncertain if the large particles would be able to pass through the pump truck valves without causing damage. Engineers determined that a dedicated fracturing pump that had modified valves would be required for all BroadBand Sequence treatments.

> BroadBand Sequence diverter pill. The composite fluid of the diverter pill contains a multimodal mixture of degradable polymer particles (top). The particle sizes are between several microns and several millimeters. The pill consists of three parts (bottom). The diversion fluid containing the polymer particles is preceded and followed by a degradable fiber–laden spacer fluid. The spacers keep the diversion fluid intact as it flows through surface equipment and casing and prevents diversion-fluid contamination before it contacts perforations. The fluid viscosity should also be at least 20 mPa.s at a shear rate of 511/s to prevent particle bridging at the perforation entrances.


Spacer

Composite fluid

Spacer

> BroadBand Sequence pumping schedule. This schematic plot presents the timing and changes of surface pressure (red line) and pump rate (blue line) for a BroadBand Sequence treatment. First, engineers perform an injection test to verify that at least some of the perforations are able to receive fluid from the wellbore. The initial fracturing treatment, Stage 1, then commences, during which proppant (green) flows into the fractures. Next (pink), engineers pump a BroadBand Sequence composite fluid into the well. They record an initial surface pressure and monitor the pressure increase as the composite fluid flows into the well. The surface pressure levels off, indicating that the perforations treated during Stage 1 have been plugged. The difference between the final and initial pressures is the ΔPdiversion. A step-down stage then commences, during which the pump rate is briefly increased to encourage further penetration of diverting material into the perforations, leaving the wellbore clear. The second fracturing treatment, Stage 2, is similar to the first. The pressure rise and decline indicates that additional perforations received fracturing fluid and new fractures were induced.


ΔPdiversion

Injectiontest Stage 1 Stage 2

Step-downDi

versi

on

Incr

easi

ng p

ress

ure

Incr

easi

ng p

ump

rate

Time

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Winter 2014/2015 11

Next, engineers assembled the equipment at client wellsites and initiated field testing. The principal objective was to establish guidelines for achieving diversion using composite fluids that had maximal diverter-material concentrations and minimal total volumes. Testing commenced based on an idealized pumping schedule (previ-ous page, top right).

This scenario calls for engineers to perform an injection test then execute a first fracturing treat-ment and monitor the surface pressure. A pressure increase followed by a drop in pressure indicates that formation breakdown and fracture initiation have occurred. The surface pressure gradually declines during proppant placement. Pumping ceases before the BroadBand Sequence composite fluid is placed. The pressure rises during the com-posite fluid placement and begins to level off,

indicating that previously stimulated perforations have been plugged. A second fracturing treatment is then performed, during which another pressure increase occurs, followed by a pressure drop, indi-cating that fracture initiation has occurred at the previously unstimulated perforations, allowing addi-tional proppant placement. Subsequent diversion treatments may be performed until optimal stimula-tion has been achieved.

One series of treatments took place in south Texas, USA. Engineers treated a perforated inter-val with six fracturing stages separated by BroadBand Sequence composite fluids (below). Three radioactive tracer logs acquired during the treatments allowed personnel to verify the diver-sion and creation of new fractures. In addition, the operator recorded the ISIP after each frac-turing stage. During this series of treatments, the

volume of each diverter pill was 20 bbl [3.18 m3], and the amount of diverting material varied from 50 to 75 lbm [23 to 34 kg]. The tracer logs indi-cated that the composite fluids were working as designed. The instantaneous shut-in pressure (ISIP) increased from 6,600 psi to 7,200 psi [44.5 to 49.6 MPa].

Schlumberger engineers formulated guide-lines for the BroadBand Sequence service after the field trials. The composite fluid volume and diverter material concentration depend on the length of the treated interval and the number of perforations. The default formulation allocates 1.4 kg [3 lbm] of diverter material per perforation hole, and sufficient material is added to plug half of the holes. As an operator gains experience in a particular field, formulation adjustments may be made to optimize results.

> BroadBand Sequence field test. During a field trial, engineers pumped six fracturing treatments into a perforated interval. Tracer logs were generated to analyze the results (top). Track 1 shows the results of an iridium log (red) after the first fracturing stage and before the first BroadBand Sequence pill was pumped. Track 2 is a scandium log (yellow), taken after the third fracturing stage. Evidence of fracture plugging may be seen at 16,950 ft, where no scandium had entered the previously created fracture. A third tracer log employing antimony (blue), measured at the end of the sixth fracturing stage, is shown in Track 3. The amount of diverting agent had been increased to 75 lbm [34 kg], and the log shows evidence of fracture plugging at 16,650 to 16,750 ft, 17,000 to 17,100 ft and 17,400 to 17,650 ft. New fractures appeared between 17,300 and 17,350 ft. Engineers also measured the instantaneous shut-in pressure (ISIP) following each stage (bottom). Following the BroadBand Sequence treatments, the ISIP increased, particularly after Stages 5 and 6. Track 4 presents another view of the tracer data, superimposed onto a lithology log. The lithology log, generated from gamma ray data, provides information about the relative clay content.

16,600 16,700 16,800 16,900 17,000 17,100 17,200 17,300 17,400 17,500 17,600

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7,200

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6,800

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6,400

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anta

neou

s sh

ut-in

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ssur

e, p

si

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Track 1

Track 2

Track 3

Track 4


6 5 4 3 2 1

Measureddepth, ft

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12 Oilfield Review

Stimulating the Eagle Ford ShaleThe Late Cretaceous-age Eagle Ford Shale forma-tion underlies much of south Texas (above). The formation has an average thickness of 250 ft [76 m] at depths between 4,000 and more than 14,000 ft [1,200 and 4,300 m]. This formation became an active play in 2008 after the first horizontal well was completed using the plug-and-perf technique. By 2012, the Eagle Ford Formation had become one of the most prolific shale plays in the world.

Initial fracturing treatments were performed at high pump rates using low-viscosity water-base fluids containing friction reducers. Proppant con-centrations were usually lower than 3 ppa.13 Completion practices in many wells changed in 2010 with the successful introduction of channel fracturing techniques such as the HiWAY service, which creates heterogeneous proppant packs.14 The HiWAY method also features fiber-laden frac-turing fluids that enhance proppant transport and reservoir coverage. Such fluids allow opera-

tors to increase the fluid viscosity and proppant concentrations, thereby reducing the volume of water required to perform a treatment.

Most wells in this region were stimulated using geometric completions. A recent study revealed that only 64% of the perforation clusters were contributing to overall production.15 In an attempt to improve results, several operators increased the differential pressure across perfo-rations by reducing the number of perforation clusters per stimulation stage. This approach required a higher number of wireline interven-tions to place additional bridge plugs as well as longer milling operations to remove the plugs. Not only did completion costs and times increase, but each intervention increased operational risks.

In view of the successful BroadBand Sequence field trial in the Eagle Ford Shale, BHP Billiton Petroleum opted to evaluate the service’s impact on production.16 The operator selected three wells from an eight-well, three-pad project for stimulation.

The bottomhole static temperature was approxi-mately 300°F [150°C], the average true vertical depth (TVD) was 12,000 ft [3,700 m] and lateral well lengths varied between 4,800 and 5,000 ft [1,460 and 1,520 m].

The completion design strategy for all wells on the pad included 300-ft [90-m] intervals with six perforation clusters spaced 50 ft [15 m] apart. The stimulation fluid and proppant volumes were equal in the BroadBand Sequence and offset wells. Engineers employed the HiWAY channel fracturing technique during all stages, using a borate-crosslinked guar fracturing fluid.

The operator performed conventional one-stage stimulation treatments in the offset wells, whereas the BroadBand Sequence treatment consisted of two fracturing events—each employ-ing half the fluid volume of the offset treat-ments—separated by the composite diverter fluid. The treated interval lengths were equal, allowing a realistic comparison. Engineers

> Eagle Ford Shale play. This formation, located in south Texas, USA, produces gas as well as relatively large volumes of oil and condensate. It is the source for the oil and gas found in the prolific Austin Chalk reservoir. Because the Eagle Ford has a high carbonate content, it is brittle and amenable to fracturing treatments. (Adapted from Kraemer et al, reference 11.)

–4,000–6,000

–8,000

–10,00

0

–12,000

–14,000

–2,000

Houston

Austin

San Antonio

M E X I C O Gul f of Mex icoTexas

S

Oil wellGas well

Wet gas, condensateDry gas

Oil

Oil wellGas well

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km0

0

50

mi


Eagle Ford ProductionE l F d P d tiE l F d P d ti

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Winter 2014/2015 13

monitored surface pressure during the treat-ments. The pump rate was 15 bbl/min [2.4 m3/min] during placement of the composite fluid. The measured diversion pressures (Δ Pdiversion) during each stage varied from 143 to 3,700 psi [1.0 to 25.5 MPa].

Engineers acquired tracer logs to monitor the diversion arising from the BroadBand Sequence treatments (above). The logs showed that 80% of the stages experienced near-wellbore diversion. The operator also recorded ISIPs before and after each treatment stage for each well. Compared with offset wells that experienced an average net pressure gain of 263 psi [1.81 MPa], the wells treated by the BroadBand Sequence technique showed a pressure gain of 313 psi [2.16 MPa].

BHP Billiton engineers then measured pro-duction rates of all the wells and normalized the results according to the lateral length of each well. After 140 days, the BroadBand Sequence wells were 20% more productive than the con-

ventionally treated offset wells. As a result, BHP Billiton has continued to employ the BroadBand Sequence service in this field.

Remedial Stimulation in South TexasAnother Eagle Ford Shale operator has been engaged in restimulating older wells in the region. The company’s goal is to accelerate and increase oil and gas recovery by reestablishing conductivity in old hydraulic fractures and stimu-lating new reservoir volume.

The wells are in the high-pressure, high- temperature (HPHT) category and have fracture gradients between 0.85 and 0.95 psi/ft [19.2 and 21.5 kPa/m], TVDs between 12,000 and 13,500 ft [3,700 and 4,100 m] and bottomhole temperatures between 300°F and 345°F [150°C and 174°C].

A key challenge for these refracturing opera-tions is achieving effective stimulation along the length of the laterals—4,000 to 6,000 ft [1,200 to 1,800 m]. Since some of the perforations are

13. Proppant concentrations are commonly expressed in pounds of proppant added—abbreviated as ppa. One ppa is defined as one pound of proppant added to each gallon of fracturing fluid. There is no recognized SI equivalent to ppa.

14. Gillard M, Medvedev O, Peña A, Medvedev A, Peñacorada F and d’Huteau E: “A New Approach to Generating Fracture Conductivity,” paper SPE 135034, presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, September 20–22, 2010.

> Tracer logs across a section of Eagle Ford Shale stimulated by the BroadBand Sequence technique. Two perforation clusters (7 and 8, Track 3) received two fracturing treatments. During the first fracturing treatment, indium tracer (Track 1, red) entered perforations in both clusters. After the BroadBand Sequence composite fluid, scandium tracer (Track 2, yellow), pumped during the second fracturing treatment, entered perforations that had been missed during the first treatment. The new fractures created during the second treatment are indicated by the presence of the scandium tracer. Track 3 presents the tracer data superimposed onto a lithology log. The lithology log, generated from gamma ray data, provides relative clay content.


8 7

Fractures plugged by diverterNew stimulated areas

14,900 15,000 15,100 15,200 15,300 15,400

Track 1

Track 2

Track 3

Totaldepth, ft

15. Slocombe R, Acock A, Fisher K, Viswanathan A, Chadwick C, Reischman R and Wigger E: “Eagle Ford Completion Optimization Using Horizontal Log Data,” paper SPE 166242, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, September 30–October 2, 2013.

16. Viswanathan A, Watkins H, Reese J, Corman A and Sinosic B: “Sequenced Fracture Treatment Diversion Enhances Horizontal Well Completions in the Eagle Ford Shale,” paper SPE 171660, presented at the SPE/Canadian Society for Unconventional Resources (CSUR) Unconventional Resources Conference—Calgary, September 30–October 2, 2014.

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14 Oilfield Review

open, mechanical aids such as bridge plugs and mechanical packers cannot be used. The BroadBand Sequence service had potential as a solution because of its ability to establish tempo-rary isolation of perforation clusters. The operator decided to evaluate the new technology.

The candidate well, originally one of the best producers in the field, had been stimulated two years earlier. The original completion strategy consisted of 13 fracturing stages. For the refrac-turing operation, engineers followed a similar 13-stage strategy using the HiWAY fracturing technique. They pumped BroadBand Sequence composite pills between each of the fracturing

stages to enable temporary isolation of previously stimulated clusters.

All 13 refracturing stages took place within 36 hours. The ISIP measurements performed at the end of each stage showed a progressive increase toward values that are characteristic of untreated rock in the area, indicating that the diverter pills were opening new paths as planned (above). Following refracturing, the operator placed the well into production. After 45 days, oil and gas production rates had doubled, and tubing pressure increased fourfold. Calculations for the well’s productivity index (PI), which take into account both rates and pressures to normalize production, indicated a PI increase greater than 600% after the restimulation operation.17

Sequenced Fracturing in MexicoIn 2010, exploration of gas- and oil-rich shale reservoirs began in northeast Mexico. The Pimienta Formation, located in the Burgos basin is a heterogeneous mudstone that con-tains thin shale beds (left). During the initial development, Petróleos Mexicanos (PEMEX)

> The Burgos basin in northeast Mexico. The Pimienta Formation in the Burgos basin is of Jurassic origin. It is a lithologically heterogeneous organic-rich mudstone that includes thin-bedded dark gray to black shales.


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17. The productivity index (PI) is a mathematical means of expressing the ability of a reservoir to deliver fluids to the wellbore. The PI is usually stated as the volume rate delivered per unit of drawdown pressure (for example, bbl/d/psi).

18. Valenzuela A, Parra PA, Gigena LD, Weimann MI, Villareal R, Acosta NL and Potapova E: “Novel Dynamic Diversion Applied in Stimulation of Shale Plays in North Mexico,” paper SPE 170902, presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, October 27–29, 2014.

19. Ajayi et al, reference 7.

> Results of refracturing treatment. After each fracturing stage, engineers measured the ISIP (left). The progressive ISIP increase demonstrated the ability of BroadBand Sequence technology to reinvigorate a depleted well. The operator monitored the gas and oil production rates and the tubing pressure before and after the refracturing treatments (right ). During the 45 days following treatment, the oil (green) and gas (red) production rates doubled, and the tubing pressure quadrupled (blue).

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drilled 19 horizontal wells and employed the plug-and-perf completion method. The wells were cased and cemented in their horizontal sections and stimulated from toe to heel in 12 to 16 geometrically spaced 100-m intervals. Unfortunately, these wells experienced an unde-sired trend of increasing completion costs that, combined with lower than expected production rates in some cases, threatened future develop-ment plans.18

The initial BroadBand Sequence program consisted of three wells. Engineers performed reservoir characterization utilizing the Mangrove stimulation design advisor.19 The advisor soft-ware considers two parameters and determines the optimal locations of stages and perforation clusters. Reservoir quality (RQ) is a prediction of how prone the rock is to yield hydrocarbons; the relevant criteria include organic content, effective porosity, intrinsic permeability, fluid saturations and hydrocarbons in place. Completion quality (CQ) is a prediction of how effectively the rock may be stimulated by hydrau-lic fracturing and is influenced by mineralogy, mechanical properties, in situ stress and the presence of natural fractures.

Engineers used the Mangrove completion advisor to create an engineered completion design that confined perforation clusters to regions with good reservoir and completion qual-

ity. As a result, the operator was able to extend the average stimulation intervals in one well from 100 m to 228 m [748 ft] (above). This reduced the number of bridge plugs and wireline interven-tions by 45% compared with those needed for the conventional completion design technique.

PEMEX elected to stimulate the three new wells using the BroadBand Sequence service. The operator performed tracer log surveys to verify stimulation of all perforations (below). The evaluation confirmed that 95% of the perfo-ration clusters received proppant. Modeling

> Pimienta Formation well data. Using the Mangrove completion advisor, Schlumberger engineers designed engineered completions for three wells. The perforation clusters were spaced around regions of maximal completion and reservoir quality. The design allowed treatment of more than one cluster during each fracturing stage. As a result, the average treated interval length could be extended from 100 m in previous wells to as long as 228 m [748 ft], resulting in a significant cost reduction per completion.

Oilfield Review WINTER 14/15Broadband Fig. Table 1ORWIN 14/15 BRODBND Table 1

Well A Well B Well C

1,565 [5,134] 1,600 [5,249] 1,500 [4,921]Horizontal sectionlength, m [ft]

174 [571] 228 [748] 167 [548]Average intervallength, m [ft]

122 [252] 102 [216] 100 [212]Bottomhole statictemperature, °C [°F]

2,740 [8,990] 2,270 to 2,300[7,448 to 7,546]

2,414 to 2,462[7,920 to 8,077]

TVD of perforatedinterval, m [ft]

16 13 15Number of stages

48 39 46Total perforations

3 3 7Number of perforation clustersper stage

9 7 9Number of intervals treated byBroadband Sequencetechnique

>Tracer logs of an engineered completion of a Pimienta Shale well. The logs show a section from Well B, which received three fracturing treatments. Iridium tracer (Track 1, red), pumped during the first fracturing treatment, entered Perforation Clusters 2, 3, 4, 5 and 6. After the first BroadBand Sequence composite fluid, scandium tracer (Track 2, yellow), pumped during the second fracturing treatment, entered Perforation Clusters 1, 2 and 5. After the second composite fluid, antimony tracer (Track 3, blue) entered Perforation Clusters 5 and 6. The tracer data are superimposed on a lithology log (Track 4) for comparison.


3,900 4,000 4,050 4,1003,950

123456

Track 1

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6 5 4 3 2 1

71917schD4R1.indd 12 1/21/15 6:16 PM

16 Oilfield Review

one-year cumulative production with a numerical reservoir simulator showed that one of the wells stimulated using the BroadBand Sequence ser-vice would be 8% more productive than if it had been completed conventionally. In addition, the stimulation time per well was 65% shorter than that of the conventional completions, resulting in significant cost savings. Based on these results, PEMEX engineers have continued to apply the combined use of the BroadBand Sequence service with the Mangrove completion advisor in the first phase of development of the field.

Openhole Completion in North DakotaAn operator manages approximately 330,000 acres [1,340 km2] of the Bakken Shale play in North Dakota, USA (above). This play has emerged in recent years as one of the most important sources of oil in the US.

New wells are completed to total measured depths exceeding 21,000 ft [6,400 m] with TVDs between 9,800 and 11,200 ft [3,000 and 3,400 m]. Fracture gradients are between 0.85 and 0.95 psi/ft [0.020 and 0.022 MPa/m], and bottom-hole temperatures are between 220°F and 250°F [104°C and 121°C]. Typical horizontal comple-tions employ noncemented casing.

> Bakken Shale play. As of 2013, the Bakken Shale produced more 10% of all US oil production, exceeding one million bbl/d [159,000 m3/d]. The US Geological Survey has estimated that the total volume of oil in the Bakken Shale may be between 271 billion and 503 billion bbl [43 billion and 80 billion m3].


Williston Basin

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In one well, the operator had difficulty while running casing. The planned TD was 21,200 ft [6,460 m]; however, the end of the casing became stuck at 20,610 ft [6,280 m]. After several unsuc-cessful attempts to move the casing farther downhole, the operator decided to investigate alternative stimulation options. Initially, the operator considered leaving the toe unstimulated or pumping a conventional stimulation treatment that might have limited success. Schlumberger engineers proposed addressing the problem by applying the BroadBand Sequence service across the openhole interval.

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Winter 2014/2015 17

> Results of openhole stimulation using the BroadBand Sequence technique. After each fracture stage, engineers measured the ISIP (top). The progressive ISIP increase demonstrated the ability of the BroadBand Sequence technology to stimulate openhole areas that would otherwise remain untreated by conventional fracturing techniques. After the well began producing, the operator measured fracture gradients along the well (bottom). The openhole portion of the well achieved a higher maximum fracturing gradient (blue dots) than that of the stages that were completed conventionally (red dots).

1 2 3 4 5 6 7 8 9 10 11

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i/ft



Maximum fracture gradient: 0.967 psi/ft

Completed withBroadBand Sequencetechnique

Completed withoutBroadBand Sequencetechnique

Maximum fracture gradient: 0.943 psi/ft

Toe Heel

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41


Engineers lowered a swellable packer to 20,299 ft [6,187 m], leaving a 901-ft [275-m] interval open at the toe. The openhole treatment consisted of 11 fracturing stages separated by 10 BroadBand Sequence composite pills. Operations were completed within 14 hours with-out the use of bridge plugs or inflatable packers.

A shut-in period followed the placement of each composite pill, allowing the operator to monitor fracture gradient changes. The ISIP measurements captured at the end of each stage showed progressive pressure increases (above). After the openhole interval had been treated, engineers set a bridge plug at the end of the cas-

ing and then completed the rest of the well using the plug-and-perf technique.

After the well began producing, engineers determined that the long openhole portion of the well treated by BroadBand Sequence technology was more productive than the portion that had been treated conventionally.

Expanding the Scope of Dynamic DiversionMore than 1,500 BroadBand Sequence treat-ments have been performed in the US, Mexico and Argentina. As engineers gain experience with the technique, they are making further refinements to improve the service.

The BroadBand Sequence service is compati-ble with either conventional or fiber-laden fracturing fluids. However, field experience indi-cates that using fiber-laden fluids achieves supe-rior results because such fluids provide enhanced proppant transport capabilities as well as opti-mal reservoir coverage and well productivity. Consequently, most BroadBand Sequence treatments today employ the HiWAY fracturing technique.

Dynamic diversion techniques are continuing to evolve. Recently, Schlumberger introduced a stimulation service for unconventional forma-tions that does not include perforating. The BroadBand Precision integrated completion ser-vice features the placement of casing fitted with sliding sleeves along the intervals to be treated. After the casing is cemented in place, the sleeves are opened to provide access to the formation. During stimulation treatments, engineers pump composite fluids between fracturing stages. The technique eliminates wireline interventions, placement of bridge plugs and milling operations, resulting in significant rig time and completion cost savings.

Hydraulic stimulation treatments have revo-lutionized unconventional reservoir plays and changed the dynamics of the oil and gas industry, especially in North America. However, stimula-tion practices are still evolving as both service companies and operators search for more effective and efficient techniques to access hard to produce resources. Innovations such as BroadBand Sequence treatments promise to enhance developments in unconventional reser-voirs that have underperformed or were ineffec-tively completed. Operators deploying these systems in new resource plays may find that mar-ginal wells and fields are economically viable from the outset, unlocking needed hydrocarbons for the world and providing secure energy resources for the future. —EBN

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18 Oilfield Review

Cables and Skates— Improving the Weakest Links

The cable is perhaps the most vital component for wireline logging; without it,

wireline measurements and wireline logs are not possible. High logging tensions

inherent in complex trajectories and ultradeep wells have exposed weaknesses in

conventional cable designs. However, engineers have introduced new technologies

and designs that improve wireline operations in ultradeep wells and are addressing

other weak links in logging components by developing new downhole and

surface hardware.

Chris BabinNew Orleans, Louisiana, USA

Serko SarianSugar Land, Texas

Oilfield Review Winter 2014/2015: 26, no. 4.Copyright © 2015 Schlumberger.MDT, MSCT, Saturn, SureLOC, TuffLINE and WellSKATE are marks of Schlumberger.Teflon and Tefzel are registered trademarks of E. I. du Pont de Nemours and Company.PEEK is a trademark of Victrex USA, Inc.

The wireline cable lends its name to a major segment of the oil and gas service industry. Schlumberger’s history as a technology corpora-tion finds its origin in being the world’s first well logging company. That first log was acquired in 1927 using tools attached to a cable and lowered into a well in the Alsace region of France. The simple cable used then was a crude precursor to the wireline cables in use today. Modern logging

cables serve a crucial role as conduits for electri-cal power sent from the logging unit to downhole tools, and they link surface equipment with downhole sensors, usually by way of telemetric data exchange. For most E&P operators, and per-haps even service providers, little thought is given to the cable—until a failure occurs. Then the importance of the logging cable and the role it fills in data acquisition become all too obvious. When problems arise, field and office personnel might view the logging cable as the weakest link in a chain.

Some wireline cable weaknesses are inherent, resulting from physical limitations; these engi-neering-based limits are well documented and exceeding them comes with recognized risk. The traditional heptacable—so named because seven insulated copper wires are located in the center of the cable—is rated for breaking strength and safe working loads (SWLs). Other limitations may be less well-known to oilfield operators, and some limitations are consequences of poor operating technique. Conditions that are out of the control of the logging operator can also result in cable damage and failure.

The trend toward ultradeep well depths has brought to light design weaknesses that were rarely a problem in the past. Recent deep drilling activity has produced wells that exceed 11,000 m [36,000 ft]. In these wells, the maximum cable tension at the surface during logging is more than double that routinely encountered in shallower

> Fishing for cable. If the wireline cable is unintentionally broken, the drilling rig must first fish the cable from the hole before retrieving the logging tools. This process can be difficult and time-consuming. The drilling roustabout is using a cutting torch to remove the tangled mass of cable from the grapple before fishing more cable from the well.

Oilfield Review WINTER 14/15Cable Fig 1ORWINT 14/15 CBL 1

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Winter 2014/2015 1919

wells. Cables deployed in deep and geometrically complex wells have high tension because of heavier logging combinations, the greater weight of longer cables and higher cable friction. The logging tensions encountered in these ultradeep and complex wells magnify systemic weaknesses and have resulted in cable-related incidents not commonly observed in the past. Because most of these operations occur in deepwater wells, the cost of failure is greatly amplified compared with lost-time costs in land-based operations.

Wireline operations–related weaknesses that are not specific to the cable can also threaten the logging process. If a toolstring fails to reach an objective zone, data cannot be acquired. These data are used by engineers, geologists and petro-

physicists to understand the hydrocarbon produc-tion potential of both well and reservoir, and the opportunity to obtain these data for a particular well may be lost forever if logging operations fail. In addition, a logging tool stuck downhole while attempting to acquire data creates a major con-cern for both service companies and operators.

Another potential weakness in wireline log-ging operations is a component that is designed to fail, or at least break on command. The connec-tion between the cable and the logging tools is the logging head. A weakpoint in the head is designed to have a lower breaking strength than that of the logging cable. The weakpoint allows controlled release of the tools without breaking the cable. When a logging toolstring becomes stuck in a well,

the drilling crew traditionally cuts the cable, runs drillpipe over the cable and down to the tools and latches onto them. After receiving indications of tool engagement with the drillpipe, the drilling crew uses the rig to pull on the cable and inten-tionally break the weakpoint. The logging crew can then retrieve the freed cable, and the drilling crew recovers the downhole tools using the pull-ing power of the drilling rig.

An unintentional release of the cable from the downhole tools, either by a broken cable or an accidentally broken weakpoint, is one of the worst cable-related failures. Broken cable still attached to the tools must first be fished out of the well before the tools can be retrieved, a pro-cess that can take days (previous page). Failure

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20 Oilfield Review

to retrieve logging tools is an expensive conse-quence in itself; however, the cost of sidetracking around unrecovered tools and redrilling intervals may far exceed the cost of lost tools.

Recent engineering efforts have addressed cable design weaknesses, produced high-strength rig-up accessories, provided more powerful log-ging units and led to the design of downhole hardware that complement higher strength cables. Software developers have also developed a program that helps logging engineers under-stand downhole cable conditions and safely retrieve tools to the surface.1

This article describes proprietary innovations in logging cable design that increase the oper-ating range and margins of safety for wireline operations. New and modified auxiliary hardware augment the use of these new cables. Case studies from deepwater operations in the Mediterranean Sea, West Africa, China, the Gulf of Mexico and the Gulf of Thailand demonstrate the application of these new technologies and designs.

Logging Cable PrimerWireline logging implies acquisition of downhole data via tools that are attached to a cable—a wireline—and lowered into a well. The cable conveys power and control commands from a surface logging unit and provides real-time, two-way communication between the unit and down-hole tools. The surface logging unit records and processes data from which petrophysical logs are generated.2

Cables are available in a variety of configura-tions, compositions and styles. Most are fit-for-purpose; for example, small-diameter, single- conductor monocables are used for production services in cased wells. Their small cross- sectional area makes them better suited than large-diameter cables for pressure operations. Compared with monocables, heptacables offer higher strength, can handle more electrical power for downhole tools and have higher data transfer rates. Heptacables are available in a range of diameters. Slickline cables may be referred to as wireline cables, but these specialty cables are solid wire and have no internal conductor.3

The heptacable is the standard for openhole logging (above). Traditional heptacables com-prise an outer armor layer of steel wires and an inner armor layer of steel wires wound around a core. The core has an outer semiconducting jacket that contains a spiral band of six conduc-tors, filler material, an inner semiconducting jacket and a single, insulated center conductor. The jacket protects the inner conductor wires, which are coated with a material such as polypro-pylene, Teflon or Tefzel (ethylene tetrafluoroeth-ylene resin) insulation.4

The outer armor layer of a standard 0.46-in. [1.17-cm] cable is a band of 24 steel wires wrapped in one direction covering a band of 24 thinner inner wires wrapped in the opposite direction; the two layers balance the tension and torque of the cable. Standard armor wires are manufactured from high-strength galvanized

improved plow steel (GIPS). To build higher strength cables, design engineers replace stan-dard GIPS armor wires with wires made from stronger metal.5

Manufacturers rate cables for temperature and tension limits. The maximum temperature for cables made with polypropylene insulating material is 150°C [300°F]; cables with Tefzel-coated insulation may have ratings above 288°C [550°F]. Ratings may be quoted for one hour of use; for continuous operations of longer duration, cables carry lower ratings.

A new 0.46-in. diameter cable made with GIPS has a breaking strength of 16,700 lbf [74.3 kN] and an SWL of 8,345 lbf [37.1 kN].6 Although GIPS cables were the standard for many years and still are in many areas of the world, Schlumberger operations typically rely on cables made with higher strength steel armor wires that significantly raise the breaking strength and the SWL. A common 0.46-in. diameter cable used for openhole logging today has a breaking strength of 19,410 lbf [86.3 kN] and an SWL of 9,705 lbf [43.2 kN].

To lower tools on a cable, logging units use a winch attached to a drum on which cable is spooled (next page, top). A full drum may carry several thousand meters of cable. Standard prac-tice is to spool cables onto the drum with an applied tension of 1,000 lbf [4.48 kN]. This ten-sion facilitates spooling cable onto the drum.

During normal logging operations, cable ten-sion is measured at the logging unit. When tools are in a well, the tension includes the weight of the logging tool, the weight of the cable spooled into the well and frictional forces that result as the cable and tools are pulled along the wellbore. Buoyancy forces from the drilling mud offset some of the tension.

As the cable is spooled onto the drum during and after logging, the tension will almost always exceed the original 1,000-lbf spooling tension. In normal operations, underlying rows of cable are not at risk of damage from this higher tension because the maximum allowable tension is not sufficient to mechanically damage the cable. This remains true providing the winch operator spools the cable properly and does not allow the cable to overlap itself, which can cause mechanical dam-age to the cable. Logging crews carefully align the logging unit during setup to ensure that the cable can be properly spooled.

Standard cables can, however, be damaged in deep and ultradeep well logging operations—wells with depths in excess of 6,100 m [20,000 ft]—even when properly spooled because the normal

> Traditional heptacable design. The seven-conductor heptacable is the standard cable for openhole wireline logging. In these cables, the wires of the outer armor layer are usually larger diameter than those of the inner layer. The outer layer is wound in the opposite direction to that of the inner layer to maintain a dynamic torque balance and counter the tendency to unwind. The outer armor layer carries more tension than the inner and thus has a higher inherent torque. The cable core consists of the jacket, conductor wires and filler material. The insulated conductor wires are protected by a semiconducting jacket.


Outer armor

Inner armor

Jacket

Conductor wires

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Winter 2014/2015 21

cable tension in these wells is sufficient to crush underlying cable. High logging tension may also occur at shallower depths in S-shaped wells because of increased frictional forces acting on the cable. Schlumberger defines high-tension logging operations as those with surface tensions exceeding 8,000 lbf [35.6 kN]. High logging ten-sion poses a risk of crushing logging cable on the drum and facilitates other types of failures.

A newly manufactured cable has substantial torque imbalance, and it takes time for the armor layers to relieve the torque, stretch and reposi-tion themselves. During the first descent of a new cable, cable tension creates an unequal load dis-tribution between the inner and outer armor lay-ers; however, the layers can move independently of one another, and cable rotation during opera-tions should balance the torque and tension dif-ferences. The process of balancing cable torque in a new cable is referred to as seasoning.

If the outer layer unwinds, an outer-armor distortion in the form of a birdcage develops (right). This condition results in tension that is no longer carried by the full cable but by the

> Full cable drum. Cable is spooled onto a drum that is attached to a winch. The wireline crew runs the logging tools in and out of the well using the winch.


> Logging cable birdcage. The inner and outer layers of a torque-balanced logging cable share the tension load. If the torque becomes unbalanced, the outer layer tends to unwind and separate from the inner layer, which allows a birdcage to form (top). When a birdcaged cable is stressed, the inner armor layer bears the majority of the load and breaks first. Stress is then rapidly transferred to the outer armor wires, which also break. The broken cable (bottom) shows evidence of a sudden tensile break of the inner layer; the elongated and nonuniform nature of the broken outer layer wires is evidence of its unwinding before the cable broke.


Outer armor wires

Inner armor wires

Inner armor wires

Outer armor wires

1 in.

1. For more on logging tool conveyance: 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.

2. For more on basic logging operations: Andersen MA: “Discovering the Secrets of the Earth,” Oilfield Review 23, no. 1 (Spring 2011): 59–60.

3. For more on slickline services: Billingham M, Chatelet V, Murchie S, Cox M and Paulsen WB: “Slickline Signaling a Change,” Oilfield Review 23, no. 4 (Winter 2011/2012): 16–25.

4. Schlumberger manufacturing often uses the following naming convention for classifying cables: X-YYZ AAA, in which X is the number of conductors, YY is the cable diameter in 1/100 in., Z refers to construction components and AAA refers to the armor. A standard-issue cable for routine logging at temperatures less than 150°C [300°F] is the 7-46P GIPS, which is a seven-conductor, 0.46-in. cable with polypropylene-coated conductors (P) and galvanized improved plow steel (GIPS) armor wires. The 7-48A SUS cable is a seven-conductor, 0.48-in. diameter cable that has Teflon-coated conductors and Tefzel jacketing material (A) and superultrastrength (SUS) cable armor wires. This cable is suited for use in high-tension and high-temperature operations. Tefzel polymer is a fluorine-based plastic with high corrosion resistance and strength over a wide temperature range.

5. For more on the development of high-strength cables: Alden M, Arif F, Billingham M, Grønnerød N, Harvey S, Richards ME and West C: “Advancing Downhole Conveyance,” Oilfield Review 16, no. 3 (Autumn 2004): 30–43.

6. Breaking strength values are quoted for a new cable and do not account for wear, age and mechanical damage, which can significantly reduce a cable’s rating. The breaking strength is measured with either both cable ends free or both ends fixed. Ends-free testing, which allows the cable to rotate when tension is applied, is representative of downhole conditions. The 7-46P GIPS cable breaking strength for ends fixed is 16,700 lbf [74.3 kN]. The SWL may be quoted as half the breaking strength, which provides a factor of safety of two. An alternate method of determining SWL for special high-strength cables is 62% of the ends-fixed breaking strength.

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22 Oilfield Review

smaller inner armor layer, which greatly reduces cable breaking strength. A birdcage is often caused by sudden changes in the cable tension such as can occur when a stuck tool comes free at high tension. Rapid tension cycling, or yo-yoing, which consists of repeatedly increasing and releasing cable tension, can cause a birdcage to form. In addition, yo-yoing can create loops in the cable when torqued cable bends back upon itself or when the cable tension is slacked off. Loops cause cable kinks and knots when tension is reapplied to the cable; kinks and knots signifi-cantly reduce the cable SWL.

Cold flow is compression-induced cable deformation. The term describes the low-temper-ature extrusion of core material from the middle of a cable. When a cable is spooled onto a drum at high tension and stored in that condition, perma-nent deformation and damage to the core mate-rial occurs over time. Compression causes the inner armor to squeeze the core, damaging the jacket material and displacing the insulation cov-ering the conductor wires (below). As the core material of the compressed cable extrudes, the inner conductor wires may eventually short out against the cable armor. Cold flow may also occur when torque in inner armor wires constricts the core and reduces the jacket diameter.

The dual-drum capstan, introduced in the 1970s, relieves cable tension that occurs while spooling the cable onto the drum (above).7 Although the capstan eliminates tension-induced cold flow for cable on the drum, it can increase cable torque, which may be the more damaging phenomenon.

Tension or TorqueIn the past 35 years, the well depths attainable by offshore rigs have increased more than 75% (next page, top). Deepwater rigs are now capa-ble of drilling to 12,200 m [40,000 ft] in 3,050-m [10,000-ft] water depth. As of 2012, the maximum

well depth in deepwater operations reached 10,700 m [35,000 ft], and utradeep wells have pushed the limits of traditional cable design.8 Normal logging tensions of 15,000 lbf [66.7 kN] have occurred in some wells—the combined effects of cable weight, long and heavy toolstrings and frictional forces.

Ultradeepwater wells that have high logging cable tensions were first encountered in the Gulf of Mexico and then the North Sea but are now common offshore Brazil, Africa, India and Asia. Gulf of Mexico operations routinely experi-ence cable tension above 13,000 lbf [57.8 kN], and 10,000 lbf [44.5 kN] is not uncommon else-

7. For more on the dual-drum capstan tension relief system: Alden et al, reference 5.

8. Sarian S, Varkey J, Protasov V and Turner J: “Polymer-Locked, Crush-Free Wireline Composite Cables Reduce Tool Sticking and HSE Risk in Emerging

> Core crushing and cold flow. Cold flow can occur after extended storage of a cable on a drum under high tension. This effect is characterized by flattening of the cable and separation of the armor strands. Over time, the polymer of the core may plastically deform, which can eventually lead to the copper conductor wire shorting to the armor wires or to each other. A cable with shorted conductors must be pulled from service and may not be repairable.


Shorted conductorto inner armor wire

> Dual-drum capstan. To prevent cable crushing, drum damage and cold flow in high-tension logging, logging crews place a capstan between the rig floor and the logging unit. The capstan (inset) consists of two large, hydraulically powered grooved wheels that have several wraps of cables around them. Cable on the rig side of the capstan is under high tension; cable on the drum side is maintained at a lower tension for spooling onto the winch drum. Capstans extend the useful life of logging cables, although they present operational risks: Maintaining the proper tension balance is difficult, and synchronizing the capstan speed with that of the logging winch can be problematic. They are also additional pieces of equipment that must be mobilized to remote offshore locations.


Logging unit

Dual-drum capstan

Dual-drum capstan

High-strengthwireline cable

Depth, ft

Weakpoint

10,000

20,000

Deepwater Reservoirs,” paper SPE 164762, presented at the North Africa Technical Conference and Exhibition, Cairo, April 15–17, 2013.

9. For more on high-tension cable maintenance: Alden et al, reference 5.

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Winter 2014/2015 23

where in the world. These are normal logging tensions; tool sticking can subject cables to higher short-term loads.

Extreme conditions have required service companies to rethink cable technologies. Service companies first produced high-strength and ultrahigh-strength cables by upgrading the armor wire material. The breaking strength of some of these cables exceeded the pulling capabilities of older-generation logging winches. Capstan tension relief systems, for example, were lim-ited to 15,000 lbf of differential load capacity. Unfortunately, stronger cables did not resolve all the problems of ultradeep well logging. Cable and drum failures, which had not previously arisen, began to occur as the forces exerted on logging systems stressed them beyond their original design specifications (below). To address these concerns, Schlumberger engineers took a close look at logging in deep wells. They studied cable structure and traced the root causes of prema-ture cable failure.

Traditional cable designs have two layers of steel armor wires that are wound in opposite directions to maintain torque balance. The armor wires are the mechanical strength element of the cable. The two layers, which are free to move independently of each other, share the tensile load; they rotate and stretch under load—although not always equally. The wires of the outer armor layer are typically of larger diameter than the wires of the inner layer.

Design engineers found that cable torque increases proportionally with tension; torque accumulates with each descent and with tension cycling. Devices that bend the cable, such as the cable drum and the sheaves that direct the cable

into the well, act as torque barriers and increase torque accumulation in the logging cable. Torque also accumulates at the logging winch when the cable is spooled onto the drum.

When a tool is stuck downhole, or if the cable is not free to rotate, the torque can become unbalanced. If the tension is repeatedly cycled, the outer layer of armor begins to unwind and lose contact with the inner layer. The inner layer tightens, constricting the core. If the outer layer unwinds, the inner layer may become the only strength element, compromising the SWL for the cable, which may cause the cable to break at

what should be a reasonable logging tension. This scenario became all too common in the early days of ultradeep well logging.

In addition to breakage, crushing and cold flow became common in cables used for logging ultradeep wells. Cables spooled under high ten-sion require tension and torque relief.9 Cable maintenance to relieve stored tension and torque is performed onshore with special spooling equipment. For most deepwater offshore opera-tions, which are located far from land, perform-ing these tasks in a timely manner is difficult because of logistics.

> Increasing Gulf of Mexico maximum well depths. From 1980 until almost 2000, the maximum true vertical depth recorded for offshore oil and gas wells was less than 25,000 ft [7,600 m]. Soon after, deep water Gulf of Mexico maximum well depth ramped up to 30,000 ft [9,145 m] and exceeded 35,000 ft [10,670 m] in 2009.


Year

10,0001980 1985 19951990 2000 2005 2010

15,000

25,000

30,000

35,000

40,000

20,000True

ver

tical

dep

th, f

t

> Cable spooling forces. Logging cables are spooled onto empty traditional drums (left) with an applied tension of 1,000 lbf. During logging operations, the tension can be much higher, which causes the spooled cable to exert large forces on the drum (middle). For example, with 10,000 lbf of cable tension, the drum flange may experience outward forces of up to 8,900 kN [2 million lbf], and the combined forces of tension and cable weight can generate drum core pressures of up to 74 MPa [10,700 psi]. Cable drums used for logging with standard and high-tension cables in shallower wells do not experience sustained forces of these magnitudes. After drum failures during high-tension operations exposed drum design weaknesses, engineers developed higher-rated drums (right) that also have greater cable-carrying capacity than do traditional drums.


Flange force up to 2 million lbf

Pressure on drum coreup to 10,700 psi

Traditional Logging Drum High-Strength Drum

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24 Oilfield Review

New Cable DesignsThe solution to both torque imbalance and mechanical damage seemed simple: build a crush-free cable using armor wires that are torque balanced, locked together and locked to the core. After several years of development and much trial and error, Schlumberger engineers introduced the TuffLINE 18000 torque-balanced composite wireline cable. The first of its kind, this heptacable has several features that other logging cables lack.

A proprietary polymer composition, which is applied in a unique extrusion process, fills the space between the inner armor and the cable core as well as between the armor layers (above). The polymer layer locks the armor wires into place and does not allow them to unwind, which eliminates birdcaging. This design allows the cable to be repeatedly cycled without fear of the cable break-ing below its SWL. No cable seasoning is required, improving operational efficiency compared with that for operations that rely on conventional log-ging cable designs.

The proprietary polymer in the TuffLINE cable core fills the void space between the con-ductor wires and is also extruded between armor layers. This process creates a cable that is almost impervious to crushing and deformation. Adding to the strength of the cable are the double- and triple-extruded conductor wires, which include a layer of PEEK polymer.10

The SWL of the TuffLINE cable is 18,000 lbf [80 kN]; the ends-fixed breaking strength is 28,000 lbf [125 kN] and the ends-free breaking strength is 27,000 lbf [120 kN]. These limits exceed the pulling power of offshore logging units. In the event the toolstring becomes stuck, the drilling rig may be used to pull the cable with a T-bar attachment.11 The TuffLINE cable diame-ter is 0.50 in. [1.27 cm], which is larger than the standard 0.46-in. logging cable but similar in diameter to that of other high-strength and ultra-high-strength cables.

The outer armor layer is composed of wires of smaller diameter than those of the inner layer. These smaller wires reduce the weight per unit

length of the cable in air to 416 lbf/1,000 ft [6.07 kN/1,000 m], which is less than that of the smaller diameter superultrahigh-strength log-ging cable (424 lbf/1,000 ft [6.18 kN/1,000 m]) that is frequently used in deepwater operations. The outer armor wires are held apart from one another by the polymer layer, reducing the slid-ing friction of the cable, which in turn reduces cable tension.

A recent deepwater exploration well in the eastern Mediterranean Sea targeted a zone around 5,000 m [16,400 ft]. The original plan called for a vertical well, but stuck pipe in a shal-lower section resulted in a sidetrack and a well deviation of 35° from vertical. High cable tension encountered during a previous logging run plus model predictions resulted in a bottomhole- tension projection in excess of 10,000 lbf. The remote location precluded mobilization of a capstan on short notice. Alternatives included multiple descents with short toolstrings or drill-pipe-conveyed logging, which would have added five days for logging.

A TuffLINE cable was mobilized to the well-site from the North Sea and installed in the existing surface equipment. Run 1 included six openhole logging tools, but hole conditions pre-vented the long toolstring from reaching TD. The toolstring was shortened, and TD was success-fully reached in Runs 2 and 3. Formation pres-sure measurements and sampling during Run 4 and rotary sidewall coring during Run 5 were completed without incident. As predicted in the modeling program, four of the five logging runs encountered sustained logging tension exceeding 10,000 lbf. Multiple short-duration pulls of 16,000 lbf [71 kN] were made while logging, each of which freed the stuck tools and allowed log-ging to continue.

The operator saved five days of rig time com-pared with the number of days that would have been required for pipe-conveyed logging. An additional day of rig time was saved because the TuffLINE cable required no seasoning prior to logging. Although cable tension exceeded 10,000 lbf, and no capstan was used, the logging crew observed no cold flow damage or crushing during postjob examination. In addition, despite multiple tension cycles to 16,000 lbf, no torque-related cable birdcages were observed.

In a deepwater offshore West Africa environ-ment, Total E&P drilled an S-shaped ultradeep well.12 The anticipated logging tension was in excess of 10,700 lbf [47.6 kN] (left). Future field


Outer armorCrush-resistant core

Inner armor

Outer polymerlayer

PEEK-coatedconductor wires

PEEK-coatedcore

Crush-resistantfiller material

> TuffLINE cable cross section. Engineers designed the TuffLINE 18000 cable with a crush-resistant core (left) that is double extruded; a thin PEEK shield covers the core and individual conductor wires. Polymer encapsulation (right, black) locks all the armor wires together as well as to the core, which eliminates birdcaging and helps maintain the cable’s torque balance. The reduced number and diameter of outer armor wires result in decreased overall cable weight and drag compared with that of other cable designs, which translates to lower downhole logging tension.

> Logging at the limits in deepwater West Africa. In deep water off the coast of West Africa, an S-shaped well profile resulted in high tension at TD. In the 121/4-in. section, the three heaviest logging strings had tensions at TD of 9,700 lbf [43 kN]; 9,400 lbf [42 kN] at 4,500 m and 8,150 lbf [36 kN]. The operator rightly anticipated logging tensions in excess of 10,700 lbf for the deeper 81/2-in. section.


Real-Time Tension at 4,600 m [15,092 ft],121/4-in. Borehole

9,700 lbf, includes drag from calipers and centralizers

8,150 lbf with caliper open

9,400 lbf at 4,500 m [14,765 ft]

Heaviest Toolstrings

Acoustic and imaging tools

Triple-combo tools

Pressure and sampling tools

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10. PEEK (polyether ether ketone) polymer is a high-performance, high-temperature thermoplastic used in engineering applications.

11. A T-bar is a device that is clamped onto a logging cable near the rig floor; it allows the drilling rig elevators to be used to apply direct tension. Using the elevators bypasses the logging unit, upper sheave and lower sheave.

development depended on acquiring a compre-hensive set of wireline petrophysical data. A traditional wireline logging suite was planned, and advanced measurements from nuclear magnetic resonance, acoustic logging and imag-ing tools along with rotary sidewall coring and fluid sampling were included in the evaluation program. Using the MDT modular formation dynamics tester to acquire uncontaminated representative samples was crucial for engi-neers to determine fluid properties and identify compartmentalization.

Normal logging tension—the weight of the toolstring while moving up the hole—includes tool weight, cable weight and frictional forces minus buoyancy forces. In the event of tool stick-ing, the logging operator increases tension with the winch up to a maximum safe pull to overcome sticking forces. The maximum safe pull tension is normally the SWL of the cable. If a mechanical weakpoint is used in the logging head, its rating, minus a factor of safety, may limit the maximum tension. Maximum safe pull values may be fur-ther reduced if they exceed any system capacity such as limitations of the logging unit, cable drum and rig-up equipment.

The well was drilled in 2,500 m [8,200 ft] of water, and well depth was in excess of 5,000 m. The initial 171/2-in. section was S-shaped with greater than 20° deviation. The 121/4-in. and 81/2-in. sections were vertical. Because the cable tension in the 121/4-in. section was slightly less than 10,000 lbf, which is the limit for logging without a capstan, operations could be per-formed with high-tension logging and rig-up equipment that included a 7-48A SUS cable.13 The predicted tension of the 81/2-in. section was greater than 11,000 lbf [48.9 kN], and the high-tension equipment previously deployed would now require the use of a capstan.

Schlumberger engineers and the operator considered four options: • deploy and install a capstan; availability was

questionable and the rig logistics were problematic.

• use drillpipe-conveyed logging; estimated addi-tional rig time was four days, which would cost an additional US$ 5 million.

• make multiple trips with short toolstrings; each trip would take from 12 to 18 hours. Assuming no pipe trips were required between logging runs, multiple trips would add a mini-mum of three days to the program.

• deploy the TuffLINE cable, which could be used with the high-tension rig-up equipment already on location without adding significant risk and would not require the use of a capstan.

The operator decided on the TuffLINE cable option, and a drum of cable was flown in from a neighboring country. In all, eight descents were performed. Although the cable was new, no sea-soning was required and stretch was negligible. Standard operating procedure when a capstan is not used in high-tension operations is to swap cables after six descents, which helps avoid torque- and tension-related damage and cold flow. Limiting descents with the TuffLINE cable was not required; the same cable was used for all eight descents.

The logging crew observed that during the job, the logging tension did not reach the pre-dicted 10,700 lbf. The maximum tension was only 9,400 lbf [42 kN], even though a heavier tool-

string was deployed than the one used in the 121/4-in. section (above). The reduction in cable tension was attributed to an 18% reduction in the drag coefficient through the S-shaped portion of the well and the reduced weight of the TuffLINE cable compared with that of the conventional high-tension cable.

Although the TuffLINE cable was previously unused, it was able to deliver repeatable depth accuracy. Traditional logging cables stretch dur-ing seasoning, which can cause depth repeatabil-ity problems that are exacerbated in deep and ultradeep wells. As a result, logs are often depth adjusted to correct for these discrepancies. After multiple descents, the TuffLINE cable exhibited negligible stretch. The logging crew saw evidence

> Cable tension while logging an S-shaped well. Wireline engineers used the Well Conveyance Planner software to predict surface cable tensions (black) and to plot a record of logging tension while descending (blue) and ascending (red) in the 81/2-in. portion of a well. For the high-strength logging cable used to log the 121/4-in. section, the planner extrapolated a surface cable tension of 10,700 lbf with tools at TD. The actual maximum cable tension was only 9,400 lbf—less than predicted—because of the TuffLINE cable’s lower drag coefficient and lower unit weight compared with the other cable. The trajectory of the S-shaped well (green) changes from vertical at about 3,000 m [9,800 ft] measured depth to a maximum angle of about 24° before it returns to near vertical around 4,000 m [13,130 ft]. In the vicinity of the deviated section, cable tension decreases while the toolstring is descending and increases while it is ascending. This phenomenon is caused by higher frictional forces on the cable through the deviated section.


Tens

ion,

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atio

n, d

egre

e

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12. Sarian S, Varkey J, Protasov V, Montesinos J, Ventura D and Greusard D: “In a Challenging West Africa Deepwater Well, Polymer-Locked, Crush-Free Wireline Composite Cables Help Save Four Days of Rig Time for TOTAL E&P CI While Avoiding Tool Sticking and Reducing HSE Risk,” paper 28, presented at the 18th Annual Offshore West Africa Conference, Accra, Ghana, January 21–23, 2014.

13. The SUS denotes superultrastrength cable.

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26 Oilfield Review

of the depth accuracy between runs of the MSCT mechanical sidewall coring tool and the Saturn 3D radial probe tool (left). They observed the imprint of a hole left by a drilled sidewall core on the packer element of the probe tool that was within 6 cm [2.4 in.] of the set depth. The two tests were taken at a depth greater than 5,000 m.

More than New CablesTwo major challenges encountered by logging crews are rugose holes and logging high-angle wells in which gravity alone may be insufficient to deliver tools to TD. Logging crews have suc-cessfully logged wells with deviations up to 70° without resorting to drillpipe-conveyed tool-strings or wireline tractors; however, some of the successes in getting downhole in high-angle wells may be attributed to chance.

Oil wells rarely have smooth bores between the bottom of casing and TD. Washouts frequently occur when the formation around the wellbore—brittle shale sections or unconsolidated sand intervals—breaks out and enlarges the wellbore. Consolidated, permeable formations are less likely to wash out, and the borehole through these sections is usually in gauge—the same diameter as the drill bit. A large washout above

>Negligible cable stretch. Conventional heptacable designs can result in new-cable stretch of up to several meters during initial descents because of torque-induced seasoning effects. The TuffLINE cable requires no seasoning or special treatment. The depth accuracy of this cable was evident from two logging runs with a new cable. A Saturn tool, which uses a packer made of soft material that allows it to conform to the borehole wall, was run after a rotary sidewall coring tool. One of the Saturn packer set depths coincided with a sampling point taken with the coring tool. When the Saturn tool was retrieved to the surface, the packer element (left) retained an imprint of the hole made by the rotary sidewall core bit. A core bit is placed on the packer near the imprint for reference (right). At approximately 5,000-m MD, less than 6-cm difference occurred between the two logging runs.


>New accessory hardware. Engineers designed the WellSKATE family of auxiliary conveyance equipment to facilitate logging operations. These low-friction and low-contact devices help logging tools reach TD and also reduce sticking while logging.


Tri-Roller Dual-Wheel Roller Roller Bottom Nose





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an in-gauge section may form a ledge, which can cause logging tools to stop, or sit down. After sit-ting down on a ledge, tools may have difficulty realigning with the wellbore and proceeding downward. If the toolstring cannot be coaxed downhole, crucial logging data may be lost.

Reaching TD is not the end of the logging journey. The toolstring can differentially stick to the wellbore wall while tools are being logged out or retrieved from a well. Differential sticking is a problem encountered most often while tools are being pulled out of the well, usually while logging at slow speeds. This condition results when the hydrostatic pressure of the mud column exceeds the pore pressure of the formation, especially in zones that have been depleted by production or when heavy mud weights are used to control the well. The mud pushes the logging tools or the log-ging cable against the permeable underpressured zone, causing them to stick.

The logging operator can increase the logging tension to pull the tools free, but the resulting stick-slip movement greatly reduces log data qual-ity. During the process of release, data may not be acquired, or the quality may be severely degraded. In the worst case, logging tools or the cable may become stuck to the wellbore wall, and cable ten-sion alone is not sufficient to pull the tool free. Tools must then be fished out using drillpipe.

Schlumberger design engineers examined available solutions for enhancing logging opera-tions and facilitating getting tools to TD along with solutions for retrieving stuck tools. Based on the results of their study of existing auxiliary equipment, they developed two families of prod-ucts: WellSKATE low-friction well conveyance accessories and the SureLOC electronically con-trolled cable release device. The WellSKATE accessories are a variety of friction reducers, standoffs, wheeled rollers, flexible connections and bottom noses designed to keep the tools mov-ing downward or to reduce sticking when moving upward (previous page, bottom). The SureLOC system is a controlled release weakpoint.

Low-friction accessories include low-contact standoffs, low-friction standoffs and inline roll-ers. These devices include dual-wheel and tri-roller wheels that are bolted on the outside of the tools. The wheels are designed to prevent the full toolstring from having direct contact with the wellbore, which reduces sticking and friction. For operations such as formation fluid and pres-sure sampling or mechanical sidewall coring that require the toolstring to remain in place for

extended periods of time, the rolling wheels eas-ily break free from the formation when the tool moves off sampling points.

A roller bottom nose, designed to replace tra-ditional flexible hole finders, moves freely should a tool sit down on a ledge. When tool weight is applied, the bottom nose can realign the tool with the wellbore.

In China, WellSKATE rollers were used on a large MDT toolstring accessing a target reservoir at 18,045 ft [5,500 m] in a well that had 70° devia-tion. Because of the rollers, the drag coefficient of the toolstring was reduced from 0.43 to 0.17. The new hardware made a logging operation pos-sible on wireline that otherwise may have required drillpipe conveyance.

For a comparable operation offshore West Africa, in a well that had 33° deviation, WellSKATE rollers helped an MDT toolstring reach a target zone and then provide better efficiency than similar operations performed without the WellSKATE rollers. During MDT tool operations, the maximum pressure differential was 2,400 psi [16.5 MPa], and the stationary time for a single set was limited by the operator to eight hours.

Based on model assumptions that the full length of the tool would be in contact with the wellbore, the expected normal cable tension at the surface would be in excess of 10,000 lbf. However, the friction reduction from WellSKATE accessories resulted in a maximum cable tension of only 8,500 lbf [37.8 kN].

In addition to reducing the normal tension, the orienting effects of the WellSKATE dual rollers helped maintain an optimal downward position for setting the MDT probe (above). Whereas the oper-ator typically experienced a 30% rate of seal failure in nearby wells, only one seal was lost in 79 sta-tions attempted—a less than 1.3% failure rate—when the WellSKATE hardware was used.

Sometimes Tools StickOne objective of the TuffLINE cable designers was to provide a cable that reduced the number of time-consuming fishing operations. Sometimes, despite the best cable designs, tools become stuck downhole. When this occurs, the logging crew usu-ally cuts the cable, and the drilling crew strips over the cable with drillpipe. They use a grapple attached to the end of drillpipe to latch onto the

> Helping an MDT toolstring reach the objective. An operator needed fluid samples from a deepwater West Africa well. The MDT tool was conveyed on wireline with tri-wheel and dual-wheel WellSKATE rollers in a 121/4-in. well that had a 33° deviation (green). The offset design of the dual-wheel roller helped orient the MDT probe downward as indicated by the relative bearing (blue) showing approximately 187.5° throughout the 79 stations attempted. A relative bearing measurement of 0° points up. This optimal positioning resulted in only one lost seal during all tests; similar nearby wells logged without the WellSKATE rollers have averaged in excess of 30% lost seals.


MDT formation tester stations

Relative bearingWell deviation

33° average deviation

187.5° average relative bearing

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28 Oilfield Review

logging tools. After the crew confirms engagement of the tools, the weakpoint is broken, the cable is retrieved, and the rig crew pulls out the pipe with the logging tools attached. This operation is referred to as cut-and-thread fishing.

Before breaking the weakpoint, an operator may elect to acquire data while pulling the tools from the hole with the drillpipe. This much lon-ger operation is referred to as logging-while-fish-ing (LWF). If the weakpoint cannot be broken, or the operator elects to maintain cable-to-tool con-tact while retrieving the toolstring, a reverse cut-and-thread may be performed, in which the cable is cut and reattached after each stand of drillpipe is pulled from the well.14

Two types of weakpoints are used for wireline logging: mechanical and controlled release. Mechanical weakpoints have long been the stan-dard hardware for wireline logging. The logging engineer determines a weakpoint strength such that the weakpoint will break before the cable breaks. The weakpoint value is determined using the SWL for the cable minus the weight of the logging tools.

If a tool is differentially stuck, the tool weight and frictional forces acting on the tool no longer act on the weakpoint. The only considerations for determining the maximum cable tension that can be applied at the surface without breaking the weakpoint are the cable weight in mud and fric-tional forces acting on the cable.

The margin of error is small for selecting a proper mechanical weakpoint in the case of heavy toolstrings; the selected weakpoint may be optimal only at the deepest point in the well. In some scenarios, such as in S-shaped wells or when the cable is differentially stuck, the tension from the surface does not effectively reach the stuck tool, and breaking the weakpoint may be impossible without exceeding the SWL of the cable. For these reasons, after extra- and ultra-strength logging cables were introduced, electri-cally controlled weakpoints became more common as a method of freeing the cable from the logging tools.

Controlled release weakpoints are designed to withstand a tension that exceeds the SWL of the cable. The SureLOC 12000 release system has an SWL of 12,000 lbf [53.4 kN] and a significantly higher breaking strength. The operator can apply direct tension to the logging string up to the SWL of the cable without fear of breaking the weak-point (above).

For example, the weakpoint in the head of a logging toolstring with a 10,000-lbf surface ten-sion while logging up experiences only the effec-tive weight of the toolstring below it. Because the SWL of the TuffLINE cable is 18,000 lbf, the oper-ator can apply an additional 8,000 lbf over the normal surface logging tension in an attempt to free the toolstring without parting the cable or unintentionally breaking the weakpoint.

Schlumberger design engineers have devel-oped a 12,000-lbf and an 8,000-lbf version of the SureLOC cable release. This new design replaces both mechanical weakpoints and previous gener-ation electrically controlled release devices (ECRDs).15 The original ECRD, rated for 8,000 lbf, is activated by applying current from the surface. It uses no software control for actuation. The ECRD can be activated only when no tension is applied; this condition may not be possible if the cable above the toolstring becomes stuck.

The SureLOC device is activated by the logging engineer using software commands combined with applied electrical power. The zero-tension condition required to activate the ECRD is not necessary for use of the SureLOC release. In a well in the Gulf of Mexico, a SureLOC device was successfully actuated with 2,300 lbf [10.2 kN] of residual head tension.

In a high-pressure, high-temperature field in the Gulf of Thailand, an operator used the SureLOC 12000 device to overcome problems previously experienced with controlled release weakpoints.16 Wireline crews logging in offset wells encountered frequent tool-sticking prob-lems; existing weakpoints and controlled release devices were found to be unreliable on multiple fishing operations. In 2011, the wireline log-ging of five wells was canceled because of per-ceived weaknesses in mechanical and controlled release weakpoint designs. After implementing the SureLOC device, which increased the limits


High-strength release spring

Upper head connection

Lower head connection

Electrical connection forcontrol release command

Prepackaged release bobbin

> Controlled release weakpoint. Rated to withstand 12,000 lbf of direct tension, the SureLOC weakpoint (left) is the strength element in the logging head. The upper and lower head connections (right) snap into the head between the cable and the tools. Should logging tools become stuck, the engineer sends software commands and power via the electrical connection to release the bobbin (bottom right). After the bobbin releases, a high-strength spring (top right) forcefully separates the cable from the head.

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Winter 2014/2015 29

for safe tension, the operator reduced the total number of fishing jobs while improving the opera-tional efficiency when fishing was required. The operator estimated it saved several million US dollars and was able to acquire full sets of log-ging data.

Fishing FlowchartTo complement new equipment and assist log-ging operators, Schlumberger engineers devel-oped software that models forces encountered while logging. The Well Conveyance Planner soft-ware analyzes well information such as borehole geometry, logging tool parameters, cable limita-

tions, mud conditions and downhole temperature and pressure. It also helps identify weaker com-ponents in the system (above). The program pre-dicts maximum sustained tension and maximum allowable instantaneous tension for pulling free; pulling capabilities are continuously updated while logging operations are in progress. Operator limitations can be entered in the software to ensure compliance with policies that may be spe-cific to the well, field or operation.

The planner can help the logging engineer visualize well conditions and track changes in tension conditions. It generates an operational risk diagram for various tool and cable scenar-ios. Deviated and extended-reach wells can be

modeled, and tension for complex logging situa-tions can be predicted in advance.

> The Well Conveyance Planner software. The planner software provides a graphical interface (top) so that engineers can visualize well profiles, monitor and predict logging tension, report on drum forces and determine optimal conveyance solutions. Planner data can be generated for routine operations and for high-tension wells. Using relevant well data such as borehole geometry, mud properties and downhole temperature and pressure and combining toolstring parameters, system components and rig-up hardware (bottom left), the software creates operational risk reports (bottom right) that can identify weaknesses in the system and offer alternative solutions that may reduce risk.


East, ft North, ft

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14. The reverse cut-and-thread technique is similar to traditional cut-and-thread fishing. The drillpipe is run in and attached to the tools, but while being pulled out of the hole with the drillpipe, the cable is reconnected for each stand, and the well is logged in short sections as the pipe is slowly retrieved. Because it is a time-consuming operation, this method is usually performed only over zones of interest.

15. For more on the original ECRD system: Alden et al, reference 5.

16. Surapakpinyo K, Hanchalay C, Fundytus N, Ford R, Pakdee S, Sarian S, Battula A and Nery N: “High Tension Electrically Controlled Release Device Improves Reliability of Stuck Tool Release in the Gulf of Thailand,” paper SPE 168281, presented at the SPE Intervention and Coiled Tubing Association, The Woodlands, Texas, USA, March 25–26, 2014.

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30 Oilfield Review

> Fishing flowchart. A fishing flowchart is integrated into the Well Conveyance Planner software. By following a well-defined systematic process, the flowchart helps engineers plan the fishing operation should a toolstring become stuck in a well. The software also plots weighted risk factors (colored circle) to predict fishing success and possible nonproductive time (NPT). The ranking results are numerical (gray quadrilateral): A higher number indicates less likelihood of failure. The risk levels are shaded from lowest (blue) to highest (dark red). In this example from a deepwater offshore well, the best option is open-ended fishing. This type of analysis led engineers to reconsider traditional cut-and-thread methods for fishing in ultradeepwater wells.Oilfield Review

WINTER 14/15Cable Fig 17AORWINT 14/15 CBL 17A

Criteriaacceptable

for open-endedfishing?

Radiationsources?

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Cablestuck?

Yes Yes

Yes

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weakpoint?

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Perform open-ended fishing


Reversecut and thread

POOH pipe andcable to casing shoe

POOH pipeand cable

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> Fishing efficiency and failure analysis. Schlumberger logging engineers working in deepwater offshore environments analyzed fishing operations over a six-year span (left). Data from fishing jobs that have fishing failures and NPT were further broken down by the fishing method used (right). Cut-and-thread operations, both traditional and reverse cut and thread, accounted for 85% of the failures. Open-ended fishing was responsible for only 11% of the failures.

20

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Cut and threadReverse cut and thread

Open endedOther

2008 2009 2010 2011


4%11%

58%

27%

A fishing flowchart is included in the planner, which the logging engineer can access before tools become stuck in the well. The flowchart helps engineers identify areas of concern, espe-cially on deepwater floating rigs, where excessive surface tension and complex rig-ups add to the risks associated with traditional cut-and-thread fishing operations.

The use of high-tension cables and controlled weakpoints has led Schlumberger offshore opera-tions personnel, along with some operators, to reassess the choice of the cut-and-thread method when fishing for logging tools. The fishing deci-sion flowchart identified a lower risk methodol-ogy for fishing logging tools from deep and ultradeep wells (previous page).

For shallow wells, the cut-and-thread tech-nique is time efficient and is usually the best fish-ing option. For ultradeep wells constructed in deep water, the hourly rig cost while fishing must be factored into the analysis for choosing a fish-ing method. In addition, complex rig-ups and high-tension cable conditions add personnel

risks that are rarely a factor when fishing in shal-lower wells.

In a recent study conducted by Schlumberger offshore operations personnel, engineers exam-ined fishing data from 2006 to 2011 (above). The data revealed that although 88% of all fishing operations were performed successfully, 34% of those operations recorded NPT. Cut-and-thread operations accounted for 85% of the NPT fishing events. Controlled weakpoint release followed by open-ended fishing for logging tools accounted for 11% of NPT events. Not only were fewer NPT events associated with open-ended fishing than with cut-and-thread operations, but the success rate was the same for both techniques. In addi-tion, the open-ended technique was deemed more efficient, more cost effective and even more reliable than traditional cut-and-thread and reverse cut-and-thread methods.

One justification for traditional cut-and-thread operations is uncertainty associated with breaking mechanical weakpoints and past unreli-ability of controlled release devices. The reliabil-ity of the SureLOC controlled release weakpoint has eliminated that concern.

Safety is another consideration for not using traditional cut-and-thread fishing. During cut-and-thread operations, for each connection of the drillpipe, the cable is tensioned to approxi-mately the same value as when the tools became stuck while logging. Maintaining and repeatedly tensioning the cable to the extreme cable ten-sions encountered while logging ultradeep wells put personnel at greater risk should any part of the system fail during fishing. Sheave wheels, tie-down chains, slings and logging units are all part of the system, and their exposure to high-tension cycles increases the risk of component failure.

Following the fishing study, Schlumberger engineers working in the Gulf of Mexico on deep-water, high-tension wells began recommending the open-ended fishing technique. Moving away from traditional cut-and-thread fishing repre-sented a major shift in methodology because cut-and-thread fishing had been considered the only reliable method for retrieving tools. In two years of using the open-ended technique, offshore

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32 Oilfield Review

operations had a 100% recovery rate for tools (above). The average fishing time for open-ended fishing attempts was less than 20 hours. The aver-age time for cut-and-thread operations was nearly 60 hours; reverse cut-and-thread average was almost 120 hours.

Engineers now recommend the open-ended fishing method for deepwater logging. Operators may be reluctant to change to this method because cut-and-thread fishing is entrenched in the industry; in addition, fishing for tools that contain radioactive sources may be controlled by local regulations that require the use of the cut-and-thread technique.

Offshore UpgradesTwo heavy-duty modular offshore logging units are now available to take advantage of the higher rated TuffLINE cables and SureLOC weakpoints. The standard Schlumberger OSU-F offshore log-ging unit, which was designed in the 1970s, is rated for 8,000 lbf of logging tension. The new OSU-PA offshore logging unit is capable of pulling 20,000 lbf and is available with a high-strength logging drum that can hold 11,000 m [36,000 ft] of TuffLINE logging cable (next page).

The OSU-PA has a Det Norske Veritas (DNV) rating for continuous logging tension up to 16,000 lbf using a full drum of cable.17 If condi-tions warrant higher short-term tension such as for stick prevention, the unit is certified for an instantaneous pull of up to 18,000 lbf without a capstan. The modular unit is composed of four parts: a diesel power pack, a logging cabin, a hydraulic winch and a lifting beam. The lifting beam has a DNV lifting certification.

The three main modules—power pack, cabin and winch—can be installed as one piece or separately and are connected by hydraulic and electric control cables. This modular flexibility is incorporated to improve safety and footprint restrictions. In high–surface tension operations, the winch operator can be located in the cabin away from the winch module.

The similarly equipped and rated OSU-PB is a Conformité Européenne- (CE-) marked offshore unit.18 The OSU-PA operates with a clean-air die-sel power pack; the OSU-PB uses an electrohy-draulic power pack. The OSU-PB has also been approved for Zone 2 atmosphères explosibles (ATEX) operations.19

A dual-drum tension-relief capstan system that has a higher rating than that of previous ver-sions is available and can be synchronized and controlled directly from the OSU-PA or the OSU-PB. This new design is rated for an SWL of 24,000-lbf [106.8-kN] tension, 30,000-lbf [133.4-kN] maximum tension and winch speeds of up to 30,000 ft/h [9,150 m/h]. A TuffLINE cable

> Open-ended fishing success. Following a study of fishing methods, offshore logging crews began recommending open-ended fishing rather than the cut-and-thread method for ultradeep wells. The success rate for tool recovery over the two-year period of study was 100% (left), with 97% recovery on the first trip in the hole with drillpipe. The efficiency of open-ended fishing in deepwater drilling is further reflected in the time per operation compared with traditional and reverse cut-and-thread methods (right).


Fish

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Reverse cutand threadThird tripSecond tripFirst trip

17. Det Norske Veritas (DNV) is an international rating and classification organization. In 2013, DNV merged with Germanischer Lloyd (GL) to form DNV GL. For more on DNV certifications that cover logging units and lifting equipment: “Standard for Certification Number 2.22,” Det Norske Veritas AS (June 2013), https://exchange.dnv.com/publishing/stdcert/2013-06/Standard2-22.pdf and “Standard for Certification Number 2.7-1,” https://exchange.dnv.com/publishing/stdcert/2008-11/Standard2-7-1.pdf (accessed November 3, 2014).

18. The CE marking declares that a product meets the requirements of applicable Conformité Européenne (CE), or European Conformity, directives.

19. ATEX is the name commonly given to the two European Commission directives for controlling explosive atmospheres. For more on ATEX directives related to offshore operations: “Directive 94/9/EC on Equipment and Protective Systems Intended for Use in Potentially Explosive Atmospheres (ATEX),” European Commission Enterprise and Industry, http://ec.europa.eu/enterprise/sectors/mechanical/documents/legislation/atex/ (accessed October 6, 2014).

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on a high-tension drum used with an OSU-PA allows continuous logging tension up to 16,000 lbf. The capstan is recommended, however, when predicted normal surface tension exceeds 13,000 lbf.

Forward ThinkingWhen almost all wells were vertical, unless devi-ated by accident or from downhole circum-stances, traditional logging tools and cables were suited for the job of acquiring petrophysical data. Today, the percentage of horizontal and high-angle wells has increased, and vertical wells have become the exception in many regions. High-angle and horizontal wells are more likely to be

logged with LWD equipment than on wireline. But LWD tools often have lower temperature and pressure ratings than wireline tools have, and some measurements must rely on wireline con-veyance for acquisition.

Evaluating deep and ultradeep wells requires the use of wireline cables for data acquisition. Innovative engineering designs are making these wireline operations feasible and adding margins of safety that were not previously possible.

The future of the drilling industry is focused on what has been, until recently, inaccessible resources. Deepwater drillers and operators have equipment to reach those prizes. By eliminating weak links in the wireline system, logging compa-nies can safely and more effectively follow them

with crucial wireline logging tools. The ultimate goal is to deliver tools downhole that acquire data to help operators better understand their fields and discoveries. —TS

> The OSU-PA offshore logging unit. This newly designed unit is DNV certified to 16,000-lbf tension. Shown in its lifting cage, the modular unit comprises a POSU clean-diesel power pack (left), a COSU logging cabin (middle) and a WOSU logging winch (right). The OSU-PA is capstan compatible.


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34 Oilfield Review

Beyond Deep—The Challenges of Ultradeep Water

Not many years ago, the E&P industry was forced to develop radically new

technologies and methods for prospecting in deep waters beyond the continental

shelf. The industry is now advancing into ultradeep water and drilling much deeper

into the subsurface, which requires a continued evolution of technology and

project workflows.

Rob CummingsChris GarciaAndrew HawthornRobert Holicek Houston, Texas, USA John R. DribusNew Orleans, Louisiana, USA

Loïc HaslinParis, France

Oilfield Review Winter 2014/2015: 26, no. 4. Copyright © 2015 Schlumberger.For help in preparation of this article, thanks to Juan Ramon Lopez Morales, Cota, Colombia; Aciel Olivares, PEMEX, Ciudad del Carmen, Campeche, Mexico; Octavio Saavedra, PEMEX, Poza Rica de Hidalgo, Veracruz, Mexico; Manuel Torres, Mexico City; and Victor Vallejo, PEMEX, Villahermosa, Tabasco, Mexico. arcVision, DrillMAP, GeoMarket, PowerDrive vorteX, Seismic Guided Drilling, seismicVISION and TeleScope are marks of Schlumberger.MeshRite is a mark of Absolute Completion Technologies.

When the E&P industry moves into untried terri-tories, the costs can be significant, and drilling and completion engineers are required to man-age such costs and expenses through reduced nonproductive time. For challenging new arenas such as deep water, where spread costs run to more than US$ 1 million per day, reducing non-productive time is a logical strategy. But empha-sis on cost reduction is today being joined, if not replaced, in the minds of ultradeepwater opera-tors by other considerations.

Many operators now understand that the value realized through reduced nonproductive time (NPT) is usually not sufficient to economi-cally redeem extremely costly ultradeepwater projects if the wells are not optimally placed within the reservoir and constructed with equip-ment able to last the life of the well. In addition, recent events have made operators keenly aware that risk management and strict adherence to regulatory dictates must be of primary impor-tance when working in an environment in which mistakes can result in human, environmental and financial catastrophe.

Safety and environmental concerns are not limited to the deepwater arena, water depths gen-erally considered greater than 500 m [1,600 ft] or in ultradeep water deeper than 1,500 m [5,000 ft]. However, the stakes are substantially higher in these water depths than in shallow water or onshore, and the consequences of missteps are pro-portionally more costly. To navigate this challeng-ing world, ultradeepwater operators and service

companies are rediscovering the virtues of close collaboration across all the disciplines that bring projects to fruition.

The ultimate driver for this renewed call for an integrated approach to ultradeepwater explo-ration may be the inability of current tools and workflows to adequately model the Earth’s sub-surface. The degree of uncertainty embedded within subsurface data acquired through tech-nologies such as seismic surveys or downhole log-ging requires experts to interpret their datasets using probabilistic estimations and contingency planning. Geophysicists, who use such data to create mechanical earth models (MEMs), include assumptions about rock types, pressure during the life of a field and the effect of changing pres-sure on permeability and effective porosity. Based on MEMs and other models, drilling engi-neers make key well design assumptions to deter-mine parameters such as mud weights, bit types, casing points and wellbore angles to build the drilling program. Uncertainty in the subsurface model, however, can lead to uncertainty in the well design, which may cause engineers to construct overly conservative, unnecessarily costly wells.

The practice of reliance on the input of others is carried through to completion, production and facilities designs because each discipline must work with decisions that are at least in part based on the assumptions of others and the data limitations each discipline has to face during the process of exploration. To minimize the ineffi-ciencies inherent in such sequential processes,

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all members of an ultradeepwater project team must understand the uncertainties that are embedded in the data they receive and communi-cate these to the entire team throughout the field design process.

Sources of uncertainty are recognized and addressed at each step of an ultradeepwater exploration and development project. Before operators select the location of the drillbit entry into the seabed, they consider seafloor and shal-low geologic hazards that they might encounter. Drilling ahead requires knowledge of expected pore pressures, but pore pressure models are cre-ated from seismic velocity calculations and modi-fied based on drillers’ experience in similar environments. Predictions of pressure and tem-perature gradients, complex geology, geomechan-ical properties, formation fluid chemistry and other factors ahead of the bit all incorporate effective risk management that has allowed the industry to successfully drill wells in this uncer-tain ultradeepwater environment.

This article describes defining, drilling, com-pleting and producing ultradeepwater reservoirs through an integrated workflow. It also explains the prominent role of regulatory agencies since the 2010 Macondo incident in the Gulf of Mexico (see “Offshore Regulations in a Post-Macondo World,” page 38). A case history from Mexico illus-trates how cross-discipline teams played a key role in the successful drilling and evaluation of a complex well in the ultradeep waters of the Gulf of Mexico. Another from northern South America demonstrates how an integrated approach can ensure success in remote operating areas.

Known UnknownsThe challenges that operators face drilling and completing wells in ultradeep water are the same, if more pronounced, as those the industry encounters in previous deepwater operations. For instance, in the Gulf of Mexico, the Loop Current—streams of warm water that flow beneath the ocean surface and that travel from the Caribbean Sea into the Gulf and back out

again—can cause considerable operational diffi-culties for deepwater drilling units (left). The Loop Current plays havoc with drilling rig station keeping and the running and retrieving of drilling risers and can cause riser fatigue from vortex-induced vibration.1

Station keeping refers to holding the vessel against wind and currents to within a specified circle, or watch circle, about the center line of the riser. The watch circle extent depends on water depth, riser geometry, riser tension distri-bution and the limits of the flex joint angles for a particular operation.

Deepwater drilling units achieve station keep-ing in most sea states through dynamic position-ing, which uses multiple, computer-controlled subsurface thrusters. The thrusters are able to rotate 360° and thus exert force on the vessel hull in any direction required to counter sea forces. Thrusters are continuously computer monitored and adjusted in response to changing seas and currents. This process, however, may require the rig to use significant amounts of fuel and thus add costs that impact overall project economics.

The Loop Current and straight-line currents push risers laterally, which makes landing them in subsea blowout preventers difficult. The deep-water drilling industry has developed special equipment to guide risers, but this equipment is very expensive, and as a consequence, some mobile drilling units are not equipped to handle drilling in offshore areas with strong currents.

In addition, as currents flow around a riser in place, vortices form downstream from it. Vortex-induced vibration—the transverse oscillation of a pipe placed in strong current—is caused by vor-tex shedding around the riser and can lead to pipe fatigue damage. To combat this phenomenon, helical fins called strakes, or fairings, are placed along the length of the riser as each section is low-ered from the rig floor. These devices break up the current and suppress creation of vortices, but because they are installed on individual riser joints on the rig as they are being prepared for deployment, strakes add considerable time and thus cost to riser running operations.2

Another hurdle addressed by operators in deep water is the narrowing drilling window that is a function of the diminishing difference between formation pore pressure and formation fracture initiation pressure as the water depth increases. The formation fracture initiation pres-sure is reduced relative to the pressure on land or in shallow water because the Earth’s overburden has been replaced by seawater, which results in

> Eastern Gulf of Mexico Loop Current. The Loop Current in the Gulf of Mexico may form a short loop (top left ) or may become elongated (top right ). When the loop is long, it often pinches off a spinning body of water called an eddy (bottom left ). These eddies drift westward over many weeks (bottom right ) and eventually lose energy in the western Gulf. The cycle of loop and eddy currents repeats itself several times a year.

Neweddy

UNITED STATES

MEXICO

Oldeddy

Gulf of Mexico

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lower vertical stress. Fracture initiation pressure can be reduced further by the structurally weak uncompacted and unconsolidated sediments typical of shallow sections of a deepwater well-bore. Because pore pressure typically increases with depth, the drilling window becomes increas-ingly narrow as water depth increases (right).3

Under ultradeepwater conditions, the hydro-static pressure of the column of drilling fluid above the bit may exceed the fracture initiation pressure of the formation being drilled. If the well reaches a depth at which the window between the fracture pressure and pore pressure closes, drill-ing mud will be lost to the formation, and the operator will have little choice but to set casing. With each casing string, the operator must reduce the bit size of the next interval. This process can lead to a final hole size that impedes the ability to acquire formation evaluation data or result in a production casing size that is too small to accom-modate economic production volumes. These smaller diameters may also be too small to accom-modate the required completion architecture such as sand control, flow control and artificial lift systems. Added casing strings may threaten proj-ect economics through material costs and addi-tional rig days.

Numerous solutions have been developed to address the shrinking drilling window. Drilling fluids that have flat rheologies that remain con-stant with varying temperature and low-density cements, which sometimes are infused with nitro-gen, have been used to reduce the hydrostatic pressure of fluid columns in the well. In some instances, when casing must be set above the tar-geted casing seat depth, the driller can avoid a reduction in the next casing size by underream-ing—drilling out and enlarging the hole beneath the casing seat—and then setting casing that can be expanded to the size of the previous casing.

Alternatively, some deepwater drilling units are equipped with dual-gradient drilling or man-aged pressure drilling systems. In the former, pumps are placed at the seafloor to lift the fluid to the surface. The effect is to reduce the hydro-static pressure on the formation by lowering the top of the fluid column to the seafloor. This extends the depth to which the well may be drilled before the hydrostatic pressure of the fluid column exceeds the formation’s fracture ini-tiation pressure. In the latter application, the formation is permitted to flow in a controlled manner, allowing the driller to control the well using a lower density mud while reducing the hydrostatic pressure on the formation.4

> Pore pressure and fracture initiation pressure. In deepwater environments, the Earth’s overburden of rock is replaced by seawater and the vertical stress imposed on the subsurface, or overburden (OB), is reduced (top). As the depth below the seafloor increases, the pore pressure (PP) and the fracture initiation pressure (FP) move increasingly toward equality (bottom left). Consequently, the drilling window shrinks. The reduction of both FP and OB is more pronounced in deepwater environments (bottom right).

Drilling window

Reservoir rock

OB land well

OB 5,000-ft water depth

Hydrostatic pressure

OB 500-ft water depth

Seafloor

Dept

hTr

ue v

ertic

al d

epth

Pressure

Pressure

Pressure

True

ver

tical

dep

th

PP FP OB

Water Depth = 100 ft Water Depth = 5,000 ft

PP FP OB

1. Koch SP, Barker JW and Vermersch JA: “The Gulf of Mexico Loop Current and Deepwater Drilling,” Journal of Petroleum Technology 43, no. 9 (September 1991): 1046–1119.

2. Koch et al, reference 1.3. Rocha LAS, Falcão JL, Gonçalves CJC, Toledo C,

Lobato K, Leal S and Lobato H: “Fracture Pressure Gradient in Deepwater,” paper IADC/SPE 88011, presented at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Kuala Lumpur, September 13–15, 2004.

The drilling window is the difference, at a given depth, between the pore pressure and the fracture initiation pressure. For safe drilling, the weight of the drilling fluid in the borehole must be within the drilling window.

4. For more on managed pressure drilling: Elliott D, Montilva J, Francis P, Reitsma D, Shelton J and Roes V: “Managed Pressure Drilling Erases the Lines,” Oilfield Review 23, no. 1 (Spring 2011): 14–23.

Cuvillier G, Edwards S, Johnson G, Plumb D, Sayers C, Denyer G, Mendonça JE, Theuveny B and Vise C: “Solving Deepwater Well-Construction Problems,” Oilfield Review 12, no. 1 (Spring 2000): 2–17.(continued on page 40)

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Safety and environmental concerns have long been a priority for offshore operators. On the heels of the Macondo incident in the Gulf of Mexico in 2010, however, US operators, who have historically policed themselves, must now comply with new offshore safety and environmental regulations. Compliance with these regulations is overseen by the US Bureau of Safety and Environmental Enforcement (BSEE), which requires operators to employ a specific Safety and Environmental Management System (SEMS) to be qualified to operate in the US Gulf of Mexico. Among its other charges, the bureau reviews applications for permits to drill and conducts inspections of drilling rigs and pro-duction platforms.

The SEMS tool was created in 1990 when the US National Research Council Marine Board found that although the industry worked to comply with regulatory agencies, operators did not encourage an environment of identifying risk or developing accident miti-gation procedures. In response, the BSEE, in cooperation with the American Petroleum Institute (API), developed Recommended Practice (RP) 75: Recommended Practice for Development of a Safety and Environmental Management Program (SEMP) for Offshore Operations and Facilities. The API also pro-duced RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, for identifying safety hazards on offshore production facilities.1

Following the April 2010 Macondo incident, the BSEE began requiring all operators in US waters to have a well-documented SEMS pro-gram in place by November 15, 2013. At that time, 12 of 84 operators subject to the deadline had not satisfied the rule and were cited by BSEE for noncompliance. Eventually, 5 of those 12 were notified to halt operations.

Initially, the BSEE allowed companies to conduct internal audits. Today, under what has become known as SEMS II, operators are required to hire a qualified independent third party as a SEMS auditor or to lead an internal audit of the company SEMS program. In addi-tion to forced shutdown of operations, non-compliance with the SEMS program may result in civil penalties.

Also called the workplace safety rule, SEMS is a management system that includes the following 13 elements:• general provisions for program implementa-

tion, planning and management review• safety and environmental information• hazard analysis• management of change• operating procedures• safe work practices• training• quality and mechanical integrity of critical

equipment• prestartup review• emergency response and control• investigation of incidents• audit of safety and environmental manage-

ment elements• documentation and record keeping.

The BSEE mandates are directed at opera-tors. The incidence of noncompliance reports issued after the Macondo incident, however, makes it clear that the BSEE, which is an agency within the US Department of the Interior, also intends to hold service and con-tractor companies accountable for safety and environmental compliance.

SEMS II, which has an audit deadline of June 4, 2015, adds requirements not included in the first version; these new requirements are designed to empower field personnel with safety management decisions under the stop-work authority and ultimate work authority

policies. To implement the intent of SEMS II, operators must establish procedures that authorize all employees on an offshore facility to assume stop-work authority. In addition, operators have to clearly define the individual or individuals who have the ultimate work authority on the facility for operational and safety decision making at any given time and must develop an employee participation plan for SEMS implementation and guidelines for reporting unsafe work conditions.

Although service companies are not techni-cally responsible for meeting the requirements of SEMS, operators are responsible for all per-sonnel on their facilities. As a consequence, the facility operator must ensure that all con-tract companies and their personnel are in compliance with SEMS requirements; opera-tors have already refused some workers access to offshore facilities for noncompliance. Similarly, service companies must ensure that their subcontractors comply with SEMS to fulfill their responsibility to the operator.

For some operating and service compa-nies, the implications of this approach include significant changes in safety programs and training to ensure employees are equipped to assume responsibility for recognizing, halting and reporting unsafe practices. Schlumberger, however, will require few changes to meet the SEMS II intent as it has a long-standing policy aligned closely with the aims of RP 75 (next page). Schlumberger offshore personnel must have a current job description on file and have completed a training plan based on that job title; the company must make certain that all offshore-bound employees have completed North Gulf Coast GeoMarket and client required training, have had their skills and

Offshore Regulations in a Post-Macondo World

1. Gordillo G and Lopez-Videla L: “Managing SEMS Audits: Past, Present and Future,” Journal of Petroleum Technology 66, no. 2 (February 2014): 72–75.

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knowledge verified and have passed a valid drug and alcohol test.

Because many operators and service com-panies that work in US offshore waters are global companies, their SEMS-based safety and environmental practices are likely to

travel with them to markets elsewhere. Corporate policies designed to comply with SEMS should be increasingly accepted on a global scale as companies not based in the US seek to work in US offshore areas. In addition, because the typical final outcome of safe and

efficient work habits is less down time and fewer expensive mistakes, it may be argued that although implementation of SEMS policy may incur some costs, the overall financial impact on deepwater development projects will likely be positive.

> Schlumberger and SEMS. Schlumberger quality, health, safety and environment (QHSE) practices dovetail with SEMS and SEMS II recommendations from API RP 75. Schlumberger needs few adjustments to pass a SEMS II audit.

PerformanceMonitoring and

Improvement

Contractorand SupplierManagement

Commitment,Leadership andAccountability

Audits andReviews

BusinessProcesses

RiskManagement

Organizationand Resources

Policies andObjectives

Safety andenvironmental

information

Safety andenvironmental

information

Audit ofSEMS elements

Hazardanalysis

Hazardanalysis

Generalelements

Third-partyauditors

SEMS

SEMS II

Managementof change

Managementof change

Managementof change

Safe workpractices

Documentationand record

keeping

Emergencyresponse and

control

Emergencyresponse and

control


keeping


keeping

Integrity ofequipment

Prestartupreview

Operatingprocedures

Operatingprocedures

Stop-workauthority

Ultimate workauthority

Prestartupreview

Third-partyauditors

Job safetyanalysis

Safe workpractices

Stop-workauthority


Safe workpractices

Stop-workauthority

Training

Training

Investigationof incidents

Investigationof incidents


Report unsafeconditions



Schlumberger QHSEManagement System

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Shallow Hazards of the DeepOperators begin the process of deepwater drilling by picking drilling targets and locations. In the early days of deepwater drilling, operators were surprised to encounter surface and subsurface phenomena that they had not observed in shal-lower areas or onshore; such phenomena repre-sent threats to ocean bed and wellbore stability. Some areas of the seafloor contain—in addition to man-made obstacles such as cables, pipelines, wellheads and even unexploded ordnance—natu-ral hazards to drilling such as active fluid escape pockmarks, mud volcanoes and active fault scarps that can create unstable substrate, making anchoring rigs and spudding wells impossible. In deep water, the floor of the ocean may also be characterized by unstable slopes, slumping, slid-ing and sinkholes.

Just below the seafloor, threats to drilling come from shallow water and gas flows, buried water- and gas-bearing channels and splays, active faults, gas clouds, chimneys and plumes, disassociating gas hydrates and lateral pressure transfer effects that can bring higher pressures up into shallower depths. If unrecognized before drilling begins, these geohazards may force drill-ers to abandon their original locations or at least

suspend operations until a plan can be made for drilling through or around the problem. On the shallower continental shelf, especially in areas of deltas, the primary subseafloor hazard is the presence of shallow water or gas pockets that pose a risk of blowouts or seafloor destabilization during and after drilling operations. In the deeper water beyond the shelf and in ultradeep water, shallow water flows (SWFs), the most com-monly encountered geohazard, pose significant risk to drilling operations.

Shallow water flows are prevalent in basins with high deposition rates and result from the rapid burial of sand and silt deposits followed by differential compaction and dewatering. These phenomena occur in water depths exceeding about 500 m and are usually found in sandstone formations at about 250 to 1,000 m [800 to 3,300 ft] below the mudline (above).5 Drilling into these trapped sands can cause water and sediments to flow into, up and sometimes around the wellbore and may threaten the viability of the wellsite. In the Gulf of Mexico, for example, one operator was forced to move a tension leg platform because 10 of 21 drill slots became unusable when the casing buckled after an SWF washed out the sediment supporting them.6

When possible, engineers avoid drilling through geohazards because mitigation can be difficult and may incur significant NPT. When the hazard is unavoidable, the drilling plan must include contingency casing and mud programs designed to contain abnormal pressures. In deep water, well control using increased mud density, which drilling engineers commonly use to com-bat abnormal pressure, is often problematic because of the narrow drilling window.

Operators protect their wellbores from shal-low hazards through identification and appropri-ate site selection and planning. In deep water, however, offset data are often sparse or nonexis-tent during the exploration phases of projects, and operators identify shallow hazards through site or hydrographic and exploration seismic sur-veys, pilot hole drilling or stratigraphic modeling. In addition, modern high-quality seismic data have significantly improved the industry’s ability to detect these shallow geohazards. But all these hazard identification techniques have both advan-tages and drawbacks (next page).

In addition to identifying the existence of an SWF, geophysicists must quantify the potential risk from the phenomenon. For example, thick SWF sands that extend over large areas are capa-ble of flowing for an extended period of time, dur-ing which flow rates typically increase for part of that time. Formation dip associated with an SWF can also contribute to risk level because signifi-cant dip allows higher pore pressure from deeper portions of the sand to move updip, which increases overpressure effects.7

Because of a lack of quality offset data, assess-ing the potential for geohazards in deep water can also be difficult. Geohazard data gathered using traditional seismic methods cannot be used to quantify risk because those data are acquired using a short-cable streamer that lacks sufficient offset to extract physical properties through quantitative analyses such as inversion.

To counter this deficiency, geophysicists have begun recently reprocessing large offset, conven-tional 3D seismic data to quantify shallow hazards. They then develop quantitative measure-ments of shallow hazards using attributes such as a compressional-wave velocity to shear-wave velocity ratio (Vp / Vs), effective stress and density.8 Sands in an SWF are highly unconsolidated, fea-turing a Vp approaching that of water and Vs approaching zero. Therefore, SWFs may be identi-fied by a high Vp / Vs compared with that of adja-cent sediments.

> Formation of shallow water flow hazards in deep water. As sediments are deposited, rates of fluid escape may or may not keep pace with the rate of compaction. If the fluids are unable to escape at a rate that allows equilibrium with hydrostatic pressure, the sands become overpressured. Drilling into an overpressured sand allows the trapped water to be released, often suddenly. Silty sediments rich in clay minerals, which eventually become shales, typically are not overpressured.

Fault

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Because of the burial and compaction process that formed SWF sands, they have poor grain-to-grain contact and thus low effective stress and high porosity. As a result, remediation through pumping cement or high-density pills—solutions for other lost circulation circumstances—is nearly impossible, and the most reliable approach for SWFs is to avoid them altogether. Surface bathymetry mapping in deltaic areas can produce a risk probability map indicating where seismic data should be carefully checked for buried chan-nel or lobe features that might host SWFs so that they can be avoided.

Mapping Uncharted GroundBecause many technical solutions were devel-oped in early deepwater operations and because the costs, risks and rewards are so high, opera-tors in ultradeep water tend to focus more on maximizing the return on their investments than on reducing NPT. Although efficient operating practices remain a priority, the overarching con-

cern for ultradeepwater operators is optimal well placement within the reservoir; such placement promises higher production and ultimate recov-ery rates. As a consequence, geology and geo-physics have assumed greater roles throughout the ultradeepwater E&P workflow than in more traditional exploration and development arenas.

Typically, in ultradeep water, little well control or direct measurements of reservoir properties are available to calibrate seismic interpretations and earth modeling. Therefore, operators rely on models to understand the financial and technical risks associated with developing their assets. The process of modeling ultradeepwater reservoirs includes geologic and geophysical modeling, res-ervoir characterization, reservoir flow modeling, facilities design, flow assurance and uncertainty and risk analyses. Developing each of these com-ponents is complicated by the lack of available hard data such as well logs, tests and core data.

Geologic and geophysical modeling typically uses seismic data, calibrated against what few logs may have been run in the area to map major features such as faults and possible stratigraphic barriers to fluid flow. Reservoir characterization relies heavily on seismic data, and to lessen the degree of uncertainty inherent in these data, geo-physicists and engineers use geostatistical meth-ods to describe reservoirs through trends, variability of properties and subjective interpre-tations.9 These models allow the scientists to pre-dict the effects of geologic features on fluid movement throughout the field.10

In situations in which offset well information is limited, engineers plan drilling programs based on seismic depth imaging and estimated proper-ties to map structures and geologic targets and to identify formation characteristics such as pore pressure gradient, fracture pressure gradient and geomechanical properties. Because data are lim-ited, uncertainties are high and the resulting geo-logic model is interpretive and not unique; each

5. Dutta NC, Utech RW and Shelander D: “Role of 3D Seismic for Quantitative Shallow Hazard Assessment in Deepwater Sediments,” The Leading Edge 29, no. 8 (August 2010): 930–942.

6. Eaton LF: “Drilling Through Deepwater Shallow Water Flow Zones at Ursa,” paper SPE/IADC 52780, presented at the SPE/IADC Drilling Conference, Amsterdam, March 9–11, 1999.

7. Dutta et al, reference 5.

> Shallow hazard identification. Numerous methods for identifying shallow hazards exist. Each method has advantages and disadvantages.

Standalone seismic measurementsacquired over proposed drill location

High-frequency focus (high-frequency source, shallow towand ultrashort offset)

Description A range of measurements including bathymetry,side-scan sonar, multibeamand seafloor photography

High-resolution reprocessingof exploration seismicmeasurements

Shallow pilot holes drilledto log near the surface

Interpretation of availableseismic reflection measurements

Limited (1 to 2 s below seafloor)Penetration Seafloor only Ultradeep (10 s) Limited by drilling cost Measurement dependent

Medium (200 to 300 Hz)Resolution High (500 to 1,000 Hz) Low (100 to 150 Hz) Not applicable Equivalent to seismic input

Identifies man-made andgeologic seafloor anomalies

Identifies shallow faulting

Can identify shallow hazardsthrough stratigraphic interpretation

Value High-resolution measurement of the seafloor

Indirect estimate of rockproperties, which identifyshallow hazards

Wide spatial coverage

Time-lapse potential

Direct measurement ofrock properties

Not suitable for rockphysics workflow

Limited spatial coverage

Deficiencies Limited penetration below the seafloor

Not suitable for rockphysics workflow

Limited resolution at theseafloor

Cost Based on geologic interpretationusing pilot hole informationfor calibration

Stratigraphic ModelingPilot Hole DrillingExploration Seismic SurveysHydrographic SurveysSite Surveys

8. For more on the Vp /Vs ratio: Alsos T, Eide A, Astratti D, Pickering S, Benabentos M, Dutta N, Mallick S, Schultz G, den Boer L, Livingstone M, Nickel M, Sønneland L, Schlaf J, Schoepfer P, Sigismondi M, Soldo JC and Strønen LK: “Seismic Applications Throughout the Life of the Reservoir,” Oilfield Review 14, no. 2 (Summer 2002): 48–65.

9. Ezekwe JN and Filler SL: “Modeling Deepwater Reservoirs,” paper SPE 95066, presented at the SPE Annual Technical Conference and Exhibition, Dallas, October 9–12, 2005.

Using geostatistical models, geologists use statistical information to indicate the probable distribution of features throughout a reservoir, although they do not know the precise location of those features.

10. Rossi D, Malinverno A and Carnegie A: “Trends in Geostatistics,” Middle East Well Evaluation Review 14 (November 1993): 45–53.

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model has multiple options that fit the same sur-face seismic data (above).11

To steer the well through uncertain intervals, engineers and geophysicists use real-time check-

shot surveys.12 This technique, which uses mud pulse telemetry and does not disturb drilling operations, allows drillers to take a checkshot, or seismic reference survey, at each connection and

receive the data at the surface in real time (below left). Geophysicists use these data to refine the predrill velocity model, which is then used to update the drilling target depths and the geo-logic model.13 Additionally, real-time seismic-while-drilling (SWD) methods, such as the Schlumberger seismicVISION seismic-while-drilling service, confirm the bit position on the seismic image.

Researchers at Schlumberger have built on the SWD approach by developing a method to integrate while-drilling data and offset and sur-face seismic data. With these data, teams revise and, if necessary, generate a new 3D model, which includes a new seismic image, and recalculate the pore pressure prediction and fracture gradient, thus reducing uncertainty ahead of the bit.14 During drilling operations, the Seismic Guided Drilling integration of surface seismic and downhole measurements workflow measures formation velocities down to the bit (next page, top). Typically covering about 100 km2 [40 mi2] around a proposed well loca-tion, Seismic Guided Drilling studies use a base-line earth model built from seismic imaging, inversion and offset well data. Earth modelers then produce an image of a small volume around the well location, allowing geophysicists to create a velocity model of near-wellbore geology.

Geophysicists then analyze the proposed well using the seismic image and estimated rock prop-erties such as pore pressure, fracture gradient and other geomechanical properties. Drilling engineers design the well and make predrilling decisions on trajectory, casing depth points, cas-ing sizes, mud types and mud weights.

While an interval is being drilled, or immedi-ately thereafter, field personnel measure the properties of the subsurface using LWD and wireline tools as well as mud logging and other drilling data. At a predetermined depth, or if real-time drilling data suggest the presence of significant errors in the starting model, geophys-icists perform a Seismic Guided Drilling work-flow. They reprocess the surface seismic data near the wellbore and use checkshot-constrained local tomographic inversion to obtain new veloc-ities, perform a full depth migration and develop an updated model ahead of the bit that includes a new velocity profile.

Geoscientists use the well logs to update the local earth model used for pore pressure and frac-ture pressure prediction. This is then applied to the new velocity model to predict pore pressures ahead of the bit. In this way, the data from the well being drilled are fully incorporated into the newly generated predictive model. In certain

> Fault location uncertainty. During seismic survey processing, map migration converts time surfaces into depth surfaces. An overlay of 500 map-migrated realizations of a fault reveals that uncertainty across this fault plane is about 400 ft [120 m]. For a vertical well, this translates to more than 700 ft [200 m] of uncertainty in pinpointing where the well should cross the fault. (Adapted from Esmersoy et al, reference 11.)

400 ft

700 ft

> Checkshot techniques. Wireline checkshots (left ) require the driller to stop drilling and rig up and run a wireline seismic tool. The seismicVISION tool (right ) is part of the bottomhole assembly. Data acquisition occurs during pipe connections and thus requires no extra rig time. The SeismicVISION waveforms are transmitted uphole from the LWD tool using the TeleScope high-speed telemetry-while-drilling service. (Adapted from Chandrasekhar et al, reference 13.)

Source

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locations or in early stage exploration drilling, this may be the only appropriate well data avail-able. Because the entire workflow is performed in near real time, engineers are able to modify the drilling program and adjust key planning ele-ments such as well trajectory, mud weights, casing designs and target locations.

Getting to TD in Ultradeep Gulf WatersIn practice, many of those in the various E&P dis-ciplines involved in most drilling, completion and production projects have typically performed much of their work in isolation, despite industry claims for the virtues of integration (right). However, the Mexican national oil company Petróleos Mexicanos (PEMEX), working in the Gulf of Mexico, is using an integrated workflow to manage some of its exploration projects in deep and ultradeep waters. The technique—visualice, conceptualice, defina, de seguimiento y evalúe, known by its Spanish acronym VCDSE—is defined by the following five stages:• visualization: identifying options and validating

the well project• conceptualization: analyzing and selecting best

options • definition: performing detailed engineering • follow-up: performing well construction • evaluation: documenting and evaluating les-

sons learned during execution of the well.Throughout the process, a project leader coor-

dinates the disciplines within the exploration VCDSE team, operational teams and service com-panies. Disciplines include geophysics; geology; petrophysics; geomechanics; and reservoir, drill-ing, completion and risk-assessment engineering.

> The Seismic Guided Drilling method. The predrill seismic image (left ) based on estimated formation velocity (black curve) includes the well trajectory (red dashed line) and the target (dark blue). Using the Seismic Guided Drilling technique, engineers can measure formation velocities to the depth of the bit (middle, red curve) and use these data to update the model in the drilled section of the well (pink shading). The data are then used to rebuild the earth model and the structural image (right, blue shading). The rebuilt model may reveal a change in the target location, requiring modifications to the well trajectory.

Velocity Velocity Velocity

> Interdependencies in deepwater operations. In deepwater projects, exploration, appraisal and developments are directly dependent on each other. Within each of these broad categories, the disciplines are also interdependent and across categories; all disciplines are at least indirectly dependent on each other.

Drilling Engineering

Casing programDrilling pore pressure window(managed pressure drilling)Completion typeFormation evaluationFormation sampling

Formation Evaluation

Constant calibration ofgeophysical, geologic andgeomechanical modelsReservoir size estimationConcept selection(engineering design)

Seismic Acquisition

DevelopmentAppraisalExploration

3D seismic surveyElectromagneticsSubsalt illumination

Completion Engineering

Concept selectionIntervention contingenciesRecovery factor strategyProduction estimationand design

Flow Assurance

Representative fluidsamplingPVT analysisChemical and heat mitigationDeposition and adhesionprediction

Geology and Geophysics

Seismic modelSubsea reservoircharacterizationProspect selectionVelocity model forpore pressure

Well Testing

Dynamic reservoir testingproducibilityConfirming completiondesign (skin)Reservoir estimation (booking)

Other Geomechanic Outputs

Regional stress cube forwell placementCompletion selection typeFuture production modeling(4D seismic survey)

Geomechanic Outputs

Mechanical earth modelPore pressure modelor cubeWellbore stability modelReal-time geomechanics

11. Esmersoy C, Ramirez A, Hannan A, Lu L, Teebenny S, Yang Y, Sayers CM, Parekh C, Woodward M, Osypov K, Yang S, Liu Y, Shih C, Hawthorn A, Cunnell C, Shady E, Zarkhidze A, Shabrawi A and Nessim M: “Guiding Drilling by Look Ahead Using Seismic and LWD Data,” paper SPE 164786, presented at the North Africa Technical Conference and Exhibition, Cairo, April 15–17, 2013.

12. A checkshot is a type of borehole seismic survey designed to measure the signal traveltime from the surface to a known depth.

13. Chandrasekhar S, Dotiwala F, Kim TK, Khaitan ML and Kumar R: “Reducing Target Uncertainties and Guiding Drilling Using Seismic While Drilling Technology, A Novel Approach in Andaman Sea Deepwater,” paper SPE 165834, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, October 22–24, 2013.

14. Peng C, Dai J and Yang S: “Seismic Guided Drilling: Near Real Time 3D Updating of Subsurface Images and Pore Pressure Model,” paper IPTC 16575, presented at the International Petroleum Technology Conference, Beijing, March 26–28, 2013.

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44 Oilfield Review

These teams are supported by specialists and international service companies.15

PEMEX and Schlumberger engineers identi-fied options and validated a well design for three ultradeep wells—Supremus-1, Maximino-1 and Trion-1—in the Perdido fold belt in the North

Tamaulipas region of the Gulf of Mexico. The team employed a methodology called No Drilling Surprises (NDS) to integrate the project design and execution.16 The NDS workflow incorporates information from the design stage to define steps for identifying and mitigating potential drilling risks and includes contingency measures pro-duced with the DrillMAP drilling engineering management and operations plan software.

Though these three wells were the first drilled in the ultradeep waters of the Mexican side of the Perdido fold belt, PEMEX has been drilling in nearby deep water since 2004. Based on analysis of data from those early wells and wellbore stabil-ity forecasts, the DrillMAP software generated a visual drilling tool that displayed the well design, including casing sizes and depths, drilling mud weight windows and locations of potential drill-ing hazards. The DrillMAP software also provided engineers with the risks per hole section, severity index, the method used to detect the risk and the mitigation plan developed during the predrill phase by the project team.

While the three ultradeepwater wells were being drilled, Schlumberger and PEMEX engi-neers monitored progress using the geomechan-ics real-time monitoring service and continuous comparison against the DrillMAP plan. At a drill-ing visualization center in Poza Rica de Hidalgo, Veracruz, Mexico, petrophysicists, geomechanics engineers and drilling optimization engineers monitored and analyzed LWD data from the rig. The multidisciplinary team used validated and updated predrill geologic, geomechanical and pore pressure models, which helped reduce uncertainty in the next drilling interval.17

After the Supremus-1 well was drilled, engi-neers reviewed how the surface conductor was jetted into place and were able to optimize ROP to ensure the casing reached the desired depth. In addition, because drillers had experienced dif-ficulty maintaining a vertical hole while drilling the surface section of the CAZA-1 deepwater well using a straight bend housing and conventional drilling motor, the planning team redesigned the bottomhole assembly (BHA). The new assembly included a PowerDrive vorteX powered rotary steerable system, 26-in. roller cone bit and hole opener to enlarge the hole to 33 in. (left).18

In the shallow sections of the well, drillers had to employ a unique directional well trajec-tory to avoid shallow hazards and to intersect shallow reservoir targets. The team also drilled a 121/4-in. hole to be able to successfully acquire

wireline logs, sidewall cores and modular pres-sure and fluid sampling data. The BHA design allowed engineers to drill the 121/4-in. pilot hole and deploy LWD tools and hole openers on the same run.

Engineers chose to acquire rock property and petrophysical data via LWD measurements to allow preliminary assessment of the potential reservoir and updating of the geomechanical model. If no zone of interest was encountered, the 121/4-in. hole section was drilled and logged to total depth at the same time the underreamer enlarged the hole and thus saved time on a subse-quent hole opener run.

If the zone proved of interest, engineers could drill the 121/4-in. hole through the reservoir and collect LWD data before reconfiguring the BHA without the reamer to drill the pilot hole to total depth. The 121/4-in. hole size allowed engineers to run a full suite of wireline logs to acquire the essential data for rock and fluid reservoir charac-terization. This strategy resulted in a successful operation and good hole quality and met drilling design objectives while reducing drilling risks.19

To accurately compute reserves for the Perdido area, PEMEX engineers designed and ran a drillstem test (DST) on the Maximino-1 well. The DST set a world record for the water depth at which such a test was performed. The team used lessons learned and formation evaluation data acquired in the drilling of three previous area wells, the Trion-1, the Supremus-1 and the PEP-1, to design the DST and define its objectives.

15. Vallejo VG, Olivares A, Saavedra O, Lopez JR and Torres ME: “Drilling Evolution of the Ultra Deepwater Drilling Campaign in Mexico, Perdido Fold Belt,” paper OTC 25030, presented at the Offshore Technology Conference Asia, Kuala Lumpur, March 25–28, 2014.

16. For more on the No Drilling Surprises process: Bratton T, Edwards S, Fuller J, Murphy L, Goraya S, Harrold T, Holt J, Lechner J, Nicholson H, Standifird W and Wright B: “Avoiding Drilling Problems,” Oilfield Review 13, no. 2 (Summer 2001): 32–51.

17. Vallejo et al, reference 15.18. For more on rotary steerable drilling: Copercini P,

Soliman F, El Gamal M, Longstreet W, Rodd J, Sarssam M, McCourt I, Persad B and Williams M: “Powering Up to Drill Down,” Oilfield Review 16, no. 4 (Winter 2004): 4–9.

Downton G, Hendricks A, Klausen TS and Pafitis D: “New Directions in Rotary Steerable Drilling,” Oilfield Review 12, no. 1 (Spring 2000): 18–29.

19. Vallejo et al, reference 15.20. For more on the extension of the Jubilee play across

the southern Atlantic: Bryant I, Herbst N, Dailly P, Dribus JR, Fainstein R, Harvey N, McCoss A, Montaron B, Quirk D and Tapponnier P: “Basin to Basin: Plate Tectonics in Exploration,” Oilfield Review 24, no. 3 (Autumn 2012): 38–57.

> Keeping the hole vertical. For a well drilled in the Perdido fold belt offshore Mexico, engineers used a BHA that included an underreamer positioned above a PowerDrive vorteX drilling motor. They first drilled a 26-in. pilot hole section to accommodate arcVision LWD logging tools, which acquired real-time resistivity, gamma ray, inclination and annular pressure-while-drilling measurements. The underreamer was then opened and they enlarged the hole diameter to 33 in. Throughout the drilling interval, they were able to maintain a vertical well trajectory of less than 1° inclination as required for the casing program.

String stabilizer

Nonmagneticdrill collar

String stabilizer

arcVision LWD tool

String stabilizer

PowerDrive vorteXpowered rotarysteerable system

Filter sub

Underreamer

TeleScopetelemetry service

Filter sub

Roller cone bit

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Winter 2014/2015 45

To avert sand production, the well test plan-ners needed to optimize drawdown pressure. They used a sand management study performed by Schlumberger geomechanics specialists. Based on the outcome of that study, the team chose MeshRite standalone screens (above). To address problems that might arise when flowing formation fluids to the surface through a long riser bathed in a column of seawater, a flow assur-ance study was conducted to predict and mitigate potential hydrate formation. Data collected from a drillstem test were a priority for the recognition of reserves and production potential but also important to all geomechanical engineers, reser-voir engineers, wireline and testing personnel and PEMEX engineers.

The completions team and well testing team designed the downhole string and the opera-tions group coordinated between the two teams. The successful DST provided PEMEX with suffi-cient data to book the reserves. Encouraged by the success of these cross-discipline operations in highly challenging circumstances, PEMEX is now appraising the remainder of its Perdido fold belt assets.

The Ultradeep Ahead: Remote, Challenging and IntegratedThe risks, complexities and costs of working in water depths greater than 1,500 m demand coor-dinated efforts and seamless communication between the various technical disciplines that identify prospects and design and drill wells to confirm hydrocarbon accumulations. In addition to the need to quantify the uncertainties associ-ated with shallow geohazards, seismic survey data and geology for each step of the operation from drilling to production, operators exploring in ultradeep water are further challenged by the remote nature of these areas. Materiel and person-nel cannot be delivered quickly to rigs hundreds of kilometers from shore; therefore, to ensure both technical and economic success, operations must not be delayed by miscommunication.

When Tullow Oil plc proposed drilling a wild-cat well 150 km [93 mi] from the coast of French Guiana, it was an oilfield frontier in every sense; because the country had no established oil industry presence, the support base was located in the Republic of Trinidad and Tobago with some support from Suriname. The operator was exploring in a remote area with water depths of

2,048 m [6,719 ft] to determine if its giant Jubilee play off the coast of West Africa could be traced across the Atlantic to the east coast of South America.20

The project was further complicated by the fact that there were no offset well data and no established supply chain, and the team would be using an untested, newly built rig. After finalizing a conceptual well design, the company chose the Schlumberger business and operation model, Integrated Services (IS), which included a dedi-cated Integrated Services Project Manager (ISPM). Integrated services included directional drilling, MWD and LWD, wireline logging, mud log-ging, drill bits, drilling mud and completion ser-vices. The IS project leveraged the Schlumberger global presence to obtain the necessary personnel and equipment and the import, transport and storage permits for oilfield supplies.

The ISPM worked in the Tullow operational office as a direct support to the Tullow drilling superintendent and worked closely with the Ensco plc rig manager in Cayenne, French Guiana. The ISPM coordinated the prejob plan-ning, risk management processes and equip-ment and personnel delivery schedules. The Project Readiness Assessment process, which consisted of a personnel and equipment plan and a risk assessment register to identify prob-lems or challenges requiring remedial action, reduced the likelihood of unplanned events and associated NPT. Experts in an operations sup-port center shared real-time data with the team on location and with the Tullow staff via the Internet. During specific challenges, the center staff included relevant bit, drilling, BHA and flu-ids experts. The project reached the operator’s targeted depth and encountered 72 m [236 ft] of net oil pay in two turbiditic sandstone fans, prov-ing that the Jubilee play analog from across the Atlantic was appropriate.

Many ultradeepwater projects, like that car-ried out by Tullow Oil in French Guiana are in remote frontiers and typically marked by few off-set data and difficult logistics. These two factors exacerbate the complexity and potential risk of already complex undertakings. To manage them, operators and service companies have little choice but to embrace cross-discipline teams and strive for seamless communication. —RvF

> Sand control option. To prevent sand flowing into the wellbore while creating sufficient drawdown to conduct well tests of the PEMEX ultradeepwater Maximino-1 well, the operator chose to use standalone MeshRite screens and to deploy them at twice the length of the interval to be evaluated. This added screen length reduced the pressure drop across the screen area; this flow area distribution allowed the system to avoid excessive flow at any specific point. The presence of such points creates hot spots. The screen’s filter is formed by wrapping layers of compressed stainless steel wool onto perforated base pipe and then covering it with a perforated outer shroud. That configuration creates a 40% open flow area and more than 3,000-D air permeability.

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46 Oilfield Review

Bioturbation: Reworking Sediments for Better or Worse

Petroleum geologists are interested in bioturbation because it reveals clues

about the depositional environment. Bioturbation can also destroy or enhance

porosity and permeability, thereby affecting reservoir quality, reserves calculations

and flow dynamics.

Murray K. Gingras S. George PembertonUniversity of AlbertaEdmonton, Alberta, Canada

Michael SmithMaturín, Venezuela

Oilfield Review Winter 2014/2015: 26, no. 4. Copyright © 2015 Schlumberger.FMI is a mark of Schlumberger. Sediments undergo several modifications to

become the source rocks, reservoirs and seals that generate and contain petroleum reserves. The changes that occur between deposition and lithification, collectively known as diagenesis, include the processes of compaction, cementa-tion, dissolution and recrystallization.1 But before any of these occur, another process can consider-ably affect rock properties. As soon as they are deposited, sediments can be altered by biotur-bation: the disruption of sediment and soil by living things.

Bioturbation is typically a small-scale but potentially significant geologic process that may occur wherever plants or animals live. It can take several forms, including displacement of soil by plant roots, tunnels created by burrowing ani-mals and footprints left by dinosaurs (next page).

Of most interest to the oil and gas industry are the changes brought about by organisms that are active near the water/sediment inter-face in marine settings. Such activities are typi-cally limited to a meter or so in depth but may cover an area of tens to hundreds of square kilo-

1. Ali SA, Clark WJ, Moore WR and Dribus JR: “Diagenesis and Reservoir Quality,” Oilfield Review 22, no. 2 (Summer 2010): 14–27.

2. Al-Hajeri MM, Al Saeed M, Derks J, Fuchs T, Hantschel T, Kauerauf A, Neumaier M, Schenk O, Swientek O, Tessen N, Welte D, Wygrala B, Kornpihl D and Peters K: “Basin and Petroleum System Modeling,” Oilfield Review 21, no. 2 (Summer 2009): 14–29.

> Surface expressions of burrows under the surface. As the tide retreats at the Bay of Vallay, North Uist, Scotland, small wormlike animals burrow into the soft, silty sand searching for food. By the thousands, they create shallow tunnels but leave waste on the surface (left). In this example, the fecal piles cover an area of at least 5 km2 [2 mi2] (right).

Oilfield ReviewAUTUMN 14Bioturbation Fig. 2ORAUT14-BIOT 2

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Winter 2014/2015 4747

meters. Understanding the behaviors of these animals helps geologists characterize the envi-ronmental conditions prevalent during a brief interval of geologic time: after the sediments were deposited, but while they were still soft enough to deform.

For many years, bioturbation studies found application mainly in exploration geology—in estimating paleobathymetry, assessing deposi-tional environment and identifying key strati-graphic surfaces. These are all important inputs to the geologic models used for determining potential source rock and reservoir quality and for modeling basins and petroleum systems.2

Recently, however, geologists have expanded the application of bioturbation to address production geology challenges.

Animal activity in sediments disrupts layering, creates flow pathways, enables exchange of min-erals and fluids between sedimentary layers, changes pore fluid chemistry and adds or removes organic matter. These changes can facilitate or impede mobility of diagenetic fluids, increase or decrease porosity and permeability and alter per-meability homogeneity and isotropy. Recognizing these effects and including them in reservoir simulation models can improve production pre-dictions and enhanced oil recovery operations.

This article describes ways in which animal activity can affect sedimentary deposits and focuses on reservoir rocks. Examples from both siliciclastic and carbonate formations show how geologists use this information to infer ancient environmental conditions and characterize pres-ent-day formation properties.

Life Just Under the SurfaceAnimals that live near the water/sediment interface often leave evidence of their life-styles. For example, surface expressions of sub-surface bioturbation can be discerned in the intertidal zone of a beach (previous page). In

> Bioturbation on the surface and in the subsurface. Bioturbation includes animal imprints and tunnels created by burrowing animals. The photographs of the crab burrow (left ) and the ant nest (middle) are from the sandy backshore of beaches near Savannah, Georgia, USA. (Photographs courtesy of Murray K. Gingras.) The photograph of the dinosaur footprint (right ) is from Dinosaur State Park, Connecticut, USA.

Oilfield ReviewAUTUMN 14 Bioturbation Fig. 1ORAUT14-BIOT 1

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48 Oilfield Review

> Traces, shafts and tunnels. Marine animals that live at or near the sediment/water interface leave traces of various shapes, sizes and complexity. (Adapted from Gingras et al, reference 3.)


> Traces of animal behavior. Ichnologists interpret traces to indicate animal activities such as escaping, dwelling, crawling, feeding, farming and grazing, among others. Traces may be variations or combinations of these. The behaviors are loosely associated with depositional settings of higher energy (top) and lower energy (bottom) and may be considered a continuum. A variety of species might produce similar structures if their activities are similar. A single species can create several kinds of traces while performing different activities and the traces may vary if made in different substrates. (Adapted from Gingras et al, reference 3.)

Oilfield ReviewAUTUMN 14Bioturbation Fig. 5ORAUT14-BIOT 5

Escaping(Fugichnia)

Crawling(Repichnia)

Grazing(Pascichnia)

Feeding(Fodichnia)

Farming(Agrichnia)

Dwelling(Domichnia)

Higher Energy Dynamic Habitats

Lower Energy Stable Habitats

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Winter 2014/2015 49

this case, thousands of piles of sand-rich fecal coils dot the floor of a shallow bay. These fecal strands are produced by burrowing, wormlike creatures that take in the bulk sediment, ingest nutrients and excrete the indigestible rock grains. Their subsurface burrows may be tens of centimeters deep, and an assemblage or com-munity of these organisms can affect an area of several square kilometers.

Infauna, or animals that live in sedi-ments—clams, tubeworms, crabs and shrimp, for example—can disrupt sediments in many ways (previous page, top). They may create tubelike tunnels and shafts of varying inclina-tion. These burrows may be simple, shallow unlined holes or may have compacted walls, be lined with contrasting material or have multi-ple openings. The burrows may remain open for a period of time, collapse or be filled imme-diately with similar or contrasting sediments (right). Tunnels in somewhat consolidated sediments have a better chance of staying open than those in softer sediments.

Some infaunal activity can cause complete mixing of a volume of sediment but leave no detectable traces. For example, animals foraging in layered sediments may disrupt the substrate so completely that the layering is no longer visible, causing the sediment to appear to be one mas-sive, homogeneous interval.

Aquatic animals that live on the sediment sur-face, epifauna, can also leave traces of their activity. Although these animals—mussels, sea stars, flounder and some crabs—may not burrow or modify the sediments to a great degree, they may leave evidence in the form of furrows and other tracks.

In the rock record, bioturbation manifests itself mainly as fossilized traces of animal activity: fossilized imprints, tracks, excavations, dwellings or waste products. The study of these traces is the field of ichnology. This specialty focuses on using trace fossils, or ichnofossils, to decipher paleoeco-logical aspects of sedimentary environments. The types, number and variety of traces may help geologists determine aspects of the depositional environment such as whether sediments were deposited quickly or slowly or in shallow or deep marine or nonmarine waters.

Ichnofossils are interpreted to be related to animal survival strategies associated with sedi-mentary and environmental conditions. They are different from body fossils in that they represent a behavior or activity, not a particular organism. Only infrequently, such as in the case of some dinosaur footprints, can ichnologists identify the animal species that created an ichnofossil. Instead, they attempt to deduce what the animal was doing when it created the trace.

By studying trace fossils, ichnologists have identified several types of animal behavior, includ-ing feeding, dwelling, fleeing, resting, crawling, grazing and farming (previous page, bottom).3 Depending on the activity, the associated traces may be found on the sediment surface—which eventually becomes the interface between two layers—or within a sediment layer. Ichnologists use the evidence of these behaviors to character-ize the paleoenvironment of a rock layer.

> Contrasting fill. This burrow in fine-grained sediment is filled with coarse-grained material. This U-shaped trace is interpreted to be the dwelling burrow of an annelid or a crustacean in a low-energy shoreface or sandy tidal flat environment. (Photograph copyright S. George Pemberton.)


3 cm

3. Gingras MK, Bann KL, MacEachern JA and Pemberton SG: “A Conceptual Framework for the Application of Trace Fossils,” in MacEachern JA, Bann KL, Gingras MK and Pemberton SG (eds): Applied Ichnology. Tulsa: Society for Sedimentary Geology, Short Course Notes 52 (2009): 1–26.

The Latin words for these trace fossils—fodichnia, domichnia, fugichnia, cubichnia, repichnia, pascichnia and agrichnia—are used to classify them according to behavior.

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50 Oilfield Review

A basic way of interpreting sedimentary rocks is to divide them into three main types of lithified sediment: unburrowed, burrowed and massive appearing (above).4 Classification of these types serves as the starting point for interpreting the depositional conditions under which such sedi-ments formed.

Unburrowed—Sediments that are relatively undisturbed, such as those with original layering intact and with little or no evidence of bioturba-tion, are usually ascribed to one or more of the following depositional environments:• freshwater, where there are few deeply burrow-

ing organisms

• anoxic settings (poorly oxygenated)• constantly shifting sediments on the seafloor• high sedimentation rates • arid or frozen locales.

Unburrowed sandy sediments usually indicate freshwater deposition or shifting sedimentation. However, many continental environments do


BurrowedUnburrowed orLaminated

Mottled orMassive Appearing

Low sedimentation ratesand good food resource

Large, diverseichnofossils

Smallichnofossils,low diversity

Moderate to rare,evenly distributed

High sedimentation rates,good food resource and

generally consistent conditions

Large,diverse

Small

Large,diverse

Small

Large,diverse Lower shoreface

Bays or deltasRarely point barsSmall

Moderate to rareSporadically distributed Laminated to scrambled

Event sedimentationgenerally dominated (temporally)

by fair-weather processes

High sedimentation rates and variable

depositional conditions

Quiescent bayor lagoon, possiblytidal flat

Inner shelfoffshore

True crypticbioturbationbedding

Cross-bedded

Planar

Laminated

Lacustrine, quiescent bay or deep marine

Fluvial, fluvio-lacustrineor deltaic

Downwardhydraulic jump

Sedimentgravity flow

Probably shallow marineor marginal marine

Probably inner shelffine-grained intertidal flat with low tide rangeor (less likely) shallowlacustrine

Distal prodeltaopen bay

Proximal prodeltaor delta front

bay mouth complex

Inner estuarytidal channel

River influenced delta,restricted bay orestuary

Unimodaldistribution of grains,

no mineralogic diversityof grains

Load-casted beddingcontacts and abundant

organic detritus

Penecontemporaneousdeformation observed

in association withmassive media

Burrowed contactsat top or bottom ofmassive-appearing

sediment, or vestigialburrows evident locally

or

or

or Sand

Mud

Sand

Mud

or

Freshwater

Oxygen depleted

or

or

High sedimentation rate

Freshwater

Freshwater

High sedimentation rate

MM

Pervasively burrowed

> Interpreting depositional conditions from bioturbation texture. Classifying sedimentary textures into three types—unburrowed or laminated, burrowed and mottled or massive appearing—helps ichnologists infer depositional environment. (Adapted from Gingras et al, reference 3.)

4. Gingras et al, reference 3.5. Buatois LA and Mángano MG: “Animal-Substrate

Interaction in Freshwater Environments: Applications of Ichnology in Facies and Sequence Stratigraphic Analysis of Fluvio-Lacustrine Successions,” in McIlroy D (ed): The Application of Ichnology to Palaeoenvironmental and Stratigraphic Analysis. London: The Geological Society, Special Publication 228 (2004): 311–333.

6. Hickey JJ and Henk B: “Lithofacies Summary of the Mississippian Barnett Shale, Mitchell 2 T.P. Sims Well, Wise County, Texas,” AAPG Bulletin 91, no. 4 (April 2007): 437–443.

Loucks RG and Ruppel SC: “Mississippian Barnett Shale: Lithofacies and Depositional Setting of a Deep-Water Shale-Gas Succession in the Fort Worth Basin, Texas,” AAPG Bulletin 91, no. 4 (April 2007): 579–601.

O’Brien NR: “The Effects of Bioturbation on the Fabric of Shale,” Journal of Sedimentary Petrology 57, no. 3 (May 1987): 449–455.

7. Taylor AM and Goldring R: “Description and Analysis of Bioturbation and Ichnofabric,” Journal of the Geological Society 150, no. 1 (February 1993): 141–148.

8. A colonization event occurs when one or more species spread to a new area.

9. Pemberton SG, MacEachern JA, Gingras MK and Saunders TDA: “Biogenic Chaos: Cryptobioturbation and the Work of Sedimentologically Friendly Organisms,” Palaeogeography, Palaeoclimatology, Palaeoecology 270, no. 3–4 (December 15, 2008): 273–279.

10. Gingras et al, reference 3.

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exhibit trace fossils.5 Unburrowed fine-grained laminated sediments rich in clay and silt are typi-cally interpreted to result from sedimentation in freshwater or anoxic conditions, although high sedimentation rates might yield the same result. Many organic-rich source rocks, some of which are targets of tight oil and gas shale plays, are examples of fine-grained sediments deposited in environments with a low oxygen supply. Because such depositional environments are not welcom-ing to many animals, the sediments may exhibit layering and ordered clay grains and show little or no bioturbation.6

Burrowed—Categorization of burrowed media is based on the distribution of ichnofossils and characteristics—primarily size and diver-sity—of the ichnological assemblage. Ichnologists have developed a bioturbation index (BI) to describe the degree to which sediments exhibit bioturbation.7 The index classifies, on a scale of zero to six, the abundance of traces and amount of trace overlap (right). The BI is related to the duration of colonization events and, through them, to rates of sedimentation.8

Highly to completely burrowed sediments are evidence of both a significant infaunal biomass and conditions of slow sediment accumulation. Moderate to sparse bioturbation, characterized by evenly distributed trace fossils, indicates a lower infaunal biomass and higher sedimentation rate. The size and diversity of ichnofossils in burrowed media reflect the chemical aspects of the deposi-tional waters. For example, in marine deposits, large trace fossils are indicative of high dissolved oxygen content and stable ocean salinity. A pre-ponderance of small trace fossils suggests salinity- or oxygen-stressed environments. High diversity of fossil types is related to oxygen content and salinity and also indicates abundant nutrients.

Massive—Sediments that appear to be mas-sive, or homogeneous in texture, can result from any of the following:• lack of sufficient grain-size variation to define

sedimentary lamination• sedimentation rate high enough that no grain-

size segregation occurs• mechanical mixing from soft-sediment defor-

mation during gravity flows• high degrees of biogenic churning.

Only the last of these is caused by bioturba-tion, and recognizing it as such is not always easy because the rock may appear homogeneous (right).9 It has therefore been given the name cryptobioturbation or cryptic bioturbation. The homogeneous texture is caused by rapid rework-ing of sediments by organisms in search of nutri-

ents. Complete obliteration of layering is the highest degree of cryptobioturbation; layering may be disrupted to lesser degrees and still be bioturbated. Cryptobioturbation in sand usually indicates a marine depositional environment, but in fine-grained sediment it may be produced in marine or freshwater environments.10

Sequence Stratigraphic InterpretationThrough sequence stratigraphy, geologists iden-tify sequences, or sedimentary deposits that are bounded by unconformities, which are surfaces

characterized by erosion, lack of deposition or abrupt changes in depositional environment. Identifying the key bounding surfaces and cor-relating them with data from wells and seismic surveys form the basis of the sequence strati-graphic approach. In creating an integrated interpretation, geologists use trace fossils along with sedimentological analysis, core measure-ments and well logs to characterize sediments within each sequence and identify the deposi-tional surfaces and discontinuities that separate sedimentary sequences.

> Bioturbation index. The bioturbation index is a scheme for quantifying the degree of sediment bioturbation. The index grades trace abundance and overlap and the resultant loss of primary sedimentary fabric. (Adapted from Taylor and Goldring, reference 7.)


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Low bioturbation, bedding distinct, low trace densityand escape structures often common

High bioturbation, bedding boundaries indistinct andhigh trace density with overlap common

Intense bioturbation, bedding completely disturbed(just visible), limited reworking and later burrows discrete

Complete bioturbation and sediment reworking because of repeated overprinting

Moderate bioturbation, bedding boundaries sharp,traces discrete and overlap rare

No bioturbation

> Cryptic bioturbation. Some biogenic activity leaves no distinct traces but instead results in widespread, subtle disruption of the original sedimentary fabric. In an outcrop-derived core from the Cretaceous Ferron Sandstone, Utah, USA (left ), bioturbation is extensive, but some layering is still intact. Cryptic bioturbation in a wellbore core from the Eocene Mirador Formation, Colombia (middle), has destroyed much of the original layering. In a wellbore core from the Middle Jurassic Bruce field in the North Sea (right), it has obliterated any sign of layering. (Adapted from Pemberton et al, reference 9.)

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52 Oilfield Review

An important factor in the distribution of organisms is the surface they inhabit.11 Ichnolo-gists characterize sedimentary surface environ-ments according to consistency of the ground and have developed a classification of surface types in terms of stiffness:• soupground—water-saturated mudrocks• softground—muddy sediment with some

dewatering• looseground—sandy • stiffground—stabilized• firmground—dewatered and compacted• hardground—lithified.

Only with adequate stiffness can these media support traces that can be preserved in the fossil record. Therefore, ichnofossils are usually dis-cernable only in stiffground and firmground sur-faces (although backfilled and lined burrows may be discernible in softgrounds); hardground sur-faces are too hard for most organisms to pene-trate. Firmgrounds in marine environments may be attractive to animal colonization. Their firm-ness offers the animal protection; they tend to occur in areas of slow sediment accumulation, and the firm sediment does not require constant burrow maintenance. However, for a surface to be both firm and populated, it must have been deposited, dewatered and somewhat compacted before serving as a habitat. In clastic settings, these requirements often are associated with erosionally exhumed substrates, and the result-ing surfaces correspond to erosional discontinui-ties.12 Identifying erosional discontinuities is important because they form the bounding sur-faces of sedimentary sequences.

Geologists have incorporated ichnological information in sequence stratigraphic studies in a wide range of environments, including Jurassic marine sequences of the North Sea, Permian flu-vio-lacustrine facies of Argentina, Jurassic car-bonates in Saudi Arabia and Cretaceous marine sequences in Canada.13 Most such studies make use of ichnofossils identified in outcrops and cores, but visual indications of bioturbation may come from well logs.

Imaging IchnofossilsIf burrows and other traces are large enough and filled with material that has resistivity of suffi-cient contrast to that of the host rock, they may appear in borehole resistivity images. Examples of resistivity images from wells in clastic forma-tions in the Orinoco heavy oil belt in Venezuela show a range of features that may be interpreted as evidence of bioturbation.

> Orinoco wellbore image. A feature in an FMI image (left ) may be interpreted (middle) as a U-shaped burrow. A photograph from an unrelated core (right ) shows a burrow of the type (an ichnofossil known as Arenicolites) that may be present in the FMI image. The green lines represent formation structural dip; the yellow lines are fractures. (Photograph copyright S. George Pemberton.)

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>Wellbore image of possible bioturbation. The FMI image (left ) has high-resistivity (light colored) features that may be interpreted (middle) to be burrows resembling the ichnofossil Thalassinoides (right ) in an unrelated core. The structures are classified as dwelling and feeding burrows of a deposit-feeding crustacean living in lower shoreface to offshore environments. (Photograph copyright S. George Pemberton.)


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There, an operating company is developing a heavy oil field with multiple horizontal wells and wants to place the wells in the best reservoir sands. To this end, the operator commissioned an integrated study that combined lithostrati-graphic, biostratigraphic, sedimentological and petrophysical analyses of cores and log data in the four main reservoir units to create a deposi-tional model. The model helped geologists iden-tify the locations and orientations of stacked channel sands and plan development wells with increased confidence.

In several cases, burrows in low-resistivity, shaly intervals were filled with resistive sediment. An FMI fullbore formation microimager log from one of the deeper formations revealed a low-resis-tivity layer with a large, U-shaped burrow filled with resistive material (previous page, top). This ichnofossil is typically associated with low-energy shoreface or sandy tidal flat environments. In the same well, a borehole image from a shallower for-mation showed circular features that could be interpreted as cross-sectional cuts through hori-zontally oriented burrows. The high-resistivity fea-tures were in a low-resistivity layer near its interface with an overlying resistive layer (previ-ous page, bottom). Burrows of this type are com-mon in lower shoreface to shelfal environments.

Possible ichnofossils that have the opposite resistivity contrast can also be seen in FMI images in this field. In a different well, geologists identi-fied a low-resistivity conical burrow in a layered interval of higher resistivity (right). Ichnofossils of this type are vertically oriented, single-entrance burrows with an opening that expands to create a funnel shape. They are commonly filled with sedi-ment that is of finer grain than that of the host layer. These are feeding or dwelling burrows of deposit feeders and are indicators of lower shore-face to proximal shelf settings.

While identification of these ichnofossils did not drive the interpretation of the depositional sequences, it corroborated the analysis of the lithostratigraphic, biostratigraphic, sedimento-logical and petrophysical properties derived from cores and log data, thus reinforcing the inte-grated interpretation. Geologists were able to identify maximum flooding surfaces and corre-late them between wells in the field and were also able to extend this interpretation to neigh-boring fields.

> A low-resistivity conical feature. An FMI image (left ) from a well in Venezuela exhibits a low-resistivity (dark) conical structure (middle) that resembles the vertical burrow ichnofossil Rosselia (right ), although the scales are quite different. An Ichnofossil of this type is a vertically oriented single-entrance burrow that has an opening that expands to create a funnel shape. These burrows are commonly filled with sediment that is of finer grain than that of the host layer. These are feeding or dwelling burrows of deposit feeders and are indicators of lower shoreface to full marine settings. The yellow lines represent formation dip; the blue lines may be flooding surfaces. (Photograph copyright S. George Pemberton.)


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11. Grain size, organic content, local energy and sediment cohesiveness are other factors that may influence colonization patterns.

Pemberton SG, MacEachern JA and Saunders T: “Stratigraphic Applications of Substrate-Specific Ichnofacies: Delineating Discontinuities in the Rock Record,” in McIlroy D (ed): The Application of Ichnology to Palaeoenvironmental and Stratigraphic Analysis. London: The Geological Society, Special Publication 228 (2004): 29–62.

Taylor and Goldring, reference 7.12. Pemberton et al, reference 11.

13. Taylor AM and Gawthorpe RL: “Application of Sequence Stratigraphy and Trace Fossil Analysis to Reservoir Description: Examples from the Jurassic of the North Sea,” in Parker JR (ed): Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. London: The Geological Society (1993): 317–335.

Buatois and Mángano, reference 5. Pemberton et al, reference 11. MacEachern JA, Pemberton SG, Gingras MK, Bann KL

and Dafoe LT: “Uses of Trace Fossils in Genetic Stratigraphy,” in Miller W III (ed): Trace Fossils: Concepts, Problems, Prospects. Amsterdam: Elsevier (2007): 110–134.

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Over the past few decades, oil company geolo-gists have used trace fossil input mainly in explo-ration and development efforts such as those in the Orinoco example. Recently, they have begun to incorporate this information in production-related studies.

Bioturbation Effects on ProductionBioturbation can destroy or enhance permeabil-ity. Geologists generally consider bioturbation detrimental to permeability; biogenic churning tends to undo grain sorting, and redistribution of fine clay grains can reduce overall permeability of layered media. However, evidence in recent

soils and sediments shows that in some cases, bioturbation enhances porosity and permeability by creating new pathways for fluid movement.

Porosity and permeability increase when holes burrowed into a firmground are filled with contrasting, usually coarse-grained, sediment.14 These ichnofossils can add porosity and permea-bility to an otherwise low-porosity, impermeable matrix. If the burrows are aligned—many will be vertically oriented—the resulting permeability is anisotropic: greater in the vertical direction than in any horizontal directions. In some instances, the burrows constitute the reservoir porosity and permeability. In others, the burrows may be filled with material that later becomes impermeable. In yet other instances, enhanced permeability lies in a diagenetic zone around the burrow.

Failing to detect or ignoring the presence of biogenically modified porosity can lead to errors in estimates of hydrocarbon reserves; if the bur-rows are filled with high-porosity material, reserve calculations that do not take them into account will be too low, and if the burrows are tight, reserve calculations could be too high. Identifying and quantifying the effects of enhanced permeability in reservoir zones are crucial for successful well completions and accu-rate production simulations.

Researchers at the University of Alberta in Edmonton, Canada, have studied the porosity and permeability effects of bioturbation.15 They see the greatest effects when burrows in dewa-tered, firmground substrate are filled with coarse-grained sediment (left). Burrows of this type can reach areal densities of 2,500 burrows/m2 [250 burrows/ft2]. The effects on permeability depend on burrow connectivity, depth of penetra-tion and permeability contrast between matrix and burrow fill. The permeability-enhanced zone may be up to 3 m [10 ft] thick and is generally limited to areal extents of 1 km2 [0.4 mi2]. Layers exhibiting this type of bioturbation have been recognized in several oil fields.

The Ghawar oil field in Saudi Arabia, the world’s largest, is one such example. The oil is contained in carbonate rocks of the Jurassic Arab-D Formation. Production logging has detected thin, superhigh-permeability zones called “super-k” zones that contribute a large proportion of the total flow. In some of the super-k zones, the permeability appears to be related to faults and fractures, while in others, the high permeability is attributed to dolomitiza-tion and leaching.16

The University of Alberta geologists examined cores of one super-k layer and reported the pres-ence of a geologic surface of burrow-enhanced permeability. They hypothesized that the surface developed when a firmground, low-porosity micritic calcite layer was exposed during regional erosion that occurred during a rise in sea level (next page). Epifaunal organisms excavated bur-rows about 1 to 2 cm [0.4 to 0.8 in.] in diameter that penetrated up to 2 m [7 ft] below the sur-face. Many burrows filled with sucrosic dolomite, which is more porous and permeable than the micrite matrix. Flowmeter measurements indi-cate that in some wells, 70% of the production comes from this single unit.

Although the high permeability of this layer is beneficial to oil production, it can cause difficul-ties when water is drawn into it from the underly-ing aquifer. The burrows may act as pathways for some of the 1 million m3 [6 million bbl] of water produced daily in the Ghawar wells.

In some instances, burrowing may be present but fail to add effective porosity. One example of this phenomenon comes from the Natih Formation of Oman, which was deposited on a shallow marine carbonate platform in the middle Cretaceous.17 The E Member of the Natih Formation is a reservoir of heavy oil in the Al Ghubar field, and as of 2003 had produced less than 5% of its estimated oil in place. Original esti-mates of reserves incorporated neutron and den-sity log–based porosities of 20% to 45%. To determine the causes of the production under-performance, geologists and engineers scruti-nized core and log porosity measurements.

Analysis of thin sections from the various carbonate rock types penetrated by a 60-m [200-ft] core revealed five types of porosity, four of which may be ineffective, meaning they do not contribute to production. The effective poros-ity type—solution-enhanced interparticle poros-

14. Pemberton SG and Gingras MK: “Classification and Characterizations of Biogenically Enhanced Permeability,” AAPG Bulletin 89, no. 11 (November 2005): 1493–1517.

15. Pemberton and Gingras, reference 14.16. For more on dolomitization: Al-Awadi M, Clark WJ,

Moore WR, Herron M, Zhang T, Zhao W, Hurley N, Kho D, Montaron B and Sadooni F: “Dolomite: Perspectives on a Perplexing Mineral,” Oilfield Review 21, no. 3 (Autumn 2009): 32–45.

17. Smith LB, Eberli GP, Masaferro JL and Al-Dhahab S: “Discrimination of Effective from Ineffective Porosity in Heterogeneous Cretaceous Carbonates, Al Ghubar Field, Oman,” AAPG Bulletin 87, no. 9 (September 2003): 1509–1529.

> Enhancing permeability. Burrows filled with coarse-grained sediments create high-permeability channels in fine-grained, low-permeability host rock. Burrows of this type, known as Glossifungites, may have population densities as high as 2,500 burrows/m2 [250 burrows/ft2]. (Photograph copyright S. George Pemberton.)


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ity—creates effective reservoir intervals in the grainstone facies that make up 20% of the total thickness of the Natih E reservoir. In some zones, leaching of cement has left the grainstones with carbonate grains held together only by the viscous oil.

The remaining 80% of the Natih E reservoir contains packstone and wackestone exhibiting the other four types of porosity, which are for the most part ineffective. These rocks have abundant

0.5- to 2.0-cm [0.2- to 0.8-in.] burrows filled with partially dolomitized grainstone, creating inter-particle porosity. The burrow fillings make up between 10% and 50% of the rock volume. However, the burrows are not sufficiently con-nected to produce significant amounts of oil. Similarly, the other porosity types—microporos-ity, moldic porosity and intragranular porosity—are not effective in this reservoir. Unfortunately, the neutron and density porosity logs cannot dis-

tinguish between effective and ineffective poros-ity, leading to inaccurate calculations of reserves.

To determine if other logs would be more suit-able for assessing effective porosity and permea-bility, the geologists correlated the rock and pore types identified in the core with other wireline log responses; they began by matching core gamma ray responses with well log gamma ray readings. Of the available well logs—gamma ray, resistivity, sonic, density porosity and neutron porosity—

> Development of a super-k layer in the Ghawar field, Saudi Arabia. Geologists propose that the superpermeability in the Jurassic Arab-D interval developed when regionally extensive erosion exposed a low-porosity micritic calcite firmground (A). Crustaceans colonized this firm sediment, creating a dense network of burrows (B). The burrows filled with detrital sucrosic dolomite (C), which is more porous and permeable than the micritic calcite that contains the burrows. Oil (gold) flows freely though the resulting super-k layer (D). (Adapted from Pemberton and Gingras, reference 14.)

A B C D A B C D A B C D A B C D

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56 Oilfield Review

only the resistivity logs showed clear correlations with core plug permeability (below).

The high-permeability oil-stained zones seen in cores correlate with intervals that exhibit high values of deep resistivity. These zones also correspond to separation between medium and deep resistivity curves, indicating invasion of drilling fluid into the formation, which occurs only in permeable units. The resistivity curves have little or no separation in the burrowed wackestone layers, indicating low permeability and ineffective porosity.

The results of the study suggest that because the grainstones that have interparticle porosity make up only 20% of the total thickness of the porous oil-prone interval, the estimate of recov-erable oil in place should be decreased by 80%. If this reduction is taken into account, about 25% of the recoverable oil in place has been produced, which the operator considered acceptable for this carbonate reservoir.

Burrow Porosity and Permeability in a Gas FieldIn carbonate formations, burrows filled with dolomite can act as primary or secondary con-duits for fluid movement. Flow behavior in bur-rowed formations depends on the amount of bioturbation, the connectivity of burrows and the contrast in porosity and permeability between the dolomite fill and the carbonate matrix.

Bioturbated carbonate mudstones make up part of the producing interval in the Pine Creek gas field of Alberta, Canada. From depths exceed-

>Well logs and core data from the E Member of the Natih Formation, Al Ghubar field, Oman. Reservoir underperformance led geologists to reevaluate log and core measurements to determine the best indicators of effective porosity and permeability. Only the logs of deep resistivity (Track 7) and of the difference between medium and deep resistivity (Track 8) showed clear correlations with core plug permeability (Track 6). High-permeability zones are shown by yellow shading. (Adapted from Smith et al, reference 17.)


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ing 3,000 m [10,000 ft], the field has produced more than 550 MMcf [15.6 million m3] of gas.

In a study using slabbed core samples from 11 wells in the field, University of Alberta geolo-gists examined the sedimentological, ichnologi-cal and petrophysical properties of facies in the Wabamun Group—the primary reservoir facies in the Pine Creek field.18 They also imaged the core

samples using X-ray micro–computed tomogra-phy (microCT) and helical computed tomography to obtain 2D and 3D images and performed spot permeability tests to analyze permeability distri-butions in the samples.

In the four reservoir facies, the amount of burrow-associated dolomite ranged from 0% to about 80% to 100%. MicroCT scans of a core from

the most heavily bioturbated facies revealed the complexity of the burrow distribution (above). The dolomitized burrows represent a mixture of

> Spot permeametry and microCT analysis of samples from the Wabamun Group in Alberta, Canada. In this formation, permeability is increased where burrows are associated with localized bioturbation. A core sample (top left ) exhibits dolomite-associated trace fossils (light brown) and a nondolomitized lime mudstone matrix (light gray). Results of spot permeametry measurements (top middle) can be contoured to produce a permeability map (top right ). The highest permeability values are up to 340 mD and correspond to the dolomitized trace fossils. MicroCT scans in 3D (bottom, top row) at 34-μm resolution reveal mineral phases in five cross sections of a core sample. The dolomite-filled burrows are represented as shades of blue, lime mudstone matrix as light gray and vugs as unfilled holes (demarcated by black arrows). The 2D cross-sectional images at the bottom were used to constrain the attenuation phases within the core sample. In these images, the dolomite-filled burrows appear in light gray, limestone matrix in dark gray and vugs in black.

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18. Baniak GM, Gingras MK and Pemberton SG: “Reservoir Characterization of Burrow-Associated Dolomites in the Upper Devonian Wabamun Group, Pine Creek Gas Field, Central Alberta, Canada,” Marine and Petroleum Geology 48 (December 2013): 275–292.

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> Production history in an ichnofossil-hosted tight gas reservoir. Monthly gas production from a well in the Pine Creek field shows early production from gas-filled burrows in the first 15 or 20 years. Gas production then declines because the gas must diffuse from the low-permeability matrix into the burrows to be produced.


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tubular structures ranging in diameter from millimeters to centimeters. The difference in lithology between the burrows and the nondolo-mitized limestone mud matrix makes the bur-rows easy to image.

Spot-permeability tests quantified the perme-ability of the cores on a 0.5-cm [0.2-in.] grid. Permeability of the matrix is less than 1 mD, whereas permeability of the dolomitized burrows is greater than 100 mD.

The large contrast in permeability between burrows and matrix gives rise to a distinctive pro-duction history for wells in the field (above). For the first 15 years in the life of a well, the forma-tion produces gas from the burrows. After the easy gas has been extracted, the declining pro-duction is interpreted to be of gas that has dif-fused from the matrix into the burrows. Geologists studying this field have coined a new term— ichnofossil-hosted tight gas—to describe this burrow-matrix association.

Burrow SignificanceBiologic disturbance of sediments can have many effects, for better or worse, on reservoirs. By recognizing burrows and other trace fossils, ichnologists gain knowledge they can incorpo-rate with other information to infer a formation’s

depositional environment and hydrocarbon potential. This information helps them guide exploration activities.

Bioturbation alters the physical properties of a rock as it is being formed. The process can increase or decrease porosity and permeability and can modify permeability anisotropy, some-times to a significant degree. Quantifying these effects and including them in reservoir simula-tion models can improve production predictions and enhanced oil recovery operations.

Bioturbation can have the same effects on fine-grained layers as it has on reservoir rocks. Shales and mudstones may lose their capability to act as reservoir seals if bioturbation causes a large increase in vertical permeability. In the Sirasun and Terang gas fields in Indonesia, the marly caprock was found to have burrows that were filled with hollow foraminifera. The low-permeability formation had certifiable reserves of 500 Bcf [14 billion m3] of gas. The burrows caused it to acquire reservoir characteristics, making for a leaky seal.19

Recent activity in gas- and oil-prone mud-stone and shale formations—called unconven-tional reservoirs because they act as both source rock and reservoir—may benefit from more studies of bioturbation. Evidence of bioturbation has been documented in several low-permeabil-ity, fine-grained rocks.20 Ichnofossils have been identified in the Woodford Formation and the Lower Marcellus Shale in the US and in the

Bakken Shale and the Montney Shale in Canada. As in the example from the Pine Creek field, extensive zones of trace fossils in these forma-tions may improve gas storativity and the con-nectivity of porosity with induced fractures. Bioturbation may also affect rock mechanical properties, potentially influencing the outcome of hydraulic fracturing.

In a manner of speaking, many human activi-ties qualify as bioturbation. The wells we drill and the tunnels we bore are on scales far sur-passing those of burrows by sea creatures, but we can still learn from the effects of their small-scale efforts. By recognizing bioturbation and appreciating its consequences, geoscientists are likely to improve their understanding of res-ervoirs and do a better job recovering hydro-carbon resources. —LS

19. Pemberton and Gingras, reference 14.20. Aplin AC and Macquaker JHS: “Mudstone Diversity:

Origin and Implications for Source, Seal, and Reservoir Properties in Petroleum Systems,” AAPG Bulletin 95, no. 12 (December 2011): 2031–2059.

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Contributors

Winter 2014/2015 59

Chris Babin, based in New Orleans, is Wireline Technology Manager for Schlumberger North America Offshore. He is responsible for the development and implementation of new technologies for offshore oper-ations in Alaska, eastern Canada and shelf and deep-water Gulf of Mexico. His duties include joint technology development projects with customers for special applications. Chris began his career as a wire-line field engineer in 1996 in Belle Chasse, Louisiana, USA, and has held several positions in sales and opera-tions, all in the New Orleans area. He holds a BSc degree in ocean engineering from Texas A&M University, College Station, USA.

Rob Cummings began his career in 1998 with WesternGeco, now a Schlumberger company, as an HSE advisor assigned to the global fleet of seismic exploration vessels. In 2005, he spent three years in Kuala Lumpur as the company’s HSE manager for the Asia Pacific area. He then became operations man-ager for West Africa in Luanda, Angola, managing high-technology offshore exploration projects for var-ious clients and next assumed a global role in manag-ing all aspects of the company’s HSE from London. In 2012, Rob began his current position as a Schlumberger HSE Manager in Houston and is responsible for implementation and support of pro-grams offshore North America and Alaska. He attended the Durban Institute of Technology and the University of Pretoria, South Africa, to obtain a quali-fication in emergency medicine.

John R. Dribus, a Global Geology Advisor for Schlumberger, is responsible for deepwater basins along the Atlantic Margin; the Gulf of Mexico; the Black, Red and Mediterranean Seas; and eastern Africa. Based in New Orleans, he is a reservoir geolo-gist with more than 30 years of experience in the Gulf of Mexico. His assignments have spanned all aspects of exploration, exploitation and production geology for Schlumberger and for a major oil and gas company, including more than 15 years working in the deepwa-ter Gulf of Mexico and 5 years as a uranium field geolo-gist. His areas of expertise are petroleum systems analysis, deepwater exploration and analogs, geologic risk analysis and geoscience training and develop-ment. John serves on the advisory committee of the Delta Chapter of the API and is a member of the AAPG Imperial Barrel Award Committee. He received BS and MS degrees in geology from Kent State University, Ohio, USA.

Chris Garcia is Latin America Deepwater Advisor for Schlumberger in Houston. He began his career with deepwater drilling contractor Zapata Offshore. Since joining Schlumberger in 1987, he has held numerous positions, including deepwater theme manager for the Gulf of Mexico and deepwater business development manager in Mexico and Latin America. Chris obtained a BS degree in petroleum engineering from The University of Texas at Austin and is pursuing a project management professional certification.

Murray K. Gingras is a Professor and Associate Chair in the Department of Earth and Atmospheric Sciences at the University of Alberta, Edmonton, Canada. He focuses on applying sedimentology and ichnology to sedimentary rock successions, as a paleoecological tool and a reservoir-development tool, and in process sedimentology. He has worked at the Northern Alberta Institute of Technology, Canada, focusing on the oil and gas industry, and as an assistant professor at the University of New Brunswick, Canada. Murray earned a diploma in mechanical engineering technology from the Northern Alberta Institute of Technology and BSc and PhD degrees from the University of Alberta.

Loïc Haslin is Vice President of Deepwater Operations for Schlumberger in Paris. He joined the company in 1998 as a field engineer after receiving an MS degree in process engineering from Institut National Polytechnique de Grenoble, France. He has held a variety of operational integrity and management posi-tions in West Africa, Asia, the North Sea and North America in testing, completions and artificial lift. Prior to his current assignment, Loïc was business manager for testing services operations in the North America Offshore region, which includes the Gulf of Mexico, the east coast of Canada and Alaska.

Andrew Hawthorn is the Schlumberger Business and Technology Development Manager, North America. He is based in Houston. He joined the com-pany in 1990 as a field engineer in Norway and held many positions around the world, mainly in the North Sea and the Middle East. For two years begin-ning in 2005, he was the LWD acoustic product champion responsible for the sonicVISION* and the seismicVISION* seismic-while-drilling and new acoustic engineering projects. Andy has a BS degree in geology and an MS degree in geological engineer-ing from Durham University in England.

Robert Holicek, has been Schlumberger Project Manager North America Offshore since 2013, support-ing technology development projects specific to deep water in North America. Currently based in Houston, he joined Schlumberger in 2001 as a field engineer in offshore stimulation in the Gulf of Mexico and then moved into the role of a district technical engineer. In 2006, he became a production stimulation engineer, evaluating production and reservoir performance and optimizing completion designs by working with geome-chanics, reservoir and completion engineers as well as with petrophysicists. In 2010, he became the Schlumberger North Gulf Coast deepwater theme man-ager; his focus was on business development, market-ing strategy and technology gap analysis for all oilfield technologies in the deepwater Gulf of Mexico. Robert holds a BS degree in chemical engineering from the University of Wisconsin, Madison, USA.

Chad Kraemer, based in Sugar Land, Texas, is a Schlumberger Pressure Pumping Services Account Manager for BHP Billiton Petroleum. He began his career in 2004 as a Schlumberger Well and Completion Services field engineer in the US. Subsequently, he held operations management positions in the US,

Indonesia and Thailand. He recently concluded two years as a product champion for the Schlumberger HiWAY* service and fiber-related technology. Chad earned a BS degree in chemical engineering from the University of Minnesota, Twin Cities, USA.

Bruno Lecerf is a Program Manager with the Pressure Pumping and Chemistry group within Schlumberger Engineering, Manufacturing and Sustaining in Sugar Land, Texas. Previously, he was a project manager at the Novosibirsk Technology Center, Russia, and prior to that, a solutions engineer for acidizing at the Integrated Productivity and Conveyance Center in Sugar Land. Bruno obtained an MS degree in chemis-try from Ecole Supérieure de Chimie Physique Electronique de Lyon, France, and an MS degree in chemical engineering from the University of Houston.

Pablo Parra is the Lead Technical Stimulation Engineer for Schlumberger Well Services in Reynosa, Tamaulipas, Mexico. He began his career in 2005 as a field engineer and held technical and field operations positions in Venezuela and Russia before moving to Mexico in 2011. Pablo holds a BS degree in chemical engineering from Universidad Simón Bolívar, Caracas.

S. George Pemberton is the C. R. Stelck Chair in Petroleum Geology and a Distinguished University Professor in the Department of Earth and Atmospheric Sciences at the University of Alberta, Edmonton, Canada. His research, which focuses on the applica-tion of ichnology to petroleum exploration and exploi-tation, includes recent work on the application of ichnology to the flow of fluids through the reservoir. He has worked on major hydrocarbon-bearing units world-wide. In addition to having served as the Canada Research Chair in Petroleum Geology, he is an honor-ary member of the Canadian Society of Petroleum Geologists and a Fellow of the Royal Society of Canada. He has received numerous awards, including the Geological Association of Canada (GAC) Past President’s Medal, the SEPM Society for Sedimentary Geology R. C. Moore Medal for Excellence in Paleontology; the AAPG Grover Murray Distinguished Educator Award; the Killiam Award for Excellence in Mentoring and the GAC Logan Medal. George has won 15 best paper or best presentation awards and has published numerous papers and edited or coedited 7 books. He received a PhD degree from McMaster University, Hamilton, Ontario.

Alejandro Peña is the BroadBand Services Manager for Schlumberger in Sugar Land, Texas. He earned a BS degree in chemical engineering and was an assis-tant professor at Universidad de Los Andes in Mérida, Venezuela. He joined Schlumberger in 2003 after com-pleting a PhD degree in chemical engineering at Rice University in Houston. Since then, he has held several operational, engineering and technology management positions within Schlumberger in North and South America. Alejandro holds nine granted patents and has authored more than 30 publications on reservoir stimulation technologies and interfacial phenomena.

ORWIN1415_contribs_04.indd 1 1/20/15 2:33 AM

60 Oilfield Review

Serko Sarian is Schlumberger Telemetry and Conveyance Portfolio Manager at the Houston Conveyance and Surface Equipment Center in Sugar Land, Texas. He is responsible for the development and introduction of wireline conveyance systems, which include downhole tractors and logging cables. Serko has been a service and support manager for operations in Europe and Africa and for wireline oper-ations in Libya, India and deepwater Gulf of Mexico. In 1987, he began his career with Schlumberger as a field engineer in Australia. He next held field positions in Vietnam and Malaysia and then worked as a training engineer at the Egypt Training Center in Alexandria. He obtained a BS degree in electrical engineering from the American University of Beirut, Lebanon.

Michael Smith is a Borehole Geologist for Schlumberger in Maturín, Venezuela. He is responsi-ble for interpreting borehole image logs and has been involved in several multiwell studies integrating structural, sedimentological, stratigraphic and petro-physical interpretations. Previously, he worked as a reservoir geologist at Petróleos de Venezuela, SA (PDVSA) Petroregional del Lago. Michael has a degree in geology from Universidad de Oriente, Bolívar, Venezuela.

Dmitriy Usoltsev is Schlumberger Product Champion for Diversion and Acid Stimulation Services in Sugar Land, Texas. He is responsible for stimulation and completion strategies, service qual-ity reinforcement and new diversion technologies implementation for proppant and acid stimulation treatments. In 2000, he joined Schlumberger as a Well Services field engineer in the US. Since then, he has held field operations and engineering posi-tions in Russia and the US. Dmitriy earned bache-lor’s and master’s degrees in mathematics from Novosibirsk State University in Russia.

Ariel Valenzuela is in charge of the Completions Engineering and Productivity department of the Petróleos Mexicanos (PEMEX) Burgos Asset; he is based in Reynosa, Tamaulipas, Mexico. He joined PEMEX in 1985 and has focused on well completions, hydraulic fracturing and productivity. Ariel has authored or coauthored several technical papers on completions and hydraulic stimulations. He received a BS degree in petroleum engineering from the Instituto Politécnico Nacional, Mexico City.

An asterisk (*) denotes a mark of Schlumberger.

Seismic Guided Drilling. Drilling is fraught with uncertainty that arises from incomplete knowledge about the subsurface geology, geophysics, mechanical properties, in situ stresses, pressures and tempera-tures of a drilling prospect. What is known about a drilling prospect is estimated from seismic and offset well data—well logs, cores, well tests and drilling reports. Reducing these uncertainties and associated risks is a key industry driver. Seismic guided drilling is an integrated process that generates predictive struc-tural and pore pressure models ahead of the bit by honoring seismic reflection data and all the data from the well being drilled.

Coming in Oilfield Review

Multiphase Flow Simulation. Before engineers develop a field, multiphase flow simulators may help them understand what types of formation fluids to expect from the target reservoir and how those fluids will flow through wells and pipelines. Operators worldwide use this information, supplied by the lat-est-generation of ever-evolving dynamic multiphase flow simulators, to choose where and how to locate wells and how many wells they must complete to optimize field development and maximize operator return on investment.

Monitoring Coiled Tubing. A coiled tubing string is subjected to numerous and varied types of strain as it is reeled in and out of the wellbore. The result-ing wear reduces the service life of the tubing. A pipe monitoring system has been designed to detect tubing defects and fatigue problems before they become unmanageable.

Interactions Between Wildlife and E&P Activities. Operators, who are expanding their quest for extractable oil and gas reserves, must fol-low regulations that guard the environment against potential adverse effects. Because of the presence of human-made sounds, light and installations on both land and sea, interactions between the E&P industry and the Earth’s wildlife are unavoidable. Decades of research and observations have been devoted to evaluating the environmental impact on various species such as migratory birds, fish and marine mammals. Results from these studies are being heeded and applied by the industry to curtail potential negative impacts on wildlife.

Hunter Watkins, based in Houston, is a Completions Advisor focusing on the Eagle Ford Shale for BHP Billiton Petroleum. He has more than 38 years of industry experience, first with Halliburton, where his duties included unconventional hydrocarbon simula-tions and technology management, and then with Pinnacle and The Western Company. He holds a BS degree from The University of Texas at Austin and is a Professional Engineer in the state of Texas.

ORWIN1415_contribs_04.indd 2 1/20/15 2:33 AM

Winter 2014/2015 61

BOOKS OF NOTE

Climate Forcing of Geological HazardsBill McGuire and Mark Maslin (eds)Wiley-Blackwell111 River StreetHoboken, New Jersey 07030 USA2013. 326 pages. US$ 164.95ISBN: 978-0-470-65865-9

The concept that anthropogenic climate change may not only affect the Earth’s atmosphere and hydrosphere but also drive geologic and geomorphological activity is at the heart of this collection of articles. Phenomena such as earth-quakes, tsunamis, volcanic eruptions and other seismic activity may be influenced and triggered by climate change. Several authors explore the ramifications of potentially hazardous geomorphological activity, as caused by climate change, and its effect on humankind and the world economy.

Contents:

• Hazardous Responses of the Solid Earth to a Changing Climate

• Projected Future Climate Changes in the Context of Geological and Geomorphological Hazards

• Climate Change and Collapsing Volcanoes: Evidence from Mount Etna, Sicily

• Melting Ice and Volcanic Hazards in the Twenty-First Century

• Multiple Effects of Ice Load Changes and Associated Stress Change on Magmatic Systems

• Response of Faults to Climate-Driven Changes in Ice and Water Volumes at the Surface of the Earth

• Does the El-Niño–Southern Oscillation Influence Earthquake Activity in the Eastern Tropical Pacific?

• Submarine Mass Failures as Tsunami Sources—Their Climate Control

• High-Mountain Slope Failures and Recent and Future Warm Extreme Events

• Impacts of Recent and Future Climate Change on Natural Hazards in the European Alps

• Assessing the Past and Future Stability of Global Gas Hydrate Reservoirs

• Methane Hydrate Instability: A View from the Palaeogene

• Index

My overall opinion of the book is very positive, although—as usual in edited volumes—some chapters are better than others. . . . The book is well produced, in colour throughout, easy to navigate, with a comprehen-sive index. Besides being a source of much information, I am sure it will serve to inspire further research of geohazards in a changing world. . . .

Migon P: “Book Review,” Pure and Applied

Geophysics 171, no. 7 (July 1, 2014): 1585–1587.

Practical Applications of Time-Lapse Seismic DataD. H. JohnstonSociety of Exploration Geophysicists8801 South Yale, Suite 500Tulsa, Oklahoma 74137 USA2013. 289 pages. US$ 58.00ISBN: 978-1-56080-307-2

This volume, which is based on a 2013 SEG Distinguished Instructor Short Course, examines 4D seismic technol-ogy and how it enables improved hydrocarbon recovery and cost-effective field operations. The book looks at reservoir engineering concepts and rock physics essential to the understanding of 4D data and topics in 4D seismic acquisition and processing as well as data interpretation and integration. Case studies enhance the key concepts.

Contents:

• Reservoir Engineering and Reservoir Management

• The Rock Physics Behind 4D Seismic

• 4D Screening and Feasibility

• Repeatability and 4D Seismic Acquisition

• Seismic Processing of 4D Data

• Interpretation and Data Integration

• The Road Ahead and Other Thoughts

• Appendix A: Jotun 4D: Characterization of Fluid Contact

Movement from Time-Lapse Seismic and Production Logging Tool Data

• Appendix B: 4D in the Deepwater Gulf of Mexico: Hoover, Madison, and Marshall Fields

• Appendix C: Monitoring Pressure Depletion and Improving Geomechanical Models of the Shearwater Field Using 4D Seismic

• Appendix D: Monitoring a CO2 Flood with Fine Time Steps: Salt Creek 4D

• Interpretation of 4D Seismic Data: Case History Reading List

• Index

The book is tremendously informa-tion dense. The breadth of information covered in a mere 194 pages of text and numerous excellent full-color illustrations plus four appendices and a thorough bibliography is wide and exhaustive. Sections bear reading several times because every repeated look reveals insights or throws its core ideas into higher relief.

Avakian R: “Book Review,” The Leading Edge 33,

no. 6 (June 2014): 670.

Carbon in Earth: Reviews in Mineralogy & Geochemistry, Volume 75Robert M. Hazen, Adrian P. Jones and John A. Baross (eds)Mineralogical Society of America and Geochemical Society3635 Concorde Parkway, Suite 500Chantilly, Virginia 20151 USA2013. 698 pages. US$ 40.00ISBN: 978-0-939950-90-4

Researchers with The Deep Carbon Observatory (DCO), a 10-year interna-tional research effort that is examining the chemical and biological roles of carbon in Earth, contributed to this volume. The book is intended to serve as a benchmark for the researchers’ understanding of Earth’s carbon; a second volume is planned to mark the progress of the DCO initiative. The chapter authors represent laboratory, field and theoretical researchers from the physical and biological sciences

who explored topics such as fundamen-tal physics and chemistry of carbon at extreme conditions, the geodynamics of Earth’s large-scale fluid fluxes and the subsurface microbial biosphere. The volume is available via Open Access.

Contents:

• Why Deep Carbon?

• Carbon Mineralogy and Crystal Chemistry

• Structure, Bonding, and Mineralogy of Carbon at Extreme Conditions

• Carbon Mineral Evolution

• The Chemistry of Carbon in Aqueous Fluids at Crustal and Upper-Mantle Conditions: Experimental and Theoretical Constraints

• Primordial Origins of Earth’s Carbon

• Ingassing, Storage, and Outgassing of Terrestrial Carbon Through Geologic Time

• Carbon in the Core: Its Influence on the Properties of Core and Mantle

• Carbon in Silicate Melts

• Carbonate Melts and Carbonatites

• Deep Carbon Emissions from Volcanoes

• Diamonds and the Geology of Mantle Carbon

• Nanoprobes for Deep Carbon

• On the Origins of Deep Hydrocarbons

• Laboratory Simulations of Abiotic Hydrocarbon Formation in Earth’s Deep Subsurface

• Hydrocarbon Behavior at Nanoscale Interfaces

• Nature and Extent of the Deep Biosphere

• Serpentinization, Carbon, and Deep Life

• High-Pressure Biochemistry and Biophysics

• The Deep Viriosphere: Assessing the Viral Impact on Microbial Community Dynamics in the Deep Subsurface

For petroleum geologists working with source rock resource plays or conventional petroleum reservoirs sourced by sedimentary petroleum systems, there will be little in this book that is directly applicable.

For those who deal with petroleum industry fringe activities, these review papers have the potential to be extremely valuable. . . .

Sorenson RP: “Book Review,” AAPG Bulletin 98,

no. 9 (September 2014): 1909–1910.

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Oilfield Review62

DEFINING INTERVENTION

Few oil and gas wells perform efficiently and produce uninterrupted from initial production to abandonment. Moving parts and seals wear out, tubu-lars develop leaks, sensors fail and formation pressures decline. To address these and other problems, operators rely on well intervention specialists. Interventions fall into two general categories: light or heavy. During light interventions, technicians lower tools or sensors into a live well while pres-sure is contained at the surface. In heavy interventions, the rig crew may need to remove the entire completion string from the well to make major changes to the well configuration, which requires killing the well by stop-ping production at the formation.

The Lighter SideWell service personnel typically perform light interventions using slickline, wireline or coiled tubing. These systems may allow operators to clear the well of sand, paraffin, hydrates or other substances that may form blockages and reduce or completely halt production. Operators also use light interven-tions to change or adjust downhole equipment such as valves or pumps and to gather downhole pressure, temperature and flow data. In many cases, because light interventions are relatively inexpensive and require minimal equipment, they are included in routine well maintenance programs.

A slickline is a single strand of thin wire that conveys tools and sensors into and out of the well (left). Slickline-based interventions include remov-ing sand and paraffin, running or retrieving subsurface control valves and running sensors into a well to record bottomhole temperatures and pres-sures. Slickline is reeled on and off a hydraulically driven drum. A heavier cable may be deployed from a second drum when the tensile strength required to complete an operation exceeds the rating of the slickline cable.

Wireline also conveys downhole tools and sensors on wire; the advan-tage to wireline is that downhole data can be delivered to the surface in near real time. The wireline cable acts as a conduit for electric power and data transfer between the surface and downhole tools and sensors. After a well has been put on production, wireline may be used to run production logs or other sensors.

Coiled tubing also conveys tools downhole, but its primary use is as a con-duit for fluid (above). Engineers use coiled tubing to wash out production-inhibiting sand or scale that has built up inside production tubing or to place acid or other treatments at precise locations within the well. Because coiled tubing has some rigidity, it may be more effective at pushing slickline or wire-line tools, which typically depend on gravity or tractors to move downhole in high-angle wells. When real-time data are desired, a wire may be inserted in the coiled tubing and connected to a sensor being conveyed downhole.

Light intervention systems usually include a mechanism that ensures well pressures are contained as the slickline, wireline or coiled tubing passes through it into the wellbore. Slickline and wireline system seals are maintained via equipment above the wellhead. Coiled tubing systems use a self-contained pressure-control system that allows the tubing to pass into the wellhead.

Upstream Maintenance and Repair

Oilfield Review Winter 2014/2015: 26, no. 4.

Copyright © 2015 Schlumberger.

Rick von FlaternSenior Editor

> Coiled tubing unit. Coiled tubing (CT) is flexible pipe that may be spooled on and off a large reel using an injector head. The hydraulically driven injector head uses a series of slips to grip and pull the tubing off the reel or from the well and through an arched guide called a gooseneck. The gooseneck bends the tubing toward the wellhead or for spooling back onto the reel. The coiled tubing enters and exits the wellbore through a stripper blowout preventer (BOP), which contains components that seal against the tubing to contain well pressure. A second set of sealing rams (not shown) in the BOP may be closed against the coiled tubing to provide a pressure barrier alternative in the event the stripper BOP fails.

StripperBOP

Injectorhead

Guide arch(gooseneck)

CT stringReel

Oilfield ReviewWinter 08/09ACTive fig. 1ORWin08/09-ACTV Fig. 1

> Basic slickline or wireline rig-up. A wire or cable runs from the drum to the lower sheave, which redirects it upward toward a second sheave. The sheave at the top of the pressure-control equipment turns the wire 180° and feeds it into the well. The wireline valve above the Christmas tree contains opposing rams (not shown) that may be closed to seal against each other without having to remove the wire, thus providing a pressure barrier alternative in the event the pressure-control equipment higher in the system fails.

Oilfield Review WINTER 11/12 Slickline Fig. 1 ORWNT11/12-SLKLN 1

Pressure-control

equipment

Lubricator

Sheave

Wireline orslickline drum

Load cell

Sheave

Christmastree

Wirelinevalve

72917schD10R1.indd 54 1/20/15 3:13 AM

Heavy LiftingTo perform heavy interventions, or workovers, rig crews remove the wellhead and other pressure barriers to allow full access to the well. Crews fill the well with kill weight mud to contain the formation pressure during an interven-tion. Kill weight mud is a dense fluid that creates a hydrostatic pressure at the formation that is greater than the formation’s pore pressure.

Heavy interventions require a rig to remove and reinstall the completion hardware. In many cases, the operator’s objective is to replace leaking or worn-out parts. Typically, this requires replacing only the failed parts and running the completion equipment back into the hole. In some cases, how-ever, operators perform workovers to adapt the completion to reservoir con-ditions that have changed as a result of production. These changes may include the onset of water and sand production or formation pressure that has fallen too low to push fluids to the surface. Assuming the formation has reserves with economic potential, an operator may make adjustments that shut off water production, deploy sand control equipment or run artificial lift systems into the well.

Operators may perform a special type of workover option—a recomple-tion—to abandon one zone and open and complete another zone that was tested and left behind pipe when the well was drilled. In some cases, slick-line may be used to shut off the first zone by running in the hole with a special tool to close a sliding sleeve that had been placed across the perfora-tions as part of the original completion. Slickline is then used to open a sleeve to allow production from a secondary zone.

Typically, however, because of initial well conditions, sleeves are not a viable completion option and operators must first abandon the primary pro-ducing zone by placing a cement plug across it. They then install new com-pletion equipment with which to produce from the secondary zone.

Operators are sometimes reluctant to use kill weight mud to perform heavy interventions because the dense fluid may permanently damage pres-sure-depleted formations. One option is to perform the heavy intervention with the well under pressure, as in light interventions, using a snubbing unit. Snubbing operations use a hydraulic jack to snub, or push, joints of pipe into a live well against well pressure. Although snubbing operations are similar to coiled tubing operations, the former use joints of stiff tubing or casing and can be performed in wells with significantly higher pressures than are possible with coiled tubing. Because snubbing equipment is more robust than that used in coiled tubing operations, it can be employed to perform nearly all operations that typically require use of a drilling rig.

Offshore WorkSince the introduction of subsea wells in the 1970s, service companies have been developing methods to perform light interventions without costly off-shore drilling units. Using specially designed vessels, service companies perform slickline, wireline and coiled tubing operations through subsea wellheads using riserless or riser-based methods (below left).

Riserless interventions deploy wireline and slickline tools from a subsea intervention vessel to a subsea pressure-control package on the wellhead. These open-water operations are currently limited to relatively shallow waters of less than about 400 m [1,300 ft]. Use of coiled tubing in open-water operations is restricted almost exclusively to operations requiring hydraulic interventions such as placing kill weight mud or performing stimulation or flow assurance treatments.

Subsea interventions may also be performed through a riser, or casing string, that connects the subsea wellhead to a surface system. Because ris-ers must be deployed from offshore drilling rigs, this method is more expen-sive than riserless methods. However, the riser effectively extends the wellbore to the surface, which permits engineers to use all light and heavy intervention options available.

To Intervene or Not to InterveneInterventions are an economic choice; operators must balance the cost of the operation against the value of potential additional production. Decisions to intervene may be made as early as the planning stage when, for instance, operators include sliding sleeves in the completion. Or engineers may con-clude that potential secondary zone production justifies installing an intel-ligent well completion equipped with permanent sensors and remotely actuated sliding sleeves that require little or no intervention to reach known reserves behind pipe.

Operators’ decisions are also influenced by new or enhanced interven-tion methods. For example, engineers have developed a slickline that enables digital two-way communication and may be deployed using a stan-dard slickline unit. This digital slickline confirms tool depth and operations as they are performed and allows operators to conduct numerous operations that were at one time available using only heavier and larger wireline units.

The greatest intervention challenges and opportunities are offshore. Recovery from subsea wells is as low as 20% compared with about 50% to 60% from land-based and platform wells. The difference lies in the economic decision-making process. Because subsea well interventions in water depths greater than 400 m must be performed from expensive offshore rigs, expected production gains often do not justify the cost of an intervention. By increas-ing depth capability of much less expensive light interventions, experts believe they can increase deepwater ultimate recovery in some fields by 15% to 30%.

Winter 2014/2015 63

> Riserless light well intervention rig-up. Using a monohull vessel with dynamic positioning capabilities, service providers perform riserless wireline and slickline interventions. A remotely operated vehicle (ROV) may be used to view the operation and to monitor and guide the landing of the well intervention package onto the subsea wellhead. The well intervention package includes the pressure-control hardware and the subsea BOP. A control umbilical allows technicians to manipulate the BOP and subsea tree valves from the surface.

Coiled tubing

Wireline or slickline

Controlumbilical

Wellintervention

package

ROV umbilical

ROV tether

Guidelines

Coiled tubing,slickline or

wireline

Subsea wellhead

Subsea BOP

ROV

72917schD10R1.indd 55 1/20/15 3:13 AM

Oilfield Review Annual Index—Volume 26

ARTICLES

Beyond Deep—The Challenges of Ultradeep WaterCummings R, Garcia C, Hawthorn A, Holicek R, Dribus JR and Haslin L.Vol. 26, no. 4 (Winter 2014/2015): 34–45.

Bioturbation: Reworking Sediments for Better or WorseGingras MK, Pemberton SG and Smith M.Vol. 26, no. 4 (Winter 2014/2015): 46–58.

Cables and Skates— Improving the Weakest LinksBabin C and Sarian S.Vol. 26, no. 4 (Winter 2014/2015): 18–33.

Developing a High-Performance, Oil-Base Fluid for Exploration DrillingFærgestad IM and Strachan CR.Vol. 26, no. 1 (Spring 2014): 26–33.

High-Definition Spectroscopy—Determining Mineralogic ComplexityAboud M, Badry R, Grau J, Herron S, Hamichi F, Horkowitz J, Hemingway J, MacDonald R, Saldungaray P, Stachiw D, Stoller C and Williams RE.Vol. 26, no. 1 (Spring 2014): 34–50.

In Search of Clean, Affordable EnergyBao Z, Benson SM, Cui Y, Dionne JA, Maher K, Boerjan W, Halpin C, Nelson R, Nichols D, Ralph J and Ramakrishnan TS.Vol. 26, no. 1 (Spring 2014): 4–15.

Land Seismic Surveys for Challenging ReservoirsBusanello G, Chen Z, Lei X, Li R, Egan M, Heesom T, Liang B, Lynn HB, Poole A, van Baaren P and Xiao F.Vol. 26, no. 2 (Summer 2014): 32–47.

PDC Bit Technology for the 21st CenturyBruton G, Crockett R, Taylor M, DenBoer D, Lund J, Fleming C, Ford R, Garcia G and White A.Vol. 26, no. 2 (Summer 2014): 48–57.

Perforating Innovations—Shooting Holes in Performance ModelsBaumann C, Fayard A, Grove B, Harvey J, Yang W, Govil A, Martin A, Mendez García RF, Ramirez Rodriguez A, Munro J, Velez Terrazas C and Zahn L.Vol. 26, no. 3 (Autumn 2014): 14–31.

Sealing Fractures: Advances in Lost Circulation Control TreatmentsBaggini Almagro SP, Frates C, Garand J and Meyer A.Vol. 26, no. 3 (Autumn 2014): 4–13.

Shushufindi— Reawakening a GiantBiedma DF, Corbett C, Giraldo F, Lafournère J-P, Marín GA, Navarre PR, Suter A, Villanueva G and Vela I.Vol. 26, no. 3 (Autumn 2014): 42–58.

Step Change in Well Testing OperationsEnnaifer A, Giordano P, Vannuffelen S, Nilssen BA, Nwagbogu I, Sooklal A and Walden C.Vol. 26, no. 3 (Autumn 2014): 32–41.

Ultradeep Scientific Ocean Drilling—Probing the Seismogenic ZoneEguchi N, Moe K, Fukuhara M, Kusaka K, Malinverno A and Tobin H.Vol. 26, no. 2 (Summer 2014): 16–31.

Unlocking the Potential of Unconventional ReservoirsKraemer C, Lecerf B, Peña A, Usoltsev D, Parra P, Valenzuela A and Watkins H.Vol. 26, no. 4 (Winter 2014/2015): 4–17.

Warming to Heavy Oil ProspectsAkram F, Stone T, Bailey WJ, Forbes E, Freeman MA, Law DH-S, Woiceshyn G and Yeung KC.Vol. 26, no. 2 (Summer 2014): 4–15.

Whipstock Options for SidetrackingBruton G, Land J, Moran D, Swadi S, Strachan R and Tørge K.Vol. 26, no. 1 (Spring 2014): 16–25.

EDITORIALS

Arctic Exploration— A Window of OpportunityStachiw D.Vol. 26, no. 1 (Spring 2014): 1.

Deep Water and Ultradeep Water: Managing Complexity Through Integrated Planning and ExecutionGarcia C.Vol. 26, no. 4 (Winter 2014/2015): 1.

Everything We Know, Everywhere You GoStewart L.Vol. 26, no. 3 (Autumn 2014): 1.

DEFINING…INTRODUCING BASIC CONCEPTS OF THE E&P INDUSTRY

Defining Coiled Tubing: Big Reels at the WellsiteVarhaug M.Vol. 26, no. 2 (Summer 2014): 63–64.

Defining Intervention: Upstream Maintenance and Repairvon Flatern R.Vol. 26, no. 4 (Winter 2014/2015): 62–63.

Defining Permeability: Flow Through PoresNolen-Hoeksema R.Vol. 26, no. 3 (Autumn 2014): 63–64.

Defining Reflection Seismic Surveys: A Beginner’s Guide to Seismic Reflections Nolen-Hoeksema R.Vol. 26, no. 1 (Spring 2014): 55–56.

NEW BOOKS

Carbon in Earth: Reviews in Mineralogy & Geochemistry, Volume 75Hazen RM, Jones AP and Baross JA (eds).Vol. 26, no. 4 (Winter 2014/2015): 61.

Climate Forcing of Geological HazardsMcGuire B and Maslin M (eds).Vol. 26, no. 4 (Winter 2014/2015): 61.

Curious: The Desire to Know and Why Your Future Depends on ItLeslie I.Vol. 26, no. 3 (Autumn 2014): 62.

Data Points: Visualization that Means SomethingYau N.Vol. 26, no. 3 (Autumn 2014): 62.

Experimenting on a Small Planet: A Scholarly EntertainmentHay WW.Vol. 26, no. 3 (Autumn 2014): 62.

The Fractalist: Memoir of a Scientific MaverickMandelbrot B.Vol. 26, no. 1 (Spring 2014): 54.

The Lost World of Fossil Lake: Snapshots from Deep TimeGrande L.Vol. 26, no. 2 (Summer 2014): 62.

Novel Science: Fiction and the Invention of Nineteenth Century GeologyBuckland A.Vol. 26, no. 2 (Summer 2014): 62.

On the Frontier of Science: An American Rhetoric of Exploration and ExploitationCeccarelli L.Vol. 26, no. 2 (Summer 2014): 62.

Oxygen: A Four Billion Year HistoryCanfield DE.Vol. 26, no. 2 (Summer 2014): 61.

PaleoclimateBender ML.Vol. 26, no. 2 (Summer 2014): 61.

Practical Applications of Time-Lapse Seismic DataJohnston DH.Vol. 26, no. 4 (Winter 2014/2015): 61.

Radical Abundance: How a Revolution in Nanotechnology Will Change CivilizationDrexler KE.Vol. 26, no. 2 (Summer 2014): 61.

A Short Bright Flash: Augustin Fresnel and the Birth of the Modern LighthouseLevitt T.Vol. 26, no. 1 (Spring 2014): 54.

The Universe Within: Discovering the Common History of Rocks, Planets, and PeopleShubin N.Vol. 26, no. 1 (Spring 2014): 54.

64 Oilfield Review

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15-OR-0001

Oilfield Review AppsThe Schlumberger Oilfield Review app for Android† devices is now available free of charge on the Google Play† store. This new app complements the iPad‡ app, which is available at the Apple‡ iTunes‡ online store. For Android devices, including phones, this is a stand-alone app; accessing content on the iPad and iPhone‡ devices is done through the Newsstand.

Oilfield Review communicates advances in finding and producing hydrocarbons to oilfield professionals. Articles from the journal are augmented on the apps with animations and videos, which help explain concepts and theories beyond the capabilities of static images. The apps also offer access to several years of archived issues in a compact format that retains the high-quality images and content you’ve come to expect from the print version of Oilfield Review.

To download and install the app, search for “Schlumberger Oilfield Review” in the App Store‡ or Google Play online store or scan the QR code below, which will take you directly to the device-specific source.

†Android and Google Play are marks of Google Inc. ‡Apple, App Store, iPad, iPhone and iTunes are marks of Apple Inc., registered in the US and other countries.

Oilfield GlossaryAvailable in English and Spanish, the Oilfield Glossary is a rich accumulation of more than 5,800 definitions from18 industry disciplines. Technical experts have reviewed each definition; photographs, videos and illustrationsenhance many entries. See the Oilfield Glossary at http://www.glossary.oilfield.slb.com/.

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Oilfield Review Apps