Autumn 2012 Oilfield Review

Autumn 2012

Pressure and Sampling in Extreme Conditions

Thermal Properties of Reservoir Rocks

Plate Tectonics in Exploration

Oilfield Review

SChlumbERgER OilfiEld REviEw

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Advances in understanding the dynamics of modern tectonic processes have transformed scientists’ interpretations of ancient tectonic environments and regional deformation regimes and have led to radical conceptual changes about the tectonic evolution of basins in continental, marginal and oceanic environments. These new concepts are making a significant impact on operators’ exploration strategies and on the discovery of hydrocarbon plays in regions that were previously unknown, poorly explored, difficult to access or quickly dismissed. Tectonic insights suggest that there may be significantly more hydrocarbon resources to be found in places that were once deemed valueless (see “Basin to Basin: Plate Tectonics in Exploration,” page 38).

For example, high orogenic plateaus, while typically set in the heart of mountainous regions, are now understood as mosaics of internally drained basins rather than as coales-cent mountain ranges. Dynamic surface processes consisting of erosion, sediment transport and deposition by large rivers interacted with tectonically rising mountain rims to shape the high, flat and smooth morphology of these plateaus. This creates “cold” basins of a novel type, best represented within and to the north of the Tibet plateau. The basins filled rapidly with great thicknesses of Tertiary clastic sedi-ments from internal drainage. The sediments likely host potential reservoirs and seals on top of source rocks in Mesozoic marine and Tertiary lacustrine limestones or shales, adding to new leads in the high plains south of the long-pro-ducing basins in western China.

On the Lebanese stretch of the Levant basin margin, recent seismic and bathymetric offshore surveys, coupled with onshore tectonic studies, have also brought new insight. They show that this passive margin has experienced inverted fold-ing since about 13 Ma. To the west of Mount Lebanon, which rises 4,800 m [15,700 ft] above the Levant basin floor, is a 150-km [93-mi] active thrust fault and an underwater fold-and-thrust belt that deforms Tortonian carbonates, Messinian evaporites and Pliocene-Quaternary turbidites. This subma-rine, thin-skinned, foreland-migrating thrust wedge is worthy of modern exploration. Many structures are sealed by the Messinian salt, which may trap large reservoirs, as it might do elsewhere in the Mediterranean region. Since 2009, discover-ies of large gas accumulations in subsalt Miocene strata off-shore Israel and Cyprus have demonstrated the importance of the Levant basin for significant natural gas resources.

In the early opening stages of both the Cretaceous South Atlantic and the Miocene Red Sea, thick salt deposition was controlled by a peculiar tectonic framework in which the marine environment was restricted between fissural “flood-gates” formed through volcanism and transform faulting. Much of the evaporitic deposition likely resulted from

Frontier Hydrocarbon Exploration: The Importance of Tectonic Models

1

precipitation in deep sags above oceanic crust during sea-floor spreading, a characteristic once attributed to hyperex-tended continental crust. The existence of the Red Sea central trough, Angola escarpment and São Paulo plateau are most easily accounted for by incorporating seafloor spreading in the early evolution of the margins. The flood-gate models may preclude simple extrapolation of onshore or shallow near-shore stratigraphy far beneath the deep salt. However, the existence of deep offshore hydrocarbon plays in a still largely unexplored environment was proved in 2007 by the discovery of the presalt Lula—formerly Tupi—oil field in the Santos basin offshore Brazil and by the discover-ies in 2012 of the presalt Azul and Cameia oil accumulations in the Kwanza basin offshore Angola.

The odds are that vast oil reserves exist on top of the deep basaltic seafloor. Thick salt forming in a restricted anoxic environment resulting from tectonic activity is the key; the presence of prerift or synrift source rocks might not be required. The North American and West African margins of the central Atlantic also may harbor such plays, sealed deep beneath thick salt. Scientists will gain a better understanding of these phenomena by developing tectonic models with overlapping spreading centers that isolate continental slivers rather than models that rely merely on crustal hyperextension.

In understanding the tectonic evolution of basins, geo-scientists may change classic perspectives and develop new paradigms for oil and gas exploration. The most important lessons from tectonic studies are that no envi-ronment should be considered beyond the bounds of explo-ration and that current models should be revisited. It seems certain that coherent, dynamic tectonic models, based on the well-constrained kinematics of active analogs, will be essential to the future of hydrocarbon exploration.

Paul TapponnierProfessor and Group Leader, Tectonics and Earthquakes GroupNanyang Technological UniversitySingapore

Paul Tapponnier is Professor and Group Leader of the Tectonics and Earthquakes Group at the Earth Observatory of Singapore at the Nanyang Technological University in Singapore, where he has worked since 2009. Previously, he worked at the Tectonique, Mécanique de la Lithosphère group at the Institut de Physique du Globe de Paris. His contributions to geology, tectonics and geophysics span more than 40 years and his research inter-ests include continental dynamics and tectonics, particularly in Asia and the Mediterranean region; active faulting and seismotectonics; earthquake hazard assessment; quantitative geomorphology; rates of active deformation processes; and rock mechanics and rock deformation physics. He is a member of both the French and US National Academy of Sciences and a Fellow of the American Geophysical Union, Geological Society of America and Geological Society of London. Paul holds an ingénieur des mines degree from Ecole Nationale Supérieure des Mines de Paris and a doctorat d’etat degree from Université Montpellier 2 Sciences et Techniques, France.

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www.slb.com/oilfieldreview

Schlumberger

Oilfield Review1 Frontier Hydrocarbon Exploration: The Importance of Tectonic Models

Editorial contributed by Paul Tapponnier, Professor and Group Leader, Tectonics and Earthquakes Group, Nanyang Technological University

4 Testing the Limits in Extreme Well Conditions

High-temperature wells pose challenges for design engineers who develop pressure and sampling tools. In addition to pressure and sampling tools, downhole pressure gauges used in long duration tests must be designed to operate for extended periods with few options to protect sensitive elec-tronics from heat. High-pressure wells present a different but equally daunting set of challenges. Case studies from the North Sea, Thailand and India demonstrate how recent innovations are overcoming these challenges.

Oilfield Review AUTUMN 12HPHT Fig. 7BORAUT 12-HPHT 7B

20 When Rocks Get Hot: Thermal Properties of Reservoir Rocks

More than half of the oil produced worldwide by enhanced recovery methods is a result of thermal stimulation. Decisions on project economics may hinge on long-term forecasts of the amount of additional oil that can be liberated from the reservoir by injected heat. Although accurate fore-casts usually require accurate knowledge of the thermal properties of the reservoir fluids and rocks, these properties of reservoir rocks are rarely measured. This article reviews rock thermal property measurements and describes an effi-cient new optical technique for obtaining them.

Executive EditorLisa Stewart

Senior EditorsMatt VarhaugRick von Flatern

EditorsRichard Nolen-Hoeksema Tony Smithson

Contributing EditorsGinger OppenheimerMichael OristaglioRana Rottenberg

Design/ProductionHerring DesignMike Messinger

Illustration Chris LockwoodTom McNeffMike MessingerGeorge Stewart

PrintingRR Donnelley—Wetmore PlantCurtis Weeks

Oilfield Review is published quarterly and printed in the USA.

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

© 2012 Schlumberger. All rights reserved. Reproductions without permission are strictly prohibited.

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

About Oilfield ReviewOilfield Review, a Schlumberger journal, communicates technical advances in finding and producing hydrocarbons to employees, clients 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:

Seismic data, shown in the background, are crucial inputs to exploration work-flows. Seismic techniques help identify subsurface structures that may trap and accumulate hydrocarbons. In this case, interpretation of seismic data from off-shore Angola reveals the presence of walls of Aptian salt (purple and white), minibasins for sediment deposition and overhangs that may serve as traps. The Aptian salt is a regional seal for presalt reservoirs. (Background data courtesy of TGS and WesternGeco. Image courtesy of Sonangol EP and WesternGeco.)

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Autumn 2012Volume 24Number 3

ISSN 0923-1730

58 Contributors

60 New Books and Coming in Oilfield Review

63 Defining Porosity: How Porosity Is Measured

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

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38 Basin to Basin: Plate Tectonics in Exploration

Exploration companies have recently made several large discoveries in rifted and transform margin systems. The plays they proved on one continent have been applied across the Atlantic Ocean—from South America to Africa—and back. This article explains how geoscientists are using plate tectonics to uncover plays in rifted and transform margin systems.

Gretchen M. Gillis Aramco Services Company Houston, Texas, USA

Roland Hamp Woodside Energy Ltd. Perth, Australia

Dilip M. Kale ONGC Energy Centre Delhi, India

George King Apache Corporation Houston, Texas

Alexander Zazovsky Chevron Houston, Texas

Advisory Panel

Editorial correspondenceOilfield Review 5599 San Felipe Houston, Texas 77056 USA(1) 713-513-1194Fax: (1) 713-513-2057E-mail: [email protected]

SubscriptionsClient subscriptions can be obtained through any Schlumberger sales office. Paid subscriptions are available fromOilfield Review ServicesPear Tree Cottage, Kelsall RoadAshton Hayes, Chester CH3 8BH UKFax: (44) 1829 759163E-mail: [email protected]

Distribution inquiriesTony SmithsonOilfield Review12149 Lakeview Manor Dr.Northport, Alabama 35475 USA(1) 832-886-5217Fax: (1) 281-285-0065E-mail: [email protected]

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4 Oilfield Review

Testing the Limits in ExtremeWell Conditions

High borehole temperatures and pressures pose design challenges for engineers

developing formation evaluation tools. Pressure and sampling tools that use motors

and pumps require high power to operate and often generate considerably more heat

than tools used for basic petrophysical measurements. Traditional solutions to

combat temperature and pressure are insufficient for these types of tools. Recent

innovations make it possible to obtain downhole pressure measurements and

samples and to perform extended well tests in extreme conditions.

Chris AvantSaifon DaungkaewBangkok, Thailand

Bijaya K. BeheraPandit Deendayal Petroleum UniversityGandhinagar, Gujarat, India

Supamittra DanpanichWaranon LaprabangPTT Exploration and ProductionPublic Company LimitedBangkok, Thailand

Ilaria De SantoAberdeen, Scotland

Greg HeathKamal OsmanChevron Thailand Exploration and Production LtdBangkok, Thailand

Zuber A. KhanGujarat State Petroleum Corporation LtdGandhinagar, Gujarat, India

Jay RussellHouston, Texas, USA

Paul SimsDar es Salaam, Tanzania

Miroslav SlapalMoscow, Russia

Chris TevisSugar Land, Texas

Oilfield Review Autumn 2012: 24, no. 3. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Renato Barbedo, Ravenna, Italy; Larry Bernard, Jean-Marc Follini, David Harrison and Steve Young, Houston; Libby Covington, Simmons & Company International, Houston; Alan Dick, Simmons & Company International, Aberdeen; Eduardo Granados, Richmond, California, USA; Khedher Mellah, Chevron, Houston; and Sophie Salvadori Velu, Clamart, France.InSitu Density, MDT, MDT Forte, MDT Forte-HT, PressureXpress, PressureXpress-HT, Quicksilver Probe, Signature, SRFT and Xtreme are marks of Schlumberger.INCONEL is a registered trademark of Special Metals Corporation.Quartzdyne is a registered trademark of Dover Corporation.

Many E&P companies are drilling wells in envi-ronments that push the limits of equipment and services as they search for new sources of oil and gas. Operators are looking in places where few have ventured or that not so long ago were con-sidered impractical. The depths they are now probing tend to be hotter and higher pressured than ever before and often exhibit extreme well conditions that test the limits of downhole tools and equipment.

Service companies continue developing solu-tions to contend with extreme well conditions; however, certain situations present particular problems for downhole tool developers.1 For instance, applications such as acquiring forma-tion pressures and fluid samples and performing extended downhole pressure tests require tools that are designed to overcome more than heat and pressure, which is a difficult feat. These tools must also deal with time as it relates to internally generated heat and the challenges of long expo-sure to potentially destructive conditions.

Pressure and sampling tools utilize motors that require high power; these motors generate heat that is trapped inside the tool. To acquire pressure measurements and formation fluid sam-ples, these tools may have to remain stationary for long periods of exposure to heat and pressure. These tools have pressure gauges and sensors that must remain stable at high operating tempera-tures while retaining their measurement preci-sion. Other uses for pressure gauges may require

that they remain downhole for hours, even days, constantly exposed to extreme conditions. Many methods traditionally employed to withstand high wellbore temperatures are ineffective in these instances.

This article reviews two pressure and sam-pling tools that require high power to operate and were engineered to withstand high-pressure, high-temperature (HPHT) operating environ-ments. In addition, a recently introduced down-hole pressure gauge has been proved to operate for many hours at high temperature. Case studies from the North Sea, Thailand and India demon-strate the application of these advances.

A Niche Market That MattersHostile environments are typically character-ized as having HPHT conditions. HPHT wells will generally cross thresholds of either tem-perature or pressure, but few wells cross both. However, the term HPHT is applied to any well that is considered hot or high pressured. Various criteria are used within the oil and gas industry to define “high,” although there is no widely accepted industry standard. Whichever criteria are used, the majority of wells drilled today are not extreme, being neither high pressure nor high temperature.

Approximately 107,000 oil and gas wells will be drilled worldwide in 2012.2 A study conducted by engineers at Schlumberger esti-mates approximately 1,600 of these wells will be

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Autumn 2012 55

1. For solutions available in extreme operating conditions: DeBruijn G, Skeates C, Greenaway R, Harrison D,

Parris M, James S, Mueller F, Ray S, Riding M, Temple L and Wutherich K: “High-Pressure, High-Temperature Technologies,” Oilfield Review 20, no. 3 (Autumn 2008): 46–60.

Chan KS, Choudhary S, Mohsen AHA, Samuel M, Delabroy L, Flores JC, Fraser G, Fu D, Gurmen MN, Kandle JR, Madsen SM, Mueller F, Mullen KT, Nasr-El-Din HA, O’Leary J, Xiao Z and Yamilov RR:

“Oilfield Chemistry at Thermal Extremes,” Oilfield Review 18, no. 3 (Autumn 2006): 4–17.

Adamson K, Birch G, Gao E, Hand S, Macdonald C, Mack D and Quadri A: “High-Pressure, High-Temperature Well Construction,” Oilfield Review 10, no. 2 (Summer 1998): 36–49.

Baird T, Fields T, Drummond R, Mathison D, Langseth B, Martin A and Silipigno L: “High-Pressure, High-Temperature Well Logging, Perforating and Testing,” Oilfield Review 10, no. 2 (Summer 1998): 50–67.

2. “Special Focus: 2012 Forecast—International Drilling and Production. Global Drilling Remains Consistently Strong,” World Oil 233, no. 2 (February 2012): 43–46.

“Special Focus: 2012 Forecast—U.S. Drilling. Growth Amidst Economic and Regulatory Turbulence,” World Oil 233, no. 2 (February 2012): 67–72.

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6 Oilfield Review

Oilfield Review AUTUMN 12HPHT Fig. 1ORAUT 12-HPHT 1

Rese

rvoi

r tem

pera

ture

, °F

Reservoir pressure, psi

HPHT Wells Drilled 2007 to 2010 Worldwide

Well

High temperature

High pressure

250

1500 5,000 10,000 20,000 30,000 35,00015,000 25,000

350

450

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classified as HPHT wells, representing about 1.5% of the worldwide total. Most of the wells consid-ered HPHT exceed established temperature limits; only a few wells exhibit truly extreme pressures (left). The study also indicated that the HPHT market is heavily dominated by two coun-tries: the US (60%) and Thailand (20%) (below).

One caveat to consider in this analysis is that geothermal wells are not included in the totals. Because of their extremely high bottomhole tem-peratures, geothermal wells present operational complexities rarely encountered in oil and gas exploration.3 Moreover, the number of geother-mal wells is small compared with the number of their oil and gas counterparts.

The HPHT market may currently be relatively small, but there is an industry-recognized accel-eration in the number of extreme wells being drilled and planned. For example, according to one report covering extreme wells drilled off-shore, during the 30-year period from 1982 to 2012, operators drilled 415 HPHT offshore wells

> Extreme temperature or pressure. Schlumberger engineers conducted an internal study of temperature and pressure data from wells worldwide. Over a four-year period, no wells exceeded both high-temperature (350°F [177°C]) and high-pressure (20,000 psi [138 MPa]) limits, which are commonly used for wireline logging tools. Many wells exhibiting extremely high pressure do not exhibit high temperature, and vice versa. In addition, more wells exceeded the 350°F temperature than exceeded 20,000 psi.

Significant high-temperature activityPotential for high-temperature activityGeothermal activity


> Drilling activity in high-temperature environments. Exploration and development drilling in high-temperature environments is regionally isolated. The majority of extreme wells are located on land, although there is significant activity in the Gulf of Mexico, the North Sea and offshore India and Southeast Asia. The number of geothermal wells, which represent the high end of extreme temperatures, is not statistically significant.

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Autumn 2012 7

worldwide (above).4 The forecast for the four-year period ending in 2016 anticipates that the total will be doubled, with the region off the coast of Brazil alone adding more than 238 deep wells by 2016. By 2020, the total number of offshore HPHT wells is projected to exceed 1,200—tripling the total number of extreme offshore wells in just 10 years. The analysis highlights the need in the coming decade for equipment to address these HPHT operating conditions. The problem with such analyses, however, is that the results depend on the user’s definition of HPHT.

A Matter of SemanticsOperators and service companies often use vary-ing criteria for classification of HPHT wells. Operators contend with the effects of pressure and temperature on drilling, well construction and surface equipment; service companies often focus on how those conditions affect their prod-ucts, equipment and services. Although the dis-tinction may appear subtle, the engineering design approach often differs.

In an effort to resolve some of the confusion, the API recently published recommendations for equipment used in HPHT wells, which were defined as those with pressure greater than 15,000 psi [103 MPa] and temperature above 350°F.5 The recommendations apply primarily to engineering standards related to design speci-fications of equipment, acceptable materials and testing of well control equipment and com-pletion hardware.

The report includes design verification and validation, material selection and manufacturing process controls, which are intended to ensure that equipment used in the oil and gas industry is fit for service in HPHT environments. The three criteria for HPHT classification are the following: • anticipated surface conditions that dictate

completion and well control equipment rated above 15,000 psi

• anticipated shut-in surface pressure in excess of 15,000 psi

• flowing temperature at the surface in excess of 350°F.

If any one of these conditions is met, the well is considered an HPHT well. Although the report establishes specific guidelines for defining HPHT and provides protocols for certifying equipment, it does not specifically address downhole elec-tronics or certification of downhole tools.

In an attempt to define thresholds that reflect physical and technological limitations, Schlumberger developed an HPHT classification system representing stability limits of common

3. A recent study estimates that approximately 4,000 geothermal wells had been drilled through 2011. Sanyal SK and Morrow JW: “Success and the Learning Curve Effect in Geothermal Well Drilling—A Worldwide Survey,” paper SGP-TR-194, presented at the 37th Workshop on Geothermal Reservoir Engineering, Stanford, California, USA, January 30–February 1, 2012.

4. These findings were noted in the Simmons & Company International Limited 2012 analysis prepared for Quest Energy. For the report, HPHT was defined as conditions greater than 10,000 psi [69 MPa] and 300°F [150°C]. The number of land-based HPHT wells drilled during the period was much higher than that of those drilled offshore.

5. API: “Protocol for Verification and Validation of HPHT Equipment,” Washington, DC: API, Technical Report PER15K-1, 1st ed., 2012.

97

238

18

14

13

17

0

0

36

90

290

10

16

3

10

26

16

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4

0


415 Drilled through 2011

Projected from 2012 through 2015433

Projected from 2016 through 2020483

Gulf of Mexico

West AfricaSoutheast Asia

Australia

Norwegian North Sea

Mediterranean Sea

North Sea

Caspian Sea

Brazil

Offshore HPHT Wells

Wells

> Offshore HPHT activity. HPHT drilling activity is projected to accelerate in the coming years, especially offshore. In the next four years, the number of offshore HPHT wells (green) is expected to be more than double the total drilled in the preceding three decades (blue). By the year 2020 (pink), the well count is projected to triple. (Adapted from Simmons & Company International Limited, reference 4. Used with permission.)

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8 Oilfield Review

components such as elastomeric seals and elec-tronics (above).6 Other service companies and operators use their own definitions, which are similar to the Schlumberger guidelines.

A Niche in Design The well type—HP or HT—dictates the engi-neering design approach because techniques used for contending with pressure differ from those for temperature. For pressure, the solution is often to design equipment with sealing ele-ments capable of withstanding extreme forces. Exposed surfaces may be at risk, but internal

electronics are protected, barring a seal failure, which would be catastrophic should failure occur (below left).

Protecting sensitive downhole electronics from extreme temperatures, however, usually relies on sheltering sensitive components from the cumulative effects of exposure to heat. This is most often accomplished using thermal barriers in the form of flasks—double-insulated metal housings—that protect electronic components long enough for data acquisition and other operations to be performed (below right). Flasks are constructed to have extremely low thermal

conductivity and thermal diffusivity to ensure that the temperature inside the housing rises very slowly.

Flasks have become an integral component in tools such as the Schlumberger suite of Xtreme tools, designed for HPHT environments.7 The Xtreme platform includes common measure-ments for petrophysical analysis. Unfortunately, the solution for keeping electronics protected from wellbore heat traps self-generated heat inside the tool housings. This heat can push internal temperatures well beyond a tool’s ther-mal rating. Logging engineers monitor both time and temperature to avoid potentially catastrophic tool failure related to temperature when using flasks in HPHT environments.

Tools that employ high-powered downhole motors and pumps, such as pressure and sam-pling tools, are examples of tools that generate considerable heat—much greater than most other evaluation tools. The thermal loads gener-ated by these tools can quickly raise the tempera-ture inside a flask above the rating of the electronic components. Thus, flasking alone may not provide sufficient operating time to complete the required task when these high-power, high heat–generating tools are used.

Tools that do not generate excessive heat and have low power consumption, such as downhole pressure gauges, may be used to collect data for many hours, even days, in extreme conditions.

> HPHT classification system. This classification system was proposed by Schlumberger engineers and is based on pressure and temperature boundaries that represent stability limits of common components used by service companies. These include electronic devices and sealing elements. The HPHT-hc classification defines environments that are unlikely to be seen in oil and gas wells, although there are geothermal wells that exceed 500°F.


0

100

200

300

400

500

600

40,00035,00030,00025,00020,000

Static reservoir pressure, psi15,00010,0005,0000

Stat

ic re

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oir t

empe

ratu

re, °

F

150°C

69 M

Pa

138

MPa

241

MPa

HPHT

Ultra-HPHT

HPHT-hc

205°C

260°C

> The results of failure. This tool failed when exposed to pressures only slightly above its rating. The failure was initiated at the threaded-ring connection, where the pressure seal was most vulnerable. The result was a catastrophic loss of the tools above and below the failure caused by the sudden inrush of drilling mud from the wellbore.

Oilfield Review AUTUMN 12 HPHT Fig. 5ORAUT 12-HPHT 5

2.50 cm > Flasks for thermal barriers. The most common method of protecting sensitive electronics from extreme heat is to use a Dewar flask (top). The flask (bottom) consists of a glass liner inside a metal housing that serves as a vacuum layer; the glass and air are poor heat conductors. Thermal insulators at each end isolate the electronics section. Internally generated heat from the electronic components is trapped inside the tool and can cause the tool to overheat.


Electronics

Vacuum layer

Thermal insulators

Dewar flask

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Autumn 2012 9

For long-duration measurements in HPHT wells, flasks are not a solution for these types of tools.

For solutions to address self-generated heat or extended operations in high-temperature environments, design engineers often focus on the circuit boards. By maximizing efficiency, ana-lyzing the heat generated by electronic compo-nents and, wherever possible, employing components that have above-average tempera-ture ratings, engineers can extend the time avail-able for tools to operate and acquire data downhole (above).

Sourcing components that withstand high

temperatures has become increasingly difficult. The electronics industry is driven by consumer products that use plastic electronic components that are not rated for use in even moderately high-temperature conditions, for instance above 125°C [257°F]. Plastic components are often composed of silicon chips, or dies, enveloped in a plastic overpack. These components cannot withstand the rigors of extreme environments because the overpack fails first from tempera-ture effects, although the underlying electronic component may not have failed. In addition, manufacturers treat plastic electronic compo-nents with flame retardant chemicals, which

6. DeBruijnetal,reference1.7. FormoreonXtremeloggingtools:DeBruijnetal,

reference1.

contain volatile compounds that are released at elevated temperatures. These chemicals are highly corrosive.

For high-temperature environments, design engineers at Schlumberger have learned to elim-inate plastic overpacks and use only the silicon chips. These chips and other components are attached directly to heat-tolerant ceramic multi-layered circuit boards; the connecting wires have the diameter of a human hair (below). In some cases, engineers have created proprietary

> Thermalimaging.Infraredimagesreveallocalizedhotspotsandoverloadedelectroniccomponents(left).Identicalcomponentsonacircuitboard(right)maynothavethesameloading.Largeloadingdifferencesmaybeidentifiedusingthermalimagingandmayrequirecircuitboardredesign.Solutionsincludechangingthelayouttoredistributetheloadorinstallingheatsinkstodrawheatawayfromtargetareas.


Thermal Hot Spots Unbalanced Loading

Temperature, °C24 26 28 30 32 34 36 38 40 42 44 46 48

> Designedforextremes.Toensuretoolsareabletooperateunderextremetemperatures,engineersusecomponentsthatrelyontheunderlyingceramicandmetal(center)withouttheplasticoverwrapcommonlyusedinconsumerelectronics.Ceramiccomponentsmaybecombinedinmultichipmodules(MCMs)(left).Componentreliabilitycanalsobeimprovedwithmanufacturingtechniquessuchastheuseoflow-massconnections(right),someofwhicharesimilarinthicknesstoahumanhair.


×65

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10 Oilfield Review

dies that are programmed and packaged for spe-cific applications and built to high-temperature specifications that exceed those readily available in the commercial marketplace.

Extensive analysis of failed electronic compo-nents has resulted in other design innovations. The failure of electronic components may occur at elevated temperatures; however, the actual failure mode is often traced to mechanical break-downs (above). The two most common causes of mechanical failure are corrosion and vibration.

Corrosion can be problematic because high temperatures accelerate chemical corrosivity, especially that resulting from humidity and vola-tilized gases from products used in the manufac-ture of circuit boards. Where space permits, desiccants are inserted in tool housings to absorb volatilized chemicals and moisture.

Techniques to extend operability time miti-gate the effects of high temperature, but such techniques only extend the time available for tools to operate at elevated temperatures. Similarly, shock and vibration cannot be elimi-nated, but better tool designs can improve the mechanical integrity of connections and compo-nents. Attaching circuit boards to specially designed mounting rails and shock absorbers can improve tool reliability. Once the designs are finalized, thorough and rigorous testing, using both thermal and mechanical loads, validates the

design effectiveness or identifies weaknesses that can then be rectified.

Engineered for ExtremesThe MDT modular formation dynamics tester has been an industry standard for fluid sampling since its introduction in 1989. Through the decades, an extensive array of sampling and downhole analy-sis tools has been added to the basic platform. Along with new features and services, several modifications have been implemented to improve the tool’s reliability and performance; however, the basic design and layout of the tool electronics and hardware have not changed.

In the years since the MDT tool was intro-duced, Schlumberger engineers have been designing tools to withstand high levels of shock and vibration—the primary sources of most elec-tronic component failures. Much of the impetus for establishing higher standards came from requirements for LWD tools, which operate in extremely harsh conditions. Design engineers have integrated techniques developed for LWD tools in wireline tools, and new designs of wire-line tools are qualified to LWD standards when-ever possible.

To pass these new qualification standards, the MDT tool could not simply be upgraded but required a full redesign. This newly designed tool was introduced as the MDT Forte rugged modular

formation dynamics tester. The electronics sys-tems for the MDT Forte tool were completely reconfigured and mounted on a ruggedized chas-sis (next page, top). Engineers then subjected the new design to a rigorous qualification process.

The temperature qualification process of the MDT Forte platform consisted of thermal aging of components, thermal cycling from –40°C to 200°C [–40°F to 392°F] and cold storage at –55°C [–67°F]. Shock and vibration qualification included thousands of shocks on individual cir-cuit boards, which were administered on differ-ent axes by rotating the boards in the test facility. Vibration testing of the boards included 10- to 450-Hz sweeps. Engineers also performed pres-sure cycling, vibration transmissibility and trans-verse shock transmissibility testing. After qualifying the boards, they conducted tempera-ture and shock qualification on full tool assem-blies. They also performed extended low- and high-temperature operations, including operation at 210°C [410°F] for 100 h while administering shocks to the tool assembly (next page, bottom).

These tests confirmed the new design could withstand mechanical shock and vibration in addition to thermal shocks, thereby meeting qual-ification standards that previous-generation tools could not. The temperature and pressure ratings of the MDT Forte tool are 177°C [350°F] and 172 MPa [25,000 psi].

> Electronic component failure mode. When electronic components fail, the mode can often be traced to mechanical failure from shock and vibration. Cracks may form at connections (left) that eventually break under repeated loading. In the sealed environments of logging tools, corrosive chemicals may be released from circuit boards and other components. At elevated temperatures, the corrosivity of these chemicals is accelerated, which causes damage to sensitive electronics (top right). If the tools are opened for maintenance and repair, moisture in the air may also become a problem. When space is available, desiccants can be used inside tool housings, protecting electronics from corrosion by absorbing humidity and volatilized chemicals (bottom right).


Seven Days at 150°C with Desiccant

Seven Days at 150°C Without Desiccant

×1,000

×200

×50

Cracked wedge

Broken wedge

54401schD3R1.indd 10 12/3/12 8:42 PM

Autumn 2012 11

Design engineers next focused on developing a tool with the improved reliability of the MDT Forte tool that could also withstand higher temperatures and pressures. The result is the MDT Forte-HT rugged high-temperature version, which is rated to 204°C [400°F] and 207 MPa [30,000 psi].

To meet the 207-MPa pressure rating of the MDT Forte-HT tools, engineers employed innova-tive sealing technology that incorporates carbon

nanotubes in the O-ring seals. The structure of these sealing elements provides strength to with-stand downhole effects such as temperature deg-radation and rapid gas decompression during operations. The seals, which provide sample assurance that is not possible with conventional elastomers, retain full high-pressure capability even at low subsea temperatures routinely expe-rienced in deepwater environments while run-ning in the well.

Engineers also upgraded the pressure gauge used for the MDT tool by adding a new-generation quartz gauge qualified to 207 MPa and 200°C for 100 h. A high-temperature InSitu Density reser-voir fluid density sensor, which monitors fluid density and helps improve fluid sample quality, was developed and placed in the flowline. The fluid density measurement provides the ability to identify compositional grading and fluid gradients at HPHT conditions—the first time

>Making tools stronger and better. Older tool designs, like those of early generation MDT tools (left), used discrete components and circuit boards attached to a central mandrel. These designs have been replaced by boards rigidly mounted to solid rails, such as those used in the MDT Forte tool (right). This approach isolates sensitive electronics from shock and vibration and also helps dissipate heat. Many of the design changes have been introduced from lessons learned developing LWD tools; newer generation tools are designed to pass LWD shock and vibration standards whenever possible.


Original Design Redesign

> Proof of concept. The MDT Forte tool platform (bottom) was designed to pass shock and vibration standards similar to those for LWD tools. Tool qualification using the laboratory equipment shown (top left) cycles the tool through temperature variations while subjecting the tool to repeated mechanical shocks. The test cycle (top right), which is just one of many, elevates the temperature to the tool limit and holds it for 50 h. The tool is allowed to return to ambient conditions and subjected to fifty 250-gn shocks on four axes. The cycle is then repeated. These tests help identify design weaknesses as well as validate design concepts.


Ambienttemperature

400°F

75% power load

Shock test Shock test Shock test

75%powerload

45 h 5 h 45 h 5 h75%powerload

100%powerload

100%powerload

50 h 50 h 50 h

54401schD3R1.indd 11 12/3/12 8:43 PM

12 Oilfield Review

these measurements have been available in these environments.

For the MDT Forte-HT version, the dual-packer module was also upgraded to 210°C. This module uses sealing elements above and below the zone of interest to isolate formations for sampling (left). The inflatable packer elements isolate an interval from 1 to 3.4 m [3.3 to 11.2 ft] in length.

The pumpout module presented one of the most challenging aspects of upgrading the MDT tools to the higher temperature and pres-sure ratings. The pumpout module is important for ensuring a reliable sample of formation fluid. It uses a positive displacement pump to transfer formation fluids that may be contaminated with drilling mud filtrate into the wellbore until the sample stream is free of impurities. When the quality of the stream is acceptable, samples are taken and recovered for analysis.

Four new pumpout displacement units are now available to meet a range of specifications, from a standard version to an extra, extra high-pressure version (below left). Engineers designed the new pump to operate more efficiently—to generate less heat, resist plugging and handle mud solids more effectively. The increased flow area of the new pump decreases O-ring erosion and delivers better sand-handling capabilities. The pumpout modules are compatible with the Quicksilver Probe device.8

Meeting the Sampling ChallengeThe challenge of taking samples and pressures in HPHT conditions extends beyond simply being able to acquire fluids or pressure data. The sam-pling time must be minimized to avoid tool dam-age from both internally generated heat and external heat exposure; however, the sample must be as free of contamination as possible to ensure that the fluids collected by the tool and analyzed in the laboratory are representative of the formation fluids. In a recent test, a North Sea operator successfully ran an MDT Forte-HT tool-string that included two pumpout tools, a Quicksilver Probe assembly and downhole fluid analysis modules.

The well was drilled with oil-base mud (OBM) into a reservoir with pressures in excess of 17,000 psi [117 MPa]. Along with high downhole pressures, the operator faced bottomhole tem-peratures ranging from 347°F to 370°F [175°C to 188°C]. Sample quality was crucial for accurately characterizing the reservoir fluids, but the high temperatures limited the time available for sam-pling. Samples had to be taken quickly, yet fluids needed to flow long enough to minimize OBM filtrate contamination.

>MDT Forte-HT tool additions. Engineers designed modules and tools to complement the new higher temperature rating of the MDT Forte-HT tool- string. This inflatable fullbore packer withstands temperatures up to 210°C.


Upgraded Inflatable Packer

>MDT pumpout module options.

Oilfield Review AUTUMN 12HPHT Table 1ORAUT 12-HPHT Tab 1

Standard tool

Volume/stroke,cm3 [in.3]

485 [30] 366 [22] 177 [11] 115 [7]

32 [4,641] 42 [6,092] 58 [8,412] 81 [11,748]

8.2 to 32.8[0.5 to 2]

6.3 to 24.6[0.4 to 1.5]

4.4 to 18.3[0.3 to 1.1]

0.8 to 16[0.05 to 1]

Pump flow rate,cm3/s [in.3/s]

Maximum differentialpressure, MPa [psi]

High-pressure tool

Pumpout Module Displacement Units

Extra high-pressure tool Extra, extra high-pressure tool

54401schD3R1.indd 12 12/3/12 8:43 PM

Autumn 2012 13

The presence of OBM filtrate affects labora-tory analysis of reservoir fluids and may distort H2S measurements because the filtrate may scav-enge H2S from reservoir fluids. Sample quality and reliability of the fluid property measure-ments are improved when engineers, using the pumpout module, first remove fluids contami-nated with filtrate. The Quicksilver Probe device, which uses a focused sampling technique, greatly decreases the time required to remove contami-nated fluids and reach acceptable purity levels, cutting sampling time by as much as half com-pared with the time required for sampling with conventional probes.

For the well in question, the North Sea opera-tor collected several high-quality PVT samples in a single trip (above). Filtrate contamination for all samples was 2% or lower. Downhole fluid anal-ysis provided fluid composition, CO2 content, GOR and fluorescence.

Because H2S was a concern for the operator, the MDT tool was configured for reverse low-shock sampling. This technique helps minimize the scavenging of H2S by tool hardware and by OBM filtrate. The low-shock sampling technique holds the pressure in the piston chambers of the pumpout module near that of the borehole pressure, minimizing the drawdown pressure during sampling. The technique produces better

results than those that draw formation fluid into chambers at atmospheric pressure. Reverse low-shock sampling routes fluid directly into sample bottles without passing it through the pumpout module. This technique reduces the opportunity for metal hardware to scavenge H2S, although additional precautions are taken to minimize scavenging, including replacing exposed parts with INCONEL alloys and coating

8. FormoreontheQuicksilverProbedevice:AkkurtR,BowcockM,DaviesJ,DelCampoC,HillB,JoshiS,KunduD,KumarS,O’KeefeM,SamirM,TarvinJ,WeinheberP,WilliamsSandZeybekM:“FocusingonDownholeFluidSamplingandAnalysis,”Oilfield Review18,no.4(Winter2006/2007):4–19.

> Qualitysamplingatextremeconditions.Usingareverselow-shocksamplingtechnique,aNorthSeaoperatorwasabletoidentifyfluidcontactsandfluidcompositioninwellboreconditionsapproaching370°FwiththeMDTForte-HTtool.SampleswereacquiredwiththeQuicksilverProbeassembly,andthefiltratecontaminationwaslessthan2%.TheoperatorwasinterestedinCO2content(Track1,purple,top),whichwasavailableinthefluidcompositionanalysis.AwatercontactcanbeidentifiedbythebluecolorinthecompositiontrackatStation5.Duringthetimeintervalshowninthesamplingplot(center),flowconsistedofhydrocarbonswithatraceofCO2.ThechangeinGOR(green,bottom)at2,750swasassociatedwithashiftindirectionofthereverselow-shocksampling.AccurateH2Scontentwasmeasuredintheflowingstreamusingspeciallydesignedcoupons.ThelowlevelsofOBMfiltrateresultedinsamplesthatwereunalteredbyfiltratecontamination,andreverselow-shocksamplingminimizedscavengingofH2Sbymetalcomponentsofthetool.


YY,000

XX,000

GOR

20406080

100

0

ft3 /bb

lFlu

id co

mpo

sitio

n, %

Dept

h

CO2 C1 C2 C3–5 C6+

Elapsed time, s2,500 3,500 4,500 5,5003,000 4,000 5,0002,000

Elapsed time, s2,500 3,500 4,500 5,5003,000 4,000 5,0002,000

Fluid Composition Pressure GOR Mobility

psi ft3/bbl mD/cPXX,000 YY,000 0.2 2,000CO2 C1 C2 C3–5 C6+

Station 1

Station 2

Station 3

Station 4

Station 5

54401schD3R1.indd 13 12/3/12 8:43 PM

14 Oilfield Review

parts with compounds that inhibit H2S adsorption. Specially designed metal strips—coupons—that detect H2S concentrations were included in the tool flowlines.

The fluid properties, measured downhole in extreme pressure and temperature conditions,

were confirmed by laboratory analysis. Combined with a Quicksilver Probe assembly, the MDT Forte-HT tool met the operator’s sampling objec-tives of obtaining uncontaminated reservoir fluid, determining CO2 concentration and detecting H2S.

Reservoir Pressure OnlyOperators cannot always acquire fluid samples or perform complex downhole fluid analyses, nor do they always need to. These tasks are especially problematic in low-permeability formations in which fluid samples may be difficult to obtain or long sampling times are required. However, accu-rate pressure and fluid mobility data are important for understanding these reservoirs.9 These data are especially crucial for establishing fluid gradi-ents and identifying fluid contacts. Engineers at Schlumberger developed the PressureXpress res-ervoir pressure while logging service, which typi-cally measures downhole pressure and mobility in less than a minute, to address situations in which pressure data alone may be sufficient.

The speed with which this service delivers multiple measurements greatly improves the like-lihood of successful operations at elevated tem-peratures, although the original tool is rated for only 150°C [300°F]. The lower temperature rating and absence of a flask to protect sensitive compo-nents severely limited the use of the tool in HPHT environments. A more robust version was devel-oped to meet the challenge of HPHT operations.

To upgrade the PressureXpress tool design, engineers focused on the electronics and the pressure gauge. Pressure measurements with quartz gauges are highly accurate, but the data must be corrected for temperature. This tempera-ture correction applies to the measurement elec-tronics rather than the reservoir temperature.

For downhole pressure measurements, the PressureXpress and PressureXpress-HT high-temperature reservoir pressure services use a Quartzdyne gauge, which differs from conven-tional quartz gauges in that it has three separate crystals: One measures pressure, another mea-sures temperature and a third acts as a reference (above left).10 The measurement is extremely accurate when all three crystals are at the same temperature, and the gauge is reliable at tem-peratures up to 225°C [437°F]. But the gauge is sensitive to abrupt pressure and temperature changes. When exposed to rapid high-tempera-ture and pressure changes, which can occur when running into the well on wireline, the gauge must be allowed to stabilize before acquiring data.

The PressureXpress-HT tool is equipped with two flasks—one for the pressure gauge and another for the electronics—to isolate the pres-sure gauge sensor from the borehole and to isolate the rest of the tool electronics from the gauge. This configuration has proved to provide more-stable measurements than those taken with tools without flasks or when the electronics are housed with the gauge in the same flask (left). Electronic

> Quartzdyne pressure transducer. Three quartz crystal resonators—a temperature sensor, a pressure sensor and a reference—make up the Quartzdyne transducer. An increase in pressure at the pressure inlet of the bellows assembly causes an increase in frequency of the signal from the pressure crystal. An increase in temperature causes the frequency of the temperature crystal signal to decrease. The signal from the temperature sensor is used to compensate for temperature effects. The reference crystal simplifies frequency counting output from the other two crystals. Its output is mixed with the output of the temperature and pressure sensors, lowering their frequencies from the MHz to the kHz range. The design results in a low power consumption gauge that is highly stable and shock resistant, while providing high-resolution measurements. A pressure resolution of 0.01 psi [70 Pa] and temperature resolution of 0.001°C [0.002°F] can be obtained using this gauge.


Pressureinlet

Bellows

Temperature crystal

Pressure crystal

Reference crystal

Bellows AssemblySensor Assembly

2.50 cm

> Thermal isolation of the PressureXpress tool pressure gauge. The PressureXpress-HT tool isolates the pressure gauge and the rest of the electronics in separate flasks, which protects the gauge from external wellbore temperatures and internally generated heat from the electronics. A comparison of measurements from a flasked sensor (red) and an unflasked sensor (blue) demonstrates the higher accuracy and greater stablility of the flasked gauge. The output of the unflasked sensor stabilizes at the input pressure (3,391.99 psi) after almost 150 s.


Pres

sure

, psi

3,390

3,389

3,3880 10 20

Time, s

30 40 50 60 70 80 90 100 110 120 130 140 150

3,393

3,392

3,391

3,391.99 psi

3,390.03 psi

Pressure Data Comparison

54401schD3R1.indd 14 12/3/12 8:43 PM

Autumn 2012 15

components for the PressureXpress-HT tool were also upgraded based on many of the lessons learned from the MDT Forte-HT tool design.

The modifications to the PressureXpress-HT tool have extended the temperature specifica-tions of the tool to 232°C [450°F] for 14 h. Pressure and mobility measurements may be obtained with drawdown differential pressures up to 55 MPa [8,000 psi] and pretest mobility as low as 0.3 mD/cP may be detected. The tool retains its slim diameter, even with the addition of flasks. The probe section can be as small as 10.3 cm [4.05 in.] while the main tool body has a diameter of only 9.8 cm [3.9 in.].

Gulf of Thailand ChallengesBecause of high geothermal gradients, the south-ern regions of the Gulf of Thailand represent some of the world’s harshest environments for hydro-carbon production (right). The Arthit field in the Gulf of Thailand is about 230 km [143 mi] off-shore. PTT Exploration and Production Plc (PTTEP) discovered the field in 1999. The field is characterized by highly compartmentalized, com-plex reservoirs that have bottomhole tempera-tures between 320°F [160°C] and 500°F [260°C].11

Production is from Late Eocene to Late Oligocene formations that are characterized by low permeability. Low-permeability formations may require extended sampling time, even when only pressures and mobility data are acquired.

Most boreholes are small, usually drilled with a 61/8-in. bit, which limits the size and selection of tools that can be run at TD. Because of the small hole size, PTTEP historically acquired pressure and sampling data with an SRFT slimhole repeat formation tester. Although this tool is rated only to 177°C [350°F], it was one of the few options available for the hole size typically drilled in the field. The measurements needed from the tool included formation pressure, fluid gradients and CO2 content. Of these, only CO2 content required fluid sampling. The pressure data were used to determine fluid contacts, fluid mobility, sand-to-sand pressure correlation, reservoir connectivity, compartmentalization and perforation design strategy. The data were also used to identify depleted zones.

In 2009, a flasked PressureXpress tool was introduced in Thailand. The tool was capable of obtaining all of the PTTEP objectives except one—CO2 content. However, this tool did not include a separate flask for the pressure gauge, which caused gauge stability problems because the internal temperature rose during operations.

An additional flasked section that isolated the gauge was added next, which resulted in a con-figuration similar to the PressureXpress-HT tool.

The success of the modified PressureXpress tool led design engineers at Schlumberger to develop a fully upgraded PressureXpress-HT tool, which was field-tested in the Gulf of Thailand. The tool, which incorporated upgraded electron-ics for high-temperature operations and flasks developed specifically for it, is combinable with other evaluation tools and can be included on the first trip into the well. The SRFT tool is not com-binable and requires an additional trip when the operator requires samples.

PTTEP compared PressureXpress-HT opera-tional and measurement performance with those of the SRFT tool. Rig time was noticeably reduced. Time savings were realized from improved effi-ciencies and through set and retract times of less

than a minute compared with two to three minutes with the SRFT tool.

Not only does the PressureXpress-HT tool set and retract more quickly than the previous- generation tool did, but tool performance and data quality are improved. A direct comparison of the data from the PressureXpress-HT tool with

9. Fluid mobility is a measurement of the ease with which fluids travel through rock. It is the ratio of rock permeability divided by the dynamic viscosity of the fluid.

10. For more on Quartzdyne Technologies: http://www.quartzdyne.com/quartz.php (accessed August 7, 2012).

11. Daungkaew S, Yimyam N, Avant C, Hill J, Sintoovongse K, Nguyen-Thuyet A, Slapal M, Ayan C, Osman K, Wanwises J, Heath G, Salilasiri S, Kongkanoi C, Prapasanobon N, Vattanapakanchai T, Sirimongkolkitti A, Ngo H and Kuntawang K: “Extending Formation Tester Performance to a Higher Temperature Limit,” paper IPTC 14263, presented at the International Petroleum Technology Conference, Bangkok, Thailand, February 7–9, 2012.

> Gulf of Thailand temperature trend. Reservoir temperatures in the Gulf of Thailand range from relatively benign in the north to extremes of 500°F [260°C] in the south. Field development in the high-temperature reservoirs, such as the Arthit field, presents challenges for equipment used downhole. (Adapted from Daungkaew et al, reference 11.)


T H A I L A N D

L A O SM Y A N M A R

C A M B O D I A

VIETNAM

Arthitfield

Songkhla

Gulf of Thailand

Andaman Sea

180°F to220°F

220°F to320°F

320°F to350°F

350°F to500°F

km0 200

0 mi 200

54401schD3R1.indd 15 12/3/12 8:43 PM

16 Oilfield Review

data from the SRFT tool demonstrated the stabil-ity and accuracy of the measurements. In a Gulf of Thailand well, the new tool provided fluid gradient data that clearly identified a gas/water contact, whereas the data from the SRFT tool were scattered and not definitive (left).

A comparison of pretest data from the first application of the tool demonstrated the higher efficiency and improved performance of the PressureXpress-HT tool (below left). Performance continued to improve after a few jobs; on an off-set well, 76% of the attempted pressure tests were successful with no unstable tests and no lost seals.

The tool is combinable with other logging tools. Because it sets and retracts quickly, and because the quartz gauge requires little stabiliza-tion time, PTTEP has experienced average time savings between 157 and 167 min per job. This translates into direct rig cost savings. Fast set-retract cycling has also allowed PTTEP to per-form more tests before the tool heats up and must be removed from the well.

The success of the PressureXpress-HT tool demonstrates that the new design meets the challenge of extreme conditions by protecting sensitive electronics with thermal barriers and minimizing heat generation. Because the PressureXpress tool does not have the capability to sample or measure CO2, PTTEP continues to use the SRFT tool for taking fluid samples. In development wells, where fluid properties are known, fluid sampling is often unnecessary and pressure data, from the PressureXpress-HT tool, for example, can be used for reservoir man-agement and modeling. Pressure information helps engineers understand dynamic properties at the wellbore and across a reservoir.

Time and Temperature To understand the reservoir limits and define field potential, engineers often conduct long-duration pressure transient tests. Shut-in and buildup tests help accurately define reservoir potential. These tests provide data on reservoir volume, permeability thickness and boundaries, along with skin effect in the well being tested.

Critical decisions that affect long-term pro-duction plans require data from long-duration tests. Although some measurements that reflect well production can be acquired at the surface, for best results, measurements are acquired with gauges positioned downhole, as close to the producing zone as feasible.

> Stable pressure measurements. Engineers identify fluid contacts from fluid pressure gradients. This information enhances conventional log evaluation. For instance, the rise in resistivity (Track 4) around X,115 ft might be interpreted as a gas/water contact (GWC). The density-neutron porosity data (Track 3) provide little help in determining the fluid contact. However, with pressure data at around X,120 ft from the PressureXpress-HT tool (Track 1, blue circles), a GWC can be identified from the change in slope of a line drawn through pressure measurements. No such trend can be established with the SRFT data (black circles). Engineers also identified permeable zones using fluid mobility measurements from the PressureXpress-HT data (Track 2). (Adapted from Daungkaew et al, reference 11.)


Drawdown Mobility

90-in. Induction

PressureXpress Pressure Data

SRFT Pressure Data

PressureXpressMobility Data

SRFT Mobility Data

Gamma Ray

0.319 psi/ft (gas)

0.401 psi/ft (water)

Gas/water contact

Depth,ft

gAPI

psi

psi

mD/cP0

X,000 Y,000

X,100

X,150

X,000 Y,000

200 0.1 10,000

ohm.m0.2 200

30-in. Induction

ohm.m0.2 200

10-in. Induction

ohm.m0.2 200

Neutron Porosity

Crossover

%

Bulk Density

g/cm31.95 2.95

45 –15

Resistivity

> Comparison of PressureXpress-HT field results with SRFT data. In the first well test (Well A-1), the PressureXpress-HT tool was able to make more attempts and had a higher success rate than the SRFT tool. In Well A-2, only the PressureXpress-HT tool was run. This test had a 76% success rate for pressure attempts, which engineers considered excellent for the downhole conditions and formation properties. (Adapted from Daungkaew et al, reference 11.)

Oilfield Review AUTUMN 12HPHT Table 2OAUT 12-HPHT Tab 2

PressureXpress-HTdata

SRFT data

Well A-1

Field Results

Number of attempts Valid Dry Tight Unstable Lost seal Supercharged

37 18 (49%) 2 (5%) 4 (11%) 1 (3%)2 (5%)10 (27%)

10 2 (20%) 2 (20%) 4 (40%) 01 (10%)1 (10%)

PressureXpress-HTdata

Well A-2


29 22 (76%) 6 (21%) 0 001 (3%)


54401schD3R1.indd 16 12/3/12 8:44 PM

Autumn 2012 17

Quartz gauges are the industry standard for measurement accuracy and precision downhole. These gauges use quartz as the active sensing ele-ment because of its well-defined elasticity. When exposed to a stress, the quartz distorts, or strains, with a precise, repeatable response in reaction to the applied load. The measurement must be cali-brated to compensate for the effects of tempera-ture on the sensing element and associated electronics. In HPHT environments, however, operators have had to forgo extended well tests because downhole conditions preclude the use of gauges needed to make the measurements.

Engineers at Schlumberger developed the Signature quartz gauge in recognition of the industry’s need for a robust downhole device that provided the accuracy and precision required but could withstand harsh HPHT conditions (right). Not only does the instrument survive HPHT envi-ronments—no simple task—but the data acquired meet needed accuracy and stability cri-teria. In developing the Signature gauge, engi-neers focused on two main areas of concern: electronics and batteries.

For high-temperature applications, engineers chose ceramic electronic components; plastic components would never survive the tempera-ture extremes for long-duration tests. The major-ity of the electronic functionality for the Signature gauge is incorporated into a high-tem-perature application-specific integrated circuit (ASIC), which minimizes component size and power consumption. Limiting power consump-tion is a challenge because consumption increases dramatically at high temperatures, often surpassing the ability of the battery to deliver sufficient current to operate the tool.

Condensing the electronics into an ASIC reduces the number of components, connections and potential failure mechanisms. Since the pre-dominant failure mode of electronics is mechani-cal, this design was developed with reliability and ruggedness in mind.

The electronic circuitry is integrated into a multichip module (MCM). There are many types of MCMs but the Signature gauge uses rigor-ously tested high-temperature electronic com-ponents on a single cofired ceramic substrate (right).12 This technology provides mechanical rigidity and hermeticity.

12.Cofiringisafabricationtechniqueusedforcreatingmultilayerceramicchips.

> Signaturegauge.TheoutsidediameteroftheSignaturegaugeisonly25mm[1in.]andthetoolweighs1.7kg[3.8lbm].Ratedto207MPaand210°C,thegaugeisaccuratetowithin0.015%atfullscaleandhasaresolutionof7Pa[0.001psi].


> Designedforextremeconditions.Theelectroniccomponents(gold)usedintheSignaturegaugeareapplieddirectlytoaceramicsubstrate(brown).Conventionaltoolsmayuseplasticcomponentsmountedoncircuitboards.TheSignaturegaugeisdesignedforlowpowerconsumptiontomaximizebatterylife,whichisachieflimitingfactorforhigh-temperatureoperationsthatrelyondownholebatteries.


10 cm

54401schD3R1.indd 17 12/3/12 8:44 PM

18 Oilfield Review

Electronics that survive long-term exposure at high temperatures still need power to operate. Because the melting point of lithium is 181°C [358°F], conventional lithium batteries—the industry standard—cannot be used in high-tem-perature wells for long periods. Battery special-ists at Schlumberger developed lithium batteries that incorporate magnesium to strengthen the cell structure of the battery, which allows battery operation up to 210°C. Although battery life remains the primary limiting factor in high- temperature operations, batteries with this design can power the tool for 12 days at 210°C and 37 days at 205°C [400°F].

To maximize test duration and extend battery life, the electronics are designed to consume min-imal power during operations. Even if the batter-ies are fully discharged, data are recorded in nonvolatile memory and stored for the duration of extended tests with no loss of information.

The Signature quartz gauges are available in three models: standard quartz, high-pressure (HP) quartz and HPHT quartz. The physical dimensions for all three gauges are the same at 25 mm [1 in.] outside diameter; however, the

gauges differ in electronics, memory size and bat-teries. The maximum pressure rating of the HP version is 207 MPa and the temperature rating is 177°C. The HPHT model has the same pressure rating but the maximum temperature is 210°C. Because of the limitations imposed by high-tem-perature environments, the HPHT memory capacity is 12 days of 1-s recordings at maximum temperature in contrast to 50 days for the other two models.13

For the Signature gauge, the accuracy and resolution for both pressure and temperature measurements are some of the best in the indus-try. The HP and HPHT models have pressure accu-racy of 0.015% at full scale—207 MPa—with a resolution better than 70 Pa [0.01 psi]. Field results have demonstrated resolution better than 7 Pa [.001 psi]. Temperature accuracy is 0.2°C [0.4°F] with a resolution of 0.001°C [0.002°F].

The Challenge of the Bay of BengalThe HPHT version of the Signature quartz gauge was recently put to the test in a well operated by the Gujarat State Petroleum Corporation (GSPC).14 GSPC, India’s only state-owned oil and gas company, made discoveries of significant

amounts of natural gas in the Krishna-Godavari basin, which extends into the Bay of Bengal off-shore India. Initial reports by GSPC in 2005 indi-cated a resource potential for 566 billion m3 [20 Tcf] of gas, the largest discovery in India at that time (above).15

The discovery well encountered 800 m [2,600 ft] of gas-bearing sandstone at around 5,500 m [18,050 ft]. Reservoir temperatures exceed 204°C. The highly faulted horst and gra-ben structures are lower Cretaceous-age sand-stones that have experienced extensive rifting and tectonic faulting. Although seismic data indi-cated potential targets for exploration, the depth and complexity of the reservoir led reservoir engineers to design a drillstem test (DST) to bet-ter understand the reservoir potential.

13.StoragecapacityforthestandardandHPSignaturegaugesis16MB.Itis4MBfortheHPHTmodel.

14.KhanZA,BeheraBK,KumarVandSimsP:“SolvingtheChallengesofTime,TemperatureandPressure,”World Oil233,no.5(May2012):75–78.

15.“India’sGujaratPetroleumStrikesRecordGasFind,”Spirit of Chennai,http://www.spiritofchennai.com/news/national-news/a0272.htm(accessedJune6,2012).

16.Khanetal,reference14.

> BayofBengalbasins.In2005,GujaratStatePetroleumCorporationmadeahugenaturalgasdiscoveryoffshoreIndiaintheGodavaribasin.Welldepthshereareapproximately5,500m[18,050ft],withbottomholetemperaturesgreaterthan200°C.(AdaptedfromKhanetal,reference14.)

Oilfield Review AUTUMN 12 HPHT Fig. 18ORAUT 12-HPHT 18

I N D I A

SRILANKA

Pranhita-Godavari Basin

CuddapahBasin

Chennai

Palar-Pennar Basin

Cauvery Basin

Krishna-Godavari Basin

GSPC lease

Deep explorationtargets

Bay of Bengal

km0 200

0 mi 200

km0 20

0 mi 20

54401schD3R1.indd 18 12/3/12 8:44 PM

Autumn 2012 19

To establish stable flow within the reservoir, engineers designed the DST to include three suc-cessive drawdowns and buildups conducted over 15 days. The estimated downhole pressure was more than 95 MPa [13,800 psi] and the tempera-ture was greater than 210°C at TD. Extensive backup systems included five different electronic recording devices. The Signature quartz gauge was the only device that engineers deemed suit-able for deployment at the 210°C level, which was close to TD.

For the most accurate data, gauges should be positioned as close to the producing zone as pos-sible because the compressibility of natural gas may distort the measurement. Although not opti-mal, but because of temperature and pressure limitations, three of the five devices were located more than 1,000 m [3,280 ft] above the depth at which the Signature gauge was positioned.

The operator ran three pressure transient tests in sequence for the full 15 days. During the first two tests, the operator experienced prob-lems that invalidated the tests but were unre-lated to the gauges. The third test sequence, however, was performed as planned.

The test assembly was retrieved and only one of the gauges was found to be operational, the Signature quartz gauge (above). No usable down-hole electronic data were recorded from the

other gauges because they had all failed prior to the commencement of the final test. The data from the Signature gauge were of sufficient quality—pressure fluctuations of as little as 7 Pa were detected—that a second confirmation test was considered unnecessary. GSPC engineers estimated that US$ 1 million was saved because remedial services to resolve reservoir complexity were not needed.16

The LimitAt one time, oil and gas service companies expressed grave concern about their ability to develop tools capable of withstanding extreme conditions. Electronics manufacturers shifted their focus from rugged components to those that consume little power and operate at ambient conditions, leaving service companies to fend for themselves. Design engineers, however, are now meeting the challenge of extreme operating envi-ronments with innovative pressure and sampling tools and downhole gauges for evaluating HPHT reservoirs.

Service companies have demonstrated an ability to meet the challenge of hostile drilling environments. Although the portfolio of offer-ings has expanded in recent years, it is still limited to primary evaluation services. Some measurements that operators would like to have to characterize producing wells remain limited

to lower temperatures and pressures. Pressure and sampling tools were once in that class. Now that it has been proved that these services can be performed in extreme conditions, geologists, engineers and geophysicists often consider the measurements essential to fully characterize and understand reservoirs.

Extreme wells call for extreme solutions. Although HPHT fields may contain a relatively small number of wells, they also may contain sig-nificant sources of hydrocarbons. Thanks to an enormous research and engineering effort, more and more options are available for operators to drill wells, evaluate formations and properly characterize reservoirs. —TS

> Extended pressure test. GSPC performed an extended well test that included three buildup and drawdown sequences performed over 15 days. Five gauges were run downhole for redundancy and data security. The first two sequences experienced operational problems, and the tests were compromised by disturbances in the pressure data (blue). The third sequence was performed properly. After the gauges were retrieved, all but one were discovered to have failed prior to the commencement of the third (and only valid) test. The only usable data retrieved were from the HPHT Signature gauge. (Adapted from Khan et al, reference 14.)


Pres

sure

, psi

Time, d

Clean buildup

Disturbanceduring buildup

Drawdown

Buildup 1 Buildup 2 Buildup 3

Drawdown

All electronic gauges, exceptthe Signature quartz gauge,

failed to record after this time.

Tem

pera

ture

, °F

TemperaturePressure 425

405

20,000

18,000

16,000

14,000

12,000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

10,000

8,000

385

365

345

325

305

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20 Oilfield Review

When Rocks Get Hot: Thermal Properties of Reservoir Rocks

For many years, thermal stimulation has been the leading method for enhanced oil

recovery. Operators are using new techniques on heavy oil, tar sands, bitumen and oil

shale to liberate a vast store of liquid energy that could provide transportation fuels

for worldwide use for a century or more. Design of stimulation programs to produce

these resources efficiently over long periods of time requires better understanding

and measurement of thermal properties of rocks.

Evgeny Chekhonin Anton Parshin Dimitri PissarenkoYury PopovRaisa RomushkevichSergey SafonovMikhail SpasennykhMoscow, Russia

Mikhail V. ChertenkovVladimir P. SteninLukoilMoscow, Russia

Oilfield Review Autumn 2012: 24, no. 3. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Yevgeniya Gelman, Houston; and Sidney Green and Roberto Suarez-Rivera, Salt Lake City, Utah, USA.Micarta® is a trademark of Norplex-Micarta.Plexiglas® is a registered trademark of ATOFINA.TerraTek is a mark of Schlumberger.

When reservoir fluid gets hot, its viscosity decreases, and a greater amount of fluid usually can be produced from the reservoir rock. Stimulation of conventional petroleum reservoirs with heat from injected steam or hot water has been practiced for more than 50 years with some

remarkable successes. At the Kern River oil field in California, USA, for example, a massive pro-gram of cyclic steam injection, starting in the 1960s, revived this supergiant field by increasing its production rate more than tenfold after it had stagnated for decades (below). Today, about

> Kern River field, operated by Chevron near Bakersfield, California, USA. Production of heavy oil at Kern River field peaked within its first 10 years of operation and went into a 50-year decline. A program of thermal EOR by cyclic steam injection, accompanied by intensive infill drilling, rejuvenated the field in the 1960s, with high production levels continuing today.

Oilfield Review SUMMER 12 Thermal Properties Fig. 1ORSUM 12-THMPTS 1

Bakersfield

C a l i f o r n i a

Kern River field

U N I T E D S T A T E S

160,000

Oil p

rodu

ctio

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120,000

100,000

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01900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010

Year

Kern River Field Production History

Steam stimulation

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Autumn 2012 2121Autumn 2012

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22 Oilfield Review

60% of world oil production attributed to methods of enhanced oil recovery (EOR) comes from thermal stimulation. For the future, heavy oil deposits, tar sands, bitumen and oil shale—unconventional resources that represent Earth’s largest store of liquid fuels—are now being coaxed into releasing the oil they contain by highly evolved forms of thermal recovery.1

This article examines an important, but often overlooked, facet of thermal EOR—the thermal behavior of reservoir rocks. Heating reservoir flu-ids means also heating large volumes of rock. And, while engineers designing a stimulation pro-gram usually know the thermal properties of the fluids, thermal properties of formation rocks are

often only loosely constrained, even though these properties help determine project economics.

After a brief look at an unusual thermal recov-ery operation taking place in the Yarega heavy oil field in Russia, this article reviews the basic ther-mal properties of rocks and their measurement by often time-consuming conventional tech-niques. It also introduces a new measurement technique that employs optical sensors to rapidly quantify thermal properties of rock. Since the 1980s, scientists have scanned thousands of rock samples with this optical method, including igne-ous and metamorphic rocks from deep scientific boreholes around the world and, more recently,

sandstones, shales and carbonates from many petroleum reservoirs. The measurements have revealed important new results about the hetero-geneity and anisotropy of thermal rock proper-ties. Investigators are also finding intriguing correlations between thermal and other petro-physical properties.

Research on cores from Russian oil fields revealed surprising variability in reservoir ther-mal properties over spatial scales ranging from centimeters to tens of meters. Reservoir simula-tions show why it is important for engineers to understand this variability when they attempt to predict the outcome of thermal EOR. In the cases simulated, incorrect values caused estimates of key metrics for thermal stimulation to vary by up to 40% after just 10 years of production.

Yarega Oil FieldThe Yarega heavy oil field in the Komi Republic, Russia, illustrates the enormous potential of thermal EOR. Discovered in 1932, and now oper-ated by Lukoil, Yarega lies in a prolific oil prov-ince west of the Ural Mountains called the Timan-Pechora basin (left). The reservoir holds large quantities of bitumen, a highly viscous, semisolid hydrocarbon formed during the pro-cess of petroleum generation. Natural bitumen occurs at depths shallower than 370 m [1,200 ft] in many Russian oil fields, where it constitutes a resource estimated at more than 16 billion m3 [100 billion bbl] of oil. The pay zone in Yarega is at depths between 180 and 200 m [590 and 660 ft] and is composed of fine-grained quartz sandstone of Middle Devonian age, with a porosity of 20% to 25% and nearly 100% oil saturation.2

Production from the shallow reservoirs at the Yarega field resembles a mining operation. Operators have used several configurations to heat the reservoir with steam and extract the lib-erated fluids. In the most common scheme, devel-oped in the 1970s and called the two-level, or two-horizon, system, steeply inclined steam injection wells, drilled from overlying chambers reached by conventional mine shafts, penetrate and heat the reservoir. Additional mine shafts lead to a second set of galleries near the bottom of the reservoir, from which gently sloping pro-duction wells are drilled upward into the oil-bearing layers.

The effect of thermal stimulation on produc-tion from the Yarega field has been dramatic. Before thermal mining began in the late 1960s, production in conventional wells drilled from the surface recovered barely 4% of the original oil in place. Thermal mining has raised the

> Yarega oil field, operated by Lukoil near Ukhta in the Komi Republic, Russia. Primary production of oil from bitumen in the shallow Yarega field started in the 1930s and peaked in the early 1950s. Production was declining rapidly around 1970, when new programs of thermal mining by steam injection were introduced.

R U S S I A

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Ukhta

0 km

0 mi 200

200

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Autumn 2012 23

average recovery to 33% and in some zones, to nearly 70%. Lukoil recently introduced new forms of steam-assisted gravity drainage (SAGD) at Yarega, which are expected to increase annual production to 3.5 million met-ric tons (3,500,000 Mg) [25 million bbl] of oil in the near future.3

Thermal Rock PropertiesEngineers often use reservoir simulations to design thermal EOR programs and predict the amount of additional oil attributed to thermal stimulation and its production rate over time at various wells in the field. To accomplish this, sim-ulators employ sophisticated algorithms to com-pute the evolution of temperature and heat flow within a reservoir after stimulation. These two quantities—temperature and heat—are linked by the thermal properties of rocks and their pore fluids (see “Physics of Temperature and Heat,” page 24). The most important of these properties are volumetric heat capacity, thermal conductiv-ity and thermal diffusivity. Volumetric heat capac-ity specifies the amount of heat required to raise the temperature of a unit volume of rock (and any pore fluids within) by one degree. Thermal con-ductivity determines where and how much heat flows in response to temperature differences in the reservoir. Thermal diffusivity determines the speed at which a temperature front moves through the reservoir.4

A fourth property, the coefficient of thermal expansion, links the thermal and mechanical responses of reservoir rocks by determining the amount by which a volume of rock expands as its temperature increases. Knowledge of this prop-erty is needed, for example, to assess changes in mechanical wellbore stability and in caprock integrity caused by changing temperature condi-tions in the reservoir.

In the enormous volume of petrophysical data from geologic formations around the world, there are relatively few measurements of thermal prop-erties of reservoir rocks made in the laboratory or in situ. As a result, engineers often calculate these thermal properties by using crude predic-tive models, without reference to actual mea-surements on core samples. This lack of thermal measurements represents a big gap in current knowledge of reservoir rock properties.

One reason for the lack of data is that it is difficult to measure thermal rock properties. The long-time standard for measuring thermal conductivity, the divided bar method, obtains the property by placing a disk-shaped sample of material between two cylindrical metal bars held at constant temperature (above right).

After a steady state is reached, the sample’s thermal conductivity is estimated by comparing the temperature drop across its faces with the drop across those of reference materials of known conductivity flanking the sample. The divided

bar method defines the standard for accuracy in measuring thermal conductivity, but is time-consuming. The measurement of a typical cylin-drical sample, 3 to 5 cm [1.2 to 2.0 in.] in diameter and 1 to 3 cm [0.4 to 1.2 in.] long, takes

1. For more on Kern River and modern methods of thermal EOR: Curtis C, Kopper R, Decoster E, Guzmán-Garcia A, Huggins C, Knauer L, Minner M, Kupsch N, Marina Linares L, Rough H and Waite M: “Heavy-Oil Reservoirs,” Oilfield Review 14, no. 3 (Autumn 2002): 30–51.

Alboudwarej H, Felix J, Taylor S, Badry R, Bremner C, Brough B, Skeates C, Baker A, Palmer D, Pattison K, Beshry M, Krawchuk P, Brown G, Calvo R, Cañas Triana JA, Hathcock R, Koerner K, Hughes T, Kundu D, López de Cárdenas J and West C: “Highlighting Heavy Oil,” Oilfield Review 18, no. 2 (Summer 2006): 34–53.

Allix P, Burnham A, Fowler T, Herron M, Kleinberg R and Symington B: “Coaxing Oil from Shale,” Oilfield Review 22, no. 4 (Winter 2010/2011): 4–15.

Butler RM: Thermal Recovery of Oil and Bitumen. Englewood Cliffs, New Jersey, USA: Prentice Hall, 1991.

For a comprehensive report on methods developed in the former Soviet Union: Bokserman AA, Filippov VP, Filanovskii VYu: “Oil Extraction,” in Krylov NA, Bokserman AA and Stavrovsky ER (eds): The Oil Industry

>Measuring rock thermal conductivity. The divided bar method is the standard laboratory technique for determining rock thermal conductivity. The method sandwiches a disk-shaped rock sample between brass plates—two ends of a divided bar—held at different temperatures. The sample is flanked by disks of a reference material of known thermal conductivity; fused silica, with a thermal conductivity of 1.38 W/m°K, is a commonly used reference. After a steady state is reached, as indicated by steady temperatures in the transducer wells, the sample’s thermal conductivity is determined by comparing the temperature drop across its length with the drop across the reference material. The hydraulic ram compresses samples for measurements under high pressure. (Adapted from Popov et al, reference 12.)

50 mm

Steel Hydraulic ram

Micarta

Micarta

Fused silicaTemperature

transducerwells

MicartaCopper

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Micarta

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Increasing temperature


of the Former Soviet Union: Reserves and Prospects, Extraction, Transportation. Amsterdam: Gordon and Breach Publishers (1998): 69–184.

For a recent comprehensive review of enhanced recovery: Alvarado V and Manrique E: “Enhanced Oil Recovery: An Update Review,” Energies 3, no. 9 (2010): 1529–1575.

2. Mamedov YG and Bokserman AA: “Development of Heavy Oils and Natural Bitumens in the Former Soviet Union and Eastern and Central Europe: State-of-the-Art and Outlook,” Proceedings of the Sixth UNITAR International Conference on Heavy Crude and Tar Sands, Houston, February 12–17, 1995: 11–18.

Chertenkov MV, Mulyak VV and Konoplev YP: “The Yarega Heavy Oil Field—History, Experience, and Future,” Journal of Petroleum Technology 64, no. 4 (April 2012): 153–160.

3. Chertenkov et al, reference 2.4. The three thermal properties are not independent;

thermal diffusivity is the ratio of thermal conductivity to volumetric heat capacity.

(continued on page 27)

54401schD4R1.indd 23 11/20/12 6:04 PM

Thermal properties connect temperature and heat flow, which are fundamental concepts in physics and classical thermodynamics. Temperature is a measure of the average energy content of macroscopic bodies—solids, liquids and gases—while heat flow represents the transfer of thermal energy between bodies or regions at different temperatures. Temperature has its own basic SI unit, degrees kelvin (°K), with absolute zero (0°K) as the lowest possible temperature. In the commonly used Celsius scale (°C), the freezing point of water is taken as 0°C, placing absolute zero at −273.15°C. A difference of one degree in either scale represents the same change in temperature.

Volumetric heat capacity, thermal conduc-tivity, thermal diffusivity and the coefficient of thermal expansion are the main thermal prop-erties of interest for engineers. Volumetric heat capacity (VHC) measures the amount of heat needed to raise the temperature of a unit volume (1 m3) of a substance by 1°K (below). The original unit of heat, the Calorie, was defined in 1824, by the French physicist and chemist Nicolas Clément, as the amount of heat needed to raise 1 kg of water by 1°C. The later discovery, by the English physicist and brewer James Prescott Joule, of the equivalence of heat and mechanical energy led to replacement of the Calorie as a basic physical unit by the derived unit for mechanical or kinetic energy, kg m2/s2—now called the

joule (J). Clément’s Calorie, which is equiva-lent to about 4.2 kJ, survives today as the com-mon unit for measuring the energy content of food. Since 1 m3 of water weighs 1,000 kg, the volumetric heat capacity of water is about 4.2 MJ/m3°K. The volumetric heat capacity of rocks is generally lower, in the range 1 to 4 MJ/m3°K (next page, bottom left).

Temperature differences drive the flow of thermal energy—the flow of heat (above). Like the flow of fluid or electrical current, heat flow has both magnitude and direction and is therefore represented as a vector quantity. The magnitude of the heat flow vector gives the amount of thermal energy per second crossing a surface of unit area oriented perpendicular to the direction of the vector. The units of heat flow are thus energy per unit time per unit area, or power per unit area and are conventionally taken as watt per square meter (W/m2).

24 Oilfield Review

Physics of Temperature and Heat

> Volumetric heat capacity. Volumetric heat capacity is the amount of thermal energy in the form of heat needed to raise the temperature of a unit volume of material—1 m3 in SI units—by 1°K, starting from a given temperature T0. There can be no change of phase, such as melting, during the temperature rise. The volumetric heat capacity of dry sandstone typically falls between that of bitumen and water.

Oilfield Review SUMMER 12 Thermal Properties Fig. 3AORSUM 12-THMPTS 3A

26°C

25°C

1.7 MJ

Bitumen

2.7 MJ

Sandstone

4.2 MJ

Water

Volumetric Heat Capacity

1 m 1 m

1 m

> Heat flow. Heat flow is a vector quantity, q, whose magnitude, at any point in a material, gives the amount of thermal energy flowing per unit time across a surface of unit area oriented perpendicular to the vector direction. If the heat flow vector (red arrow) is oriented at an angle, θ, to the surface, energy flow across the surface is reduced by the cosine of the angle.

Oilfield Review SUMMER 12 Thermal Properties Fig. 3BORSUM 12-THMPTS 3B

Heat Flow

1 m

1 m

qHeat flowvector

θ

54401schD4R1.indd 24 1/9/13 3:20 PM

Thermal conductivity provides the quanti-tative connection between heat flow and temperature differences (right). It can be defined by considering a cube of homoge-neous material with a temperature differ-ence between two opposite faces. The amount of heat flowing through the cube, from the high- to low-temperature faces, is

proportional to the temperature difference divided by the distance between the faces. The constant of proportionality is the ther-mal conductivity, which thus has units of W/m°K. The thermal conductivity of water is about 0.6 W/m°K. The thermal conductivity of rocks is generally higher, in a range from about 0.5 to 6.5 W/m°K.

Some materials, including rocks, exhibit macroscopic thermal anisotropy; for example, different numerical values for thermal con-ductivity result from measurements across different pairs of opposing faces on a cube of the material. The simplest type of thermal anisotropy, common in rocks, arises when the material has a layered structure at fine scales. The thermal conductivity in the direction per-pendicular to the layering is generally lower than the conductivity in any direction parallel to the layering.

Autumn 2012 25

> Thermal properties of common materials.

Oilfield Review SUMMER 12 Thermal Properties Fig. 3FORSUM 12-THMPTS 3F

Carbon dioxide

Air

Motor oil, grade SAE 50Bitumen

GlassCarbon

Methanol

Water

Stainless steel

LeadSteel

Nickel

AluminumGoldCopperSilver

0.01

0.1

1.0

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Thermal Conductivity,W/m°K

Air, dry at sea level

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1

2

3

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BitumenEthanol

Paraffin

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Ammonia

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Water at 100°C

Volumetric HeatCapacity, MJ/m3°K

> Thermal conductivity. Thermal conductivity relates temperature gradients and heat flow. A block of material with a temperature difference ΔT across two opposing faces separated by a distance Δz sustains a heat flow whose magnitude is proportional to the temperature difference divided by the distance (top). The proportionality constant is the block’s thermal conductivity k. Many materials display anisotropic thermal conductivity, in which temperature differences placed across different pairs of opposing faces of a cube result in different magnitudes of heat flow (bottom). Thermal anisotropy is common in finely layered materials, such as rocks, where the thermal conductivity parallel to layers (k ||) is up to 50% higher than thermal conductivity perpendicular to layers (k⊥).

Oilfield Review SUMMER 12 Thermal Properties Fig. 3CORSUM 12-THMPTS 3C

qz

q

qx

T

T

Tx∆

T + T∆q = –k ∆z

T∆

T + T∆

T + T∆qz = –k ∆z

T∆ qx = –k ∆xT∆

z∆

z∆

Thermal Conductivity

Anisotropic Thermal Conductivity

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26 Oilfield Review

> Thermal expansion. The coefficient of thermal expansion measures a fractional change in linear dimension of a uniform cube for a unit temperature rise. Each side of the cube may expand by a different amount in anisotropic materials.

Oilfield Review SUMMER 12 Thermal Properties Fig. 3EORSUM 12-THMPTS 3E

1 m + ∆x

Block of materialat temperature T0

Block of materialat temperature T0 + 1°K

1 m 1 m1 m + ∆y

1 m

1 m

+ ∆

z

Thermal Expansion

> Thermal diffusivity. Thermal diffusivity controls the rate at which temperature rises in a uniform block of material when more heat is flowing into the block than flowing out. If an initial temperature gradient is established between the block and its surroundings, the heat fluxes in and out are determined by the block’s thermal conductivity, while the temperature rise caused by the heat imbalance is determined by the block’s volumetric heat capacity. Thermal diffusivity is thus the ratio of thermal conductivity to volumetric heat capacity.

Oilfield Review SUMMER 12 Thermal Properties Fig. 3DORSUM 12-THMPTS 3D

qout

T

qout

q in q in

Time0 + 1 sTime0

T + T∆

Thermal Diffusivity

Volumetric heat capacity and thermal conductivity combine to determine a third thermal property, called thermal diffusivity (left). Imagine a cube of uniform material with more heat flowing in through the bot-tom face than is flowing out through the top face. The difference in the two flows is the rate at which heat is being added to the cube, which will cause its temperature to rise. Since the rate of heat flow is deter-mined by the material’s thermal conductivity and the temperature increase by its volumet-ric heat capacity, the rate of temperature increase is obtained by dividing the thermal conductivity by the volumetric heat capacity. This ratio, called thermal diffusivity, governs the speed at which temperature changes propagate through a material.

Temperature is not the only property that changes when a cube of material is heated: Most substances also expand. The rate of linear expansion—defined as the fractional increase in length of a cube’s sides per unit temperature rise—is called the coefficient of linear thermal expansion (below left). The thermal expansion of reservoir rocks provides an important link between the ther-mal and mechanical responses of the reser-voir during thermal EOR.

Thermal conductivity, heat capacity, thermal diffusivity and the coefficient of thermal expansion are properties that apply to macroscopic chunks of matter. The con-cepts break down when applied to individual atoms or molecules of a substance. Like all macroscopic properties—including petro-physical properties such as porosity, permea-bility and electrical conductivity—thermal properties may vary from point to point in a rock formation and depend on its tempera-ture and pressure.

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Autumn 2012 27

5. Beck A: “A Steady State Method for the Rapid Measurement of the Thermal Conductivity of Rocks,” Journal of Scientific Instruments 34, no. 5 (May 1957): 186–189.

Pribnow DFC and Sass JH: “Determination of Thermal Conductivity for Deep Boreholes,” Journal of Geophysical Research 100, no. B6 (June 10, 1995): 9981–9994.

Beck AE: “Methods for Determining Thermal Conductivity and Thermal Diffusivity,” in Haenel R, Rybach L and Stegena L (eds): Handbook on Terrestrial Heat Flow Density Determination. Dordrecht, the Netherlands: Kluwer (1988): 87–124.

6. Jaeger JC: “The Measurement of Thermal Conductivity with Cylindrical Probes,” EOS Transactions American Geophysical Union 39, no. 4 (1958): 708–710.

about 10 to 15 minutes. In addition, laboratory technicians must spend an hour or two cutting, trimming and polishing the disk to ensure good thermal contact with the heating bars. This last step is difficult to complete with fractured or poorly consolidated reservoir rocks.5

Alternatives to the steady state method are transient methods in which a scientist applies a pulse of heat to the sample, usually with a needle-shaped probe, and records the temperature response at one or more locations on the sample (right). Thermal conductivity or diffusivity is then calculated from a theoretical model that predicts how the material should respond in the given configuration. One configuration of this transient line source method, which is useful for measuring loose samples such as unconsolidated sediments and soils, applies the pulse of heat along a thin wire that carries a temperature sen-sor at its midpoint. This wire is inserted, like a hypodermic needle, into the material and mea-sures the temperature as a function of time. In another configuration, a scientist places the needle-shaped probe with its sensor on the flat top of a cylindrical core and records this surface’s temperature response to a pulse of heat.6

Because thermal conductivity relates two directional quantities, the temperature gradient and the heat flow vector, its value may depend on the direction of measurement, for example, on the direction of the temperature gradient imposed on a sample. The line source method provides a convenient way of characterizing directional dependence: Any variation of the temperature response as the needle is rotated through various directions on the surface of the core indicates that its thermal conductivity is anisotropic—heat flows preferentially in certain directions through the rock.

The most common form of anisotropy in crustal rocks is the result of features such as thin layers or oriented fractures that determine the directional characteristics of a rock’s bulk physi-cal properties. The simplest example is fine layer-ing or bedding, which is present in nearly all clastic reservoir and source rocks—sandstones and shales—and distinguishes the direction per-pendicular to the layers from the directions par-allel to the layers. This type of anisotropy induced by layering—also called transverse isotropy, axial anisotropy or cross anisotropy—may be present in sedimentary and igneous rocks perme-ated by thin oriented fractures, and in metamor-phic rocks that have been compressed strongly in

>Measuring thermal conductivity of unconsolidated or anisotropic materials. The line source method determines thermal conductivity by placing a thin probe with a heating element and temperature sensor in contact with a sample. A theoretical model predicting the temperature response to a pulse of heating is used to calculate the sample’s thermal conductivity. For unconsolidated samples, the probe is inserted, like a hypodermic needle, inside the material (top). For solid rocks, the probe is attached to the bottom of a Plexiglas block placed on the surface of the sample. For laminated samples cut at an angle to the measurement surface, the response of the probe changes as it rotates through various directions (bottom). Variations in response with angle may be used to determine the thermal anisotropy of layered rocks.

Sample

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Azimuth, degree0 30 60 90 120 150 180

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Von Herzen R and Maxwell AE: “The Measurement of Thermal Conductivity of Deep-Sea Sediments by a Needle-Probe Method,” Journal of Geophysical Research 64, no. 10 (October 1959): 1557–1563.

Waite WF, Gilbert LY, Winters WJ and Mason DH: “Estimating Thermal Diffusivity and Specific Heat from Needle Probe Thermal Conductivity Data,” Review of Scientific Instruments 77, no. 4 (April 2006): 1–5.

Woodside W and Messmer JH: “Thermal Conductivity of Porous Media. I. Unconsolidated Sands,” Journal of Applied Physics 32, no. 9 (September 1961): 1688–1699.

Woodside W and Messmer JH: “Thermal Conductivity of Porous Media. II. Consolidated Rocks,” Journal of Applied Physics 32, no. 9 (September 1961): 1699–1706.

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28 Oilfield Review

one direction and, as a result, have acquired a distinctive planar fabric.7

In finely layered rocks, the value of thermal conductivity in the direction perpendicular to the layers—and therefore the heat flow for a given temperature drop—is usually 5% to 30% lower than its value in directions parallel to the layers; in some rocks, the difference is as high as 50%. The physics and mathematics of thermal anisotropy are similar to those of electrical

anisotropy, which is critical to the proper evalua-tion of laminated reservoirs.8

Measuring Thermal Properties by Optical ScanningMost of the fundamental science of rock thermal properties was carried out in two waves. The first took place in the 1930s, when scientists began to unravel the thermal structure of Earth’s interior; the second occurred during the years of the plate

tectonics revolution of the 1960s and 1970s, when scientists recognized that the Earth’s internal heat and its flow to the surface were driving forces of global tectonics. Much of the latter research was devoted to mapping heat flow through ocean basins, which shows the thermal signature of convection patterns in the Earth’s deep interior (below).9 Scientists study thermal rock properties as a necessary component for heat flow determination and to understand the

> Earth’s surface heat flow. Flow of heat from the Earth’s deep interior to the surface is a driving force of global tectonics. A map of surface heat flow highlights ocean ridges, where magma derived from partial melting of the upper mantle rises to the surface to create new oceanic crust (bottom, adapted from Davies and Davies, reference 9). To produce this map, Davies and Davies compiled nearly 40,000 measurements, from which correlations of heat flow with geologic regions were derived to extend the discrete measurements using a digital map of global geology. At ocean ridges (top right), heat flow is dominated by convection—the movement of hot material (white arrows) from depth to the surface. Over the continents, average heat flow is determined by the geothermal gradient—the variation of temperature with depth—and the thermal conductivity of crustal rocks. The graph shows geothermal gradients in the shallow crust for several regions of the US (top left). Each geothermal gradient corresponds to a different value of surface heat flow.


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potential of geothermal energy. Beginning in the 1980s, researchers looked at thermal properties of sedimentary rocks to provide input to model the thermal history of basins in early quantita-tive attempts at petroleum system modeling.10

These lines of research converged in a study of thermal and other petrophysical measurements on rocks from deep scientific boreholes, including the 12,262-m [40,230-ft] Kola Superdeep Borehole in the Soviet Union, the deepest hole ever drilled. The work was driven by the recognition that thermal properties measured along the track of long scientific boreholes were much more hetero-geneous than previously imagined. Scientists realized that new methods were needed to char-acterize the thermal properties of rocks, includ-ing better methods of measuring these properties in situ, as well as laboratory methods that worked more rapidly and at higher resolution on smaller core samples.11

In the 1990s, scientists from Russia, Germany and the US participated in a joint study of major laboratory methods for measuring thermal con-ductivity, focusing on cores from the superdeep KTB borehole in Germany.12 One method in this study used an optical device developed in the early 1980s in the former Soviet Union. Unlike prior techniques for measuring thermal proper-ties, the optical method is contactless—no sen-sor touches the material; instead, the device uses remote optical thermal sensors to scan the sam-ple surface for the thermal signature of a con-stant, focused heat source (right). The source and sensors move together along the sample—a core, for example—in a fixed arrangement that

7. Transverse isotropy, axial anisotropy and cross anisotropy are synonymous terms referring to the particular directional character of materials in which properties have the same values in all directions parallel to planes of isotropy and different values perpendicular to or crossing the planes of isotropy; this perpendicular direction is the axis of cylindrical symmetry.

8. Thin oil-bearing layers in laminated reservoirs significantly increase the resistance to current flow, but only in the direction perpendicular to the beds. A resistivity logging tool that measures resistance in directions parallel to the beds generally will not detect the presence of oil. For more on the anisotropy of finely layered formations: Anderson B, Barber T, Leveridge R, Bastia R, Saxena KR, Tyagi AK, Clavaud J-B, Coffin B, Das M, Hayden R, Klimentos T, Minh CC and Williams S: “Triaxial Induction—A New Angle for an Old Measurement,” Oilfield Review 20, no. 2 (Summer 2008): 64–84.

9. The earliest systematic studies of Earth’s surface heat flow were a series of papers in the late 1930s: Anderson EM: “The Loss of Heat by Conduction from Earth’s Crust,” Proceedings of the Royal Society of Edinburgh 60, part 2. Edinburgh, Scotland: Robert Gran and Son, Ltd. (1939–1940): 192–209.

Benfield AE: “Terrestrial Heat Flow in Great Britain,” Proceedings of the Royal Society of London A 173, no. 955 (December 29, 1939): 428–450.

> Principle of the optical scanning method. Optical scanning provides a fast, contactless method of measuring thermal properties (top right). This method determines thermal conductivity and thermal diffusivity by heating a spot on the sample with a moving optical heat source—a laser or focused electric light (top left). Three infrared sensors, moving in tandem with the source, measure temperature at the surface of the sample. Sensor 1 is situated ahead of the heat source along the scan line to register surface temperature before the sample is heated. Two trailing sensors register the temperature rise induced by the heating: Sensor 2 measures along the scan line, and Sensor 3, along a parallel line (dashed black). A theoretical model predicting the temperature at these two locations as a function of time is used to calculate the thermal conductivity and thermal diffusivity at various locations under the scan line. By scanning the sample in three different directions, the method can determine anisotropic thermal properties of laminated rocks (bottom right).


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Krige LJ: “Borehole Temperatures in the Transvaal and Orange Free State,” Proceedings of the Royal Society of London A 173, no. 955 (December 29, 1939): 450–474.

Bullard EC: “Heat Flow in South Africa,” Proceedings of the Royal Society of London A 173, no. 955 (December 29, 1939): 474–502.

Birch AF and Clark H: “The Thermal Conductivity of Rocks and Its Dependence on Temperature and Composition, Part I,” American Journal of Science 238, no. 8 (August 1940): 529–558.

Birch AF and Clark H: “The Thermal Conductivity of Rocks and Its Dependence on Temperature and Composition, Part II,” American Journal of Science 238, no. 9 (September 1940): 613–635.

Many researchers contributed to mapping surface heat flow over the globe and unraveling its relation to plate tectonics. For more: Sclater JG and Francheteau J: “The Implications of Terrestrial Heat Flow Observations on Current Tectonic and Geochemical Models of the Crust and Upper Mantle of the Earth,” Geophysical Journal of the Royal Astronomical Society 20, no. 5 (September 1970): 509–542.

The most recently published compilation of surface heat flow data: Davies JH and Davies DR: “Earth’s Surface Heat Flux,” Solid Earth 1, no. 1 (February 22, 2010): 5–24.

10. Brigaud F, Chapman DS and Le Douaran S: “Estimating Thermal Conductivity in Sedimentary Basins Using Lithologic Data and Geophysical Well Logs,” AAPG Bulletin 74, no. 9 (September 1990): 1459–1477.

McKenna TE, Sharp JM Jr and Lynch FL: “Thermal Conductivity of Wilcox and Frio Sandstones in South Texas (Gulf of Mexico Basin),” AAPG Bulletin 80, no. 8 (August 1996): 1203–1215.

For more on petroleum system modeling: 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.

11. Orlov VP and Laverov NP (eds): Kola Superdeep Well: Scientific Results and Research Experience. Moscow: Technoneftegaz, 1998 (in Russian).

Burkhardt H, Honarmand H and Pribnow D: “Test Measurements with a New Thermal Conductivity Borehole Tool,” Tectonophysics 244, nos. 1–3 (April 15, 1995): 161–165.

12. Popov YA, Pribnow DFC, Sass JH, Williams CF and Burkhardt H: “Characterization of Rock Thermal Conductivity by High-Resolution Optical Scanning,” Geothermics 28, no. 2 (April 1999): 253–276.

KTB is the Kontinentales Tiefbohrprogramm der Bundesrepublik Deutschland, or German Continental Deep Drilling Program. For more on the KTB borehole: Bram K, Draxler J, Hirschmann G, Zoth G, Hiron S and Kühr M: “The KTB Borehole—Germany’s Superdeep Telescope into the Earth’s Crust,” Oilfield Review 7, no. 1 (January 1995): 4–22.

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allows the first sensor to register the ambient surface temperature under laboratory condi-tions. After a spot on the surface has been heated by the source—either a laser or a focused elec-tric light—one or two trailing sensors record the rise in temperature along lines parallel to the trace of the heated spot.13

Optical scanning uses tailored theoretical models to determine thermal properties from the

recorded temperature profiles. According to a model for the arrangement with two thermal sen-sors flanking the heat source, the maximum tem-perature rise seen by the trailing sensor is directly proportional to the source power, in watts, and inversely proportional to the product of the source-sensor separation and the sample’s thermal con-ductivity. This model can be inverted for the unknown thermal conductivity, given the mea-

sured temperature rise, source-to-sensor distances and source power. Alternatively, thermal conduc-tivity can be determined by comparing the tem-perature rise in the sample with that in a standard material of known conductivity placed next to it in the scan line. Another common configuration adds a second trailing sensor offset from the main scan line and uses two different standards flanking the sample to determine both thermal diffusivity and thermal conductivity. Aligning the axis of the scan along various directions through the rock allows characterization of the thermal conductivity of an anisotropic sample; full characterization requires scans along three distinct directions lying in two nonparallel planes.

Nearly all of the core samples from the KTB borehole were crystalline metamorphic rocks, chiefly amphibolites and gneisses, possessing a dis-tinctive foliation and requiring measurement of thermal conductivity parallel and perpendicular to their planar fabric.14 The joint international study of cores from the KTB borehole demonstrated that measurements of thermal properties by optical scanning compare well in precision, or repeatabil-ity, and in accuracy with measurements made by the divided bar and line source methods (left). The divided bar measurements were conducted with a device maintained and continually improved since the late 1960s by the US Geological Survey; the line source measurements were conducted with a unit specially constructed at the Technische Universität Berlin to work on cores from deep scientific wells. Differences between optical scanning and divided bar measurements averaged 2.1%, with a standard deviation of 6.5%; the closest agreement was for measurements in directions parallel to rock folia-tion. Differences between optical scanning and line source measurements were generally less than 5%.15

The accuracy and reliability of thermal properties measured by optical scanning have since been con-firmed on thousands of core samples. Many of these cores come from deep scientific wells drilled into large impact structures such as the Puchezh-Katunki impact structure in Russia, the Ries impact structure in Germany, the Chesapeake crater in the US and the Chicxulub crater in Mexico.16 This work established that optical scanning measurements can be accurate to within 1.5% for thermal conductivity within the range 0.1 to 50 W/m°K and to within 2% for thermal diffusivity in the range 0.1 × 10–6 to 5 × 10–6 m2/s. The remote sensing and nondestructive nature of optical scanning allows easy, repeated testing of samples of a variety of sizes; the laboratory instrument used in the scientific studies characterizes samples from 1 to 70 cm [0.4 to 28 in.] long.

Optical scanning measurements are also rela-tively immune to the shape and quality of the sample

> Thermal properties of rock samples from the superdeep KTB borehole. A study of core samples from the KTB borehole in Germany (top) demonstrated that measurements of thermal conductivity by optical scanning compare well with measurements made by the divided bar and line source methods. The crossplot at upper left, for example, shows good agreement between optical scanning measurements of thermal conductivity and divided bar measurements on 36 different samples cut from the KTB cores. Scientists prepared this collection so that the same physical rock sample could be used in both instruments. The remaining crossplots compare one method against another when two different rock samples are cut from the same core. Open diamonds represent measurements in the direction parallel to the rock foliation; solid diamonds represent measurements perpendicular to the foliation. (Adapted from Popov et al, reference 12.)


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surface, tolerating up to 1 mm [0.04 in.] of roughness with little loss of accuracy. The scan speed is routinely set between 1 and 10 mm [0.04 and 0.4 in.] per sec-ond, which usually allows a throughput of about one sample per minute. Slower speeds and a smaller dis-tance between the heating spot and temperature sen-sor enlarge the measurement’s depth of investigation, which can be up to 3 cm in samples with moderate to high thermal conductivity.

A new instrument developed at Schlumberger Moscow Research Center and engineered at the Schlumberger Innovation Center in Salt Lake City, Utah, USA, has further refined the specifications for rapid, high-resolution optical measurement of thermal properties (right). This instrument for rock profiling, housed at TerraTek Rock Mechanics and Core Analysis Services laboratory, can detect heterogeneity in thermal conductivity and thermal diffusivity—or volumetric heat capacity, as calcu-lated from these two quantities—with a resolution better than 0.4 mm [0.016 in.] at a core scanning velocity of 3.0 mm/s [0.12 in./s] (below right).17

13. Popov Yu A: “Theoretical Models for Determination of the Thermal Properties of Rocks on the Basis of Movable Sources of Thermal Energy, Part I,” Geologiya i Razvedka (Geology and Prospecting) no. 9 (September 1983): 97–105 (in Russian).

Popov Yu A: “Theoretical Models for Determination of the Thermal Properties of Rocks on the Basis of Movable Sources of Thermal Energy, Part II,” Geologiya i Razvedka (Geology and Prospecting) no. 2 (February 1984): 81–88 (in Russian).

Popov Yu A: “Peculiarities of the Method of Detailed Investigations of Rock Thermal Properties,” Geologiya i Razvedka (Geology and Prospecting) no. 4 (April 1984): 76–84 (in Russian).

14. Foliation is the layered fabric—the orientation, arrangement and texture of minerals, grains and other constituents in rock—of metamorphic rocks that have been strongly compressed in one direction.

15. Popov et al, reference 12. 16. Popov Yu, Pohl J, Romushkevich R, Tertychnyi V and

Soffel H: “Geothermal Characteristics of the Ries Impact Structure,” Geophysical Journal International 154, no. 2 (August 2003): 355–378.

Popov Yu, Romushkevich R, Korobkov D, Mayr S, Bayuk I, Burkhardt H and Wilhelm H: “Thermal Properties of Rocks of the Borehole Yaxcopoil-1 (Impact Crater Chicxulub, Mexico),” Geophysical Journal International 184, no. 2 (February 2011): 729–745.

Mayr SI, Burkhardt H, Popov Y, Romushkevich R, Miklashevskiy D, Gorobtsov D, Heidinger P and Wilhelm H: “Physical Rock Properties of the Eyreville Core, Chesapeake Bay Impact Structure,” in Gohn GS, Koeberl C, Miller KG and Reimold WU (eds): The ICDP-USGS Deep Drilling Project in the Chesapeake Bay Impact Structure: Results from the Eyreville Core Holes. Boulder, Colorado, USA: The Geological Society of America, Special Paper 458 (2009): 137–163.

The Chicxulub crater is believed to be an imprint of the catastrophic asteroid impact that ended the age of dinosaurs. For more: Barton R, Bird K, Garcia Hernández J, Grajales-Nishimura JM, Murillo-Muñetón G, Herber B, Weimer P, Koeberl C, Neumaier M, Schenk O and Stark J: “High-Impact Reservoirs,” Oilfield Review 21, no. 4 (Winter 2009/2010): 14–29.

17. Popov Yu, Parshin A, Chekhonin E, Gorobtsov D, Miklashevskiy D, Korobkov D, Suarez-Rivera R and Green S: “Rock Heterogeneity from Thermal Profiles Using an Optical Scanning Technique,” paper ARMA 12-509, presented at the 46th US Rock Mechanics/Geomechanics Symposium, Chicago, June 24–27, 2012.

> High-resolution optical scanner at the Schlumberger Innovation Center in Salt Lake City, Utah.


Thermal conductivity range 0.2 to 6.0 W/m°K

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>Resolution and repeatability of optical scanning. Two optical scans (red and blue, top) of a gravelly sandstone core illustrate the strong heterogeneity of thermal properties in rocks and the repeatability of optical measurements. Excess surface temperature—the temperature rise measured along a scan line (yellow, bottom) after heating by the laser—is proportional to thermal conductivity. The difference between the maximum and the minimum, divided by the average, gives a measure of property heterogeneity.


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Thermal Properties of Reservoir Rocks: A Growing DatabaseBecause scientists are now better able to mea-sure thermal properties, new avenues of petro-physics are opening up. Like many rock properties, thermal conductivity depends in com-plex ways on the composition and distribution of minerals in the rock matrix and fluids in its pore space. Studies going back to the 1950s have pro-vided data on this dependence, but until recently such studies were limited by measurement tech-niques that were unable to resolve layers and fractures at scales finer than a few centimeters. Moreover, conventional techniques cannot deter-mine thermal conductivity and diffusivity simul-taneously and have difficulty characterizing unconsolidated rocks and core samples and plugs saturated with brine, oil or gas.18

Optical scanning avoids nearly all of the obstacles hindering accurate, routine determina-tion of thermal rock properties. This method enabled a large petrophysical study of more than 8,000 samples, including sedimentary rocks of various lithologies, ages and geologic settings from eight geologic regions, to uncover new con-nections between thermal rock properties and the usual staples of petrophysical reservoir evalu-ation: porosity, permeability, electrical conduc-tivity, acoustic velocity and fluid saturation.19

Most of the cores in this study came from basins in petroleum provinces of the former Soviet Union (above left). Scientists measured the thermal conductivity of all samples under both dry and fluid-saturated conditions, and the high-resolution scans revealed several key fea-tures of this diverse collection.

Scientists first discovered a wide variation of thermal properties within individual dry samples. A simple measure of heterogeneity within a sam-ple is the difference between the maximum and minimum thermal conductivity measured along a scan line, divided by the average conductivity along the same line. This heterogeneity factor, expressed as a percentage, characterizes the range of conductivity in the sample as seen by optical scanning. Measured on dry samples, the factor varied from about 4% to 50% for rocks in the collection (left).

Second, and more interesting, was that the heterogeneity factor went no higher than about 15% when measured on samples saturated with water. This result could be explained by higher values of porosity in samples whose heterogene-ity factor, when dry, was above about 15%. Void space, or air, has essentially zero thermal con-ductivity, in contrast to most solid rock, and is distributed in a complex way at scales below the


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> Core samples from Russian oil provinces. Scientists have compared thermal conductivity measured by high-resolution optical scanning with other petrophysical properties on more than 8,000 core samples of sedimentary rocks from various petroleum provinces in Russia. The collection was supplemented by samples from deep scientific boreholes and oil fields in Germany, Mexico and the US.

> Heterogeneity of thermal conductivity and porosity. Heterogeneity of rock thermal properties is closely related to variations in porosity. In this plot, 50 clay-rich limestone samples, studied under dry and water-saturated conditions, are arranged in order of increasing heterogeneity as measured under dry conditions (blue). Heterogeneity is quantified as the difference between the maximum and minimum thermal conductivities measured along a scan line, divided by the average value along the line. When this heterogeneity factor of a dry sample is less than about 15%, it changes by only a few percent when the sample is saturated with water and scanned again (red). When the heterogeneity factor of a dry sample is greater than 15%, it generally changes dramatically after water saturation. Scientists traced this effect to large spatial variations of porosity in samples with dry heterogeneity factors above 15%. (Adapted from Popov et al, reference 12.)


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resolution of the optical scans—about 1 mm. When its low thermal conductivity is averaged with that of the rock matrix, void space has large effects on the result because an optical scan senses low and high values of conductivity depending on whether the heated spot contains more or less pore space. In contrast, when pore space is saturated with water, whose thermal conductivity is relatively close to that of solid rock, its effect on the average thermal conductiv-ity is much less significant.

Scientists have known for some time that changes in thermal properties are caused by the opening of microscopic cracks and fissures in rock samples brought from high pressure deep underground to atmospheric pressure at the sur-face.20 But high-resolution optical scans con-firmed the importance, for thermal properties, of even small variations in natural porosity in sedi-mentary rocks. The threshold of 15% to 20% in the heterogeneity factor is significant: When varia-tions along a scan line remain below this level on dry samples, saturating the rock with water does not change the measured range of scanned con-ductivity values. In such rocks, heterogeneity along a scan line arises directly from variations in composition or mineralogy of the rock matrix.

Optical scans have also revealed that anisot-ropy may be a key to unlocking new relationships among thermal and other petrophysical proper-ties. One example is the relationship between thermal conductivity and permeability (right). These two properties depend not only on the amount of pore space, but also on its distribution through the rock volume—in isolated pores or in connected pathways. When compared on a col-lection of rock samples, permeability and ther-mal conductivity often show a wide scatter. But when the samples are limited to rocks with a heterogeneity factor above 20%—that is, to sam-ples in which thermal conductivity is strongly affected by pore fluids—there appears to be a direct correlation between permeability and the percentage change in thermal conductivity in going from dry to water-saturated conditions. The relationship is strongest when both thermal con-ductivity and permeability are measured parallel

> Anisotropic thermal conductivity and permeability. Most sedimentary rocks have anisotropic thermal properties: Thermal conductivity measured in a direction parallel to the layering generally is 5% to 50% higher than its value measured perpendicular to the layering. Moreover, the value measured in each direction changes in going from dry to water-saturated conditions. The degree of thermal anisotropy and its change with fluid saturation are both related to permeability (top). Samples with higher thermal anisotropy generally have lower permeability. Moreover, the percentage change in thermal conductivity parallel to layering when going from dry to water-saturated conditions—a quantity labeled δk || in these plots—closely tracks the logarithm of permeability. Measurements on core samples collected throughout a 140-m [450-ft] depth interval in the Middle Ob’ province of Russia show that this correlation holds across different lithologies (bottom). (Adapted from Popov et al, reference 19.)


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18. Early studies of the thermal properties of fluid-saturated porous rocks include the following:

Asaad Y: “A Study of the Thermal Conductivity of Fluid Bearing Porous Rocks,” PhD thesis, University of California, Berkeley, USA, 1955.

Zierfuss H and van der Vliet G: “Laboratory Measurements of Heat Conductivity of Sedimentary Rocks,” AAPG Bulletin 40, no. 10 (October 1956): 2475–2488.

Somerton WH: “Some Thermal Characteristics of Porous Rocks,” Petroleum Transactions, AIME 213 (1958): 375–378.

A large, published compilation of thermal rock properties is maintained by the US Geological Survey: Robertson EC: “Thermal Properties of Rocks,” Reston, Virginia, USA: US Geological Survey, Open File Report 88-441 (1988).

19. Popov Y, Tertychnyi V, Romushkevich R, Korobkov D and Pohl J: “Interrelations Between Thermal Conductivity and Other Physical Properties of Rocks: Experimental Data,” Pure and Applied Geophysics 160, no. 5–6 (2003): 1137–1161.

20. Walsh JB and Decker ER: “Effect of Pressure and Saturating Fluid on the Thermal Conductivity of Compact Rock,” Journal of Geophysical Research 71, no. 12 (June 15, 1966): 3053–3061.

Pribnow D, Williams CF, Sass JH and Keating R: “Thermal Conductivity of Water-Saturated Rocks from the KTB Pilot Hole at Temperatures of 25 to 300°C,” Geophysical Research Letters 23, no. 4 (February 15, 1996): 391–394.

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to any layering. A conclusion of the large study of samples from Russian oil fields was that a specific relative change of thermal conductiv-ity—defined as the percentage change in ther-mal conductivity in the direction parallel to layering when going from dry to water-saturated conditions—may be the single most important thermal property for the petrophysical charac-terization of reservoir rocks.21

Understanding these subtleties enabled sci-entists to discern new correlations relating ther-mal conductivity to porosity, acoustic velocity and electrical resistivity (left). These functional mappings hold promise in both directions: Going from the standard petrophysical properties to thermal conductivity opens the possibility of detecting changes in thermal properties far from the wellbore by remote geophysical sensing with electrical or seismic methods; going in the reverse direction enables high-resolution optical scans to explore the petrophysical heterogeneity of rocks at both macroscopic and microscopic scales. Thermal rock properties may also help to quantify this multiscale heterogeneity in the evaluation of unconventional reservoirs such as gas shale.22

Thermal Properties at Reservoir ConditionsOptical scanning provides rapid measurements of thermal properties under normal laboratory conditions—ambient temperature and atmo-spheric pressure. To calibrate these measure-ments to conditions in the reservoir, a special chamber was built at the Schlumberger Moscow Research Center to study the influence of ele-vated temperature and pressure on thermal properties (next page). The new device employs a variation of the line source method to deter-mine thermal conductivity and diffusivity at temperatures up to 250°C [480°F] and at pres-sures up to 200 MPa [29,000 psi]. Pore pressure in the sample and axial and lateral components of confining stress can be varied independently within the chamber.23

Thermal conductivity and diffusivity usually have an inverse relationship with temperature. For example, under an increase of temperature from 25°C to 100°C [77°F to 212°F], thermal con-ductivity in core samples from the Yarega oil field decreased by 50% while thermal diffusivity decreased by 70%. A suite of measurements on samples selected from different reservoir rocks determined average trends for changes in thermal properties with temperature, which were then applied to all measurements in the database.

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> Correlation of thermal conductivity with porosity, acoustic velocity and electrical resistivity. Thermal conductivities of samples from the Yarega field show good correlation with porosity (top) and acoustic velocity (center). The solid lines in the top two panels are based on best least-squares fits to the measurements for curves with an exponential dependence of thermal conductivity on porosity or on acoustic velocity. Measurements on samples from western Siberia (bottom) show a correlation between thermal conductivity and resistivity. The solid lines in the bottom plots are best fits to the measurements for curves with a logarithmic dependence of thermal conductivity on the logarithm of resistivity.

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To connect thermal and mechanical proper-ties, a new instrument was developed at the Schlumberger Moscow Research Center to mea-sure the thermal expansion of core samples over a range of typical reservoir temperatures. The instrument, which uses a standard test method called a quartz-rod dilatometer, accommodates either cube-shaped samples or standard cylindri-cal core plugs used in petrophysical studies— 3 cm in diameter and length—and can measure anisotropic thermal expansion coefficients by ori-enting the same sample in different positions. This measurement technique gives results that are more consistent than conventional approaches in which thermal expansion along a variety of directions is measured on three different samples cut from the same rock core. A typical measure-ment sequence, which takes up to 12 hours, deter-mines the coefficient of thermal expansion at temperatures from 20°C to 300°C [70°F to 572°F] in temperature steps of 20°C.24

A second instrument at TerraTek provides thermal expansion measurements at elevated pressure. The device accommodates dry or satu-rated cylindrical plugs 5 cm [2 in.] long and 2.5 to 3.8 cm [1 to 1.5 in.] in diameter. The specimen can be loaded axially and radially in two direc-tions and subjected to a maximum hydrostatic confining stress of 27 MPa [3,900 psi]. The device measures thermal expansion coefficients at tem-peratures up to 200°C [400°F] in a few tempera-ture steps.25

Thermal Properties in Russian Heavy Oil FieldsSince its introduction in the 1980s, the optical scanning method has measured thermal proper-ties of more than 80,000 rock samples. About 10% of the samples come from 15 oil and gas fields in Russia.26 This growing database of reservoir ther-mal properties is beginning to change the way petrophysicists regard the importance of hetero-geneity in EOR processes.

Thermal rock properties measured by scans of more than 500 cores from the production zone and surrounding formations at Yarega field, for example, showed variations up to 150% over dis-tances of a few meters. The largest variations cor-related generally with changes in lithology, but the degree of heterogeneity in individual dry samples was not expected. Moreover, differences in thermal conductivity and diffusivity of up to

21. Popov et al, reference 19.22. Popov et al, reference 17.23. Popov YA, Spasennykh MY, Miklashevskiy DE,

Parshin AV, Stenin VP, Chertenkov MV, Novikov SV and Tarelko NF: “Thermal Properties of Formations from Core Analysis: Evolution in Measurement Methods, Equipment, and Experimental Data in Relation to Thermal EOR,” paper CSUG/SPE 137639, presented at the Canadian Unconventional Resources and International Petroleum Conference, Calgary, October 19–21, 2010.

>Measuring thermal properties at high temperature and pressure. Scientists at Schlumberger Moscow Research Center constructed a chamber (top) to determine rock thermal properties at reservoir conditions. The measurement cell (bottom left), which employs a version of the line source method, was calibrated on quartz crystals, a material with well-known anisotropic thermal properties. Measurements (bottom right) indicate that values for the thermal conductivity along the principal axes (1, 2 and 3) of the quartz thermal conductivity tensor measured at different temperatures and pressures with the new instrument (solid circles) compare well with published results (open circles). (Adapted from Popov et al, reference 23.)


Platinum line sourcePlatinum

line source

Rock sample

PlatinumpotentialleadPlatinum

potentiallead

12

11

10

9

8

7

6

420 40 60 80 100 120 140

123

5Ther

mal

con

duct

ivity

, W/m

°K

Temperature, °C

0.1 25 50 80 100 130Pressure, MPa

Side (overburden)pressure

Pressure for axialstress

Lower internal screw

Lower power gate

External heater

Rock sample

Perforated container

Elastic cuff

Sealing rubber

Upper power gate

Input and output wires

Axial stress gauge

Heat screen

Heat insulating disks

Rubber rings

Rubber rings

Plunger

Water thermostat

Pore pressure

24. Popov Yu, Parshin A, Miklashevskiy D and Abashkin V: “Instrument for Measurements of Linear Thermal Expansion Coefficient of Rocks,” paper ARMA 12-510, presented at the 46th US Rock Mechanics/Geomechanics Symposium, Chicago, June 24–27, 2012.

ASTM International: “Standard Test Method for Linear Thermal Expansion of Solid Materials with a Push-Rod Dilatometer,” West Conshohocken, Pennsylvania, USA, ASTM E228-11, April 2011.

25. Popov et al, reference 24. 26. Popov et al, reference 23.

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36 Oilfield Review

120% were observed among nearly identical rock samples saturated with air, oil or water (left).

Overall, the ranges of thermal properties seen in the Yarega study ran from 0.8 to 5.2 W/m°K for thermal conductivity and from 1.1 to 3.4 MJ/m3°K for volumetric heat capacity. Coefficients of lin-ear thermal expansion, measured on samples from Yarega under reservoir conditions, varied by more than a factor of two, from 8 × 10–6 to 17 × 10–6 per °K.

This variation far exceeds what had been observed in previous studies. Optical scanning and complementary measurements are revealing, possibly for the first time, the natural variability of thermal properties in reservoirs—caused either by natural heterogeneity in rock texture, mineral and organic composition, or by changes in fluid saturation, temperature and pressure. All these factors affect the flow of heat into the res-ervoir and therefore the production forecasts for a thermal recovery project.

Precise Design and Control of Thermal EOR Estimating the economics of thermal EOR requires that operators accurately predict the amount of additional hydrocarbon that will be produced from a field and the production rates of wells following stimulation by a given amount of heat. The thermal properties used in these reservoir simulations are often derived from theoretical models, called mix-ing laws, that estimate the combined thermal properties of a volume of rock and pore fluid from the volume fractions of its constituents.27

27. The bulk physical properties of a composite material generally cannot be precisely calculated without knowledge of the microscopic distribution of its constituents. Mixing laws are mathematical combinations of the constituent properties to estimate bulk properties. Examples are the weighted arithmetic mean, weighted harmonic mean, weighted geometric mean and Hashin-Shtrikman model.

For more on mixing laws see: Berryman JG: “Mixture Theories for Rock Properties,” in Ahrens TJ (ed): Rock Physics & Phase Relations: A Handbook of Physical Constants. Washington, DC: American Geophysical Union (1995): 205–228.

Zimmerman RW: “Thermal Conductivity of Fluid-Saturated Rocks,” Journal of Petroleum Science and Engineering 3, no. 3 (1989): 219–227.

28. Popov Y, Parshin A, Ursegov S, Taraskin E, Chekhonin E, Andrianov N, Bayuk I and Pimenov V: “Thermal Reservoir Simulation: Thermal Property Data Uncertainties and Their Influence on Simulation Results,” paper WHOC12-291, presented at the World Heavy Oil Congress, Aberdeen, September 10–13, 2012.

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

30. For more on asphaltenes: Akbarzadeh K, Hammami A, Kharrat A, Zhang D, Allenson S, Creek J, Kabir S, Jamaluddin A, Marshall AG, Rodgers RP, Mullins OC and Solbakken T: “Asphaltenes—Problematic but Rich in Potential,” Oilfield Review 19, no. 2 (Summer 2007): 22–43.

> Variation of rock thermal properties. Thermal properties at the Yarega oil field show large variations—up to 150%—over a 50-m [166-ft] interval covering the depths of thermal mining. Each data point represents a separate core sample measured under various conditions. Colored lines represent moving averages of the data. (Adapted from Popov et al, reference 23.)


X850 1 2 3 4 5 6 0.5 1.0 1.5 2.0 2.5 0.5 4.0

X90

X95

Y00

Y05

Y10

Y15

Y20

Y25

Y30

Dept

h, m

Dry sample Oil-saturated sample Water-saturated sample

Quartz sandstone and leucoxene sandstone

Quartz sandstone

Siltstone with layers of sandstone and silty sandstone

Siltstone

Basalt

Y35

Y40

1.0 1.5 2.0 3.02.5 3.5

Thermal Conductivity, W/m°K Thermal Diffusivity, 10–6 m2/s Volumetric Heat Capacity, MJ/m3°K

>Models of rock thermal properties. Reservoir engineers use predictive models called mixing laws to calculate a rock’s bulk thermal conductivity as a function of porosity from the conductivities of the solid matrix and saturating fluid. Each model employs different assumptions about the distribution of pore space. Predictions of standard mixing laws for oil-saturated quartz sandstones, with matrix thermal conductivity of 6.6 W/m°K and varying porosity, overlap the range of thermal conductivities measured by optical scanning of oil-saturated sandstones from the Yarega oil field (blue shading), but can differ from actual values for specific samples by more than 100%.


Porosity, %

Harmonic

Weiner

Hashin-Shtrikman

Landau

Arithmetic

Range of measurementsmade by optical scanning

Ther

mal

con

duct

ivity

, W/m

°K

00

2

4

6

10 20 30 40

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Values of thermal conductivity obtained from standard mixing laws may be compared with experimental results obtained by optical scan-ning (previous page, bottom). Although the mix-ing laws provide helpful bounds, the predicted values may differ from measured values by more than a factor of two. Similar large discrepancies are found between the default settings for ther-mal conductivity and volumetric heat capacity programmed in most reservoir simulators and the average values calculated from the database of measured thermal properties maintained at the Schlumberger Moscow Research Center.28

A simplified model of a SAGD process illus-trates the importance of using accurate rock prop-erties in simulations of thermal EOR (above). This

model has two horizontal wells crossing a 150-m by 500-m by 25-m [490-ft by 1,640-ft by 80-ft] pay zone of uniform thermal and production prop-erties, typical of tar sand reservoirs. The key met-rics for a SAGD operation are the cumulative oil production (COP) and the cumulative steam/oil ratio (CSOR), which is the volume ratio of steam input to oil produced. This ratio largely determines efficiency of a steam injection process. Simulations in which the thermal conductivity and volumetric heat capacity were varied by factors of up to two—to reflect a range of uncertainties in reservoir properties—show production scenarios with rela-tive deviations in COP and CSOR of 20% to 50% persisting over the duration of the simulated SAGD operation.

The economic implications for the various scenarios differ dramatically from one another and, given the typical life of an EOR project, have long-term consequences. Production predictions based on empirically derived thermal rock prop-erties may provide field operators with realistic expectations for returns on capital investments.

Other ApplicationsMany oilfield processes other than thermal stim-ulation may benefit from operators having accu-rate knowledge of thermal properties surrounding the wellbore. A cementing operation, for exam-ple, has to maintain pressure in the annulus between the casing and the formation in the nar-row range between formation pore pressure and formation fracture pressure. This requirement holds over the full length of the wellbore from the start of the job until the cement fully cures. Since the curing process can raise the temperature of the slurry by more than 100°C [180°F], pressure and temperature in the annulus may be strongly affected by the thermal response of the surround-ing rock and its pore fluids. Knowing the actual values of thermal properties in a formation helps operators determine the best choice of cement mixtures and additives.29

Another important process governed in part by the temperature regime near the wellbore, and therefore by the surrounding distribution of thermal properties, is the precipitation of asphaltenes, which can choke off production by clogging flow pathways. Knowing where asphaltenes are likely to precipitate helps engi-neers design better well completions.30

Petroleum production is essentially a ther-momechanical process. Modern reservoir simu-lators calculate the pressure, volume and temperature changes accompanying mass and heat transfer during production or testing, but they often use average values of thermal proper-ties, usually based on point measurements on cores, to characterize the entire reservoir. The growing database of measurements made possi-ble by optical scanning shows that thermal rock properties vary significantly at both macroscopic and microscopic scales. Understanding the effects of heterogeneity in scaling up from high-resolution thermal scans of cores to full reser-voir simulations is a fundamental challenge for engineers constructing the next generation of reservoir models. —MO

> Sensitivity of a SAGD operation to reservoir thermal properties. In SAGD operations (top), steam is injected into a heater well and oil is produced from a producer well. Predictions of the performance over time of a SAGD operation—in terms of cumulative oil production (bottom left) and cumulative steam/oil ratio (bottom right)—vary with the modeled thermal properties of the reservoir zone. The base scenario (dashed black line) is modeled with an assumed, or measured, average volumetric heat capacity (VHC) and thermal conductivity (TC) for the reservoir zone. Variation in cumulative oil production from the base scenario is determined, on the low side, by doubling volumetric heat capacity (left, dashed red line), thereby reducing the temperature rise for a given amount of injected heat. Variation in oil production on the high side is determined by doubling thermal conductivity (left, red line), thereby increasing the speed at which the temperature rise at the heater well propagates into the reservoir. Increasing thermal conductivity or volumetric heat capacity drives the cumulative steam/oil ratio higher (right, red line) than its value in the base scenario (dashed black line). Relative changes (green) in oil production and steam/oil ratio in these different scenarios are as high as 40% in the early years of production and persist at levels above 20% for 10 years or more. (Adapted from Popov et al, reference 28.)


Number of years

Rela

tive

varia

tion,

%

Relativevariation Re

lativ

e va

riatio

n, %

Cum

ulat

ive

oil p

rodu

ctio

n, ×

105 m

3

00 5 10 15

0

10

20

30

40

50

0.5

1.5

3.5

2.5

1.0

2.0

3.0

4.0

TC, VHC × 2

TC × 2, VHC

TC, VHC

TC × 2, VHC × 2

Number of years

Heater well

Reservoir

Producer well

Cum

ulat

ive

stea

m/o

il ra

tio

00 5 10 15

0

10

20

30

40

50

60

1

3

7

50 110

Temperature, °C

170 230 290

5

2

4

6

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38 Oilfield Review

Basin to Basin:Plate Tectonics in Exploration

The principles of plate tectonics help explorers understand and evaluate hydrocarbon

plays. Since the start of the 21st century, these ideas have been successfully applied

to presalt basins and turbidite fans along the coasts of South America and western

Africa. Guided by global plate tectonics, exploration companies are applying winning

play strategies from one coast of the South Atlantic to discover and prove similar

plays on the opposite coast.

Ian BryantNora HerbstHouston, Texas, USA

Paul DaillyKosmos EnergyDallas, Texas

John R. DribusNew Orleans, Louisiana, USA

Roberto FainsteinAl-Khobar, Saudi Arabia

Nick HarveyNeftexAbingdon, England

Angus McCossTullow Oil plcLondon, England

Bernard MontaronBeijing, People’s Republic of China

David QuirkMaersk OilCopenhagen, Denmark

Paul TapponnierNanyang Technological UniversitySingapore

Oilfield Review Autumn 2012: 24, no. 3. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Steve Brown, Copenhagen, Denmark; George Cazenove and Jonathan Leather, Tullow Oil plc, London; James W. Farnsworth, Cobalt International Energy, Inc., Houston; Winston Hey, Houston; Susan Lundgren, Gatwick, England; and Richard Martin and Mike Simmons, Neftex, Abingdon, England.Petrel is a mark of Schlumberger.

New discoveries often emerge from previous suc-cesses. Once a play concept has proved commer-cially viable, oil companies are able to apply characteristics from their play to a regional or global framework in search of other accumula-tions. Through integration of exploration infor-mation, drilling data and geologic models from a successful play and through application of plate tectonic models, geoscientists are finding analog plays across ocean basins.

From the North Sea to the Gulf of Mexico and from offshore South America to offshore Africa, explorationists have discovered major oil and gas fields in continental margin systems. The Santos, Campos and Espirito Santo basins off the coast of Brazil contain prolific oil discoveries, and the application of plate tectonic concepts has enabled explorers to extend that play across the Atlantic to offshore western Africa. Within the last few years, exploration companies have applied prin-ciples of plate tectonics to extend and relate upper Cretaceous turbidite fan plays westward—from West Africa across the Equatorial Atlantic to French Guiana and Brazil. This article describes some of the fundamental concepts that today’s geoscientists use to extrapolate plays across ocean basins. Case studies demonstrate how explorers have used plate tectonics and regional geology to expand exploration efforts in both directions across the Atlantic Ocean.

Basic ConceptsBasins, petroleum systems and hydrocarbon plays are vital concepts in petroleum exploration. Basins collect the sediments that become the building blocks for petroleum systems. A petroleum system comprises an active source rock and the oil and gas derived from it that migrate to a reservoir and become confined there by a trap and seal.1 A play is a model used to explore for hydrocarbon depos-its having similar characteristics. Petroleum sys-tems may contain one or more plays, depending on the reservoir and style of trapping mechanism.2 Exploration experts systematically apply these concepts to locate prospects for drilling. Software platforms for databases, data integration and modeling are helping experts optimize their explo-ration workflows.

A basin is a depression in the Earth’s surface that accumulates sediments. Basins form when the Earth’s lithosphere is stretched, fractured, loaded down or compressed in response to global tectonic processes. These processes also govern the size and depth—the accommodation space—of a basin, while climatic conditions determine water and sediment input for the basin fill material.

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Basins may be deformed by tectonic motion: extension, compression, strike-slip motion or any combination thereof. Extension may cause normal faulting and may be accompanied by stretching, thinning and sagging of the crust. Compression results in thrust faulting, folding, shortening and thickening. Strike-slip motion gives rise to translation and lateral faulting. A combination of these phenomena produces

1. Al-Hajeri MM, Al Saeed M, Derks J, Fuch 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.

Stewart L: “The Search for Oil and Gas,” Oilfield Review 23, no. 2 (Summer 2011): 59–60.

2. Doust H: “Placing Petroleum Systems and Plays in Their Basin History Context: A Means to Assist in the Identification [of] New Opportunities,” First Break 21, no. 9 (September 2003): 73–83.

Doust H: “The Exploration Play: What Do We Mean By It?,” AAPG Bulletin 94, no. 11 (November 2010): 1657–1672.

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pull-apart basins, push-up blocks and transten-sion or transpression oblique slip. Thus, local or large-scale movements provide the impetus for creation of stratigraphic or structural traps. Stratigraphic traps result from facies changes or juxtaposition of impermeable and permeable strata. Structural traps form as a result of strata deformation. The tectonic and stratigraphic history of a basin gives it a global and regional setting for its formation, filling and deformation.3

Exploration teams composed of geologists, geo-chemists, paleontologists, geophysicists and petro-physicists unravel the history of a basin and sequence of tectonic events and cycles of sedimen-tation filling a basin. They identify source rocks within the basin and correlate them with known trapped hydrocarbons.The teams examine the geo-logic elements and processes that created known source rocks and traps to develop leads to other similarly generated accumulations (above). After further investigation, if the lead still appears to

have potential to trap hydrocarbons, it becomes a prospect.4

Once identified, the prospects are ranked according to uncertainty, risk, potential reward and market value of hydrocarbons.

Integrated software systems that incorporate mapping and petroleum systems and play analy-sis tools, such as the Petrel E&P platform, help geoscientists evaluate basins (next page).5 Geoscientists use them to construct and share geologic models in 3D and provide an environ-ment for storing data and models.

> Petroleum systems. Explorationists define the petroleum system as the geologic elements and processes that are essential for the existence of a petroleum accumulation. This cross section summarizes petroleum systems along a South Atlantic continental margin. The geologic elements must be present in the following order: The source rock contains organic matter, reservoir rock receives the hydrocarbons and has sufficient porosity and permeability for storage and recovery of hydrocarbons, sealing caprock is impermeable to keep the fluids in the reservoir and overburden rock buries the source rock to depths having the optimal temperature and pressure for source rock maturation and hydrocarbon generation. Rifting of the South Atlantic Ocean started with extension and faulting (black solid going to dashed lines) of continental crust (brown). The continental crust thinned and eventually split apart. As the two parts of the continental crust separated (only the right side is shown here), oceanic crust (gray) formed at a midocean ridge (not shown) during seafloor spreading. The continental margin is located where the thinned continental crust meets oceanic crust. Synrift lacustrine basins were preserved and filled with source (blue) and reservoir (white) rock that were eventually trapped and sealed underneath salt (purple). Hydrocarbons from synrift source rock migrated to limestone reservoirs (green bricks) that were buried and trapped beneath postsalt marls (green). The marls also provided source rock (dark green). During the Tertiary, clayey-sandy sediments (yellow and tan) buried the margin, providing source rock, reservoirs, caprock and overburden. [Illustration adapted from Huc AY: “Petroleum in the South Altantic,” Oil & Gas Science and Technology—Revue de l’Institut Français du Pétrole 59, no. 3 (May–June 2004): 243–253.]

Fig1_6

Clayey-sandysediments

Marls

Limestone

Salt

Synriftlacustrinesediments

Oceaniccrust Continental crust

Lithosphere

C

O

C

R

CR

O

Terti

ary

Cret

aceo

us

C

C

C

R

R

OverburdenCaprockReservoirsSource rocks

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By creating models at various scales, geo-scientists are able to develop geocellular mod-els from global to regional and local scales. This integration allows geoscientists to deter-mine, for example, whether a particular local channel-levee interpretation is consistent with the regional interpretation or whether a wide-spread organic-rich facies mapped at the tec-tonic plate scale corresponds to source rock facies in the prospect model of the targeted petroleum system.

3. A facies is a rock unit defined by characteristics that distinguish it from neighboring units.

For more on stratigraphic and structural traps: Caldwell J, Chowdhury A, van Bemmel P, Engelmark F, Sonneland L and Neidell NS: “Exploring for Stratigraphic Traps,” Oilfield Review 9, no. 4 (Winter 1997): 48–61.

For sequence stratigraphy: Neal J, Risch D and Vail P: “Sequence Stratigraphy—A Global Theory for Local Success,” Oilfield Review 5, no. 1 (January 1993): 51–62.

> Exploration software platform. Exploration experts combine seismic information, well logs, geochemical and heat flow data and other geologic data to work from basin to prospect scale (clockwise top center to middle right). Regional to prospect scale models of traps (top right) and reservoirs (middle right) built in the Petrel platform benefit from integration with structural restoration tools (bottom right) and petroleum system modeling (bottom center). Both petroleum system modeling and structural restoration tools may be used to gain an understanding of the geomechanics of the basin to guide evaluation of seals (bottom left) and plan exploration wells. Risk assessment tools allow exploration teams to assign uncertainty and risk to acreage and drillable prospects (middle left). Petroleum economic evaluation enables planning exploration portfolios (top left).

Fig2_1

Project and portfolio economics Model-based interpretation from basin to prospect Trap

Play and prospect evaluation Reservoir

Geomechanics and seal analysis Charge and timing petroleum system modeling Structural restoration

4. This chain of events from hydrocarbon source to its resting place in a distant reservoir applies to conventional petroleum systems. For unconventional systems, the source rock may also be the reservoir rock. Such unconventional systems include oil and gas from shale or coalbed methane.

McCarthy K, Rojas K, Niemann M, Palmowski D, Peters K and Stankiewicz A: “Basic Petroleum Geochemistry for Source Rock Evaluation,” Oilfield Review 23, no. 2 (Summer 2011): 32–43.

5. Al-Hajeri et al, reference 1.

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42 Oilfield Review

Because these various input data are con-strained by a stratigraphic model, the geocellular models are displayed not only in true vertical depth (TVD) or two-way traveltime, but also in geologic time (above). In addition, geologists are able to project characteristics of a given strati-

graphic interval to analogous strata in conjugate basins or in frontier areas. Geologists are also able to use qualities from a data-rich region to develop a sequence stratigraphic context for pre-dicting facies in data-poor regions.

Plate Boundaries and Rifted and Transform MarginsPlate tectonic science has established that the Earth’s outermost layer, the lithosphere, com-prises a number of major and many minor plates that move relative to one another (next page).6

> South Atlantic conjugate margins through geologic time. Two regional geologic models, built on opposing coasts of the South Atlantic, are constrained by a global sequence stratigraphic model. By assimilating interpretations into a 3D environment using the Petrel platform, geoscientists have derived a workflow to populate a tectonic plate–scale geocellular model for the sedimentary evolution of the margins through geologic time as illustrated in the exploded view of the South Atlantic continental margins from Precambrian time at the deepest surface to the present at the upper surface. Data assembled in this way on a common software platform allow explorationists to project petroleum system facies to a data-poor region by using sequence stratigraphy and elements of petroleum system modeling from a data-rich region to correlate and extrapolate associated facies. A recent example of this approach may be found along the transform margin where successful exploration concepts developed in Turonian-age lowstand turbidite fans offshore Ghana have been applied offshore French Guiana, leading to the recent Zaedyus discovery within similar deposits. Visualized in geologic time, these lowstand systems may be explored with their associated petroleum elements. Compelling evidence from wireline log responses, hinterland cooling events and biostratigraphically constrained unconformities were integrated; the results suggest that Campanian-age lowstand deposits may also provide attractive reservoir targets in the Guyana-Suriname basin offshore northern South America. The Campanian stratigraphic interval, while not as well tested as the Turonian interval, has also been attracting interest on the African margin offshore Ghana, Liberia and Côte d’Ivoire. (Illustration used with permission from Neftex.)

Fig3_2

Jubilee discovery,Tano basin

Fig3_1

Present day

Azul and Cameia discoveries,Kwanza basin

Cretaceous

Precambrian

CretaceousPresent day Precambrian

Zaedyus discovery,Guyana-Suriname basin

Play projection

Tupi discovery,Santos-Campos basin

Extrusive volcanicsNondepositionOrganic-rich clasticsLacustrine faciesDeep marine sand-dominated clasticsParalic faciesDeep marine carbonatesShallow marine carbonatesDeep marine clasticsShallow marine clasticsTerrestrial sediments

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This motion is driven by the convection and flow of hot ductile material in the mantle underlying the lithosphere. The lithosphere consists of two layers: the crust and the lithospheric mantle.7 The crust is further divided into two categories. Continental crust is mostly of granitic composi-tion; its density averages about 2.7 g/cm3, and its thickness is about 35 km [22 mi] in most places but ranges from 20 to 70 km [12 to 43 mi]. Oceanic crust has a basaltic composition and is

denser and thinner than continental crust. Its density averages about 2.9 g/cm3, and its thick-ness ranges from 5 to 10 km [3 to 6 mi]. The higher density of the oceanic crust causes it to rest lower in the mantle than continental crust.

Over geologic time, tectonic plate motions have amalgamated small continents to form super-continents and separated them again into a collec-tion of smaller continents distributed across the planet. The most recent giant supercontinent,

Pangea, formed during the Paleozoic era, then was rifted apart beginning about 225 to 200 million years ago [Ma]. The breakup started with Pangea separating into the Laurasia and Gondwana super-continents in the north and south, respectively. The subsequent breakup of Laurasia and Gondwana resulted in the opening of the Atlantic and Indian oceans and evolved to the present day configuration of continents and oceans.

> Plates. The Earth’s lithosphere is divided into numerous plates. Relative motion of the plates (arrows) determines whether the plate boundaries are convergent, transform or divergent. [Map adapted from “Interpretative Map of Plate Tectonics,” an inset to Simkin T, Tilling RI, Vogt PR, Kirby SH, Kimberly P and Stewart DB: “This Dynamic Planet—World Map of Volcanoes, Earthquakes, Impact Craters, and Plate Tectonics,” US Geological Survey, Geologic Investigations Series Map I–2800 (2006).]

Fig4_3

Eurasia plate

Pacific plate

North America plate

Eurasia plate

Anatolia plate

Africa plate

Antarctica plateAntarctica plate

Scotia plate

Antarctica plate

Convergent boundary barbs pointto direction of convergence Major transform boundaryPossible boundary Divergent boundary Plate movement

Arabiaplate

Indiaplate

Australia plate

Australiaplate

Pacific plate

Nazca plate

Cocosplate

South America plate

Juan de Fucaplate

Philippineplate

Caribbean plate

6. The lithosphere is the 50 to 200 km [30 to 120 mi] thick, rigid outer layer of Earth; its thickness is determined by the depth of the brittle-to-ductile transition temperature, which is roughly 1,000°C [1,800°F]. The upper part of the lithosphere is the crust and the lower part is the lithospheric mantle.

For more on plate boundaries: Bird P: “An Updated Digital Model of Plate Boundaries,” Geochemistry Geophysics Geosystems 4, no. 3 (March 2003), http://dx.doi.org/10.1029/2001GC000252 (accessed August 21, 2012).

7. Earth’s mantle is the 2,900 km [1,800 mi] thick layer that lies between Earth’s crust and outer core. The mantle is divided into the upper mantle, transition zone and lower mantle. The upper mantle is about 370 km [230 mi] thick and divided into the lithospheric mantle and the asthenosphere.

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44 Oilfield Review

The plates move relative to one another and interact with each other at their boundaries (left). The three types of plate boundaries are the following: convergent, or compressional; trans-form, or strike slip; and divergent, or extensional.

At convergent plate boundaries, plates move toward one another. Plates respond in a number of ways when they collide, depending on whether the convergence is continent to continent, ocean to ocean or ocean to continent. Continent-to-continent convergence—collision—results in shortening and thickening of the crust. The colli-sion between the Indian and Asian continents is one example. This convergence created the Himalaya Mountains and Tibetan Plateau and resulted in the southeastward lateral escape of Sundaland and southeast China in the direction away from the collision between India and Asia.8

Ocean-to-ocean or ocean-to-continent conver-gence results in subduction: one oceanic plate dives under the other plate. An example of ocean-to-ocean convergence occurs at the Marianas Trench, where the Pacific plate plunges west-ward under the small Philippine plate in the western Pacific Ocean. Ocean-to-continent con-vergence occurs along the western Andes Mountains, where the Pacific plate dives east-ward under the South America plate.

At transform boundaries, plates slide past each other, which occurs along the San Andreas Fault in California, USA. This fault accommo-dates movement of the Pacific plate northward past the North America plate. The North and East Anatolian faults in Turkey are also trans-form boundaries. These faults accommodate the westward movement of the Anatolia plate toward the Mediterranean Sea as it escapes the compression between the converging Eurasia and Arabia plates.

At divergent plate boundaries, a plate splits, forming two smaller plates that move apart from each other. Divergent plate boundaries may start out as continental rift systems; in millions of years, these land-based rifts become oceanic rifts. Examples of modern-day continental rifts are the East African rift; the Lake Baikal rift, Russia; and the Basin and Range Province, western USA.

In continental rifts, the crust undergoes extension, faulting and thinning until it splits. At the split, a volcanic ridge forms as hot mantle material wells up to fill the void left by the sepa-rating plates. The mantle material of basaltic composition accretes to the plate edges, cools and forms new oceanic crust. As the plates move apart, the oceanic crust grows, building an ocean that widens between the slowly separating plates. The process is called seafloor spreading. The Red

>Midocean ridge and transform fault plate boundary. Midocean spreading (white and red arrows) rarely occurs along a single clean rift zone. Here, the divergent plate boundary (dashed yellow line) consists of two segments of a midocean ridge connected by a transform fault. In the transform fault, or the active part of the fracture zone between the ridge segments, the plates slide past each other in opposite directions (black opposing arrows). In the inactive part of the fracture zone, outside of the ridge segments, the plate sections are locked together and move in the same direction (black parallel arrows). (Adapted from Garrison TS: Oceanography: An Invitation to Marine Science, 4th ed. Pacific Grove, California, USA: Brooks/Cole Publishing Company, 2002.)

Fig6_1

Ocean crust

Midoceanridge

Plate boundary

Plate boundary

Fracturezone(inactive)

Transform fault(active part offracture zone)

Fracturezone(inactive)

LithosphereOceanic crust

Asthenosphere

> Plate boundaries. Earth’s lithospheric plates move relative to one another. This movement is accommodated along plate boundaries. Convergent boundaries occur where plates move toward one another. One plate may subduct—dive—under another; trenches mark the line of the bending, subducting plate. Chains of island arc stratovolcanoes may form along subduction zones above the downgoing plate. Transform boundaries occur where plates slide past one another; oceanic transform fault zones transfer seafloor spreading from one midocean ridge segment to another. Divergent plate boundaries occur where plates split apart at seafloor spreading ridges and continental rift zones. Hot spots occur where plumes of hot mantle material impinge on lithospheric plates; they may induce shield volcanoes and cause flood basalts to pour out over plates (not shown). [Image adapted from “Schematic Cross Section of Plate Tectonics,” an inset to Simkin T, Tilling RI, Vogt PR, Kirby SH, Kimberly P and Stewart DB: “This Dynamic Planet—World Map of Volcanoes, Earthquakes, Impact Craters, and Plate Tectonics,” US Geological Survey, Geologic Investigations Series Map I–2800 (2006).]

Convergentplate boundary

Trench Shieldvolcano

Hot spot

AsthenosphereOceanic crust

Lower mantle

Upper mantleUpper m

antleContinental crust

Subductingplate

Lithosphere

Island arcstratovolcano

Trench

Transformplate boundary

Divergentplate boundary

Oceanic spreadingridge

Convergentplate boundary

Continental rift zone(young plate boundary)

Fig5_1

Transform boundaryConvergent boundary

Plate

Asthenosphere

Divergent boundary

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Sea and Gulf of Aden rift that separates the Africa and Arabia plates is a young divergent plate boundary. The Mid-Atlantic Ridge, which encompasses the midocean rift and ridge that separates the Americas from Europe and Africa, is a mature divergent plate boundary.

As continents move apart, they rarely do so along a single separation zone or rift. Rather, the rift is a series of segments offset by trans-form faults and fracture zones. Transform faults are strike-slip faults that connect rift segments. They transfer the spreading motion or accom-modate spreading rate differences between rift segments; they are active only between rift seg-ments.9 Transform faults leave scars on the ocean floor called fracture zones. Transform faults and fracture zones are oriented perpen-dicular to the midocean ridge and parallel to the spreading direction; they mark the path of plate movement as the rifted continental mar-gins move farther apart.

The ages and thermal histories of oceanic rocks differ on opposite sides of transform faults. Along the fault, younger, hotter and lower density rocks are juxtaposed against older, colder and higher density rocks. Because they are hotter, the younger rocks are thermally uplifted to a higher elevation than their older, cooler and denser cross-fault neighbors, causing a difference in ocean floor elevation on either side of the fault. These elevation differences may remain as the rocks cool, leaving scars—fracture zones. Because the fracture zones are nearly parallel to the midocean ridge spreading direction—the direction of relative plate motion—they leave tracks of the opening of the ocean (previous page, bottom).

As seafloor spreading continues, previously connected continental margins move farther apart. A continental margin, where continental crust meets or transitions to oceanic crust, is a relic of faulting during continental breakup. Thus, continental margins that face a midocean rift commonly have overlaps and may also have transform and rifted margin segments. Transform margins occur where continents break up and separate by shear movement along transform strike-slip faults. Rifted margins form where con-tinents break up and separate by extensional movement perpendicular to coastlines and along dip-slip faults.

Gondwana BreakupThe relative movement of adjacent tectonic plates throughout geologic time has been quanti-fied by remote-sensing technologies. For conti-nents, scientists determine plate movement by

fitting apparent polar wander curves.10 For oceans, scientists determine plate movement from magnetic anomaly patterns caused by north-to-south polarity reversals of Earth’s mag-

netic field and from fracture zones on the ocean floor (below).11 However, there are no useful mag-netic anomalies to constrain the Gondwana breakup history during the Cretaceous period

8. Sundaland refers to the Sunda shelf region of Southeast Asia, which includes Malaysia, Sumatra, Java and Borneo. For more about the lateral escape of Southeast Asia and Sundaland: Tapponnier P, Lacassin R, Leloup PH, Schärer U, Zhong D, Wu H, Liu X, Ji S, Zhang L and Zhong J: “The Ailao Shan/Red River Metamorphic Belt: Tertiary Left-Lateral Shear Between Indochina and South China,” Nature 343, no. 6257 (February 1, 1990): 431–437.

9. Strike-slip displacement or motion refers to the horizontal movement of the other side of the fault relative to the reference side—the side on which one is standing, facing the fault. The motion is right lateral when the other side of the fault moves to the right and left lateral when the other side moves to the left.

10. For more on plate motions and polar wander: Besse J and Courtillot V: “Apparent and True Polar Wander and the Geometry of Geomagnetic Field Over the Last 200 Myr,” Journal of Geophysical Research 107, no. B11 (November 2002): EMP 6-1 to 6-31.

>Magnetic anomalies and seafloor spreading. Scientists obtained evidence of seafloor spreading by determining the polarity of magnetic anomalies on both sides of midocean ridges. Earth’s magnetic field changes its polarity from time to time. The ocean floor is youngest and hottest at the oceanic ridge spreading center and becomes progressively older and cooler toward the continent-ocean boundary. As the ocean floor rocks and their ferromagnetic minerals cool below the Curie temperature, the ferromagnetic minerals become magnetized in the direction consistent with the existing polarity of Earth’s magnetic field. Rocks displaying dominantly normal polarity, equivalent to present-day magnetism, are shown by black stripes on the plate cross section. Rocks with dominantly reverse polarity magnetism are shown as white stripes. The symmetry of the magnetic anomaly striping on either side of the ridge demonstrates the movement of the seafloor away from the spreading center. Dating each polarity shift—normal to reverse and reverse to normal—turns the magnetic anomaly map into an magnetochronology map for seafloor spreading; the age of each reversal is an isochron (white lines)—a contour of time—and the time interval between magnetic reversals is a magnetic chron (MC), during which Earth’s magnetic field is dominantly, or constantly, one polarity.

Seafloor spreading

Magnetic chrons

Oceaniccrust

Plate temperature and age

Hot andyoung

Coldand old

Lithosphere

MC6 MC5 MC5 MC6MC4 MC4MC3 MC3MC2 MC2MC1 MC1

Reverse polarity

Normal polarity

Fig7_1

Isochrons

Midocean ridge

Isochrons

Besse J and Courtillot V: “Correction to ‘Apparent and True Polar Wander and the Geometry of Geomagnetic Field Over the Last 200 Myr,‘” Journal of Geophysical Research 108, no. B10 (October 2003): EMP 3-1 to 3-2.

11. For more on plate motions, magnetic anomalies and seafloor spreading: Hellinger SJ: “The Uncertainties of Finite Rotations in Plate Tectonics,” Journal of Geophysical Research 86, no. B10 (October 1981): 9312–9318.

Karner GD and Gambôa LAP: “Timing and Origin of the South Atlantic Pre-Salt Sag Basins and Their Capping Evaporates,” in Schreiber BC, Lugli S and Babel M (eds): Evaporites Through Space and Time. London: The Geological Society, Special Publication 285 (January 2007): 15–35.

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from roughly 120 to 84 Ma because Earth’s mag-netic field was stable and did not experience magnetic polarity reversals during that interval.12 Nonetheless, through dating of the flood basalts that poured over the Gondwana continent, geo-scientists generally agree that the breakup of the Gondwana supercontinent, which resulted in the opening of the South Atlantic Ocean and the separation of the South America and Africa plates, started about 130 Ma during the Early Cretaceous epoch. The breakup started in the south, moved progressively north and was com-pleted about 20 to 30 million years later during the Aptian to Albian geologic ages.13 The central

segment opened later because the continental plate was hotter and softer there. Consequently, it stretched further and reached a higher eleva-tion because of thermal uplift before breakup.

The South Atlantic Ocean extends from the Marathon Fracture Zone (FZ) in the north to the Antarctic Plate in the south and may be divided into four segments separated by major FZs that cross the Atlantic Ocean (above).

Adjacent to the Rio Grande FZ, the Rio Grande Rise and the Walvis Ridge originated from the Tristan da Cunha hot spot that is responsible for the Paraná and Etendeka flood basalts in Brazil and Namibia, respectively.14 When the ocean opened, the Rio Grande Rise and Walvis

Ridge formed as the South America plate drifted to the NW and the African plate drifted NE rela-tive to the Tristan da Cunha hot spot. The result-ing ridges formed a broad volcanic high that isolated the central segment of the South Atlantic Ocean from encroachment by marine water from the southern segment.

The basin filling histories of the central and southern segments of the South Atlantic differ from one another.15 In particular, the central seg-ment is dominated by thick salt basins that formed during the Aptian age (125 to 112 Ma), whereas the continental margins of the southern segment subsided at the margins of an open ocean.

> Tectonic map of the South Atlantic Ocean at the end of magnetic polarity chron 34 (MC34, 84 Ma). The red line represents the midocean ridge at the end of MC34. From north to south, the South Atlantic Ocean is divided into the Equatorial, Central, Southern and Falkland segments, bounded by the Marathon, Ascension, Rio Grande and Agulhas-Falkland fracture zones (FZs). The black dots show the approximate locations of the discoveries of Tupi offshore Brazil, Azul and Cameia offshore Angola, Jubilee offshore Ghana and Zaedyus offshore French Guiana. (Adapted from Moulin et al, reference 12.)

Fig8_1

AFRICA

SOUTHAMERICA

Marathon FZ

Chain FZ

Romanche FZ

Potiguar basin

Ascension FZ

Kwanzabasin

Gabonbasin

Congobasin

Namibebasin

Namibiabasin

Rawsonbasin

Pelotasbasin

ParanáProvince

Sergipe-Alagoas

basin

WalvisRidge

EspíritoSantobasin

Camposbasin

Gulf ofGuinea

Santosbasin

Rio Grande FZ

Agulhas-Falkland FZ

Rio GrandeRise

Tristan da Cunhahot spot

GuineanPlateau

DemeraraPlateau

Equatorial Segment

Central Segment

Southern Segment

Falkland Segment

Cratons

Cretaceousvolcanism

MidoceanridgeAptian salt

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The equatorial South Atlantic segment began to open later in the Early Cretaceous epoch—around 112 Ma.16 In its northern latitudes, this segment encompasses the Demerara plateau of Suriname and French Guiana and the Guinea pla-teau in West Africa. In its southern latitudes, it includes coasts of northern Brazil, Côte d’Ivoire and Ghana.17 The opening of the equatorial seg-ment, unlike the other segments, was not perpen-dicular to the continental margins because some of the plate motion was taken up by oblique movement or sideways tearing along faults.18

Geologists’ understanding of the geologic events that controlled geography, climate and basin history are based on the principles of plate tectonics. These principles form the foundation for developing exploration plays. Discoveries in the presalt and transform margin basins along the South American and western African coasts since 2006 illustrate these points.

Matching Salt Basins: From Brazil to AngolaThe Lula oil field—renamed from Tupi in 2010 to honor former Brazilian president Luiz Inacio Lula da Silva—was discovered in 2006 within

the Santos basin by Petróleo Brasileiro SA, or Petrobras.19 The discovery was made beneath Aptian salt on the Brazilian rifted margin of the central South Atlantic and established the pre-salt play.20

The presalt fields offshore Brazil are charged with hydrocarbons migrating from organic-rich source rocks deposited within anoxic lakes that developed around the time the South Atlantic was forming. At the start of the Aptian age, continental rifting ended and seafloor spreading began; how-ever, lake, rather than marine, conditions pre-vailed as the region was uplifted above the mantle plume of the Tristan da Cunha hot spot. In these lakes above the rifted continental margins, unusual carbonates were deposited during the Early Aptian (123 to 117 Ma). Similar to the pro-cess in present-day Lake Tanganyika in East Africa, shallow lacustrine carbonates were depos-ited during slow deepening of the lakes. Within the Early Aptian carbonates, the fossil record shows coquina strata overlain by microbialite strata as conditions changed from fresh to hypersaline water when the climate became more arid.21 These

carbonates form the reservoirs of Brazil’s Santos and Campos presalt basins.

With increased aridity during the Late Aptian (117 to 113 Ma), the basins became conducive to deposition of thick, 800- to 2,500-m [2,600- to 8,200-ft] layered evaporite sequences. Evaporites in the Santos basin show a history of rapid pre-cipitation of mostly halite from marine waters, followed by slow precipitation of complex salts. These later salts precipitated from highly con-centrated brines augmented by hydrothermal processes involving a fluid-rock chemical exchange with basaltic rock. The first 600 m [2,000 ft] of these evaporites are formed by two massive halite layers separated by a thin anhy-drite layer. The top of the evaporite sequence shows a number of deposition cycles with potas-sium- and magnesium-rich layered evaporites.22 This entire evaporite sequence precipitated in a deep rift lake behind the barrier created by the Walvis Ridge and Rio Grande Rise. This barrier was penetrated by deep fissures along which marine waters traveled, interacting chemically with the basaltic wall rock and leaking into the evaporating lake.

12. Torsvik TH, Rousse S, Labails C and Smethurst MA: “A New Scheme for the Opening of the South Atlantic Ocean and the Dissection of an Aptian Salt Basin,” Geophysical Journal International 177, no. 3 (June 2009): 1315–1333.

Moulin M, Aslanian D and Unternehr P: “A New Starting Point for the South and Equatorial Atlantic Ocean,” Earth-Science Reviews 98, no. 1–2 (January 2010): 1–37.

Blaich OA, Faleide JI and Tsikalas F: “Crustal Breakup and Continent Ocean Transition at South Atlantic Conjugate Margins,” Journal of Geophysical Research 116, B01402 (January 2011): 1–38.

Cartwright J, Swart R and Corner B: “Conjugate Margins of the South Atlantic: Namibia–Pelotas,” in Roberts DG and Bally AW (eds): Regional Geology and Tectonics: Phanerozoic Passive Margins, Cratonic Basins and Global Tectonic Maps, Vol. 1c. Amsterdam, The Netherlands: Elsevier BV (2012): 202–221.

Mohriak WU and Fainstein R: “Phanerozoic Regional Geology of the Eastern Brazilian Margin,” in Roberts DG and Bally AW (eds): Regional Geology and Tectonics: Phanerozoic Passive Margins, Cratonic Basins and Global Tectonic Maps, Vol. 1c. Amsterdam, The Netherlands: Elsevier BV (2012): 222–283.

13. Szatmari P: “Habitat of Petroleum Along the South Atlantic Margins,” in Mello MR and Katz BJ (eds): Petroleum Systems of South Atlantic Margins. Tulsa: The American Association of Petroleum Geologists, AAPG Memoir 73 (2000): 69–75.

14. Hot spots are surface manifestations of mantle plumes, which are stationary thermal anomalies that produce thin upwelling conduits of magma within the mantle. Hot spot volcanism yields flood basalts and long linear chains of volcanoes within tectonic plate interiors; along each chain, the volcanoes become progressively older in the direction of plate movement.

Wilson M: “Magmatism and Continental Rifting During the Opening of the South Atlantic Ocean: A Consequence of Lower Cretaceous Super-Plume Activity?,” in Storey BC, Alabaster T and Pankhurst RJ (eds): Magmatism and the Causes of Continental Break-Up. London: The Geological Society, Special Publication 68 (1992): 241–255.

Quirk DG, Hertle M, Jeppesen JW, Raven M, Mohriak W, Kann DJ, Nørgaard M, Mendes MP, Hsu D, Howe MJ and Coffey B: “Rifting, Subsidence and Continental Break-Up Above a Mantle Plume in the Central South Atlantic,” in Mohriak WU, Danforth A, Post PJ, Brown DE, Tari GC, Nemcok M and Sinha ST (eds): Conjugate Divergent Margins. London: The Geological Society, Special Publication 369 (in press).

15. Séranne M and Anka Z: “South Atlantic Continental Margins of Africa: A Comparison of the Tectonic vs. Climate Interplay on the Evolution of Equatorial West Africa and SW Africa Margins,” Journal of African Earth Sciences 43, no. 1–3 (October 2005): 283–300.

16. Moulin et al, reference 12.17. The Guyanas, or Guianas, is the region of northern South

America that includes the nations of Suriname, Guyana and French Guiana. West Africa, or western Africa, is the westernmost region of the African continent and its southern edge extends along the northern coastline of the Gulf of Guinea and includes, from east to west, Nigeria, Togo, Benin, Ghana, Côte d’Ivoire, Liberia, Sierra Leone and Guinea.

18. Darros de Matos RM: “Tectonic Evolution of the Equatorial South Atlantic,” in Mohriak W and Talwani M (eds): Atlantic Rifts and Continental Margins. Washington, DC: American Geophysical Union, Geophysical Monograph 115 (2000): 331–354.

Mascle J, Lohman P, Clift P and ODP 159 Scientific Party: “Development of a Passive Transform Margin: Côte d’Ivoire–Ghana Transform Margin—ODP Leg 159 Preliminary Results,” Geo-Marine Letters 17, no. 1 (February 1997): 4–11.

Darros de Matos RM: “Petroleum Systems Related to the Equatorial Transform Margin: Brazilian and West African Conjugate Basins,” in Post P, Rosen N, Olson D, Palmes SL, Lyons KT and Newton GB (eds): Petroleum Systems of Divergent Continental Margin Basins. Tulsa: Gulf Coast Section, Society for Sedimentary Geology (2005): 807–831.

19. Beasley CJ, Fiduk JC, Bize E, Boyd A, Frydman M, Zerilli A, Dribus JR, Moreira JLP and Pinto ACC: “Brazil’s Presalt Play,” Oilfield Review 22, no. 3 (Autumn 2010): 28–37.

20. Presalt refers to before the formation or deposition of salt deposits. Presalt reservoirs are beneath salt deposits that have not flowed away from their place of deposition—beneath the autochthonous, or in place, salt. This definition differentiates presalt strata from subsalt or postsalt strata. For more: Beasley et al, reference 19.

21. Coquina is a limestone formed principally from shell fragments and indicates a nearshore environment with vigorous wave action. Microbialites, which are carbonate structures thought to be formed by microbes, have a range of shapes and sizes. They form in environments that are not conducive to the growth of corals.

22. Hardie LA: “On the Significance of Evaporites,” Annual Review of Earth and Planetary Sciences 19 (May 1991): 131–168.

Jackson MPA, Cramez C and Fonck J-M: “Role of Subaerial Volcanic Rocks and Mantle Plumes in Creation of South Atlantic Margins: Implications for Salt Tectonics and Source Rocks,” Marine and Petroleum Geology 17, no. 4 (April 2000): 477–498.

Nunn JA and Harris NB: “Subsurface Seepage of Seawater Across a Barrier: A Source of Water and Salt to Peripheral Salt Basins,” Geological Society of America Bulletin 119, no. 9–10 (September–October 2007): 1201–1217.

Nunn JA and Harris NB: “Erratum for ‘Subsurface Seepage of Seawater Across a Barrier: A Source of Water and Salt to Peripheral Salt Basins,’” Geological Society of America Bulletin 120, no. 1–2 (January–February 2008): 256.

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The necessary factors promoting such thick salt accumulations were a rapidly sinking margin with balance-filled basins or lakes behind an elevated outer volcanic high. This volcanic high was a leaky barrier that restricted inflow of sea-water in an environment characterized by a warm, arid, desert climate (next page, bottom).23 Conditions were somewhat similar to present-day conditions in the Dead Sea basin and in the Danakil Depression on the Afar Peninsula, north-east Africa.24 These layered salts form the seal for the presalt reservoirs (See “Salt Deposition in Actively Spreading Basins,” page 50).

The end of the Aptian age saw the final breaching of the Walvis Ridge–Rio Grande Rise barrier accompanied by flooding of marine waters from the southern segment of the South Atlantic Ocean. These open marine conditions allowed ocean waters to fill the basins of the cen-tral segment, halting any further evaporite depo-sition. Marine sediments formed on top of the salt, starting with marine carbonates in the Albian age (113 to 110 Ma). The postsalt sedi-mentation was controlled by continual opening and deepening of the South Atlantic by global changes of sea level. As the ocean opened, the

rifted margins tilted seaward, causing halokine-sis, in which the salt flows and deforms, giving rise to the salt structures that affected postsalt sediments where large volumes of oil were found in the Campos basin (above).25

The Tupi discovery in 2006 opened up a new petroleum play in the central South Atlantic, the presalt play. Lula field lies in 2,126 m [6,975 ft] of water in the Santos basin Block BM-S-11 about 250 km [155 mi] southeast of Rio de Janeiro. The 1-RJS-628A discovery well was drilled to 4,895 m [16,060 ft] TVD subsea.26 The well flowed 780 m3/d [4,900 bbl/d] of oil and 187,000 m3/d [6.6 MMcf/d]

23. Davison I: “Geology and Tectonics of the South Atlantic Brazilian Salt Basins,” in Ries AC, Butler RWH and Graham RH (eds): Deformation of the Continental Crust: The Legacy of Mike Coward. London: The Geological Society, Special Publication 272 (January 2007): 345–359.

Lakes or basins are balance filled when the rate of water and sediment input is similar to the rate that the accommodation space—area and depth—forms. For more: Carroll AR and Bohacs KM: “Stratigraphic Classification of Ancient Lakes: Balancing Tectonic and Climatic Controls,” Geology 27, no. 2 (February 1999): 99–102.

24. Montaron B and Tapponnier P: “A Quantitative Model for Salt Deposition in Actively Spreading Basins,” Search and Discovery Article 30117, adapted from an oral presentation at the AAPG International Conference and

>Seismic lines across conjugate presalt rifted margins. These paired seismic lines are dip lines from the Santos basin offshore Brazil (above) and the Kwanza basin offshore Angola (next page, top). The Santos basin seismic section is from a generic 2D seismic line crossing close to the Lula field, a presalt discovery. The seismic section shows a nearly 2-km [1.2-mi] thickness of presalt sediments underneath the salt. The Kwanza basin section, offshore Angola, is from a 3D seismic survey and shows a well-developed presalt section separated from postsalt sediments by complex salt geometries. (The Santos basin section is used with permission from WesternGeco and TGS. The Kwanza basin section is used with permission from WesternGeco and Sonangol.)

Fig10_1_left page

Postsalt sediments

Presalt

Basement

Salt

2 km

20 km

Exhibition, Rio de Janeiro, November 15–18, 2009. Bosworth W, Huchon P and McClay K: “The Red Sea

and Gulf of Aden Basins,” Journal of African Earth Sciences 43, no. 1–3 (October 2005): 334–378.

Mohriak WU and Leroy S: “Architecture of Rifted Continental Margins and Break-Up Evolution: Insights from the South Atlantic, North Atlantic and Red Sea– Gulf of Aden Conjugate Margins,” in Mohriak WU, Danforth A, Post PJ, Brown DE, Tari GC, Nemcok M and Sinha ST (eds): Conjugate Divergent Margins. London: The Geological Society, Special Publication 369, http://dx.doi.org/10.1144/SP369.17 (accessed September 17, 2012).

25. Halokinesis is the deformation of salt. Halokinetic processes include downslope movement under gravity flow, expulsion and diapirism caused by overburden loading and faulting resulting from tectonic stretching or

shortening. Salt deformation may cause deformation in the strata deposited above it.

Hudec MR and Jackson MPA: “Terra Infirma: Understanding Salt Tectonics,” Earth-Science Reviews 82, no. 1–2 (May 2007): 1–28.

Quirk DG, Schødt N, Lassen B, Ings SJ, Hsu D, Hirsch KK and Von Nicolai C: “Salt Tectonics on Passive Margins: Examples from Santos, Campos and Kwanza Basins,” in Alsop GI, Archer SG, Hartley AJ, Grant NT and Hodgkinson R (eds): Salt Tectonics, Sediments and Prospectivity. London: The Geological Society, Special Publication 363 (January 2012): 207–244.

Beasley et al, reference 19.26. Parshall J: “Presalt Propels Brazil into Oil’s Front

Ranks,” Journal of Petroleum Technology 62, no. 4 (April 2010): 40–44.

(continued on page 52)

W E

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> Conditions conducive for thick salt accumulations. By the Aptian, about 120 Ma, the South Atlantic Ocean (map, center ) had scissored open from the south. The central segment of the South Atlantic was isolated from the open marine conditions of the southern segment by the Walvis Ridge (purple). The region was in an arid belt (between dashed white lines) where climate conditions were similar to those in the present-day Atacama desert, northern Chile (bottom left ), and Kalahari desert, southern Africa (bottom right ). The central segment contained balance-filled basins and lakes. Under these climatic and isolated basin conditions, the basins and lakes became centers for precipitation of thick, layered salt sequences from basinal and hydrothermal brines, which were fed by marine water flowing through fractures in the leaky basaltic dam formed by the Walvis Ridge. (Map courtesy of CR Scotese, used with permission.)

Tropic of Capricorn

Salt basins

Arid belt

450 km

WalvisRidge

Present-day Kalahari DesertPresent-day Atacama Desert

Fig10_1_right page

Postsalt sediments

Presalt

Basement

Salt

2 km

20 km

WE

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Salt Deposition in Actively Spreading Basins

Rifting, Spreading and TectonicsThe salt basins that face one another between the Rio Grande Rise and the Gulf of Guinea are among the largest found along Phanerozoic passive ocean margins (below). They formed during the Aptian (125 to 110 Ma), during the opening stages of the cen-tral South Atlantic. The geometric, kinematic and temporal environment of this lower Cretaceous salt deposition appears strikingly similar to that of the Mid-Late Miocene Red Sea (15 to 5 Ma).1

After the Tristan da Cunha hot spot induced giant volcanic eruptions that covered huge areas of the African–South American litho-sphere with thick flood basalts about 143 Ma, the plates started to separate slowly at several millimeters per year. Narrow rifts, 50 to 80 km [31 to 50 mi] wide, which overlapped, formed

along the newborn plate boundary. Basaltic vol-canism and anoxic deepwater lakes—some deeper than 1,000 m [3,300 ft], similar to Lake Tanganyika today—punctuated the geology of such rifts in the Late Hauterivian to Early Barremian (133 to 128 Ma).2

Continental separation was completed 128 to 125 Ma. As full seafloor spreading began, the rate of plate separation increased to a few centimeters per year. The marine basin, now 1,700 km [1,060 mi] long, 300 to 500 km [190 to 310 mi] wide and 2 km [1.2 mi] deep, remained isolated between two large “dams” formed by the nascent equatorial Atlantic transform margin to the north and the Walvis Ridge and Rio Grande Rise to the south. These dams restricted seawater flow into the basin—flow that took place mostly along tectonic fissures through the southern

Walvis Ridge. Rapid evaporation of seawater created thick, layered evaporite deposits. Continuous open marine conditions were rees-tablished in the Early Albian (112 to 110 Ma).

Evaporites in the Santos BasinThree conditions are required to create a thick, layered salt deposit: a basin about 1,500 m [4,900 ft] deep, a continuous supply of mineral-laden seawater and a warm and arid climate. As evaporation takes place, the basin water level drops quickly and stabilizes to a critical level: The evaporation rate equals the water intake rate. The water salinity increases gradually until the saturation concentration is reached for the least soluble salt mineral con-tained in the water.

Layers of calcite, dolomite and gypsum pre-cipitate—in that order—followed by halite (rock salt). Halite precipitates in quantities just sufficient to maintain the water salinity at the halite saturation level; this process can last several thousand years to accumulate hundreds of meters of halite. If the climate becomes wet-ter, increased freshwater intake from rivers and rain may reduce the salinity enough to stop halite precipitation. For example, salinity may drop back to the gypsum precipitation point and eventually increase back to the halite pre-cipitation point. This is the layered sequence observed in the bottom 600 m [2,000 ft] of Santos basin evaporites.

Water salinity levels may increase further, until they reach the saturation point at which complex salts begin to precipitate. These salts are potassium-, calcium- and magnesium-rich evaporites such as sylvite, carnallite and tachyhydrite. Precipitation of complex salts requires an extremely arid climate and pre-cipitation may take a long time because these highly saline brines evaporate very slowly. During this process, the lake surface level will not change despite salt accumulating on the lake bottom. The final result is a salt flat (next page).

> South Atlantic restoration. The Aptian, about 120 Ma, salt basin (purple) was 1,700 km [1,060 mi] long and restricted from open ocean conditions by the Tristan da Cunha hot spot (red circle) to its south and the embryonic equatorial Atlantic transform margin (opposing red arrows) to its north. The black arrows indicate the direction of plate movement. (Map courtesy of CR Scotese, used with permission.)

Side Bar Fig1_1

Aptian salt basin

Transform margin

Hot spot

SOUTH AMERICA

AFRICA

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1. Mohriak WU and Leroy S: “Architecture of Rifted Continental Margins and Break-Up Evolution: Insights from the South Atlantic, North Atlantic and Red Sea–Gulf of Aden Conjugate Margins,” in Mohriak WU, Danforth A, Post PJ, Brown DE, Tari GC, Nemcok M and Sinha ST (eds): Conjugate Divergent Margins. London: The Geological Society, Special Publication 369, http://dx.doi.org/10.1144/SP369.17 (accessed September 17, 2012).

Bosworth W, Huchon P and McClay K: “The Red Sea and Gulf of Aden Basins,” Journal of African Earth Sciences 43, no. 1–3 (October 2005): 334–378.

2. Karner GD and Gambôa LAP: “Timing and Origin of the South Atlantic Pre-Salt Sag Basins and Their Capping Evaporates,” in Schreiber BC, Lugli S and Babel M (eds): Evaporites Through Space and Time. London: The Geological Society, Special Publication 285 (January 2007): 15–35.

During the Aptian, South Atlantic salt basins were located at latitudes correspond-ing to the arid belt that contains most of the southern hemisphere’s modern deserts. The initial evaporation rate was probably 2 m [7 ft] per year greater than the rainfall input, a rate currently observed in the Red Sea.4 At an average halite deposition rate of 2 to 3 cm [0.8 to 1.2 in.] per year, it may have taken 20,000 to 30,000 years to deposit the lower-most 600 m of Santos basin evaporites.5 Above that level, there are at least nine cycles con-taining complex salts, and these could have taken 10 times longer to precipitate. Replacing water by salt doubles the weight applied to the basin floor and accelerates sub-sidence. Approximately 30% of accommoda-tion space is gained in about 50,000 years by adding 500 m [1,600 ft] to the initial 1,500-m [4,900-ft] basin depth.

Observations from modern analogs such as Lake Assal in the Afar region, Ethiopia, sug-gest seawater entered the salt basin through fissures across the basaltic Walvis Ridge. This fissural process is also based on other considerations:• The volumetric flow rate through cracks

must be small, as required by the salt pre-cipitation model.

• Because fissures in basalts can be up to a hundred meters deep, seawater flowing through fissures is less sensitive to varia-tions in ocean water level compared to that required by flow over a dam.

• When the evaporation rate increases and the basin level drops below the ocean level, the hydraulic-head difference will tend to promote flow through the fissures to main-tain the basin’s water level.

• The fractures provide a large contact sur-face between seawater and basalts, which favors the rock-to-fluid chemical exchange required for a chemical composition that is compatible with complex salt deposition.6

Field observations and model results dem-onstrate that the deposition of thick, layered evaporitic sequences requires a deep basin in a hot and arid climate with a continuous sup-ply of mineral-laden saltwater. These condi-tions must remain stable long enough for thick deposits to accumulate.

> Salt deposition sequence. During early rifting (1), freshwater lakes form on the stretching continental margin. (The developing ocean is on the left side of each panel.) The ocean level drops and the lakes deepen (2) as the stretching continental margins thin and subside. The barrier that separates the ocean from the lakes increases in relief with respect to the lake bottom. Sea level rises (3), and seawater spills over the barrier and mixes with the lake water. About 123 Ma in the Early Aptian (4), sea level falls by 50 m [80 ft] and isolates the basins from open ocean waters. The evaporation rate from the basins (5) is greater than the rate of water influx from rivers and rainfall and from seawater springs emanating from the leaky barrier; such leaks are the result of fractures and fissures. The basin water level drops and water salinity gradually increases until the brine salinity level reaches the saturation concentration of the least soluble chemical component in the brine, which begins to deposit as a salt mineral (white, 6). During salt deposition, salt layers (not shown) form as the brine chemistry changes. Salinity and salt saturation concentrations depend on the climatic water balance within the basins and the seawater input to them through the leaky barrier. Salt mineral precipitation begins with the least soluble chemical component in the brine. This component precipitates until it depletes. More soluble components precipitate later. In this way, salt layers gradually build up and fill the basins to form thick layered salt sequences. The final episode of salt deposition is marked by a terminal brine (purple, 7) of high salinity, supersaturated with the least soluble component at the time. Finally, sea level rises sufficiently to inundate the continental margins (8); open marine conditions are reestablished above the salt basins and such marine conditions shut down salt deposition.

Side Bar, Fig3_4

1

2

3

4

5

6

7

8

Freshwater lakes form.

Freshwater lakes deepen. Ocean level falls.

Ocean level rises, spills over barrierand floods into freshwater lakes.

Ocean level falls.Fractured ridge allows hydraulic

communication between ocean and lake.

Basin level dropsas water evaporates.

Salt deposition starts.

Salt deposition ending.

Basin returns tofull marine conditions.

Terminal brine marks final salt deposition.

Montaron B and Tapponnier P: “A Quantitative Model for Salt Deposition in Actively Spreading Basins,” Search and Discovery Article 30117, adapted from an oral presentation at the AAPG International Conference and Exhibition, Rio de Janeiro, November 15–18, 2009.

3. Montaron and Tapponnier, reference 2.4. Hardie LA: “The Roles of Rifting and Hydrothermal

CaCl2 Brines in the Origin of Potash Evaporites: An Hypothesis,” American Journal of Science 290, no. 1 (January 1990): 43–106.

Hardie LA: “On the Significance of Evaporites,” Annual Review of Earth and Planetary Sciences 19 (May 1991): 131–168.

Warren JK: Evaporites: Sediments, Resources and Hydrocarbons. Berlin: Springer-Verlag, 2006.

5. Montaron and Tapponnier, reference 2.6. Montaron and Tapponnier, reference 2.

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of gas on a 5/8-in. choke, producing light oil with a density of about 880 kg/m3 [30° API gravity] and a low sulfur content of about 0.5%.27 Development drilling in the field confirmed the operator’s esti-mates of up to 1,000 million m3 [6.5 billion bbl] of recoverable oil, thus drawing worldwide atten-tion to Brazil’s presalt play.28 Many subsequent presalt discoveries have been made in the Santos and Campos basins of Brazil.

In 2012, the Azul-1 well by Maersk Oil and then the Cameia-1 well by Cobalt International Energy, Inc., extended the proven presalt play across the South Atlantic to the Kwanza basin, offshore Angola.29 The Azul-1 well was in 953 m [3,130 ft] of water in Kwanza basin Block 23; the well was drilled to 5,334 m [17,500 ft] and dem-onstrated potential flow capacity of greater than 3,000 bbl/d [480 m3/d] of oil. The Cameia-1 well

was in 1,682 m [5,518 ft] of water in Kwanza basin Block 21; the well was drilled to 4,886 m [16,030 ft] and flowed 5,010 bbl/d [800 m3/d] of oil and 14.3 MMcf/d [405,000 m3/d] of gas.

In the process leading up to the Cameia-1 discovery, exploration experts at Cobalt International Energy recognized that during the Aptian age, the present-day Kwanza and Campos presalt basins were in the same depositional basin, separated by only 80 to 160 km [50 to 100 mi]; explorationists concluded the basins must have shared the same presalt history and have similar characteristics.30 The presalt play that led to the Tupi discovery in the Brazilian Santos basin was extended north along the Brazilian coastline to the Campos basin. Cobalt drilled the Cameia-1 well to hunt for a Campos basin presalt play analog across the Atlantic Ocean in the Kwanza basin offshore Angola. The Cameia-1 oil discovery well drilled into a reser-voir that contained high-quality, highly perme-able and fractured carbonates in postrift and presalt strata atop a basement high and was sealed by salt. The well encountered an oil col-umn that was about 370 m [1,200 ft] thick and contained more than 270 m [900 ft] of net pay.31

To appraise the discovery, Cobalt drilled the Cameia-2 well and confirmed the vertical and lat-eral extent, geometry and quality of the reservoir (left). The appraisal well validated the Cobalt model of additional reservoirs within the postrift and synrift strata beneath the original discovery and indicated the reservoirs were separated by seals. Cobalt is conducting ongoing testing to determine reservoir potential—the number of reservoirs and seals, how the fluids vary between the reservoirs, the reservoir properties and the depths to the oil/water contacts.32

Matching Turbidite Sequences: From Ghana to French GuianaThe West Cape Three Points partnership discov-ered the Jubilee oil field offshore Ghana in June 2007. The partnership comprises Kosmos Energy Ltd., Tullow Oil plc, Anadarko Petroleum Corporation, Sabre Oil & Gas, Inc., Ghana National Petroleum Company and EO Group Ltd. The Mahogany-1 discovery well encountered 90 m [300 ft] of high-quality pay in an upper Cretaceous turbidite reservoir confined by a combination structural-stratigraphic trap.33 In August 2007, the Hyedua-1 well, located 5.3 km [3.3 mi] southwest of the Mahogany-1 discovery, encountered 41 m [130 ft] of high-quality reservoir in equivalent tur-bidite sandstones. These wells opened up a deep-

> Kwanza basin presalt prospects and discoveries. The Cobalt Cameia-1 and Cameia-2 wells discovered and appraised, respectively, oil reservoirs in the synrift (light brown) and postrift (yellow) sedimentary basins under the autochthonous salt (purple)—the presalt sediments—in Block 21 (center right ), Kwanza basin offshore Angola. Cobalt plans to drill the Lontra, Idared, Mavinga and Bicuar wells (dashed lines) to test other prospects in Blocks 20 and 21. The Cameia-1 well discovered a superpay reservoir (bright green) atop a basement high (bottom). Cobalt drilled the Cameia-2 well, a step-out well, to confirm the size of the discovery and to explore prospective reservoir zones below the superpay reservoir. The appraisal well confirmed the discovery and underlying reservoir intervals (light green), which are separated by sealing intervals (red). (Illustrations used with permission from Cobalt International Energy, Inc., reference 32.)

Fig11_2

Lontra

Block 20

Idared Mavinga Cameia-1 Cameia-2 Bicuar

Block 21SouthNorth

SaltSalt

BasementSynrift Synrift Synrift

SynriftSynrift

Basement

Postsalt

Postrift

Postrift Postrift

PostriftPostrift

SaltSalt

Superpay reservoir

Middle reservoir

Lower reservoir

Cameia-1 Cameia-2

AFRICA

20

21

Angola

Postsalt Postsalt

Postrift

Oil confirmed by production

Oil confirmed by log or oil sample

Untested possible oil zone

Seal

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27.“BG,PetrobrasAnnounceDiscoveryofOilFieldinSantosBasinOffshoreBrazil,”Drilling Contractor62,no.6(November–December2006):8.

28.“CountryAnalysisBriefs:Brazil,”USEnergyInformationAdministration(February28,2012),http://www.eia.gov/countries/cab.cfm?fips=BR(accessedAugust29,2012).

29.“MaerskOilStrikesOilwithItsFirstPre-SaltWellinAngola,”MaerskOil(January4,2012),http://www.maerskoil.com/Media/NewsAndPressReleases/Pages/MaerskOilstrikesoilwithitsfirstpre-saltwellinAngola.aspx(accessedMarch29,2012).

“CobaltInternationalEnergy,Inc.AnnouncesSuccessfulPre-SaltFlowTestOffshoreAngola,”CobaltInternationalEnergy,Inc.(February9,2012),http://ir.cobaltintl.com/phoenix.zhtml?c=231838&p=irol-newsArticle&ID=1659328&highlight(accessedApril4,2012).

30.CobaltInternationalEnergy,Inc.:“UpdateonWestAfricaandGulfofMexicoDrillingPrograms,”(February8,2012),http://phx.corporate-ir.net/External.File?item=UGFyZW50SUQ9MTI1NzQyfENoaWxkSUQ9LTF8VHlwZT0z&t=1(accessedAugust2,2012).

DribusJR:“IntegratingNewSeismicTechnologyandRegionalBasinGeologyNowaMust,”Journal of Petroleum Technology64,no.10(October2012):84–87.

water play targeting reservoirs in Late Cretaceous turbidites along the equatorial African transform margin, which stretches from northern Sierra Leone east to southern Gabon in the equatorial segment of the South Atlantic Ocean.

Deepwater turbidite fields discovered off-shore Ghana are charged with hydrocarbons sourced from organic-rich sediments that rap-idly filled deep, active pull-apart basins during the Early Cretaceous epoch (above). These basins formed on rifted continental crust between transform faults. During the Albian age, the continents split and seafloor spreading began. Oblique motion between the two margins is recorded by transform faults and fracture

> OpeningoftheequatorialAtlanticOcean.RiftingbetweennorthernSouthAmericaandsouthernWestAfricastartedduringtheEarlyCretaceousabout125Ma(top left).Smallbasinsopenedwhencontinentalcruststretched,thinnedandfaulted.Thesebasinsfilledwithsedimentfromtheerodingcontinentaluplandsandweredeformedalongthetransformfaultzones.DuringtheLateAptiantoEarlyAlbian,about110Ma(bottom left),oceanicspreadingandaccretionbegan.OceanfloorsgrewastheplateswereseparatingduringtheLateAlbian,about100Ma(top right).ByLateSantoniantoEarlyCampanian,about85Ma(bottom right),thecontinentalseparationwascomplete.Theseafloorspreadingandpassivemarginphasebeganandthesteeptransformmarginssubsidedthermallyandwerecut,loadedandblanketedbyriveranddeltasedimentsfromthecontinentswhileSouthAmericaandAfricacontinuedtoseparate.(AdaptedfromBrownfieldMEandCharpentierRR:“GeologyandTotalPetroleumSystemsoftheGulfofGuineaProvinceofWestAfrica,“Reston,Virginia,USA:USGeologicalSurveyBulletin2207-C,2006.)

Fig12_1

Benuetrough

Benin andKeta basins

Voltabasin

Bové basin

Ivory Coastbasin

Senegal basin AFRICA

SOUTH AMERICA

Voltabasin

Senegal basin

Ivory Coastbasin


Benuetrough

Para-Maranhaobasin

15˚W 10˚W 5˚W 0˚ 5˚E

15˚W 10˚W 5˚W 0˚ 5˚E

10˚N

5˚N

15˚W 10˚W 5˚W 0˚ 5˚E

10˚N

5˚N

Voltabasin


Benuetrough

Ivory Coastbasin

Senegal basin

Para-Maranhaobasin

~

~

Bové basin

Bové basin

Para-Maranhaobasin

10˚N

5˚N

15˚W 10˚W 5˚W 0˚ 5˚E

10˚N

5˚N

0 500 km

0 310 mi

0 500 km

0 310 mi

0 500 km

0 310 mi

0 500 km

0 310 mi

Senegal basin

Voltabasin

Ivory Coastbasin


Benuetrough

Ocean

Bové basin

Para-Maranhaobasin

AFRICA

SOUTH AMERICAEarly Cretaceous, 125 Ma Late Albian, 100 Ma

Late Aptian to Early Albian, 110 Ma Late Santonian to Early Campanian, 85 Ma

West African shield

Brazilian shieldOnshore Mesozoic to Cenozoiccoastal basins

Thick continental crustand extension

Divergent basins, thinnedcontinental crust and thick clastics Direction of crustal extension

Transform fault zones

Present-day 2,000-m [6,560-ft] isobath

Zaedyus discovery,Guyane Maritime, French Guiana

Jubilee discovery,Tano basin, Ghana

AFRICA AFRICA

SOUTH AMERICASOUTH AMERICA

OceanOcean

OceanOcean

~

~

31.CobaltInternationalEnergy,Inc.:“InvestorPresentation—March2012,”(March13,2012),http://phx.corporate-ir.net/phoenix.zhtml?c=231838&p=irol-presentations(accessedJune8,2012).

32.“MultipleCatalystsToGrowShareholderValue,”CobaltInternationalEnergy,Inc.(September19,2012),http://phx.corporate-ir.net/External.File?item=UGFyZW50SUQ9NDgwMTA3fENoaWxkSUQ9NTEzNzk4fFR5cGU9MQ==&t=1(accessedSeptember20,2012).

33.Aturbiditeisarockdepositedfromaturbidityflow,whichisanunderwatercurrentofsediment-ladenwaterthatmovesrapidlydownaslope.Thegravity,ordensity,currentmovesdownslopebecauseitsdensityishigherthanthatofthesurroundingwater.

DaillyP,HendersonT,HudgensE,KanschatKandLowryP:“ExplorationforCretaceousStratigraphicTrapsintheGulfofGuinea,WestAfricaandtheDiscoveryoftheJubileeField:APlayOpeningDiscoveryintheTanoBasin,OffshoreGhana,”inMohriakWU,DanforthA,PostPJ,BrownDE,TariGC,NemcokMandSinhaST(eds):Conjugate Divergent Margins.London:TheGeologicalSociety,SpecialPublication369,http://dx.doi.org/10.1144/SP369.12(accessedAugust7,2012).

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zones, and subsidence and sediment deposition occurred during rifting and subsequent sag of the margins (above).

The opening and deepening of the equatorial South Atlantic and the global rise and fall of sea level controlled sedimentation after continental breakup. Erosion of the continent led to deposi-tion of sediments in deltas on the continental margins. When sea level fell—a lowstand—the rivers cut through their deltas and carried sedi-ments, often in sediment avalanches known as turbidity currents, onto the steep continental slopes and toward the deep abyssal plain. Sands that were deposited as these turbidity currents slowed may have formed reservoirs for deepwater oil fields such as those of the upper Cretaceous series in the Jubilee field. Subsequent deposition of muds sealed these reservoirs as they were

buried beneath thousands of meters of younger sediment. During the Late Cretaceous epoch, the movement of the tectonic plates changed direc-tion, causing deformation of the rifted margin and the formation of structures that helped form traps, and oil started migrating updip toward the coast (next page, bottom right).34

The partnership drilled the Mahogany-1 well to reservoir rock in a Turonian-stage stack of low-stand turbidite sands on the SW flank of the South Tano ridge.35 The reservoir was 3,530 to 3,760 m [11,600 to 12,300 ft] below the seafloor. A drillstem test demonstrated that the well was capable of flowing oil at 20,000 bbl/d [3,200 m3/d]. The oil was sourced from Early Cretaceous rift-related organic-rich shales. The Jubilee well proved the Late Cretaceous turbi-

dite play concept and subsequent drilling revealed that Jubilee is part of a collection of fields offshore Ghana that includes Tweneboa, Enyenra and Ntomme.

Similar Late Cretaceous turbidite reservoirs occur along the entire equatorial African coast, which have led to additional oil discoveries such as the Akasa and Teak fields offshore Ghana, the Paon field offshore Côte d’Ivoire and the Venus, Mercury and Jupiter fields offshore Sierra Leone.

Tullow Oil sought to project the Jubilee play to the transform margin of South America and duplicate the company’s deepwater success.36 Exploration experts at Tullow Oil used the prin-ciples of plate tectonics, followed the major frac-ture zones across the equatorial Atlantic and identified basins offshore South America that displayed similar elements of the Jubilee play.

> Conjugate transform margins. These seismic lines cross the Suriname–French Guiana (above) and Côte d’Ivoire–Ghana (next page, top) transform margins; the red dots on the globes are the locations of these seismic sections. The red lines mark the approximate position of the Demerara Fracture Zone (FZ) and the Romanche FZ, on the left and right, respectively. Transform margins are characterized by shallow dipping, often narrow, continental margins, bordered by marginal ridges that backstop steep continental slopes across abrupt continent-ocean boundaries leading to oceanic abyssal plains. Explorers are targeting reservoirs located in abyssal plain sediments in upper Cretaceous turbidites that lie on top of lower Cretaceous organic-rich source rocks. The green dots mark the approximate stratigraphic position of these upper Cretaceous reservoirs. These Cretaceous source and reservoir rocks are sealed and buried under marine shales. On the Côte d’Ivoire–Ghana seismic line, the labels A through F represent stratigraphic units identified from seismic data. [Adapted from Greenroyd CJ, Peirce C, Rodger M, Watts AB and Hobbs RW: “Demerara Plateau—The Structure and Evolution of a Transform Passive Margin,” Geophysical Journal International 172, no. 2 (February 2008): 549–564.]

320 330 340 350 360 370 380 390 400

Suriname–French Guianaabyssal plain

Continentalslope

Marginalridge

Demerara Plateau

Offset, km

Fig13_1_left page

SW NE

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They found evidence for an upper Cretaceous series of lowstand turbidite channels and fans deposited during seafloor spreading and buried under a thick sequence of marine shales. They inferred the presence of Cretaceous source rocks and stratigraphic traps, buried and sealed by the marine shales. This led the exploration teams to focus on the continental slope off the Guyana

34.AntobrehAA,FaleideJI,TsikalasFandPlankeS:“Rift–ShearArchitectureandTectonicDevelopmentoftheGhanaMarginDeducedfromMultichannelSeismicReflectionandPotentialFieldData,”Marine and Petroleum Geology26,no.3(March2009):345–368.

35.Daillyetal,reference33.36.PatelT:“DidtheContinentalDriftCreateanOil

Bonanza?:TullowOilBetsHugeFieldsAre‘Mirrored’AcrosstheAtlantic,”Bloomberg Businessweek(February24,2011),http://www.businessweek.com/magazine/content/11_10/b4218020773519.htm(accessedAugust20,2012).

102030405060708090

Marginalridge

Deep Ivorian basin

Offset, km

Continentalslope

Gulf of Guineaabyssal plain

Fig13_1_right page

E

F

D

C

BA

> ReservoirsinLateCretaceousturbidites.Explorationistslookedforcanyonsfeedingreservoirrocksinchannel-leveeandturbiditefandepositsonthebasinfloorthatoriginatedfromtheGuyanaContinentalShelfandslope.ThesereservoirrocksaresourcedandchargedbyEarlyCretaceousorganic-richshalesthatweredepositedduringcontinentalrifting.Sincetheirdeposition,thesereservoirrockshavebeenburiedandsealedbymarineshales(notshown).Expectedwelllogresponsesareplottedforthefivetypesofdeposits(boxedredareasbetweenblackcurves);theleftcurveisspontaneouspotentialorgammaray,andtherightcurveisresistivity.(IllustrationusedwithpermissionfromTullowOilplc.)

Canyon fed by activenearshore littoral driftor relict shelf sands

Sandy coastalplain

Barrier bar

Inner fanchannels

Midfanchannelized

lobes

Slumpscar

Inner fan

Basin plain

Basin plain

Coastalplain

Continentalshelf

Slopeapron

Slumps

Slump

10 to 50 km6.2 to 31 mi

Longshoredrift

Slumpscar Outer fan

Midfan channelized andunchannelized sands

Shelf anddelta

Fig14_1

500 to 2,000 m[1,640 to 6,562 ft]

S N

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Shelf and east of the Demerara Plateau offshore French Guiana (below).37

Tullow Oil and partners acquired 2,500 km2 [970 mi2] of high-quality 3D marine seismic data over the steep continental slope offshore French Guiana.38 Explorers at Tullow Oil used these data to look for submarine canyons and turbidite deposits on the basin floor that origi-nated from the Guyana Continental Shelf and slope. These seismic data showed features simi-lar to those observed in 3D seismic data over the Jubilee field offshore Ghana. The exploration team identified and mapped a number of pros-pects (next page). After follow-up regional investigations, the Tullow Oil team decided to test the play by drilling a well at the GM-ES-1 location within the Zaedyus prospect, in the Guyane Maritime license, which is about 150 km [93 mi] offshore.39

Tullow Oil started operations in March 2011, drilling near the toe of the continental slope in 2,048 m [6,719 ft] of water. By September 2011, the company announced the discovery of 72 m [240 ft] of net oil pay within two turbidite fans.40 Wireline logs and samples of reservoir fluids showed good quality reservoir sands at a reser-voir depth of 5,711 m [18,740 ft]. The Zaedyus exploration well proved that the Jubilee play—developed for the transform margin offshore Ghana and applied successfully elsewhere along the equatorial African margin—was also appli-cable to the transform margin offshore French Guiana and probably elsewhere along the trans-form margin of northern South America.

Learning from SuccessThe recent history of oil discovery along the South Atlantic margins has been one of learning from success. Pioneering explorationists studied the large discoveries of the Lula reservoir in the Santos basin, offshore Brazil, and the Jubilee reservoir, offshore Ghana, and stepped along the same margin to look across the ocean where con-jugate margins hosted similar large discoveries.

Explorationists used the principles of plate tectonics to leverage their accomplishments. When a continent splits and a new spreading center opens up, plate tectonic concepts pro-vide the basis for hypothesizing which series of tectonic and stratigraphic events will occur. Armed with the principles of plate tectonics and astute observations from exploration plays that have led to successful discoveries, exploration-ists have extrapolated plays into new leads,

Fig15_1

Oceanic transform fracture zone

FrenchGuiana

Guyana

SierraLeone

GhanaCôte d’IvoireLiberia

Equatorial Atlantic transform marginSuriname

Mid-Atlantic Ridge

SOUTH AMERICA

WEST AFRICA

Oceanic transform fracture zone

0 600 km

0 370 mi

West CapeThree Points block

DeepwaterTano block

Jubilee discovery

Oil discoveryGas condensate and oil discoveryProspectDry holeOil shows

0 25 km

0 16 mi

Atlantic Ocean

GuyaneMaritimelicense

Zaedyus discovery

DiscoveryProspectLead

0 100 km

0 62 mi

> Extending West African success across to South America. Tullow Oil plc used plate tectonic concepts to develop an exploration program to extend the Jubilee play (black star) proved along the West Africa transform margin to the northern South America transform margin. The transform margins (gray shading) on the west and east sides of the Equatorial Atlantic have similar geology. Explorationists had recognized Late Cretaceous stratigraphic traps within the Guyana-Suriname basin that were analogous to those proved by the Jubilee and similar discoveries in West Africa. Tullow explorationists made the Zaedyus discovery in the Guyane Maritime license, offshore French Guiana (red star). (Illustration adapted with permission from Tullow Oil plc.)

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prospects and drilling targets both regionally and globally.

Understanding plate tectonics also allows explorationists to take what they learn from one play and ask, “What if?” If hydrocarbons are found in an immature rift margin setting, could one find the same in a mature rift margin or a transform margin setting? In recent years, exploration com-panies have answered these questions affirma-tively through discovery wells. Recent discoveries in the Albert rift basin of Uganda, the East Africa

rift basin of Kenya, the Levant basin offshore Israel and Cyprus and the Mozambique basin off-shore Tanzania have been similarly impressive. Plate tectonic concepts and models, and their ability to engender reasoned hypotheses for new plays, are powerful exploration tools for hitherto undeveloped basins. They are also cause for reexamining basins that have been explored but deemed either hydrocarbon poor or too risky to develop. —RCNH

37.PlunkettJ:“FrenchGuiana—ANewOilProvince,”presentedattheKayennMiningSymposium,Cayenne,FrenchGuiana,December1–3,2011.

38.ThepartnershipwasajointventurebetweenTullowOilplc—theoperator—RoyalDutchShell,TotalandNorthpet,acompanyowned50%byNorthernPetroleumplcand50%byWessexExplorationplc.RoyalDutchShellformallytookoverasoperatoroftheGuyaneMaritimelicenseonFebruary1,2012.

39.Plunkett,reference37.40.“ZaedyusExplorationWellMakesOilDiscovery

OffshoreFrenchGuiana,”TullowOilplc(September9,2011),http://www.tullowoil.com/index.asp?pageid=137&newsid=710(accessedAugust10,2012).

> JubileeanalogsoffshoreFrenchGuiana.TullowOilplcacquired2,500km2[970mi2]of3Dseismicdatain2009(redboxinmapinset).Thedepth-basedseismicinterpretationimage(top),viewedfromaboveandthenortheast,showsanEarlyCretaceoushorizon(color-codedinredtobluefromshallowtodeep)overlainbyaLateCretaceoushorizon(browntoyellow)intersectingatthesteepcontinentalslopeformedbythetransformmargin.ThedatarevealedfeaturessimilartothoseobservedintheTano–WestCapeThreePointsarea,offshoreGhana.Thesefeaturesincludeaturbiditefeedercanyonandstructuralhighthatfocussedimentsintochannelsandfansystemsthatareprospectsforreservoirs.Theclose-upviewofthearea(bottom)showschannelsandturbiditefansimagedbythe3Dseismicdata.(ImagesusedwithpermissionfromTullowOilplc.)

Fig16_2

Turbidite feeder canyon

Fan systems

Major turbidite fan

Structural high

Channels

Channel

Atlantic Ocean

GuyaneMaritimelicense

Zaedyus discovery

DiscoveryProspectLead

0 100 km

0 62 mi

Early Cretaceoushorizon

Late Cretaceoushorizon

Seismic horizon relationship

View angle

54401schD5R1.indd 57 1/9/13 3:25 PM

Chris Avant is the Schlumberger Oilfield Services Account Manager for Chevron in Bangkok, Thailand. He manages all contracts and business development with Chevron Thailand, a position he has held since 2011. He began his career with Dowell Schlumberger in 1999 and has held a number of positions with the company in Canada, Indonesia, Mexico and the US, acquiring expertise in cementing, coiled tubing and wireline operations. Chris received a BS degree in petroleum engineering from the University of Alberta, Edmonton, Canada.

Bijaya K. Behera is a Professor at the School of Petroleum Technology in Pandit Deendayal Petroleum University, Gandhinagar, Gujarat, India. Previously, he was the deputy general manager (geo-sciences) with Gujarat State Petroleum Corporation (GSPC) Ltd where he was responsible for exploration and development projects in the Krishna-Godavari offshore HPHT field. He has 18 years of experience in the oil and gas industry and prior to GSPC, he worked for Schlumberger, Fugro Group of Companies, Geosoft Infotech LLC, Tata Petrodyne and Jubilant Oil and Gas Pvt Ltd. Bijaya earned a doctorate degree in geology from the Indian Institute of Technology, Mumbai, India.

Ian Bryant is a Senior Geoscience Advisor and Worldwide Métier Manager for Technical Consulting for Schlumberger Information Solutions in Houston. Before moving to this position, he managed the Schlumberger Integrated Services for Exploration group and held a variety of research, marketing and business development positions. He began his career in 1984 with Shell, first as a reservoir geologist at the Exploration and Production Laboratory, in Rijswijk, the Netherlands, and then as a geologist working in exploration, appraisal and development in New Zealand. Ian has a BS degree in physical geography with geology and a PhD degree in sedimentology from the University of Reading, England.

Evgeny Chekhonin is a Schlumberger Senior Research Scientist in Moscow. He works in the thermal measure-ments and interpretation program with a focus on opti-cal scanning technology and theoretical support of thermal property measurement. Evgeny received a mas-ter’s degree in applied mathematics and a doctorate degree in mathematics and computer science from Gubkin Russian State University of Oil and Gas, Moscow.

Mikhail V. Chertenkov is the Head of the Field Development Technologies Department for Lukoil in Moscow. His areas of interest are the enhancement of heavy-oil fields and new field development technologies. Mikhail obtained a degree in reservoir geology and exploration from Tomsk Polytechnic University, Russia.

Paul Dailly is Senior Vice President for Exploration and a founding partner of Kosmos Energy Ltd in Dallas. He led the technical team that discovered the Jubilee play offshore Ghana, currently coordinates the Kosmos exploration portfolio and manages the transi-tion of the company’s Ghanaian discoveries from appraisal to development. Before joining Kosmos in 2004, he spent 15 years as an exploration geologist, including positions with BP and Triton Energy. After the sale of Triton to Hess Corporation, he served as the

technical team leader for Equatorial Guinea and later as regional exploration manager in the deepwater Gulf of Mexico. Paul holds a BSc degree in geology from Edinburgh University, Scotland, and a DPhil degree in geology from the University of Oxford, England.

Supamittra Danpanich is Vice President, Petroleum Development, Arthit Asset, PTT Exploration and Production Public Company Limited (PTTEP). She began her career in 1987 as a geologist in airborne projects for the Thailand Department of Mineral Resources and then worked for Unocal Thailand, Ltd, until 1995. She next worked as senior geologist for Thai Shell Exploration and Production Company Ltd. During that time, she published articles on enhanced oil recovery and reservoir karstification. In 2004, she joined PTTEP as chief geologist and then worked in Vietnam as deputy subsurface manager until 2011 when she assumed her current position; she is based in Bangkok, Thailand. Supamittra received a BSc degree in geology from Chulalongkorn University, Bangkok.

Saifon Daungkaew is a Schlumberger Principal Reservoir Engineer and Reservoir Domain Champion for Thailand and Myanmar; she is based in Bangkok, Thailand. Prior to taking this position in 2009, she was also a senior reservoir engineer and reservoir domain champion for Malaysia, Brunei and the Philippines. Saifon has a BS degree in chemical engineering from the Prince of Songkla University, Thailand, and MS and doctorate degrees in petroleum engineering from the Imperial College London.

Ilaria De Santo, based in Aberdeen, is a Principal Reservoir Engineer and a Reservoir Domain Champion for Schlumberger Wireline in the North Sea. She joined Schlumberger in 1998 and has worked in soft-ware support, marketing and reservoir engineering in Italy, France, Algeria, Nigeria and the UK. She special-izes in advanced application of downhole fluid analysis and its integration with pressure surveys, vertical interference tests and interval pressure transient tests. Ilaria obtained an MS degree in geology from the University of Pavia, Italy, and an MS degree in petro-leum engineering from Heriot-Watt University, Edinburgh, Scotland.

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 five years as a uranium field geologist. 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.

Roberto Fainstein is a Geophysics Advisor to Schlumberger in the Dhahran Carbonate Research Center, Al-Khobar, Saudi Arabia. Beginning in 1995 when he joined Schlumberger, he designed the multi-client seismic libraries offshore Southeast Asia and offshore Brazil; recently, he was the UniQ* land seis-mic system project coordinator and is currently involved in the interpretation of complex salt tectonics in the Red Sea. He has worked for Petrobras as chief geophysicist for the first comprehensive survey off-shore South America, was on the oceanography and ocean engineering faculty at the Florida Institute of Technology, Melbourne, USA, and was a senior staff geophysicist and manager of exploration teams for Atlantic Richfield Company. Roberto holds a PhD degree in geology from Rice University, Houston.

Nick Harvey is the 3D Modeling Team Leader at Neftex, Abingdon, England. After joining Neftex in 2008, he built a sequence stratigraphic framework of the South and Central American regions. His subse-quent projects have focused on the origin of the Caribbean Plate, the sedimentary evolution of the Gulf of Mexico and integrated approaches to regional geo-logical studies. Nick studied geology and oceanography at the University of Southampton, England, and received a master’s degree in micropaleontology from University College London.

Greg Heath is a Petrophysicist and Operations Geologist for Chevron Thailand Exploration and Production Ltd in Bangkok, Thailand, and has worked as a consulting petrophysicist in Thailand since 1997. He began his career in 1978 with Exlog North Sea Ltd in the UK and Norwegian North Sea before moving to Baker Hughes in 1980, with positions in Canada, the US, Senegal and Ghana. Greg was an independent wellsite geologist for Décollement Consulting Inc. from 1985 to 1997 and has a BSc degree (Hons) in geology from the University of Portsmouth, England.

Nora Herbst, based in Houston, is a Geology Interpretation and Inversion Team Leader for Schlumberger. Nora, who has 20 years of exploration experience in the oil industry, joined WesternGeco in 2007. Prior to that, she worked for Repsol YPF in Argentina and Spain and as a consultant for various operating companies in Argentina. She focuses on the geology of passive margin basins, mainly in deep- and ultradeepwater offshore western Africa, East Africa and in Libya and works on seismic interpretation and depth imaging in salt tectonic basins. She has been a company portfolio manager and developed play con-cepts and risk analysis. Nora earned a degree in geol-ogy from the Universidad Nacional de Tucumán, San Miguel de Tucumán, Argentina.

Zuber A. Khan began his career with Geoservices as a mudlogging geologist, monitoring more than 200 wells for various multinational E&P operators. Currently a Senior Geology Manager with Gujarat State Petroleum Corporation Ltd in Gandhinagar, Gujarat, India, he joined the company in 2000 as an operations geologist focused on the Krishna-Godavari offshore HPHT field. Zuber earned a BS degree (Hons), an MS degree in geo-sciences and a PG diploma in hydrogeology, all from Aligarh Muslim University, Aligarh, Uttar Pradesh, India.

Contributors

58 Oilfield Review

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Waranon Laprabang has been Senior Vice President, Arthit Asset, PTT Exploration and Production Public Company Limited (PTTEP) since 2011. He began his career in 1980 as geologist for the Thailand Department of Mineral Resources and Italian-Thai Development plc, Thailand. After working for Geoservices Eastern, Inc. in South and Southeast Asia, he joined PTTEP as senior geologist and worked in several exploration and new ventures. In Oman, as an asset manager, he was responsible for oil, gas and con-densate field discoveries and for setting up production processing facilities and pipelines; he was also involved in forming the first gas sale agreement between PTTEP and the Omani government. In 2005, he returned to Thailand as PTTEP vice president of domestic and Malaysia-Thailand Joint Development Area, Joint Venture Assets. Waranon has a bachelor’s of science degree in geology from Chiang Mai University, Thailand.

Angus McCoss is Exploration Director for Tullow Oil plc in London. Before joining Tullow in 2006 as general manager of exploration, he had 21 years of exploration experience, primarily with Shell in Africa, Europe, China, South America and the Middle East. He held a number of Shell senior positions including Americas regional vice president of exploration and general manager of exploration in Nigeria. He was appointed to the board of directors of Tullow in 2006. He is a Nonexecutive Director of Ikon Science Limited and a member of the advisory board of the Energy & Geoscience Institute of the University of Utah, Salt Lake City, USA. Angus received a BSc degree (Hons) in geology from the University of Dundee, Scotland, and a PhD degree in structural geology from the University of St Andrews, Scotland.

Bernard Montaron is Director of the Schlumberger China Petroleum Institute in Beijing. He joined Schlumberger in 1985 and has worked in R&D and marketing in Europe, the US and the Middle East. His assignments included theme director for carbonates and naturally fractured reservoirs, director of engi-neering and general manager of R&D and manufac-turing at Schlumberger Riboud Product Center in Clamart, France; Oilfield Services marketing vice president for Europe, CIS and Africa; and vice presi-dent of marketing for Schlumberger Middle East. Bernard obtained an MSc degree in physics from École Supérieure de Physique et de Chimie Industrielles (ESPCI ParisTech) in Paris and a PhD degree in mathematics from Université Pierre et Marie Curie, Paris. He is a member of the board of directors of ESPCI ParisTech and a member of AAPG, SPE, SPWLA and the European Association of Geoscientists and Engineers.

Kamal Osman is a Senior Staff Petrophysicist at Chevron Thailand Exploration and Production Ltd and is the Geologic Operations Team Leader in Bangkok, Thailand. He began his career in 1980 as a develop-ment geologist in the Sudan and has worked in Chevron overseas operations in West Africa, Papua New Guinea, the Middle East and Kazakhstan. Kamal, who has coauthored several petrophysical papers and is a member of SPE and the SPWLA, received a BS degree (Hons) in geology from the University of Khartoum, Sudan.

Anton Parshin is the Thermal Measurements and Interpretation Program Manager with Schlumberger in Moscow. His responsibilities include production log-

ging in low-rate horizontal wells and formation satura-tion monitoring in freshwater environments. Anton has BS and MS degrees in physics and a doctorate degree in petroleum engineering, all from Bashkir State University, Ufa, Russia.

Dimitri Pissarenko, based in Moscow, has been the Schlumberger Moscow Research Director since 2007. He focuses on the development of partnerships with Russian academia and research institutions. Dimitri earned a higher national diploma in electronic engi-neering from the Moscow Power Engineering Institute, Russia, and a doctorate degree in geophysics from the Institut de Physique du Globe de Paris, France.

Yury Popov is a Scientific Advisor at the Schlumberger Moscow Research Center. He manages the development of advanced experimental methods in thermal petro-physics and their implementation in the oil and gas industry. He is the author of more than 200 publications and holder of more than 40 patents. Prior to joining Schlumberger, he was the head of the department of technical physics and rock physics and was the scien-tific leader of the research laboratory of geothermic problems at Russian State Geological Prospecting University, Moscow. Yury obtained a PhD degree from the Russian Technological Institute and a doctorate degree in physics and mathematics from the Institute of Physics of the Earth, Russian Academy of Sciences.

David Quirk is Lead Geoscientist in global play analy-sis at Maersk Oil in Copenhagen, Denmark. He was previously technical team leader for Maersk Brazil exploration activities. Before joining Maersk, he worked for Shell, Oxford Brookes University in England, Burlington Resources and Hess Corporation. His recent publications have focused on plate recon-structions in the South Atlantic, salt tectonics and analysis of risk and uncertainty in petroleum explora-tion. David holds a PhD degree in geology from the University of Leicester, England.

Raisa Romushkevich is a Geologist for the Schlumberger Moscow Research Center, where she focuses on geologic interpretation of experimental results on the thermal properties of rocks. Before join-ing Schlumberger, she was a geologist and head of the laboratory of rock physics at Russian State Geological Prospecting University, Moscow. The coauthor of more than 50 publications, Raisa received an MSc degree from Irkutsk State University, Russia.

Jay Russell is the Oilfield Services and Technical Challenges Marketing Communications Manager for Schlumberger in Houston. He began his career in 1991 as a wireline field engineer for Schlumberger in Bakersfield, California, USA, and held various field operations positions worldwide. He has also worked at engineering centers and held wireline management positions for Schlumberger. Jay has a BS degree in mechanical engineering from Worcester Polytechnic Institute, Massachusetts, USA, and an MS degree in operations management from Rensselaer Polytechnic Institute in Troy, New York, USA.

Sergey Safonov is a Reservoir Physics Discipline Manager at the Schlumberger Moscow Research Center. He concentrates on a wide range of topics related to measurement and interpretation of complex fluid flows in reservoirs. Sergey earned a BS degree in natural science and an MS degree in physics from the Moscow Institute of Physics and Technology and a postgraduate diploma in physics from the University of Exeter, England.

Paul Sims is the South and East Africa Operations Manager of Testing Services for Schlumberger in Dar es Salaam, Tanzania. Prior to his current position, he was the product champion for Testing Services in Clamart, France, where he was responsible for new product development and the introduction of surface testing and memory gauge technology. He joined Schlumberger in 2004 as a field engineer in Australia and then became a field service manager there; he next worked as a location manager for East Malaysia, Brunei and the Philippines. Paul obtained bachelor’s degrees in petroleum engineering and finance, both from the University of Western Australia in Perth.

Miroslav Slapal, who is based in Moscow, is the Sales and Marketing Manager for Schlumberger Wireline Russia and Central Asia. He joined Schlumberger in 1994 as a field engineer and had assignments in the North Sea, West Africa and Russia. During his most recent assignment in Houston as reservoir sampling and pressure product champion, he was involved in the development and definition of future Schlumberger HPHT technologies for reservoir pres-sure and sampling. Miroslav has an MS degree in petroleum engineering from the Technical University of Ostrava, Czech Republic.

Mikhail Spasennykh is a Business Development Manager with Schlumberger. He is based in Moscow.

Vladimir P. Stenin is the Head of the Geological Prospecting and Exploration Section for Lukoil in Moscow. His 30-year career includes positions with Schlumberger, PetroAlliance and Orenburg Geophysical Research Expedition. Vladimir received a PhD degree in engineering and geophysics from Gubkin Russian State University of Oil and Gas, Moscow.

Paul Tapponnier is Professor and Group Leader of the Tectonics and Earthquakes Group at the Earth Observatory of Singapore at the Nanyang Technological University in Singapore, where he has worked since 2009. Previously, he worked at the Tectonique, Mécanique de la Lithosphère group at the Institut de Physique du Globe de Paris. His contributions to geol-ogy, tectonics and geophysics span more than 40 years and his research interests include continental dynam-ics and tectonics, particularly in Asia and the Mediterranean region; active faulting and seismotec-tonics; earthquake hazard assessment; quantitative geomorphology; rates of active deformation processes; and rock mechanics and rock deformation physics. He is a member of both the French and US National Academy of Sciences and a Fellow of the American Geophysical Union, Geological Society of America and Geological Society of London. Paul holds an ingénieur des mines degree from Ecole Nationale Supérieure des Mines de Paris and a doctorat d’etat degree from Université Montpellier 2 Sciences et Techniques, France.

Chris Tevis, based in Sugar Land, Texas, USA, is a Product Champion with Schlumberger at the Houston Pressure and Sampling Product Center. Prior to his cur-rent position, he was a field engineer, an engineer in charge, a field service manager and quality operations support manager and worked in China, Southeast Asia and the US. Chris has a BS degree in mechanical engi-neering from Columbia University, New York City, and is pursuing an MSc degree in oil and gas industry manage-ment from Heriot-Watt University, Edinburgh, Scotland.

Autumn 2012 59

An asterisk (*) is used to denote a mark of Schlumberger.

54401schD6R1.indd 59 12/4/12 9:55 AM

60 Oilfield Review

NEW BOOKSComing in Oilfield Review

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

Debris Removal. Small debris can foul completions, increase operation costs and ultimately diminish well productivity. Engineers are designing specialized wellbore cleaning sys-tems capable of performing critical debris recovery operations. Case studies from Alaska, USA, the Gulf of Mexico and the North Sea demon-strate how operators are using these new systems to reduce risks and improve operational efficiency.

Fishing. Any object that is lost in the hole or that impedes normal downhole operations must be retrieved. The concept of fishing—the process of recovering lost items such as tubulars, tools or completion components from the wellbore—requires imagination and innovation. This article describes tools and strat-egies developed for dealing with lost equipment in the wellbore.

Evaluation While Drilling. Motivated by environmental, health and security reasons, scientists have spent years developing alternatives to radioisotope-based logging tools. Through the use of pulsed-neutron generators that have replaced chem-ical sources in other logging tools, engineers have developed a radio-isotope-free gamma-gamma density measurement. This innovation allows operators to deploy a full suite of LWD tools that have no chemical sources.

Waking the Giant: How a Changing Climate Triggers Earthquakes, Tsunamis, and VolcanoesBill McGuireOxford University Press198 Madison AvenueNew York, New York 10016 USA2012. 320 pages. US$ 29.95ISBN: 978-0-19-959226-5

The author describes how the Earth’s climate has affected and caused major geologic events through the millennia. By looking at such trends, McGuire contends that as our climate change crisis emerges, the world may experience a resulting increase in natural disasters.

Contents:

• The Storm After the Calm

• Once and Future Climate

• Nice Day for an Eruption

• Bouncing Back

• Earth in Motion

• Water, Water, Everywhere

• Reawakening the Giant

• Selected Sources, Further Reading, Index

McGuire . . . has written a dry but enthralling overview of how climate affects the geophysical world, and vice versa. . . . He provides a solid critical foundation for current climate projections, noting the difference between the scientific and popular narratives of climate change. . . . Despite its heavy-handed scene-setting, the book will satisfy dooms-day eschatologists and curious Earth lovers interested in what the future holds.

“Book Review,” Publishers Weekly (February 13,

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

19-959226-5 (accessed September 6, 2012).

McGuire lays out a strong case for the interconnectedness of Earth systems. . . . Yet when it comes to the most crucial question, of how future climate change will affect the planet, even he cannot say.

Witze A: “Book Review,” Science News 181,

no. 10 (May 19, 2012): 30.

Free Radicals: The Secret Anarchy of ScienceMichael Brooks Overlook Press141 Wooster StreetNew York, New York 10012 USA2012. 320 pages. US$ 27.95ISBN: 978-1-59020-854-0

This book looks behind the formal doors of scientific discovery to reveal the extreme behavior some celebrated scientists have engaged in to bring the world’s attention to their findings. Sparing no one—from Newton and Einstein to Watson and Crick—author Brooks finds fraud, deception, manipu-lation and unethical experiments are just some of the behaviors that break the illusion of the logical and level-headed “Scientist” front that is pre-sented to the world.

Contents:

• How It Begins: Dreams, Drugs and Visions from God

• The Delinquents: Rules Are There to Be Broken

• Masters of Illusion: Evidence Isn’t Everything

• Playing with Fire: No Pain, No Gain

• Sacrilege: Breaking Taboos Is Part of the Game

• Fight Club: There’s No Prize for the Runner-Up

• Defending the Throne: Machiavelli Would Be Proud

• In the Line of Fire: Life on the Barricades

• Epilogue, Notes and Sources, Index

‘Science is not for the meek and mild,’ Michael Brooks writes in this entertaining new book. . . . ‘Free Radicals’ is an exuberant tour through the world of scientists behaving badly.

Bouton K: “Rebels Whose Bold Moves Set

Science Aglow,” The New York Times (May 21,

2012), http://www.nytimes.com/2012/05/22/

science/free-radicals-book-review-rebels-

who-set-science-aglow.html?_r=1 (accessed

May 29, 2012).

The Idea Factory: Bell Labs and the Great Age of American InnovationJon GertnerThe Penguin Press, a division ofPenguin Group (USA) Inc.375 Hudson StreetNew York, New York 10014 USA2012. 432 pages. US$ 29.95ISBN: 978-1-594-20328-2

Author Jon Gertner describes the history of the AT&T Bell Laboratories and its role in one of the most produc-tive periods in US innovation—the 1920s to the 1980s. In addition to describing the birth of pioneering technologies such as radar, lasers, radio astronomy and mobile phones, all of which were developed at Bell Laboratories, Gertner explains how Bell Laboratories created a culture of creativity. The book also explores the concept of the business of innovation.

Contents:

• Introduction: Wicked Problems

• Oil Drops

• West to East

• System

• War

• Solid State

• House of Magic

• The Informationist

• Man and Machine

• Formula

• Silicon

• Empire

• An Instigator

• On Crawford Hill

• Futures, Real and Imagined

• Mistakes

• Competition

• Apart

• Afterlives

• Inheritance

• Echoes

• Endnotes and Amplifications, Sources, Selected Bibli- ography, Index

54401schD7R1.indd 60 12/1/12 2:38 PM

• Icarus and Fukushima Daiichi: Human Factors in a Meltdown (Sv=1J/kg.w)

• References, Index

Each essay provides its fair share of wit and satire, poignantly illustrat-ing faults or curiosities in current scientific thought or public discourse of the scientific realm.

Ingram MAC: “#FramingTheArtofScience,”

Science 337, no. 6096 (August 17, 2012): 801.

A crackle of erudite energy leaps from this lively commingling of art, culture and science. In 28 essays, biologist Gerald Weissmann explores the complex territory of modern biology and epigenetics in this era of social media. In each, Weissmann finds links between research and elements of history and pop culture, which play off each other to illuminat-ing effect.

“Books in Brief,” Nature 483, no. 155 (March 8,

2012), http://www.nature.com/nature/journal/

v483/n7388/full/483155a.html (accessed

September 24, 2012).

Turing’s Cathedral: The Origins of the Digital UniverseGeorge DysonPantheon Books, a division of Random House, Inc.1745 BroadwayNew York, New York 10019 USA2012. 432 pages. US$ 29.95ISNB: 978-0-375-42277-5

Through interviews, exploration of archives and a unique personal vantage point, George Dyson tells the story of the people who came together at the Institute for Advanced Study at Princeton University, New Jersey, USA, to create the “Turing Machine.” Though mathematician Alan Turing lends his name to the title, this is the story of mathematician John von Neumann and his team, which created the Mathematical Analyzer, Numerical Integrator, and Computer, or MANIAC. Dyson argues that this early computer is the nucleus of today’s digital universe.

In a series of essays, the author explores epigenetics: the concept of how our genes respond to our environ-ments. Biology meets pop culture in these pages, and the author furthers the nature versus nurture debate.

Contents:

• Walter Benjamin and Biz Stone: The Scientific Paper in the Age of Twitter

• Epigenetics in the Adirondacks

• A Nobel Is out of Order: “J. Lo” vs. Hypatia of Alexandria

• Epigenetics and Alma Mahler

• Inflammation Is Complicated: From Metchnikoff to Meryl Streep

• An Arrowsmith for the NASDAQ Era: Extraordinary Measures

• Sarah Palin and Marie-Antoinette: Post-Traumatic Tress Disorder

• Coca-Cola and H.G. Wells: Dietary Supplements as Subprime Drugs

• Voodoo Economics and Voodoo Healing: Witchcraft Persists in Massachusetts

• Myrna Loy: Co-Principal Investigator

• Dr. Ehrlich and Dr. Atomic: Beauty vs. Horror in Science

• Free Radicals Can Kill You: Lavoisier and the Oxygen Revolution

• Experimental Errors: Paul Bert and the Alabama Tenure Killings

• Monumental Revolutions: Scientific, Sanitary and ’Omic

• Quorum Sensing on the Airbus Wing

• SiCKO Statistics: Michael Moore and L’École de Paris

• Ask Your Doctor: Justice Holmes and the Marketplace of Ideas

• Filter the Dogs: Microbial Mishaps in Massachusetts

• Pattern Recognition and Gestalt Psychology: The Day Nüsslein-Volhard Shouted “Toll!”

• Not by the Sword, but Disease: Doctor Howe and General Shinseki

• Science as Oath and Testimony: Joshua Lederberg

• X-Ray Politics: The Nazi War on Röntgen and Einstein

• Wild Horses and The Doctor’s Dilemma

• Glass Ceilings at the Nobel Prizes

• Medea and the Microtubule

• Wiki-Science and Molière’s Beast

• Arts and Science: Lewis Thomas and F. Scott Fitzgerald

Jon Gertner, an editor at Fast Company magazine, has produced a well-researched history of Bell Labs, filled with colorful characters and inspiring lessons. But more important, “The Idea Factory” explores one of the most critical issues of our time: What causes innovation? Why does it happen, and how might we nurture it?

Isaacson W: “Inventing the Future,” The New York

Times (April 6, 2012), http://www.nytimes.

com/2012/04/08/books/review/the-idea-factory-by-

jon-gertner.html?_r=1 (accessed April 12, 2012).

‘The Idea Factory’ is an expansive treatment of the labs’ history. . . . The tensions among the three nominal inventors, Walter Brattain, John Bardeen and William Shockley, have been chronicled often. But Gertner’s version is especially well told.

Yet Gertner’s focus may be too narrow. . . . ‘The Idea Factory’ might have benefited from a fuller discus-sion of the fate of corporate research in today’s world.

Hiltzik M: “‘The Idea Factory’ by Jon Gertner,”

Los Angeles Times (March 25, 2012),

http://articles.latimes.com/2012/mar/25/

entertainment/la-ca-jon-gertner-20120325

(accessed April 11, 2012).

. . . Mr. Gertner’s book offers fascinating evidence for those seeking to understand how a society should best invest its research resources.

Metcalfe B: “Where the Future Came From,”

The Wall Street Journal (March 16, 2012),

http://online.wsj.com/article/SB1000142405

2970204781804577271442604380350.html


Epigenetics in the Age of Twitter: Pop Culture and Modern ScienceGerald WeissmannBellevue Literary PressNew York University School of Medicine 350 First Avenue OBV 612 New York, New York 10016 USA2012. 300 pages. US$ 18.95ISBN: 978-1- 934-13739-0

Autumn 2012 61

Contents:

• 1953

• Olden Farm

• Veblen’s Circle

• Neumann János

• MANIAC

• Fuld 219

• 6J6

• V-40

• Cyclogenesis

• Monte Carlo

• Ulam’s Demons

• Barricelli’s Universe

• Turing’s Cathedral

• Engineer’s Dreams

• Theory of Self-Reproducing Automata

• Mach 9

• The Tale of the Big Computer

• The Thirty-Ninth Step

• Key to Archival Sources, Notes, Index

(Dyson’s book is worth reading for its treatment of the institute’s early history alone.) . . . While Dyson doesn’t shy away from discussing obscure technical and theoretical aspects of Von Neumann’s computer, he also provides ample social and cultural context. . . . Dyson, who grew up at the institute, where his father Freeman Dyson was a fellow, also brings a charming personal touch to the narrative. . . . Turing’s Cathedral is an engrossing and well-researched book that recounts an important chapter in the convoluted history of 20th-century computing.

Morozov E: “Turing’s Cathedral by George

Dyson—Review,” The Guardian (March 24,

2012), http://www.guardian.co.uk/books/2012/

mar/25/turings-cathedral-george-dyson-review


Mr. Dyson’s . . . determination to keep the book accessible to the layman means that there is not enough for the more expert reader to get a step-by-step sense of what the computer did.

Modern digital computing is too complicated a thing to be traced to a single moment of divine conception. But Mr. Dyson’s chronicle, if too limited in scope to be a definitive history of the computer, is a well-told chapter of that larger story.

Kakaes K: “The Nucleus of the Digital Age,”

The Wall Street Journal (March 3, 2012),

http://online.wsj.com/article/SB1000142405

2970204909104577237823212651912.html

(accessed March 21, 2012).

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Oilfield Review

Climate Matters: Ethics in a Warming WorldJohn BroomeW.W. Norton & Company, Inc.500 Fifth AvenueNew York, New York 10110 USA2012. 224 pages. US$ 23.95ISBN: 978-0-393-06336-3

In this book from the Amnesty International Global Ethics Series, philosopher John Broome posits that the principles that underlie everyday decision making also provide simple and effective ideas for confronting climate change. The author explores the moral dimensions of climate change and discusses universal standards of goodness and justice that both citizens and governments must adhere to when trying to solve this global dilemma.

Contents:

• Introduction

• Science

• Economics

• Justice and Fairness

• Private Morality

• Goodness

• Uncertainty

• The Future Versus the Present

• Lives

• Population

• Summary

• Notes, Index

By providing readers with an overview of the science and economic questions behind global warming, Broome lays a solid foundation for the . . . arguments in the book. . . . Broome’s overall message appeals to the moral goodness of humanity. . . . A moral and just viewpoint on an ever-expanding global issue.

“Book Review,” Kirkus Reviews (May 15, 2012),

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

john-broome/climate-matters/#review (accessed

September 4, 2012).

Philosopher and ‘lapsed econo-mist’ John Broome vaults in where policy-makers fear to tread, exploring the moral aspects of climate choices. In the latest installment in the Amnesty International Global Ethics Series, Broome argues that countries and individuals are ethically obliged to curb emissions. With penetrating clarity, he uses science and economics as a springboard to cover big issues, from the need for action despite uncertainty to the value of human life.

“Books in Brief,” Nature 487, no. 299 (July 19,

2012), http://www.nature.com/nature/journal/

v487/n7407/full/487299a.html (accessed

September 24, 2012).

Reinventing Discovery: The New Era of Networked ScienceMichael NielsenPrinceton University Press41 William StreetPrinceton, New Jersey 08540 USA2012. 280 pages. US$ 24.95ISBN: 978-0-691-14890-8

In this book, Michael Nielsen, a pioneer of quantum computing, describes how the internet is not only transforming our collective intelligence, but also revolutionizing scientific discovery. Nielsen shows how online collaboration tools, networked science and open data policies are bringing scientists together, expanding our problem- solving ability and increasing our combined brainpower.

Contents:

• Reinventing Discovery

• Part 1: Amplifying Collective Intelligence: Online Tools Make Us Smarter; Restructuring Expert Attention; Patterns of Online Collaboration; The Limits and the Potential of Collective Intelligence

• Part 2: Networked Science: All the World’s Knowledge; Democratizing Science; The Challenge of Doing Science in the Open; The Open Science Imperative

• Appendix, Selected Sources and Suggestions for Further Reading, Notes, References, Index

In Reinventing Discovery, [Nielsen’s] easy-to-read and enthusi-astic narrative integrates a set of ideas that could, indeed, revolutionize knowledge creation. . . . Nielsen’s timely volume weaves together themes of big data, open access, gamification, and citizen science to make bold claims about what discovery may look like in the 21st century.

While he should be applauded for integrating these developments, one wishes for a deeper analysis of foundational issues. . . .

The social, organizational, and computational sciences have a long and rich history in understanding and improving collaboration. . . . Nielsen provides an important foundation for moving forward.

Fiore SM: Science 336, no. 6077 (April 6, 2012):

36–37.

. . . Nielsen makes a compelling case in this self-described manifesto. With friendly, engaging writing, he describes specific approaches and characteristics that can make collaborations truly bloom.

Ehrenberg R: “Book Reviews,” Science News 181,

no. 6 (March 24, 2012): 34.

Eruptions That Shook the WorldClive OppenheimerCambridge University Press32 Avenue of the AmericasNew York, New York 10013 USA2011. 408 pages. US$ 30.00ISBN: 978-0-521-64112-8

Volcanologist Oppenheimer takes a forensic approach to describe some of the largest cataclysmic volcanic events of the past quarter of a billion years by examining geologic, historic, archaeo-logical and paleoenvironmental records such as ice cores and tree rings. The author argues that catastrophic risk management will be an easier task if scientists have a better understanding of these events and how they affected all aspects of life on Earth.

Contents:

• Fire and Brimstone: How Volcanoes Work

• Eruption Styles, Hazards and Ecosystem Impacts

• Volcanoes and Global Climate Change

• Forensic Volcanology

• Relics, Myths and Chronicles

• Killer Plumes

• Human Origins

• The Ash Giant/Sulphur Dwarf

• European Volcanism in Prehistory

• The Rise of Teotihuacán

• Dark Ages: Dark Nature?

• The Haze Famine

• The Last Great Subsistence Crisis in the Western World

• Volcanic Catastrophe Risk

• Appendices, References, Index

Oppenheimer, a reader at the University of Cambridge, argues that volcanoes and life have been inter-twined throughout time. . . . [and] uses all sorts of evidence to unravel the stories behind some of the greatest and most significant volcanic cataclysms.

I recommend Eruptions That Shook the World as motivational reading for physics students looking for a thesis topic in Earth or environ-mental sciences. The book may encourage physicists to take up the fascinating but challenging mission of understanding the workings of deep Earth and the claims that are made for it.

Anderson DL: “Book Review,” Physics Today 65,

no. 5 (May 2012): 55.

62

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The most common reservoir rocks are sandstone (ρmatrix = 2.65 g/cm3), limestone (ρmatrix = 2.71 g/cm3) and dolomite (ρmatrix = 2.87 g/cm3). These matrix density values are used to compute density porosity. The other input, ρfluid, is usually that of water (1 g/cm3).

Appropriate choice of ρmatrix values, which are often derived from other measurements, is crucial to the density porosity computation. An incorrect ρmatrix input or a mixture of rock types will yield an incorrect density porosity measurement. The same is true for the ρfluid input.

Neutron porosity tools emit high-energy fast neutrons (on the order of 106 eV) from chemical or electronic sources (below). Neutrons, which are neutrally charged subatomic particles, lose energy when they collide with nuclei of formation materials. The energy loss is related to the relative mass of the particles with which the neutron collides. Hydrogen, which consists of a nucleus with a single proton, is the most effective element for slowing fast neutrons. In reservoir rocks, hydrogen is associated with the liquids—oil or water—that fill the pore space. Gas has a much lower hydrogen density than oil and water.

When it comes to evaluating conven-tional reservoirs, petrophysicists are often concerned with three key parameters: permeability, porosity and the presence of hydrocarbons. Permeability is the measure of a rock’s ability to allow fluids to pass through it. Porosity is the volumetric void space in the rock—the space not occupied by solid material (right). Without the presence of hydrocar-bons, porosity—which is directly related to production potential—and permeability may be of little interest to log analysts.

Although porosity is a crucial parameter for evaluating reservoirs, the first logs measured formation resistivity. Introduced in the 1920s, resistivity tools helped identify potential hydrocarbon-bearing rocks. High resistivity is a characteristic of the presence of hydrocarbons and low resistivity is indic-ative of water. However, log analysts could not differentiate between rocks containing hydrocarbons and those with no porosity because both exhibit high resistivity. Even when hydrocarbon-bearing zones were identified using resistivity tools, the volume of hydrocarbon could not be determined with-out a porosity measurement.

The first porosity measurements, which became available in the early 1950s, came from sonic, or acoustic, logging tools. Sonic porosity is com-puted by comparing the speed of sound through the formation to that of rocks with no porosity. Sound travels more slowly though fluid-filled rocks than through rocks with no porosity.

Scientists have developed an assortment of porosity logging tools based on various physical principles. Today, although sonic porosity logs are still used, the two predominant porosity measurements are density porosity and neutron porosity.

Porosity MeasurementsDensity tools emit medium-energy gamma rays into a borehole wall (above right). The gamma rays collide with electrons in the formation, lose energy and scatter after successive collisions. The number of collisions is related to the number of electrons per unit volume—the electron density. The elec-tron density for most minerals and fluids encountered in oil and gas wells is directly proportional to their bulk density, ρbulk.

The bulk density measured by the tool, ρlog, results from the combined effects of the fluid (porosity) and the rock (matrix) and is used to compute density porosity (fdensity):

.

Oilfield Review AUTUMN 12 Defining Porosity Fig. 1ORAUT 12-DEFPOR 1

Porosity Rock grain

> Porosity. The void space in rocks not occupied by solid material may be filled with water, oil or gas.

Autumn 2012 63

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How Porosity Is Measured

Oilfield Review Autumn 2012: 24, no. 3. Copyright © 2012 Schlumberger.

Tony SmithsonEditor


Long-spaceddetector

Short-spaceddetector

Source

Formation

> Density porosity tool. A radioactive source emits gamma rays into the formation, where they interact with minerals and fluids; some gamma rays return to detectors where they are counted and their energy levels measured.

matrix – fluiddensity = φ matrixρ ρ

ρ ρlog –


Neu

tron

ener

gy, e

V

Time, ms

Electronic sourceFormation

Long-spaced

detector

Borehole

Short-spaced

detector

Neutronsource

Thermalneutronregion

Chemical source

Average thermalenergy 0.025 eV

Capture

10–2

10 100

100

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106

> Life of a fast neutron. The neutron porosity tool (left) sends out high-energy neutrons that collide with molecules in the formation rocks and fluids, lose energy (right) and eventually reach thermal energy level (0.025 eV) in a region some distance from the source. Some of the thermal neutrons return to the tool where they are counted by the detectors. These counts are converted into a hydrogen index (HI) measurement, which is used to compute neutron porosity. Thermal neutrons are eventually captured by elements in the formation.

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After multiple collisions, the neutrons achieve a low energy state (0.025 eV) and are referred to as thermal neutrons. The number of thermal neutrons resulting from collisions with hydrogen is proportional to the hydro-gen index (HI) of the formation.

A conventional neutron porosity tool has two detectors located fixed dis-tances from the source. The detectors count neutrons that have passed through the formation and attained thermal energy levels. The HI is derived from the ratio of counts from these two detectors, and analysts apply a lithology-dependent transform to convert HI to neutron porosity. As with the density porosity, obtaining accurate neutron porosity depends on using the correct matrix.

For clean, shale-free formations, in which the porosity is filled with water or oil, the neutron log measures the fluid-filled porosity. Because gas has a much lower hydrogen density than oil or water, gas-filled porosity appears as low porosity.

Several environmental factors affect neutron porosity measurements and corrections have been developed to compensate for them. These include bore-hole size, mud weight and salinity, mudcake thickness, hydrostatic pressure, formation salinity and temperature.

Complementary MeasurementsPorosity tools respond in well-defined ways to the physical attributes of fluids and rocks. As part of the log interpretation process, log analysts account for these different responses. Two of the most easily recognized examples of tool responses are the shale effect and the neutron-density gas effect (above).

In clean rocks filled with water, the density and neutron porosity logs should overlie each other if the correct lithology input is applied. When shale is present, the neutron porosity measurement is higher than the density porosity. This results from the neutron responding to the large volume of fluid adsorbed by the shale. The net effect is that, in shales, there is a separation between the density and neutron porosity curves—the shale effect.

The effects of shale also give rise to another term—effective porosity. Petrophysicists derive total porosity values by combining different

measurements and correcting for environmental and lithologic conditions. This total porosity includes fluids associated with shale. Because the fluids in shales cannot usually be produced, their contributions to the measure-ment can be subtracted from the total porosity. By quantifying the shale contribution and removing it from the total porosity measurement, log analysts are able to compute the effective porosity, which more accurately portrays a reservoir’s potential.

The gas effect results from two physical measurement principles. Gas-filled porosity is seen by the neutron porosity tool as low porosity. In contrast, the density porosity measurement may be higher than the true porosity. The result is that the density and neutron porosity curves are neither overlying each other—which would indicate water- or oil-filled porosity and the correct matrix—nor separated from each other, the shale effect. Because the neutron porosity is lower than the density porosity, the curves cross over each other, giving rise to the term crossover.

The shale effect counteracts the crossover effect; however, petrophysicists use other measurements to correct for the shale volume and determine the effective porosity. The gas effect can also be masked by the presence of deep invasion when drilling fluid filtrate displaces the original gas in place. Logging-while-drilling (LWD) tools, which acquire data before invasion takes place, may identify the presence of gas zones that are missed by wireline tools, which are run some time after drilling.

Other measurement techniques can be used to determine porosity. These include nuclear magnetic resonance (NMR) tools and core samples. An NMR tool directly measures liquid-filled porosity. Core data provide an empirical porosity value, although damage during the core recovery process may affect the measured value.

Crucial ParameterPorosity is one of the most critical parameters for quantifying hydrocarbon reserves. Petrophysicists have developed numerous ways to determine porosity to make sure they have the most accurate data possible. The ulti-mate goal is to use these data to understand a reservoir’s production poten-tial and ensure that its hydrocarbons are effectively recovered.

Oilfield Review64

DEFINING POROSITY


Crossover Crossover Crossover

Shale effect Shale effect Shale effect

SandstoneFormation

Shale

Matrix: SandstoneAssumed Matrix Density: 2.65 g/cm3

Curves overlieeach other

4% difference 12% difference

Matrix: LimestoneAssumed Matrix Density: 2.71 g/cm3

Matrix: DolomiteAssumed Matrix Density: 2.87 g/cm3

Gas

Oil

Water

Porosity, %60 0 Porosity, %60 0 Porosity, %60 0

> Lithology and fluid effects. Density porosity (red) and neutron porosity (dashed blue) are computed from lithology-dependent relationships. Log analysts use the tools’ characteristic responses to help determine fluid type and lithology. For example, in a sandstone formation, with porosity computed using correct parameters (left ), the curves overlie one another at the correct porosity of 30% in water, cross over somewhat in oil, cross over a great deal in gas and separate in shales. If an incorrect matrix is used, such as limestone (middle) or dolomite (right ), the computed porosities are incorrect by 4% and 12%, respectively.

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Autumn 2012

Pressure and Sampling in Extreme Conditions

Thermal Properties of Reservoir Rocks

Plate Tectonics in Exploration

Oilfield Review

SChlumbERgER OilfiEld REviEw

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Autumn 2012 Oilfield Review