Schlumberger Oilfield Review

Winter 2010/2011

Enhanced Oil Recovery

Arctic Operations

Oil Shale

Oilfield Review

SCHLUMBERGER OILFIELD REVIEW

WIN

TER 2010/2011VOLUM

E 22 NUM

BER 4

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The global imbalance between supply and demand for oil and gas is growing. This trend is pointed out in studies from numerous organizations that watch the E&P industry, including the International Energy Agency, Cambridge Energy Research Associates and the World Petroleum Council. Some studies indicate that the decline rate of existing oil fields is increasing significantly over time, so additional production is becoming progressively more cru-cial to bridge the supply and demand gap.

In my opinion, neither we, as professionals in the oil and gas industry, nor the resource owners can be satisfied with recovery factors that average well below 40%. We need to do better. Enhanced oil recovery (EOR) is a vital means to achieve additional production and recovery from new and existing fields. In addition, several sizable resources, such as extra-heavy oil fields, cannot be developed without EOR techniques. The high capital investments for offshore and deepwater projects warrant a reassessment of development philosophies because production options once considered tertiary now need to be considered as possibilities in initial development stages.

EOR techniques employ fundamental physical and chem-ical rock and fluid interactions to improve reservoir sweep and reduce residual oil saturations (see Has the Time Come for EOR? page 16). Of the three basic EOR processesthermal, gas injection and chemicalused to achieve these ends, thermal and gas injection are the most mature. Chemical EOR is advancing rapidly in the use of mobility improvements (polymer and steam), residual saturation reducers (surfactants and designer waterflooding) or com-binations thereof (alkali-surfactant-polymer flooding).

Extensive customization, fundamental to ensure that an EOR process will be successful for a specific field, contrib-utes significantly to the complexity and cost of EOR projects. This customization usually includes detailed laboratory studies, field trials, pilots and phased developments, all needed to reduce project risk before sanction. Unfortunately, this also leads to quite long development times and higher up-front investment, hence, longer payback times. Faster maturation workflows are required, which can be enabled by technological solutions to speed up appraisal and devel-opment. The fiscal regimes that work well for primary and secondary developments in several countries stand in the way of economic EOR projects, thus change of the fiscal frameworks is required as well.

Enhanced recovery comes at a price. The technical costs in dollars per barrel produced are notably higher than those of primary or secondary recovery methods. In addi-tion, the environmental footprint of some EOR techniques

Enhanced Oil Recovery: Here to Stay

1

can be significant and necessitates mitigation, also adding to the costs. EOR processes developed in the past are not necessarily the solutions we need for today and tomorrow. We therefore need continued investment in EOR technology development, from the processes and fundamental concepts, to new engineering solutions, to surveillance techniques that improve sweep efficiency.

Recent research efforts have greatly advanced the funda-mental understanding of the rock and fluid interface in chemical EOR. This understanding has opened up new opportunities that have lower costs and higher recovery efficiencies. It has also increased the scope for recovery to domains that were previously thought to be unattractive as targets for EOR. However, more work is required. If we want to reduce the EOR technology timeline and deploy projects earlier, we must encourage wider cooperation between industry, academia and resource holders. There must be sharing of risk, data and knowledge while address-ing and overcoming potential blocks such as intellectual property ownership and other commercial aspects.

I am therefore pleased that Schlumberger and Shell have recently agreed to start a significant landmark research partnership. The research is aimed at discovering and developing new methodologies and technologies for enhancing recovery, with the aim of addressing many of the challenges mentioned above. Enhanced oil recovery is here to stay.

Jeroen RegtienVice President, Hydrocarbon Recovery TechnologiesInnovation, Research & DevelopmentShell International Exploration and Production

Jeroen Regtien leads the improved oil recovery/enhanced oil recovery, smart field, CO2 storage and rock and fluid science research and development activities in the Shell Projects and Technology Group. His extensive career in the upstream oil and gas industry has included roles as technical manager, chief petroleum engineer, manager of strategy and planning, head of geother-mal energy, asset manager and development manager during assignments in Brunei, Australia, Oman, the USA and The Netherlands. He is a member of the World Petroleum Council and International Advisory Board of the Oman Research Council. Jeroen is an experimental physicist with an MSc degree from the University of Groningen, The Netherlands.

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www.slb.com/oilfieldreview

Schlumberger

Oilfield Review1 Enhanced Oil Recovery: Here to Stay

Editorial contributed by Jeroen Regtien, Vice President, Hydrocarbon Recovery TechnologiesInnovation, Research & Development; Shell International Exploration and Production

4 Coaxing Oil from Shale

Oil shale contains copious amounts of immature organic material. Heating the rock accelerates the normal maturationprocess to generate oil and gas. Historically, oil shales weremined, crushed and heated at the surface, but companies arefinding it may be more efficient to access these formationsthrough boreholes, heat the subsurface and bring the oil to the surface.

16 Has the Time Come for EOR?

Enhanced oil recovery (EOR) methods are designed to produce additional oil beyond what is obtainable through traditional methods of pressure depletion and simple pressure maintenance. EOR techniques include miscible gasflooding, chemical flooding and thermal recovery. This article describes the basics of these methods; fieldexamples illustrate their application.

Executive EditorMark A. Andersen

Advisory EditorLisa Stewart

Senior EditorsMatt VarhaugRick von Flatern

EditorsVladislav GlyanchenkoTony Smithson

Contributing EditorsRana RottenbergGinger Oppenheimer

Design/ProductionHerring DesignSteve Freeman

IllustrationChris LockwoodMike MessingerGeorge Stewart

PrintingWetmore Printing CompanyCurtis Weeks

Oilfield Review is published quarterly andprinted in the USA.

Visit www.slb.com/oilfieldreview forelectronic copies of articles in multiplelanguages.

2011 Schlumberger. All rights reserved.Reproductions without permission are strictly prohibited.

For a comprehensive dictionary of oilfieldterms, see the Schlumberger OilfieldGlossary at www.glossary.oilfield.slb.com.

About Oilfield ReviewOilfield Review, a Schlumberger journal,communicates technical advances infinding and producing hydrocarbons to employees, clients and other oilfieldprofessionals. Contributors to articlesinclude industry professionals and expertsfrom around the world; those listed withonly geographic location are employeesof Schlumberger or its affiliates.

On the cover:

Engineers prepare a slim tube for a testof minimum miscibility pressure at theSchlumberger Reservoir Fluids Center inHouston. The sand-filled metal coil provides sufficient length for a multiple-contact miscibility condition to developbetween a crude oil in the coil and aninjected gas. Miscible gas injection isone of several enhanced oil recoverymethods used to sweep post-waterfloodresidual oil from a reservoir (inset ).

2


Winter 2010/2011Volume 22Number 4

ISSN 0923-1730

50 Contributors

52 New Books and Coming in Oilfield Review

54 Annual Index

3

36 Petroleum Potential of the Arctic: Challenges and Solutions

Although constituting only about 6% of the Earths surface,the Arctic potentially contains a significant portion of theworlds undiscovered petroleum resources and, thus, isattracting the growing attention of oil and gas companies.However, this region poses numerous challenges, including aharsh climate, short operational season, complex surface andshallow-subsurface conditions and increasing environmentalrestrictions. Operators and service companies are improvingexisting technologies and developing new ones to address theunique challenges of this remote region.

Abdulla I. Al-KubaisySaudi AramcoRas Tanura, Saudi Arabia

Dilip M. KaleONGC Energy CentreDelhi, India

Roland HampWoodside Energy Ltd.Perth, Australia

George KingApache CorporationHouston, Texas, USA

Richard WoodhouseIndependent consultantSurrey, England

Advisory Panel

Editorial correspondenceOilfield Review5599 San Felipe Houston, Texas 77056 USA(1) 713-513-1194Fax: (1) 713-513-2057E-mail: [email protected]

SubscriptionsClient subscriptions can be obtainedthrough any Schlumberger sales office.Clients can obtain additional subscrip-tion information and update subscriptionaddresses at www.slb.com/oilfieldreview.

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

Paid subscriptions are available fromOilfield Review ServicesLane End Farm, Kelsall RoadAshton Hayes, Chester CH3 8BH UKFax: (44) 1829 759163E-mail: [email protected] subscription rates are availableat www.oilfieldreview.com.


4 Oilfield Review

Oilfield ReviewWinter 10Oil Shale Fig. OpenerORWIN10-OilShl Fig. Opener

Coaxing Oil from Shale

Oil shale is plentiful, but producing its petroleum can be complicated. Since the

1800s, these rocks have been mined and fed into surface facilities where liquid

hydrocarbons were extracted. Now, operators are developing methods to heat the

rock in situ and pipe the liberated oil to the surface. They are also adapting oilfield

technology to evaluate these deposits and estimate their fluid yields.

Pierre AllixTotalPau, France

Alan BurnhamAmerican Shale Oil LLCRifle, Colorado, USA

Tom FowlerShell International Exploration and ProductionHouston, Texas, USA

Michael HerronRobert KleinbergCambridge, Massachusetts, USA

Bill SymingtonExxonMobil Upstream Research CompanyHouston, Texas

Oilfield Review Winter 2010/2011: 22, no. 4. Copyright 2011 Schlumberger.For help in preparation of this article, thanks to Neil Bostrom, Jim Grau, Josephine Mawutor Ndinyah, Drew Pomerantz and Stacy Lynn Reeder, Cambridge, Massachusetts; John R. Dyni, US Geological Survey, Denver; Martin Kennedy, University of Adelaide, South Australia, Australia; Patrick McGinn, ExxonMobil Corporation, Houston; Eric Oudenot, London; Kenneth Peters, Mill Valley, California, USA; and Carolyn Tucker, Shell Oil, Denver.ECS and RST are marks of Schlumberger.CCR is a mark of American Shale Oil LLC.Electrofrac is a mark of ExxonMobil.Rock-Eval is a mark of the Institut Franais du Ptrole.

Oil shale is the term given to very fine-grained sedimentary rock containing relatively large amounts of immature organic material, or kero-gen. It is essentially potential source rock that would have generated hydrocarbons if it had been subjected to geologic burial at the requisite temperatures and pressures for a sufficient time.

In nature, it can take millions of years at burial temperatures between 100C and 150C [210F and 300F] for most source rocks to gen-erate oil. But the process can be accelerated by heating the kerogen-rich rock more quickly and to higher temperatures, generating liquid hydro-carbons in much shorter time: from a matter of minutes to a few years.

1. Dyni JR: Geology and Resources of Some World Oil-Shale Deposits, Reston, Virginia, USA: US Geological Survey Scientific Investigations, Report 2005-5294, 2006.

Smith MA: Lacustrine Oil Shales in the Geologic Record, in Katz BJ (ed): Lacustrine Basin Exploration: Case Studies and Modern Analogs. Tulsa: The American Association of Petroleum Geologists, AAPG Memoir 50 (1990): 4360.

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Winter 2010/2011 5

Forcing petroleum products from immature formations is one of the more difficult ways to extract energy from the Earth, but that has not kept people from trying. From prehistoric times to the present, oil shale, like coal, has been burned as fuel. Methods for coaxing oil from the rock to produce liquid fuels have existed for hun-dreds of years. The earliest such ventures mined oil shale and heated it in processing facilities on the surface to obtain liquid shale oil and other petroleum products. More recently, methods have been tested to heat the rock in situ and extract the resulting oil in a more conventional way: through boreholes. These approaches are being developed, but the worlds oil shale resources remain largely untapped.

Current estimates of the volumes recoverable from oil shale deposits are in the trillions of barrels, but recovery methods are complicated and expensive. However, with todays sustained high prices and predictions of future oil short-ages in the coming decades, producing oil from shale may soon become economically viable. Therefore, several companies and countries are working to find practical ways to exploit these unconventional resources.

This article explains how oil shales form, how they have been exploited in various parts of the world and which techniques are currently being developed for tapping the energy they contain. Examples from the western US illustrate innova-tive applications of oilfield technology for evaluat-ing oil shale deposits and assessing their richness.

Oil Shale FormationOil shales form in a variety of depositional envi-ronments, including freshwater and saline lakes and swamps, near-shore marine basins and subtidal shelves.1 They may occur as minor sedi-mentary layers or as giant accumulations hun-dreds of meters thick, covering thousands of square kilometers (above right).

As with other sedimentary rocks, composi-tions of shales containing organic material range from mostly silicates to mostly carbonates, with varying amounts of clay minerals (right). Mineral composition has little effect on oil yield, but it can impact the heating process. Clay minerals contain water, which may affect the amount of heat required to convert the organic material to petroleum. Carbonate shales, upon heating, gen-erate additional CO2 that must be considered in any oil shale development program. Many depos-its also contain valuable minerals and metals such as alum, nahcolite, sulfur, vanadium, zinc, copper and uranium, which may themselves be targets of mining operations.

> Outcropping oil shales. The oil shale of the Green River Formation in the Piceance Creek basin in Colorado covers about 3,100 km2 [1,200 mi2]. The inset (top) shows a hand specimen from that region, with dark layers of rich oil shale interbedded with pale layers of lean shale. The white scale bar is 7.2 cm [2.8 in.] long. (Outcrop photograph courtesy of Martin Kennedy, University of Adelaide. Inset photograph courtesy of John R. Dyni, US Geological Survey, Denver.)

Oilfield ReviewWinter 10Oil Shale Fig. 1ORWIN10-OilShl Fig. 1

> Shale mineralogy. Worldwide average shale composition regardless of organic content (black diamond) is high in clay minerals and contains some quartz and feldspar with little or no calcite or dolomite. Organic-rich shales (other diamonds and dots) tend to have a wider variety of compositions. Oil shales from the Green River Formation are highlighted in dotted blue ovals. Those from the Parachute Creek Member (green squares) have low clay-mineral content, while oil shales from the Garden Gulch Member (red dots) are richer in clay minerals. Gray lines subdivide the triangle into compositional regions. (Adapted from Grau et al, reference 32.)


ClayMinerals

Calcite and Dolomite

Siliceousdolomite

Eagle Ford

Niobrara

Calcareousor dolomiticmudstone

Argillaceousmarlstone

Siliceousmarlstone

Argillaceousmudstone

(traditional shale)Siliceousmudstone

MontereyMontney

MuskwaBarnett

Bakken

Haynesville

LowerMarcellus

Siliceous shale

Montereyporcellanite

BazhenovAverage shale

Garden Gulch MemberParachute Creek MemberGas shales from Poland

Quartz andFeldspar

Various other locations

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6 Oilfield Review

Interspersed between the grains of these rocks is kerogeninsoluble, partially degraded organic material that has not yet matured enough to generate hydrocarbons. The kerogen in oil shale has its origins predominantly in the

remains of lacustrine and marine algae, and con-tains minor amounts of spores, pollen, fragments of herbaceous and woody plants and remnants of other lacustrine, marine and land flora and fauna. The type of kerogen has a bearing on what kind of hydrocarbon it will produce as it matures thermally.2 The kerogens in oil shale fall into the Type I and Type II classifications used by geo-chemists (left).

The thermally immature kerogens in oil shales have undergone low-temperature diagen-esis but no further modifications.3 Some other organic-rich shales may have reached thermal maturity but not yet expelled all of their liquid petroleum products. To distinguish them from oil shales, for the purposes of this article, mature, organic-rich shales that have not expelled all of their oil are called oil-bearing shales. Examples of these are the Bakken, Monterey and Eagle Ford shales, which currently produce oil in the US. Other organic-rich shales are more thermally mature or of different kerogen type and contain gas instead of oil, such as the Barnett, Fayetteville and Marcellus shales, also in the US.4

Many shales attain source-rock status, achiev-ing full maturity and expelling their oil and natu-ral gas, which then migrate, and under the proper conditions, accumulate and become trapped until discovered and produced. Some such shales can manifest in several ways. For example, the Kimmeridge Clay Formation is the main source rock for the oil fields of the North Sea, but where it outcrops in England it is an oil shale. Similarly, the Green River shale, which is presumed to be

the source rock for the oil produced from the Red Wash field in Utah, USA, outcrops in the same region. It also contains the worlds largest reserves of shale oil.

Oil Shales in Time and SpaceThe earliest use of oil shale was as fuel for heat, but there is also evidence of weaponry applica-tions, such as flaming, oil shaletipped arrows shot by warriors in 13th-century Asia.5 The first known use of liquid petroleum derived from shale dates to the mid-1300s, when medical practitio-ners in what is now Austria touted its healing properties. By the late 1600s, several municipali-ties in Europe were distilling oil from shale for heating fuel and street lighting. In the 1830s, mining and distillation activities began in France, and reached commercial levels there and in Canada, Scotland and the US by the mid-1800s. The country with the longest history of commer-cial shale oil production is Scotland, where mines operated for more than 100 years, finally closing in 1962.6

Fuel shortages during the two World Wars encouraged other countries to exploit their oil shale resources. Tapping a kerogen-rich carbon-ate sequence, Estonia began mining oil shale from a deposit about 20 to 30 m [65 to 100 ft] thick that covers hundreds of square kilometers in the northern part of the country. The operation continues today.

The shale, which occurs as 50 or so beds of organic-rich shallow marine sediments alternat-ing with biomicritic limestone, is produced from open-pit mines at depths to 20 m. Where the shale is buried deeper than that, down to 70 m [230 ft], it is accessed by underground mines. Roughly three-quarters of the mined rock supplies fuel for electric power plants, providing 90% of the coun-trys electricity. The remainder is used for heating and as feedstock for petrochemicals. In the past 90 years, 1 109 metric tons [1 109 Mg, or 1.1 billion tonUS] of oil shale has been mined from the primary Estonia deposit (left).7

China has a significant history of oil shale min-ing as well, with shale oil production beginning in the 1920s. In the Fushun area, extensive shale lay-ers 15 to 58 m [49 to 190 ft] thick are mined along with coal, both from Eocene lacustrine deposits. The total resource of oil shale at Fushun is esti-mated at 3.3 109 Mg [3.6 billion tonUS].8 As of 1995, Fushuns petroleum production capacity from shale was 66,000 m3/yr [415,000 bbl/yr].

Brazil began developing an oil shale mining and processing industry in the 1960s. The national oil company, Petrleo Brasileiro SA (Petrobras),

> Kerogen maturation. The Type I and Type II kerogens in most oil shales are not yet mature enough to generate hydrocarbons. As these kerogens matureusually through geologic burial and the increased heat associated with itthey transform into oil, and then with more heat, to gas. Methods that accelerate the maturation process attempt to control heat input, thereby producing only the desired type of hydrocarbon.


1.5

Hydr

ogen

/car

bon

ratio

1.0

0.5

0 0.1 0.2

Type I

Type II

Type III

Type IV

Oxygen/carbon ratio

Dry gas

Increasingmaturation

CO2, H2OOilWet gas

No hydrocarbonpotential

Products Givenoff from Kerogen

Maturation

>More than a century of commercial oil shale mining. Tonnage of mined shale rose dramatically in the 1970s when oil prices were also rising; it peaked in 1980, but declined as oil prices made shale oil noncompetitive. Several countries continue to mine oil shale as a source of heat, electricity, liquid fuel and chemical feedstock. Since 1999, mined shale tonnage has started to increase again. (Data from 1880 to 1998 from Dyni, reference 1.)


Min

ed s

hale

, mill

ion

met

ric to

ns

40

50

30

20

10

01880 1900 1920 1940 1960 1980 20001890 1910 1930 1950 1970 1990

Year2010

Germany

China

Brazil

Scotland

Russia

Estonia

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Winter 2010/2011 7

established the Shale Industrialization Business Unit (SIX) to exploit the countrys several large oil shale deposits. The Irati Formation, which outcrops extensively in southern Brazil, contains reserves of more than 1.1 108 m3 [700 million bbl] of oil and 2.5 1010 m3 [880 Bcf] of gas.9 Surface facilities at So Mateus do Sul, in the state of Paran, are capable of processing 7,100 Mg [7,800 tonUS] of shale per day to produce fuel oil, naphtha, liquefied petroleum gas (LPG), shale gas, sulfur and asphalt additives.

To date, almost all the oil extracted from the worlds oil shale has been from rock that was mined and then processed at surface facilities. Mining is typically performed either through sur-face mining or through underground mining using the room-and-pillar method associated

with coal mining. After mining, oil shale is trans-ported to a facilitya retortwhere a heating process converts kerogen to oil and gas and sepa-rates the hydrocarbon fractions from the mineral fraction. This mineral waste, which contains sub-stantial amounts of residual kerogen, is called spent shale. After retorting, the oil must be upgraded by further processing before being sent to a refinery.

Mining operations require handling massive volumes of rock, disposing of spent shale and upgrading the heavy oil. The environmental impact can be significant, causing disruption of the surface and requiring substantial volumes of water. Water is needed for controlling dust, cool-ing spent shale and upgrading raw shale oil. Estimates of water requirements range from 2 to 5 barrels of water per barrel of oil produced.10

The worlds oil shale deposits are widely distrib-uted; hundreds of deposits occur in more than 30 countries (above). Many formations are at depths beyond mining capabilities or in environmentally fragile settings. In these areas, heating the rocks in place may offer the best method to hasten kerogen maturation. If ways can be found to do this safely, efficiently and cost effectively, the potential prize is immense. By conservative estimatebecause oil shales have not been the target of modern explora-tion effortsresources of the worlds shale oil total about 5.1 1011 m3 [3.2 trillion bbl].11 It is estimated that more than 60% of this amountroughly 3 1011 m3 [2 trillion bbl]is located in the US.

Converting Oil Shale to Shale OilTranslating volume of rock to volume of recover-able oil requires information on oil shale proper-ties, such as organic content and grade, which can vary widely within a deposit. Traditionally, for the purposes of surface retorting, oil shale grade is determined by the modified Fischer assay method, which measures the oil yield of a shale sample in a laboratory retort.12 A 100-g [0.22-lbm] sample is crushed and sieved through a 2.38-mm [8] mesh screen, heated in an aluminum retort to 500C [930F] at a rate of 12C/min [22F/min] and then held at that temperature for 40 min.13 The resulting distilled vapors of oil, gas and water are condensed and then separated by centrifuge. The quantities delivered are weight percentages of oil, water and shale residue and the specific gravity of the oil. The difference between the weight of the products and that of the starting material is

2. Tissot BP: Recent Advances in Petroleum Geochemistry Applied to Hydrocarbon Exploration, AAPG Bulletin 68, no. 5 (May 1984): 545563.

3. For more on diagenesis: Ali SA, Clark WJ, Moore WR and Dribus JR: Diagenesis and Reservoir Quality, Oilfield Review 22, no. 2 (Summer 2010): 1427.

4. Boyer C, Kieschnick J, Suarez-Rivera R, Lewis RL and Waters G: Producing Gas from Its Source, Oilfield Review 18, no. 3 (Autumn 2006): 3649.

5. Moody R: Oil & Gas Shales, Definitions and Distributions in Time & Space, presented at the Geological Societys History of Geology Group Meeting, Weymouth, England, April 2022, 2007, http://www.geolsoc.org.uk/gsl/cache/offonce/groups/specialist/hogg/pid/3175;jsessionid= 4CC09ACD6572AE54454755DE4A9077DC (accessed September 14, 2010).

6. Shale Villages: A Very Brief History of the Scottish Shale Oil Industry, http://www.almondvalley.co.uk/V_background_history.htm (accessed September 24, 2010).

> Significant oil shale deposits. Most of the known high-quality shale oil resources are in these 14 countries. (Data from Knaus et al, reference 11.)


Brazil (4)82

Canada (11)15

United States (1)2,085

France (12) 7

Italy (5)73

Russia (2)247

China (10)16

DemocraticRepublic of

Congo (3)100

Australia (8)31

Shale oil resource,billion bbl(global ranking)

Morocco (6) 53

Egypt (13) 5.7

Estonia (9)16

Israel (14) 4

Jordan (7)34

7. Sabanov S, Pastarus J-R and Nikitin O: Environmental Impact Assessment for Estonian Oil Shale Mining Systems, paper rtos-A107, presented at the International Oil Shale Conference, Amman, Jordan, November 79, 2006.

8. Dyni, reference 1. 9. Petrobras SIX Shale Industrialization Business Unit:

Shale in Brazil and in the World, http://www2.petrobras.com.br/minisite/refinarias/petrosix/ingles/oxisto/oxisto_reservas.asp (accessed November 10, 2010).

10. Bartis JT, LaTourrette T, Dixon L, Peterson DJ and Cecchine G: Oil Shale Development in the United States: Prospects and Policy Issues. Santa Monica, California, USA: The RAND Corporation, Monograph MG-414, 2005.

11. Knaus E, Killen J, Biglarbigi K and Crawford P: An Overview of Oil Shale Resources, in Ogunsola OI, Hartstein AM and Ogunsola O (eds): Oil Shale: A Solution to the Liquid Fuel Dilemma. Washington, DC: American Chemical Society, ACS Symposium Series 1032 (2010): 320.

12. Dyni, reference 1.13. Screen mesh of 8 means the particles can pass

through a wire screen with 8 openings per linear inch.

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8 Oilfield Review

recorded as gas plus loss. The oil yield is reported in liters per metric ton (L/Mg) or gallons per short ton (galUS/tonUS) of raw shale. Commercially attractive oil shale deposits yield at least 100 L/Mg [24 galUS/tonUS], and some reach 300 L/Mg [72 galUS/tonUS].14

The Fischer assay method does not measure the total energy content of an oil shale because the gases, which include methane, ethane, pro-pane, butane, hydrogen, H2S and CO2, can have significant energy content, but are not individu-ally specified. Also, some retort methods, espe-cially those that heat at a different rate or for different times, or that crush the rock more finely, may produce more oil than that produced by the Fischer assay method. Therefore, the method only approximates the energy potential of an oil shale deposit.15

Another method for characterizing organic richness of oil shale is a pyrolysis test developed by the Institut Franais du Ptrole, in Reuil-Malmaison, France, for analyzing source rock.16 The Rock-Eval test heats a 50- to 100-mg [0.00011- to 0.00022-lbm] sample through several temperature stages to determine the amounts of hydrocarbon and CO2 generated. The results can be interpreted for kerogen type and potential for oil and gas generation. The method is faster than the Fischer assay and requires less sample material.

The reactions that convert kerogen to oil and gas are understood generally, but not in precise molecular detail.17 The amount and composition of generated hydrocarbons depend on the heating conditions: the rate of temperature increase, the duration of exposure to heat and the composition of gases present as the kerogen breaks down.

Generally, surface-based retorts heat the shale rapidly. The time scale for retorting is directly related to the particle size of the shale, which is why the rock is crushed before being heated in surface retorts. Pyrolysis of particles on the millimeter scale can be accomplished in minutes at 500C; pyrolysis of particles tens of centimeters in size takes hours.

In situ processes heat the shale more slowly. It takes a few years to heat a block tens of meters wide. However, slow heating has advantages. Retorting occurs at a lower temperature so less heat is needed. Also, the quality of the oil increases substantially (above left). Coking and cracking reactions in the subsurface tend to leave the heavy, undesirable components in the ground. As a result, compared with surface pro-cessing, in situ heating can produce lighter liquid hydrocarbons with fewer contaminants.

During in situ conversion, the subsurface acts as a large reactor vessel in which pressure and heating rate may be designed to maximize prod-uct quality and quantity while minimizing pro-duction cost. In addition to generating a superior product relative to surface processing, in situ methods have a reduced environmental impact in terms of surface disturbance, water require-ments and waste management.

Several companies have developed methods for heating oil shale in situ to generate shale oil. They are testing these techniques in the rich sub-surface deposits of the western US.

The Epitome of Oil ShalesThe Green River Formation at the intersection of the states of Colorado, Utah and Wyoming, USA, contains the most bountiful oil shale beds in the world. Estimates of the recoverable shale oil in this area range from 1.2 to 1.8 trillion bbl

[1.9 to 2.9 1011 m3]. Nearly 75% of the resources lie under land managed by the US Department of the Interior.

The fine-grained sediments of this formation were deposited over the course of 10 million years in Early and Middle Eocene time, in several large lakes covering up to 25,000 mi2 [65,000 km2]. The warm alkaline waters provided conditions for abundant growth of blue-green algae, which are believed to be the main component of the organic matter in the oil shale.18 The formation is now about 1,600 ft [500 m] thick and in places has shale layers that contain more than 60 galUS/tonUS [250 L/Mg] of oil (next page).19 A particularly rich and widespread layer, called the Mahogany zone, reaches a thickness of 50 ft [15 m]. It contains an estimated 173 billion bbl [2.8 1010 m3] of shale oil. The Green River area has been well studied, with more than 750,000 assay tests performed on samples from outcrops, mines, boreholes and core holes.20

Settlers and miners began retorting oil from the shale in the 1800s. The region experienced mining and exploration booms from 1915 to 1920 and again from 1974 to 1982, each period fol-lowed by busts.21 In 1980, Unocal built a major plant for mining, retorting and upgrading oil shale in the Piceance Creek basin in Colorado; it operated until 1991. During that time, the company produced 4.4 million bbl [700,000 m3] of shale oil.22

Recently, oil price volatility and growing energy needs have combined to again focus inter-est on the region. In 2003, the US Bureau of Land Management initiated an oil shale development program and solicited applications for research, development and demonstration (RD&D) leases.

Several companies applied for and received lease awards to develop in situ heating techniques on public lands, and some are testing methods

> Improved oil quality with slow heating. Data from the Shell in situ conversion process (ICP) and Lawrence Livermore National Laboratory (LLNL), in California, show a clear increase in oil API gravity as heating rate decreases. The red endpoint represents the results of typical laboratory pyrolysis.


Shal

e oi

l, de

gree

API

gra

vity

20

24

28

32

36

40

1101001,00010,000100,000

Heating rate, C/d

ICP LLNL

> Shells thermal conduction pilot projects. Shell has performed seven field pilots using the in situ conversion process (ICP) to heat oil shale to conversion temperature. (Adapted from Fowler and Vinegar, reference 24.)

Red Pinnaclethermal conduction test

Mahogany fieldexperiment

Mahogany demonstrationproject

Mahogany demonstrationproject, South

Deep heater test

Mahogany isolation test

Freeze wall test

Project Name Primary Purpose Dates HeaterHoles

TotalHoles

Depth,ft

ICP field demonstration

ICP field demonstration

ICP field demonstration,recovery

ICP field demonstration,recovery

Heaters

Freeze wall

Freeze wall

1996 to 1998

1981 to 1982

1998 to 2005

2003 to 2005

2001 to present

2002 to 2004

2005 to present

3

6

38

16

21

2

0

14

26

101

27

45

53

233

20

130

600

400

700

1,400

1,700


38607schD4R1.indd 8 3/1/11 9:35 PM

Winter 2010/2011 9

on privately held land. Examples from three companiesShell, ExxonMobil and American Shale Oil LLC (AMSO)show the range of concepts being applied to the challenges of in situ retorting in the Green River oil shale.

Shell has done extensive laboratory and field work in efforts to demonstrate commercial viabil-ity of in situ retorting using downhole electric

heaters.23 The process follows a method developed in Sweden during World War IIa technique used until 1960, when cheaper supplies of imported oil became available.

Shell participated in early mining and surface retort attempts in the Green River area, but chose to withdraw from those in the mid-1990s to focus on an in situ method.24 Years of laboratory testing,

thermal simulations and field pilots contributed to the development of Shells in situ conversion pro-cess (ICP). Through seven field pilot tests, Shell has investigated a variety of heating methodsincluding injected steam and downhole heatersand well configurations with patterns of wells of varying depths for heating, producing and dewa-tering (previous page, top right).

14. Knaus et al, reference 11.15. Dyni JR, Mercier TJ and Brownfield ME: Chapter 1

Analyses of Oil Shale Samples from Core Holes and Rotary-Drilled Wells from the Green River Formation, Southwestern Wyoming, in US Geological Survey Oil Shale Assessment Team (ed): Fischer Assays of Oil-Shale Drill Cores and Rotary Cutting from the Greater Green River Basin, Southwestern Wyoming, US Geological Survey, Open-File Report 2008-1152, http://pubs.usgs.gov/of/2008/1152/downloads/Chapter1/Chapter1.pdf (accessed October 8, 2010).

16. Pyrolysis is the controlled heating of organic matter in the absence of oxygen to yield organic compounds such as hydrocarbons.

Peters KE: Guidelines for Evaluating Petroleum Source Rock Using Programmed Pyrolysis, AAPG Bulletin 70, no. 3 (March 1986): 318329.

. Lithology (center) and grade (right) of the Green River Formation. Oil shales in the Parachute Creek Member are carbonate rich, and the underlying shales of the Garden Gulch Member are clay rich. High-grade (blue) oil shales are interspersed with lean layers (pink). Oil yield from Fischer assay measurement is plotted in red. Total shale oil resources contained in the various layers are shown in the chart (bottom left). (Lithology and shale oil resources from Dyni, reference 1; shale grade from Johnson et al, reference 19.)


Sandstone, siltstone and somemarlstone and lean oil shale

Oil shale

Marlstone and low-grade oil shale

Leached oil shale; contains open solutioncavities and marlstone solution brecciasNahcolite-bearing oil shale; contains nodules,scattered crystals and beds of nahcolite

Clay-bearing oil shale

Interbedded halite, nahcolite and oil shale

Nahcolite and oil shale A-groove

R-8 zone

Mahoganyzone

B-groove

R-6 zone

R-5 zone

R-4 zone

R-3 zone

L-5 zone

L-4 zone

L-3 zone

L-2 zone

R-2 zone

L-1 zone

R-1 zone

L-0 zone

R-0 zone

0 20 40 60 80 100Shale oil yield,galUS/tonUS

Anvil PointsMember

0

500

1,000

1,500

2,000

2,500

3,000

Gard

en G

ulch

Mem

ber

Para

chut

e Cr

eek

Mem

ber

Gree

n Ri

ver F

orm

atio

n

GeneralizedLithologyDepth, ft

Rich oil shale zones, carbonate rich

Rich oil shale zones, clay rich

Lean oil shale zones, carbonate rich

Lean oil shale zones, clay rich

Uint

a Fo

rmat

ion

(with

tong

ues

of G

reen

Riv

er F

orm

atio

n)

Shale Oil Resources

109 tonUS

Total

Mahogany

Zone

147.17

No data

1,008.10

No data

109 bbl

No dataNo data

No dataNo data

115.3510.7053.0720.0858.3818.72

107.7860.85

178.7252.42

159.09172.94

R-1L-1R-2L-2R-3L-3R-4L-4R-5L-5R-6

R-8

L-0R-0

16.841.567.752.938.522.73

15.748.88

26.097.65

23.2325.25

Espitalie J, Madec M, Tissot B, Mennig JJ and Leplat P: Source Rock Characterization Method for Petroleum Exploration, paper OTC 2935, presented at the Offshore Technology Conference, Houston, May 25, 1977.

17. Burnham AK: Chemistry and Kinetics of Oil Shale Retorting, in Ogunsola OI, Hartstein AM and Ogunsola O (eds): Oil Shale: A Solution to the Liquid Fuel Dilemma. Washington, DC: American Chemical Society, ACS Symposium Series 1032 (2010): 115134.

18. Dyni, reference 1.19. Johnson RC, Mercier TJ, Brownfield ME, Pantea MP

and Self JG: Assessment of In-Place Oil Shale Resources of the Green River Formation, Piceance Basin, Western Colorado, Reston, Virginia, USA: US Geological Survey, Fact Sheet 2009-3012, March 2009.

20. US Department of Energy: Secure Fuels from Domestic Resources, http://www.unconventionalfuels.org/

publications/reports/SecureFuelsReport2009FINAL.pdf (accessed November 12, 2010).

21. Hanson JL and Limerick P: What Every Westerner Should Know About Oil Shale: A Guide to Shale Country, Center of the American West, Report no. 10, June 17, 2009, http://oilshale.centerwest.org (accessed August 4, 2010).

22. Dyni, reference 1.23. Ryan RC, Fowler TD, Beer GL and Nair V: Shells In Situ

Conversion ProcessFrom Laboratory to Field Pilots, in Ogunsola OI, Hartstein AM and Ogunsola O (eds): Oil Shale: A Solution to the Liquid Fuel Dilemma. Washington, DC: American Chemical Society, ACS Symposium Series 1032 (2010): 161183.

24. Fowler TD and Vinegar HJ: Oil Shale ICPColorado Field Pilots, paper SPE 121164, presented at the SPE Western Regional Meeting, San Jose, California, March 2426, 2009.

38607schD4R1.indd 9 2/21/11 9:25 PM

10 Oilfield Review

The ICP method uses closely spaced down-hole electric heaters to gradually and evenly heat the formation to the conversion temperature of about 650F [340C]. Depending on heater spac-ing and the rate of heating, the time projected to reach conversion temperature in a commercial project ranges from three to six years. Tests have demonstrated liquid-recovery efficiencies greater than 60% of Fischer assay value, with the low-value kerogen components left in the ground. The resulting oil is of 25 to 40 degree API gravity. The gas contains methane [CH4], H2S, CO2 and H2. Taking into account the oil equivalence of the gas generated, the recovery efficiency approaches 90% to 100% of Fischer assay value. From results of the pilot testing, a commercial-scale project is expected to have an energy gain close to 3, meaning the energy value of the

products is three times the energy input to obtain them.

Commercialization of the ICP process requires a method that prevents water influx to the heated volume and contains the fluid prod-ucts, thereby maximizing recovery and protecting local aquifers.25 The Shell ICP process makes use of a freeze wall, created by circulating coolants, to isolate the heated formation from ground-water. Use of a freeze wall is a relatively common practice in some underground mining operations. Inside the freeze wall, water is pumped from the formation. The formation is heated, the oil is pro-duced and the residual shale is cleaned of con-taminants by flushing with clean water. The recovered oil in one test had 40 degree API grav-ity, similar to modeling results for oil produced at heating rates of 1C/h [0.5F/h] and 27 MPa.

Pilot testing of the freeze wall began in 2002 with 18 freeze wells arranged in a circle 50 ft across. One producer, two heating wells and eight monitor wells were located within the freeze cir-cle (left). After five months of cooling, the freeze wall was complete. This pilot showed that a freeze wall could be established and could isolate fluids inside the circle from those outside.

Shell tested the freeze wall concept on a larger scale starting in 2005, with an ambitious project involving 157 freeze wells at 8-ft [2.4-m] intervals to create a containment volume 224 ft [68 m] across (next page, top). The operator began chill-ing in 2007 by circulating an ammonia-water solutioninitially at shallow depth and gradually deepening. As of July 2009, the freeze wall was continuing to form in the deeper zones, down to 1,700 ft [520 m]. The test is designed to evaluate the integrity of the freeze wall, and will not involve heating, or production of hydrocarbons.

ExxonMobil is also pursuing research and development of a process for in situ oil shale con-version. The companys Electrofrac process hydraulically fractures the oil shale and fills the fractures with an electrically conductive material, creating a resistive heating element.26 Heat is thermally conducted into the oil shale, converting the kerogen into oil and gas, which are then pro-duced by conventional methods. Calcined petro-leum coke, a granular form of relatively pure carbon, is being tested as the Electrofrac conduc-tant. By pumping this material into vertical hydraulic fractures, ExxonMobil hopes to create a series of parallel planar electric heaters (next page, bottom). As in the Shell ICP method, the resistive heat reaches the shale by thermal diffu-sion. A potential advantage of the Electrofrac pro-cess is that, compared with line sources, the greater surface area of planar fracture heaters will permit fewer heaters to be used to deliver heat to the subsurface volume. The use of planar heaters should also reduce surface disturbance when com-pared with line sources or wellbore heaters.

25. Ryan et al, reference 23.26. Symington WA, Kaminsky RD, Meurer WP, Otten GA,

Thomas MM and Yeakel JD: ExxonMobils Electrofrac Process for In Situ Oil Shale Conversion, in Ogunsola OI, Hartstein AM and Ogunsola O (eds): Oil Shale: A Solution to the Liquid Fuel Dilemma. Washington, DC: American Chemical Society, ACS Symposium Series 1032 (2010): 185216.

Symington WA, Olgaard DL, Otten GA, Phillips TC, Thomas MM and Yeakel JD: ExxonMobils Electrofrac Process for In Situ Oil Shale Conversion, presented at the AAPG Annual Convention, San Antonio, Texas, USA, April 2023, 2008.

> Shell freeze wall isolation test. Using a technique dating to the 1880s, Shell constructed a circular freeze wall 1,400 ft [430 m] deep by circulating coolant in 18 freeze wells for 5 months. A 430-ft [130-m] interval of the enclosed formation was then heated to generate shale oil. The test verified that the freeze wall could confine produced fluids.


Plan View

Side View

22 ft

50 ft

8 ft

1,400-ftfreeze

interval430-ftheatedinterval

Inside monitor (8)Freeze (18)Producer (1)Heater (2)

Wells

38607schD4R1.indd 10 2/21/11 9:25 PM

Winter 2010/2011 11

> Large-scale freeze wall test. In a step toward supporting commercial viability of the ICP, Shell is testing a large-scale freeze wall for isolation and containment. In addition to the freeze wells shown in the plan view (left) there are 27 observation holes for geomechanical, pressure, fluid level and temperature measurements; 30 special-use holes for venting, squeezing, water reinjection, water production and hydraulic fracturing; and 40 groundwater monitoring holes. An artists rendering (right) depicts the freeze wall in 3D.


A

B

C

Plan View

Side View

TestSection B

1,700-ftfreeze

interval

TestSectionsA and C1,500-ftfreezeinterval

224 ft

Freeze well8 ft

B

C

A


A

B

C

Plan View

Side View

TestSection B

1,700-ftfreeze

interval

TestSectionsA and C1,500-ftfreezeinterval

224 ft

Freeze well8 ft

B

C

A

> The ExxonMobil Electrofrac process. Horizontal wells penetrate the oil shale. The horizontal sections are hydraulically fractured (left) and filled with electrically conductive proppant made of calcined coke (bottom right). A 20/40 mesh proppant (top right) is displayed for scale. Field testing has shown it is possible to create an electrically conductive fracture and heat it for several months. The plus and minus signs indicate electric charge applied to heat the fractures. (Illustration and photographs courtesy of ExxonMobil.)

20/40 Mesh Proppant

Calcined Coke

Toe connector well Production wells Electrofrac processheater wells

Conductive heating andoil shale conversion

Hydraulic fracturewith electrically

conductive material


38607schD4R1.indd 11 2/21/11 9:26 PM

12 Oilfield Review

Prior to embarking on field research, ExxonMobil conducted modeling and laboratory studies addressing several important technical issues for the Electrofrac process. These included establishing the following:Thattheconductantinthefracturecanmain-

tain its electrical continuity while the surround-ing rock is heated to conversion temperatures.

Thatoilandgasgeneratedby theprocessareexpelled from oil shale, not only at surface con-ditions, but also under in situ stress conditions.

Thatacompletionstrategycanbedesignedtocreate fractures that deliver heat effectively.

Based on these results, ExxonMobil advanced to field research to test the Electrofrac method in situ.27 The test site is at the company-owned Colony oil shale mine in northwest Colorado. The Colony mine provides a large, highly accessible volume of rock for testing. ExxonMobil has cre-ated two Electrofrac fractures at Colony by drill-ing horizontally into the oil shale and pumping a

slurry of calcined petroleum coke, water and portland cement at pressures sufficient to break the rock. The larger of the two Electrofrac frac-tures has been heavily instrumented to measure temperature, voltage, electrical current and rock movement. As a preliminary test of the Electrofrac process, the fracture was heated to relatively low temperatures. This low- temperature experiment was not intended to generate oil or gas. To date, the results of this field program have been encouraging. They demonstrate that it is possible to create an elec-trically conductive hydraulic fracture, to make power connections to the fracture and to operate it, at least at low temperature, for several months.

AMSO, 50% owned by Total, proposes to use the CCR conduction, convection and reflux pro-cess to recover shale oil. By focusing the heating effort on shales beneath an impermeable shale caprock, this method isolates production zones from protected sources of groundwater.28

The company plans to drill two horizontal wellsa heater below a producerin the bot-tom of the illite shale at the base of the Green River Formation (above left). Heat is delivered by a downhole burner that eventually runs on pro-duced gas. As the kerogen decomposes, the lighter productshot vaporsrise and reflux. Heat is distributed through the formation by the refluxing oil; thermomechanical fracturing, or spalling, creates permeability for the convective heat transfer.

The concept for commercial-scale produc-tion uses an array of horizontal wells about 2,000 ft [600 m] long at 100-ft [30-m] intervals (left). The formation is heated slowly, yielding oil with lower concentrations of heteroatoms and metals than that generated by surface pro-cessing methods.29 Meanwhile, the aromatic portions of kerogen tend to stay in the rock matrix as coke. More than enough gas is copro-duced to provide the energy required to operate a self-sustaining commercial retorting process, and it is likely that most of the propane and butane produced can be exported to market.

Computational studies show that heat deliv-ery by convection and conduction is much more effective than by conduction alone. The CCR pro-cess is estimated to give a total energy gain between 4 and 5, counting all the surface facility requirements, including an oxygen plant for pro-ducing pure CO2 from the downhole burner. The method is projected to use less than one barrel of water per barrel of oil produced. No water is needed to clean spent retorts because they remain isolated from usable groundwater.

> The AMSO CCR conduction, convection and reflux process. Two horizontal wells target the illitic oil shale beneath a nahcolitic caprock. The heating well is at the base and the production well is at the top of the shale (left). As heat causes the kerogen to decompose, the lighter products rise and condense (right), efficiently heating a large volume of rock. Hydrocarbon fluids are produced via the production well.

Dept

h, ft 1,000

0

500

1,500

2,000

Low-salinity water

High-salinity water

Mahogany zone

Nahcolitic oil shale caprock

Illitic oil shale

Heating well

Production well

2,000 ft

Boiling oil

Vapo

r

Cond

ensa

te

Cond

ensa

te

Heating well

Rubble-filledretort

Production well


> The AMSO concept for commercial-scale production. By using long horizontal wells concentrated in a 200-ft corridor, drilling should impact less than 10% of the surface area. While one 2,000-ft square panel is being heated and converted in situ, wells will be drilled in an adjacent panel. The operation is projected to produce about 1 billion bbl of shale oil over a 25-year period.


200 ft

2,00

0 ft

2,000 ft

2,000 ft

Panel being drilled

Panel being retorted

38607schD4R1.indd 12 2/21/11 9:26 PM

Winter 2010/2011 13

AMSOs initial RD&D pilot test is currently under construction and will begin in mid-2011. Heating will take up to 200 days. The operation will retort a formation volume equivalent to 4,000 tonUS [3,600 Mg] of oil shale and produce up to 2,000 bbl [320 m3] of shale oil. Development of a commercial operation will proceed in steps up to 100,000 bbl/d [16,000 m3/d], with plans to sustain that production for 25 years. That trans-lates into about 1 billion bbl [1.6 108 m3] of oil to be produced from an 8-mi2 [20.8-km2] lease.

Evaluating Oil ShalesCompanies are looking at ways to assess oil shale richness and other formation properties without having to take core samples and perform Fischer assay analysis. Methods that show promise include integration of several conventional log-ging measurements, such as formation density, magnetic resonance, electrical resistivity and nuclear spectroscopy.

One way of quantifying kerogen content is by combining density porosity and magnetic reso-nance responses. In a formation with porosity that is filled with both kerogen and water, the density porosity measurement does not distin-guish between kerogen- and water-filled porosity. However, the magnetic resonance measurement sees the kerogen as a solid, similar to the grains of the rock, and so senses a lower porosity. The difference between the magnetic resonance and density readings gives kerogen volume.30 The vol-ume of kerogen can be related empirically to Fischer assay values for oil shales in the region.

The method was tested in an AMSO oil shale well in the Green River basin. Kerogen content was calculated from density porosity and mag-netic resonance logs (right). Using a correlation between kerogen content and Fischer assay

27. Symington WA, Burns JS, El-Rabaa AM, Otten GA, Pokutylowicz N, Spiecker PM, Williamson RW and Yeakel JD: Field Testing of Electrofrac Process Elements at ExxonMobils Colony Mine, presented at the 29th Oil Shale Symposium, Colorado School of Mines, Golden, Colorado, USA, October 1921, 2009.

28. Burnham AK, Day RL, Hardy MP and Wallman PH: AMSOs Novel Approach to In-Situ Oil Shale Recovery, in Ogunsola OI, Hartstein AM and Ogunsola O (eds): Oil Shale: A Solution to the Liquid Fuel Dilemma. Washington, DC: American Chemical Society, ACS Symposium Series 1032 (2010): 149160.

29. Heteroatoms are atoms of elements other than hydrogen and carbonthe components of pure hydrocarbons. They commonly consist of nitrogen, oxygen, sulfur, iron and other metals.

30. Kleinberg R, Leu G, Seleznev N, Machlus M, Grau J, Herron M, Day R, Burnham A and Allix P: Oil Shale Formation Evaluation by Well Log and Core Measurements, presented at the 30th Oil Shale Symposium, Colorado School of Mines, Golden, Colorado, October 1822, 2010.

> Kerogen content from porosity measurements in Green River oil shales. Neither gamma ray (Track 1, dashed green) nor resistivity measurements (Track 2) show much correlation with kerogen content, but porosity measurements are more useful. The difference between density porosity (Track 3, red) and nuclear magnetic resonance (NMR) porosity (green) represents kerogen-filled porosity (gray). The kerogen values can also be depicted as a log (Track 4) of total organic matter (TOM, red), which compares favorably with laboratory Fischer assay results on core samples (black dots). Mineralogical analysis incorporating ECS elemental capture spectroscopy measurements (Track 5) indicates the high levels of calcite and dolomite in these shales, as well as the presence of rare minerals such as dawsonite (light gray) and nahcolite (solid pink) in some intervals.

X,000

X,050

X,100

X,150

X,200

Depth,ft6 16in.

Caliper

0 10

PEF

0 200gAPI

GammaRay

0.2 2,000ohm.m

10-in. Array

0.2 2,000ohm.m

20-in. Array

0.2 2,000ohm.m

30-in. Array

0.2 2,000ohm.m

60-in. Array

0.2 2,000ohm.m

90-in. Array

Resistivity

NMR Porosity

45 % 15

Density Porosity

45 % 15

Porosity

0 % 50

TOM Log

0 % 50

Core Fischer Assay

Total Organic MatterKerogen

IlliteMontmorilloniteOrthoclasePyriteDawsoniteNahcoliteAlbiteQuartzCalciteDolomiteBound waterKerogenWater


38607schD4R1.indd 13 2/21/11 9:26 PM

14 Oilfield Review

results on Green River shales, researchers com-puted an estimated Fischer assay log based on the wireline logging measurements (above). The estimated Fischer assay values show excellent agreement with those from laboratory measure-ments on cores from the same interval.

Another approach distinguishes mineral from organic content using spectroscopy data. The ECS elemental capture spectroscopy sonde measures concentrations of silicon [Si], aluminum [Al], cal-cium [Ca], iron [Fe], sulfur [S], potassium [K], sodium [Na], magnesium [Mg], titanium [Ti] and gadolinium [Gd].31 Grain mineralogy is computed from these element concentrations.

The total carbon concentration comes from the RST reservoir saturation tool. Of this concen-tration, some carbon is inorganic and some organic. The inorganic carbon combines with cal-cium and other elements to form calcite and dolomite, along with lesser-known minerals,

such as nahcolite [NaH(CO3)] and dawsonite [NaAl(CO3)(OH2)], which are common in Green River shales. The ECS concentrations of Ca, Mg and Na are used to compute the inorganic car-bon. The remainder, called total organic carbon (TOC), makes up the kerogen.

Using this spectroscopy method, researchers computed a TOC log for an AMSO well in the Green River basin, showing a good match between log-based results and core measurements (next page).32 The TOC log was converted to a Fischer assay yield log using a correlation derived inde-pendently by AMSO scientists. The Fischer assay log exhibited excellent agreement with Fischer assay tests performed on cores (above right). This technique employing geochemical logs, along with the complementary method using nuclear magnetic resonance logs, provides reliable, effi-cient means to characterize shale oil yield with-out having to resort to core measurements.

Heating ElementsOne of the most fundamental issues for oil shale retorting is how to get the heat into the oil shale. After early testing, steam injection was aban-doned as other, more efficient techniques were discovered. In situ combustion has also been tried, but is difficult to control. Electric heaters, electrically conductive proppant and downhole gas burners have all been evaluated and reported to be effective with varying degrees of efficiency.

Another concept, heating by downhole radio-frequency (RF) transmitters, has also been mod-eled and has undergone laboratory testing.33 Advantages of the RF method are that it heats the interior of the formation instead of the borehole, and it can be controlled to customize heating rate. But like all electrical methods, it sacrifices effi-ciency, losing about half the heating value of the fuel originally burned to produce the electricity.

It is important to note that all the current projects to produce shale oil by in situ heating methods are in test and pilot stages; none have demonstrated large-scale commercial produc-tion. Operators are still working to optimize their heating technologies. For a given oil shale, the

> Fischer assay estimates from wireline logs. Core measurements on Green River shales show a strong correlation between total organic matter (TOM), or kerogen, and Fischer assay values (top). Total organic matter is calculated using the density k of the kerogen, bulk density of the formation b and the difference between density porosity D and magnetic resonance porosity MR. Researchers computed a kerogen log from the difference between density and NMR porosity, then used this linear correlation to convert the kerogen log to a Fischer assay log (bottom). The log-based Fischer assay estimates (black) show excellent agreement with values from laboratory Fischer assay measurements on cores (red).


Fisc

her a

ssay

, gal

US/t

onUS

20

0

40

60

80

X,000 X,050 X,100 X,150 X,200Depth, ft

Core-measured Fischer assay valuesWell log Fischer assay estimate

TOM = D MRkb ( )

Total organic matteras fraction of ore weightTo

tal o

rgan

ic m

atte

r (TO

M),

%

0

10

20

30

40

20 40 600Modified Fischer assay, galUS/tonUS

TOM = D MRkb ( )

Total organic matteras fraction of ore weight

> Fischer yield from TOC. Fischer assay estimates (black) from the TOC log exhibit an excellent correlation with core Fischer assay results (red).


Dept

h, ft

X,200

X,000

X,400

X,600

X,800

Y,000

Y,200

Y,4000 20 40 60

Shale oil yield, galUS/tonUS

TOC converted toFischer assay yieldCore Fischer assay

38607schD4R1.indd 14 2/21/11 9:26 PM

Winter 2010/2011 15

heating historyhow much heat and for how longdetermines the amount and content of the resulting fluids. By controlling the heat input, companies can fine-tune the output, essentially designing a shale oil of desired composition.

Beyond heating methods, there are other aspects of oil shale operations that have yet to be fully addressed. Mechanical stability of the heated formation is not well understood. All the in situ heating techniques rely on some thermo-mechanical fracturing within the shale to release matured organic material and create additional permeability for the generated fluids to escape the formation. With many oil shales containing 30% or more kerogen, most of which leaves the rock after in situ retorting, treated formations may not be able to support their

newfound porosity. Overburden weight can help drive production, but may also cause compac-tion and subsidence, which in turn can affect wellbore stability and surface structures.

It is also unclear how to deal with the CO2 generated along with other gases. Companies retorting oil shale in situ may need to investigate ways to capture and use the CO2 for enhanced oil recovery or sequester it in deep storage zones. An alternative, being explored by AMSO, is mineral-ization of CO2 in the spent shale formation.34 This option exploits the chemical properties of the heat-treated shale. AMSO scientists expect the depleted formation to have sufficient porosity to accommodate all the generated and reinjected CO2 as carbonate minerals.

Work also remains to understand the kerogen-maturation process. To optimize heating pro-grams, operators would like to know when the shale has been heated enough and if the subsur-face volume has been heated uniformly. To this end, scientists are conducting laboratory experi-ments to monitor the products of kerogen pyroly-sis.35 To understand when the process should be modified or stopped, researchers plan to analyze the composition of an oil shale and its hydrocar-bons as they evolve with time. In the future, it may be possible to control and monitor oil shale heating and production to obtain oil and gas of desired compositions. LS

31. Barson D, Christensen R, Decoster E, Grau J, Herron M, Herron S, Guru UK, Jordn M, Maher TM, Rylander E and White J: Spectroscopy: The Key to Rapid, Reliable Petrophysical Answers, Oilfield Review 17, no. 2 (Summer 2005): 1433.

32. Grau J, Herron M, Herron S, Kleinberg R, Machlus M, Burnham A and Allix P: Organic Carbon Content of the Green River Oil Shale from Nuclear Spectroscopy Logs, presented at the 30th Oil Shale Symposium, Colorado School of Mines, Golden, Colorado, October 1822, 2010.

33. Burnham AK: Slow Radio-Frequency Processing of Large Oil Shale Volumes to Produce Petroleum-Like Shale

> Organic and inorganic carbon from logs and cores. Total carbon (left) is made up of inorganic and organic carbon, the latter of which resides in kerogen. The inorganic carbon is present in mineral form, such as in carbonates and some exotic minerals sometimes found in oil shales. Estimates of inorganic (middle left) and organic carbon (middle right) based on nuclear measurements (black) correlate extremely well with laboratory measurements on cores (red). An expanded section (right) shows the quality of the match across the bottom 150-ft interval.

0 20 40Total carbon, weight percent

Dept

h, ft

X,000

X,200

X,400

X,600

X,800

Y,000

Y,200

Y,4000 10 20Inorganic carbon, weight percent

0 20 40

0 20 4010 30Organic carbon, weight percentTOC, weight percent

150-

ft in

terv

al


Oil, Livermore, California: Lawrence Livermore National Laboratory, Report UCRL-ID-155045, August 20, 2003.

Raytheon: Radio Frequency/Critical Fluid Oil Extraction Technology, http://www.raytheon.com/businesses/rtnwcm/groups/public/documents/datasheet/rtn_bus_ids_prod_rfcf_pdf.pdf (accessed November 16, 2010).

34. Burnham et al, reference 28. 35. Bostrom N, Leu G, Pomerantz D, Machlus M, Herron M

and Kleinberg R: Realistic Oil Shale Pyrolysis Programs: Kinetics and Quantitative Analysis, presented at the 29th Oil Shale Symposium, Colorado School of Mines, Golden, Colorado, October 1921, 2009.

38607schD4R1.indd 15 2/21/11 9:26 PM

16 Oilfield Review

Has the Time Come for EOR?

For twenty years, much of the E&P industry turned away from the term enhanced oil

recovery. Yet, during that period, field successes through flooding with steam and

carbon dioxide continued. Decreasing production levels in maturing fields have

revived interest in enhanced recovery techniques in many parts of the world.

Improved technologies for understanding and accessing reservoirs have increased

the possibilities for successful EOR implementation.

Rifaat Al-MjeniShell Technology OmanMuscat, Oman

Shyam AroraPradeep CherukupalliJohn van WunnikPetroleum Development OmanMuscat, Oman

John EdwardsMuscat, Oman

Betty Jean FelberConsultant Sand Springs, Oklahoma, USA

Omer GurpinarDenver, Colorado, USA

George J. HirasakiClarence A. MillerRice UniversityHouston, Texas, USA

Cuong JacksonHouston, Texas

Morten R. KristensenAbingdon, England

Frank LimAnadarko Petroleum CorporationThe Woodlands, Texas

Raghu RamamoorthyAbu Dhabi, UAE

Oilfield Review Winter 2010/2011: 22, no. 4. Copyright 2011 Schlumberger.CHDT, CMR-Plus, Dielectric Scanner, ECLIPSE, FMI, MDT, MicroPilot and Sensa are marks of Schlumberger.

A tantalizingly large source of additional oil sits within reach of existing oilfield infrastructure. Operating companies know where it is, and they have a good idea how much is there. This resource is oil left in reservoirs after traditional recovery methods, such as primary production and water-flooding, have reached their economic limits.

The percentage of original oil remaining var-ies from field to field, but a study of 10 US oil-producing regions found that about two-thirds of the original oil in place (OOIP) remained after traditional recovery methods were exhausted.1 The study found that about 23% of the oil remain-ing in those regions could be produced using established CO2 flood technologies. That techni-cally recoverable resource of almost 14 billion m3 [89 billion bbl] of oil could, by itself, supply more than a decade of US consumption at current rates. Interest in methods to recover those resources has increased in recent years.2

Worldwide, the number of mature fields will continue to grow, with more passing their produc-tion peak each year. Operators work to optimize recovery from these fields, and in the past 20 years tremendous advances have been made that

help access the remaining resource. Bypassed oil can be located with advanced logging tools, 4D seismic evaluations, crosswell imaging technolo-gies, 3D geomodeling and other state-of-the-art software systems. The industry has made strides in understanding clastic sedimentary structures and carbonate petrophysics to construct models and in reservoir geomechanics to plan well paths. Today, the industry can drill more-complex wells and precisely reach multiple targets containing untapped oil. Completions can be designed to bet-ter monitor and control production and injection downhole and to measure fluid properties both in situ and at the surface. Tailored chemicals can be designed to improve recovery, and advanced research is looking at the use of nanoparticles to mobilize remaining oil. In addition, the world is now more environmentally aware, presenting the opportunity to use depleted reservoirs for storage of CO2 while also increasing recovery factors.

Methods for recovering oil are referred to by several terms.3 An early concept described sequential phases of production using the terms primary (pressure depletion, including natural water or gas drive), secondary (mostly

1. Hartstein A, Kusskraa V and Godec M: Recovering Stranded Oil Can Substantially Add to U.S. Oil Supplies, Project Fact Sheet, US Department of Energy Office of Fossil Energy (2006), http://fossil.energy.gov/programs/oilgas/publications/eor_co2/C_-_10_Basin_Studies_Fact_Sheet.pdf (accessed November 8, 2010).

2. For a recent review of enhanced recovery methods: Manrique E, Thomas C, Ravikiran R, Izadi M, Lantz M, Romero J and Alvarado V: EOR: Current Status and Opportunities, paper SPE 130113, presented at the SPE Improved Oil Recovery Symposium, Tulsa, April 2428, 2010.

For results of a biennial survey of activity: Moritis G: Special Report: EOR/Heavy Oil Survey: CO2 Miscible, Steam Dominate Enhanced Oil Recovery Processes, Oil & Gas Journal 108, no. 14 (April 19, 2010): 3653.

Moritis G: EOR Oil Production Up Slightly, Oil & Gas Journal 96, no. 16 (April 1998): 4977, http://www.ogj. com/index/current-issue/oil-gas-journal/volume-96/issue-16.html (accessed February 7, 2011).

3. A proposal made to the SPE in 2003 to clarify the definitions was not implemented. See Hite JR, Stosur G, Carnahan NF and Miller K: IOR and EOR: Effective Communication Requires a Definition of Terms, Journal of Petroleum Technology 55, no. 6 (June 2003): 16.

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water- or gasflooding, including pressure main-tenance) and tertiary (everything else). However, with advances in reservoir modeling, engineers sometimes found that waterflooding should occur before pressure decline, or that a tertiary method should be used in place of a waterflood, or that potential recovery by a ter-tiary method might be lost due to reservoir damage from earlier activities. The terms lost their original sense of a chronological order. Engineers today often include methods for-merly termed tertiary as part of the field devel-opment plan from the beginning.

Another distinction that has been difficult to define is that between improved oil recovery (IOR)which had essentially the same defini-tion as secondary recoveryand enhanced oil recovery (EOR), which included more-exotic recovery methods. Over the years, a few EOR pro-cesses were commercially successful in many applications, and some companies began refer-ring to them as a form of IOR instead. This rela-beling process accelerated after many companies severely cut or stopped funding EOR research during the era of low crude-oil prices in the 1980s and 1990s.4

Regardless of the labels used, the range of activities applied to increase recovery from reser-voirs is wide. Waterflooding is common as an eco-nomical way to displace oil and provide pressure support. Methods that improve physical access to oil include infill drilling, horizontal drilling, hydraulic fracturing and installation of certain types of completion hardware. Conformance con-trol improves recovery by blocking off high- permeability zones either by mechanical means,

such as inflow control devices, or by injecting flu-ids, such as foam or polymer, that plug those zones; these activities improve recovery from lower-permeability zones. Thermal processes are common to decrease viscosity of heavy oils and to mobilize light oils.

Finally, injecting chemicals and effective recovery gasessuch as CO2can change certain physical properties of the crude oil-brine-rock (COBR) system. These methods alter inter facial tension (IFT), mobility, viscosity or wettability, swell the oil or alter its phase composition.

The specific method or combination of EOR methods applied to recover oil is typically based on an engineering study of each reservoir. In most cases, the objective is to achieve the most economical return on investment, but some national oil companies have different goals, such as maximizing ultimate recovery. Operators examine several risk factors, including oil price, need for a long-term program to achieve satisfac-tory return on investment, large upfront capital investments and cost of drilling additional wells and running pilots.

Many oil-recovery techniques depend on pore-level interactions involving COBR-system proper-ties. Most projects begin by screening EOR candidates against field parameters such as tem-perature, pressure, salinity and oil composition.5 Many companies have established screening criteria for EOR projects, but since these are changing as new technologies are introduced, this article does not present a specific set of criteria.6

EOR techniques that pass initial screening are further evaluated based on laboratory studies of the rock and fluids and on simulation studies that use field properties. If laboratory tests have positive results, the operator might next perform

field-level tests, ranging from single-well to multiple-pattern pilots. If the early steps indicate likelihood of a positive economic result, full-field implementation can follow.

EOR technology has even resurrected signifi-cant levels of production after abandonment. The Pru Fee property in Midway-Sunset field, San Joaquin basin, California, USA, produced about 2.4 million bbl [380,000 m3] of heavy oil between start of production in the early 1900s and abandonment in 1986.7 Cyclic steam injection had been partially successful in increasing pro-duction, but by the time of abandonment, the oil rate was less than 10 bbl/d [1.6 m3/d] for the entire field.

In 1995, The US Department of Energy (DOE) selected the Pru Fee property for a demonstra-tion EOR project. After cyclic steamflooding in several old wells at the center of the site demon-strated good production levels, the project team added 11 new producers, 4 injectors and 3 tem-perature-observation wells, obtaining production rates in the range of 363 to 381 bbl/d/well [57.7 to 60.6 m3/d/well]. In 1999, operator Aera Energy added 10 steamflood patterns.8 By 2009, the site had produced an additional 4.3 million bbl [684,000 m3] of oil after original abandonment.9

This article describes a broad range of recov-ery methods, but focuses on techniques tradition-ally considered EORand referred to as suchincluding miscible and immiscible gas-flooding, chemical flooding and thermal technol-ogies. A case study for a Gulf of Mexico field evaluated its gasflooding potential. An extensive laboratory evaluation indicates how to tailor a chemical combination for EOR injection. Another case, from Oman, describes the first use of a method for performing rapid single-well, in situ evaluations of injection to demonstrate the effi-ciency of a flooding process.

Displacement EfficiencyWaterflooding in oil fields was first legalized in the US in the state of New York in 1919, but so-called unintentional waterflooding was recorded as early as 1865, near Pithole City, Pennsylvania, USA.10 Less than a decade after waterflooding became legal, inventors proposed means to improve flood recovery by adding surfactant to lower interfacial tension or by injecting alkali to generate surfactant in situboth now accepted EOR methods.11

A boom of activity in EOR techniques came after the oil-price rise of the 1970s, but the bust in the late 1980s led many companies to abandon marginal and uneconomic projects (above left). A sustained period of higher crude-oil prices in

> EOR project history. The number of ongoing EOR field projects in the US peaked in 1986, then declined for nearly 20 years. Since 2004, the number of projects has been rising again. Currently, miscible gas EOR projects (green) dominate, followed by thermal projects (pink). At present, only a few chemical floods (blue) are underway. [Data from Moritis (1998 and 2010), reference 2.]

Oilfield ReviewWinter 10 EOR Fig. 1ORWIN10-EOR Fig. 1

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ber o

f US

proj

ects

600

500

400

300

200

100

1978

Data from Oil & Gas Journal surveys

ChemicalThermalGas

1982 1986 1990Year

1994 1998 2002 2006 20100

= Oil/water interfacial tension= Contact angle

OWcos

Viscous forces

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the past 10 years has revived operator interest in some of these techniques and encouraged intro-duction of new ones. That interest has survived the more recent price volatility.

Many techniques aimed at improving recov-ery are designed to increase the efficiency of oil displacement using injected water or other flu-ids. Some methods address the macroscopic dis-placement efficiency, also called sweep efficiency. Other recovery methods focus on microscopic, or pore-scale, displacement efficiency. The overall displacement efficiency is the product of both macroscopic and microscopic efficiencies.

Macroscopic displacementAt the scale of interwell distances, oil is bypassed because of lat-eral or vertical formation heterogeneity, well-pattern inefficiencies or low-viscosity injection fluids. Improving sweep efficiency is typically one of the goals of reservoir engineering and model-

ing. Although the efficiency of well patterns such as five- or nine-spots can be determined for a uni-form reservoir, reservoir heterogeneities affect flow paths (above left). If these are unknown or not compensated for by adjusting the pattern, then sweep efficiency suffers.

Advances in seismic acquisition, processing and interpretation have given reservoir engi-neers new tools to locate faults and layer changes. Some companies have applied 4D seismic meth-ods to follow a flood front through a reservoir, allowing their engineers to update models based on observed flow geometries. Pattern sweep effi-ciency can be improved by infill drilling or the use of horizontal or extended-reach wells and by creating zones within well intervals using down-hole flow-control devices.12

Sweep is also affected by vertical variations in properties (above right). In particular, a high-

permeability, or thief, zone will be swept by a waterflood before adjacent low-permeability zones are swept. Techniques can be applied to equalize the flow in the zones, most commonly by decreasing thief-zone permeabilities. If there is little or no communication between zones, the thief zone can be shut off near the injection site, but if the zones communicate throughout the reservoir, it may be necessary to design an injectant that will block the zone all the way to the producing well. For both near-well and far-field solutions, engineers use foams and polymers for this purpose.

Viscous fingering is another concern of macro-scopic displacement efficiency. If the displacing fluidtypically wateris significantly less vis-cous than the oil it is displacing, the flood front can become unstable. Rather than being linear or radially symmetric, the leading edge of the front

4. One indication of the rise and fall of the term EOR is the naming of the biennial meeting sponsored by the SPE in Tulsa. The first five meetings, spanning 1969 through 1978, were called the SPE Improved Oil Recovery Symposia. From 1980 through 1992, the US Department of Energy jointly sponsored the conferences, and they were called the SPE/DOE Enhanced Oil Recovery Symposia. In 1994, the conferences returned to sole sponsorship by SPE, and again became the SPE Improved Oil Recovery Symposia, which they remain today. Throughout this 31-year period, conference papers covered topics typically considered both IOR and EOR.

5. Lake LW, Schmidt RL and Venuto PB: A Niche for Enhanced Oil Recovery in the 1990s, Oilfield Review 4, no. 1 (January 1992): 5561.

6. For an overview of EOR engineering, including criteria to consider: Green DW and Willhite GP: Enhanced Oil Recovery. Richardson, Texas, USA: Society of Petroleum Engineers, SPE Textbook Series, vol. 6, 1998.

> Areal displacement efficiency. Oil can be bypassed because of inefficiencies in macroscopic sweep. A pattern flood can be affected by a heterogeneous formation (such as the presence of sealing faults) or by fingering of a less viscous injectant into the oil.

Seali

ng f

ault

Viscous fingers

Injectant

Injection well Production well

Pattern Flood

> Vertical displacement efficiency. Vertical sweep can be affected by viscous fingering, as well as by preferential movement of fluids along a high-permeability thief zone or by gravity override of injection gas (as indicated here) or underride of injection water.

Vertical Profile

Gravity override

Barrier

Barrier

High permeability

Low permeability

For another set of criteria: Taber JJ, Martin FD and Seright RS: EOR Screening Criteria RevisitedPart 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects, SPE Reservoir Engineering 12, no. 3 (August 1997): 189198.

Taber JJ, Martin FD and Seright RS: EOR Screening Criteria RevisitedPart 2: Applications and Impact of Oil Prices, SPE Reservoir Engineering 12, no. 3 (August 1997): 199205.

7. Schamel S: Reactivation of the Idle Pru Lease of Midway-Sunset Field, San Joaquin Basin, CA, The Class Act: DOEs Reservoir Class Program Newsletter 7, no. 2 (Summer 2001): 16, www.netl.doe.gov/technologies/oil-gas/publications/newsletters/ca/casum2001.pdf (accessed November 10, 2010).

8. Schamel S and Deo M: Role of Small-Scale Variations in Water Saturation in Optimization of Steamflood Heavy-Oil Recovery in the Midway-Sunset Field, California, SPE Reservoir Evaluation & Engineering 9, no. 2 (April 2006): 106113.

9. State of California Department of Conservation Division of Oil, Gas and Geothermal Resources, Online Production and Injection database, http://opi.consrv.ca.gov/opi (accessed December 3, 2010).

10. Blomberg JR: History and Potential Future of Improved Oil Recovery in the Appalachian Basin, paper SPE 51087, presented at the SPE Eastern Regional Meeting, Pittsburgh, Pennsylvania, USA, November 911, 1998.

11. Uren LC and Fahmy EH: Factors Influencing the Recovery of Petroleum from Unconsolidated Sands by Water-Flooding, Transactions of the AIME 77 (1927): 318335.

Atkinson H: Recovery of Petroleum from Oil Bearing Sands, US Patent No. 1,651,311 (November 29, 1927).

12. Ellis T, Erkal A, Goh G, Jokela T, Kvernstuen S, Leung E, Moen T, Porturas F, Skillingstad T, Vorkinn PB and Raffn AG: Inflow Control DevicesRaising Profiles, Oilfield Review 21, no. 4 (Winter 2009/2010): 3037.

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forms waves that transition to fingers extending farther into the oil. Eventually, water fingers reach the producing well. At that point, additional injected water will preferentially follow the water-filled paths. Engineers avoid this by increasing water viscosity through methods such as adding polymer or foam to it.

Microscopic displacementAt the other end of the size scale, small blobs of oil can be trapped within a pore or a connected group of pores (above). Oil at this scale is trapped because vis-cous or gravity-drive forces within the pore space are insufficient to overcome capillary forces.

The amount of oil trapped within pore spaces depends on a variety of physical properties of the COBR system. One of these properties is wettability.13 In a strongly water-wet rock, water preferentially coats the pore walls. Conversely, strongly oil-wet surfaces within a pore are pref-erentially contacted by oil. In an intermediate-wetting condition, the pore surfaces do not have a strong preference for either water or oil.

Most reservoir rocks have a mix of wetting conditions: The smaller pores and spaces near grain contacts are generally strongly water wet-ting, while the surfaces bounding the larger pore bodies may range from less water wetting to oil wetting. Thus, the wettability of the bulk material is between the two extremes. Although measures of wettability, such as Amott-Harvey or US Bureau of Mines (USBM) wettability tests, may result in similar index numbers for intermediate and mixed-wet rocks, the two are distinct wetting conditions. Intermediate wettability applies to rocks with all surfaces of neutral wetting prefer-ence, while mixed wetting applies to rocks with surfaces of markedly different wettability.

Optimal recovery from waterflooding is obtained in mixed-wet material that is slightly water wet-ting.14 The reason for this can be made clear by a discussion of pore-level oil-trapping mechanisms.

Most reservoirs were water-wet formations before oil accumulated. Oil migrating into a for-mation must overcome the rocks wetting forces before it can enter the pores. This resistance is the rocks capillary entry pressure, which is the pres-sure difference between the water and oil phases n

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