exploration & production
carbonate reservoirs EXTRACTING THEIR VALUE
the know-how Series
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Page 04 BACKGROUND // Challenges Concentrated mainly in the Middle East, carbonate reservoirs contain half the world’s hydrocarbon resources. However, their heterogeneity and the acid gases they usually contain pose huge challenges.
Page 06 A WINNING HAND // ToTal seTs The sTandard On the strength of its experience and its commitment to continuous innovation, Total is setting ambitious goals to enhance its mastery of carbonate reservoirs, largely untapped to date.
Page 08 REFERENCES // experTise aT work From the Arabian/Persian Gulf to the glacial horizons of the Arctic Circle, a panorama of key projects where Total is implementing an array of leading-edge technologies.
P. 09 dolphin P. 10 abu al Bukhoosh P. 13 al khalij P. 14 kharyaga and kashagan
Page 16 KNOW-HOW // aT The forefronT of TeChnology From understanding the long history of basin geology to optimizing well productivity, carbonate reservoirs demand the mobilization of experts in every discipline.
P. 17 defining and modeling heterogeneities P. 20 The difficult task of predicting reserves P. 23 optimizing production
Page 26 TOMORROW // new Challenges ahead In the upstream and downstream sectors alike, it is by fully integrating all its fields of expertise that Total unlocks its innovative capabilities and remain in the vanguard of the strategic area of producing carbonate reservoirs.
P. 27 overcoming obstacles to seismic characterization P. 29 enriching conceptual geological models P. 30 improving well performance
CarBonaTe reservoirs
EXTRACTING THEIR VALUE
//. ConTenTs
In 2006, Total decided to add carbonate reservoir expertise to the list of specialized know-how required to drive vital future growth in the world’s hydrocarbon production. That decision signalled the launch of a multidisciplinary Research & Development program specifically dedicated to mastering these promising structures. The geologic diversity of limestone and/or dolomitic reservoirs, which are much more complex than their sandstone counterparts, reflects the diversity of the fossilized remains of living organisms that led to their formation. Carbonate reservoirs exhibit extreme heterogeneity. The significant small- and large-scale
variability in their properties, coupled with the often acid fluids they contain, make them challenging targets and to date, they remain under-exploited, despite the fact that they contain half of the world’s hydrocarbon resources. On the strength of expertise already acquired in this area, Total has the determined ambition of being among the industry frontrunners who will forge vital innovations to optimize their value.
“The determined ambition to forge vital innovations”
Key implications for future growth in oil reserves
The desert of Abu Dhabi, United Arab Emirates.
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Carbonate reservoirs are concentrated primarily in the Middle East but are found on every continent. The fact that they contain approximately 50% of the world’s hydrocarbon resources attests to their importance for the long-term growth of petroleum reserves. And the challenges involved in producing them are proportional to that promise.Because carbonates are composed of the fossilized remains of living organisms and their myriad paleoenvironments, they bear the imprint of this complexity. The extreme variety of the sedimentary deposits and the climatic conditions in which they were formed, as well as the numerous physical-chemical transformations they have undergone over time, together translate into highly heterogeneous geology. For the oil companies seeking to develop them, they entail tremendous challenges: characterizing the reservoirs, understanding fundamental heterogeneities, reducing the uncertainty of reserve estimates and improving productivity and recovery factors.
What is a carbonate reservoir?Carbonate rocks are the fossilized product of biological activity that took place mainly in shallow, warm-water marine environments. They are the result of the build-up of organisms or organic debris of varying size and nature: bacteria; foraminifers; gastropod, lamellibranch and rudist shells, and others (see photos). In other words, carbonate deposits
reflect the evolution, diversity and extension of species over the course of geological time. In addition to the considerable original heterogeneity of these sediments, the numerous transformations that have taken place over thousands of years (diagenesis) have altered the initial properties of the reservoirs. From the chemical standpoint,
carbonate reservoirs are generally characterized by high concentrations of the acid gases hydrogen sulfide (H2S) and carbon dioxide (CO2). Two factors explain the presence of these gases. One is the absence of iron: unlike sandstone reservoirs, in which H2S readily reacts with the ferrous minerals present in the deposits and mineralizes to form pyrite, such
HAlF THE world’s rEsErvEs
BACKGROUND // Challenges
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The Middle East: the crux of the matter
Carbonate reservoirs are highly prevalent in the Middle East, especially in the countries bordering the Arabian/Persian Gulf (Saudi Arabia, Iran, Iraq, United Arab Emirates, Oman, Qatar, Bahrain), where they
account for 80% of the region’s oil reserves and 90% of its gas reserves (or 45% of oil and 30% of gas reserves worldwide). The Commonwealth of Independent States (CIS) is the second main carbonated province, with most
of its carbonate reservoirs located in Russia and Kazakhstan. Other carbonate traps are scattered throughout South America, Central America (Mexico), Africa, Europe and Asia.
difficulties for reserve recoveryThe recovery factors currently being achieved in the major carbonate fields are not, by any means, determined by permeability alone, and range from less than 10% to more than 40% on fields of average permeability (10 to 100 mD). Fractures and permeable drains are the fundamental heterogeneities and thus determine the dynamic behavior of the reservoir, but are much more difficult to model. This explains why recovery from this type of reservoir is so difficult to predict and so variable. The diversity of recovery mechanisms and development plans only adds to the difficulty.
What is a carbonate reservoir?mineralization is not possible in carbonate reservoirs, which explains why H2S can easily accumulate there via physical-chemical processes that may also evolve CO2. The other factor is the presence of sulfates in carbonate reservoirs, because they supply the sulfur needed to form H2S either by organic decomposition or by thermo-chemical reactions.
1. Laminar limestone showing traces of rich organic content.
2. Carbonate grains fringed with cement.
3. Ooid with partially dissolved concentric envelope bands.
4. Hole left by a burrowing organism, with calcite and anhydrite fill.
5. Rudist colony (giant mollusks of the Cretaceous).
Ultimate recovery factor versus permeability. (Source: IHS, SPE)
Carbonate fields of various averagepermeabilities and their recovery mechanisms. (Source: IHS, SPE)
60%89% 40%11%
80%
20%
87%
13%
74%
26%
87%13%
75%25%
86%
14%75%25%
YEMEN0.1 Gboe
UAE99 Gboe
BAHRAIN28 Gboe
KUWAIT45 Gboe
QATAR71 Gboe
OMAN6.8 Gboe
Gulfof Oman
Gulf of Aden
Oman Sea
IRAN220 GboeIRAQ
91 Gboe
SYRIA3.1 Gboe
SAUDIARABIA263 Gboe
Reef
Shelf carbonates
Deep carbonates
Carbonates oil province
Oil
Gas
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Through its involvement as operator or partner in the prolific regions of the Middle East, the Commonwealth of Independent States and the Caspian Sea, in Africa and in Europe, Total has had many opportunities to enhance its expertise in the field of carbonate reservoirs. Its knowledge in this area is already longstanding, drawing notably on the Group’s presence in Abu Dhabi since 1939, its development and production of the huge sour gas field at Lacq (France) beginning in the 1950s, and the operation of the Abu Al Bukhoosh (Abu Dhabi) field for more than thirty years to date. Today however, finding economically-viable ways to extract value from carbonate reservoirs has become one of Total’s strategic objectives. Due to their complexity, most of these reserves are still untapped. Each carbonate reservoir is unique and poses its own challenges: in addition to being extremely heterogeneous, difficult to characterize, unsuited to the use of many conventional tools to estimate reserves and to interpret fluid dynamics within the reservoir, many plays are complex to drill and produce, and contain acid gas. These are the reasons behind Total’s 2006 decision to launch an integrated, multidisciplinary R&D program dedicated to producing carbonate reservoirs, to develop the leading-edge tools and technologies needed to better characterize, model and exploit these promising targets.
A WINNING HAND // ToTal seTs The sTandard
R&D in the heart of the Middle EastAs Total’s first Research & Development center in the Middle East, the new Total Research Center-Qatar® (TRCQ) houses laboratories dedicated to two major areas of interest related to carbonate reservoirs: geochemistry, notably focusing on heterogeneities in the composition and distribution of sour gases; and optimization of well stimulation processes.
Model of fluid flows, Al Khalij field, Qatar.
CArbOnATEs, a prioriTy TargeT s s s
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Total’s major positions in carbonate reservoirs
Abu Al Bukhoosh (UAE) Thirty-five years of production and an extensive portfolio of technologies to maximize recovery.
Kharyaga (Russia) Dynamics made
complicated by karstification.
Dolphin (Qatar) Major advances in the dynamic modeling of this field of dolomitic limestone.
Al Khalij (Qatar) The challenge of managing unwanted water influx.
Kashagan (Kazakhstan) A giant field that will begin reinjecting high-pressure H2S in 2012.
Valhall (Norway)
Qatargas I (Qatar)
South Pars (Iran)
Ekofisk (Norway)
Lacq (France)
N’kossa (Congo)
Qatargas II (Qatar)
Tempa Rossa (Italy)
Al Jurf (Libya) Yadana (Myanmar)
Total has committed to an ongoing quest to optimize the characterization and productivity of carbonate reservoirs. To meet the numerous inherent challenges of these complex geological objects, the group, whether as operator or as partner, is mobilizing its know-how to resolve the major issues involved, drawing on multidisciplinary synergy to do so. The following pages present a panorama of the leading-edge technologies being deployed for this purpose, from the arabian/persian gulf to glacial arctic horizons.
Trains 1 and 2 of the plant that processes the multiphase gas flows from the Dolphin project, Qatar.
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Overcoming the obstacles that can foil attempts to image carbonate reservoirs, the seismic characterization of the Dolphin reservoir in Qatar has shed light on the field’s dynamics.
Dolphin, the new star development of the North Field, one of the world’s largest gas fields, exports its production from Qatar to the United Arab Emirates and Oman. The difficulties encountered in both static and dynamic modeling of this Permo-Triassic system are on par with its size: 225 x 120 km. In addition to the complex distribution of its many facies at the regional scale, sharp alterations caused by several diagenetic sequences amplify the heterogeneities and reservoir properties at the metric scale.Nonetheless, Dolphin is one of the rare cases where seismic technology, often incapable of precisely imaging carbonate structures, was applied successfully in this context of reservoir characterization. In the first-time use of a new algorithm, studies carried out from 2004 to 2007 led to a high-quality seismic inversion: seismic amplitude cubes (which indicate the energy of the signal reflected by the subsurface) were transformed into porosity and lithology cubes to optimize the geomodel. Thanks to a significant attenuation of seismic multiples (successive reflections that create “noise” in the primary data, a common phenomenon in carbonates), the inversion quality was such that the modeled porosities correlated perfectly with the well-log data.
REFERENCES // experTise aT work
dolphinsTUDyInG POrOsITy wITH sEIsMIC IMAGInG
DOLPHIN FACT SHEET _operator: dolphin energy limited (Mubadala Development Company, 51% - Total, 24.5% - Occidental Petroleum, 24.5 %)_first gas: 2007_plateau production: 2.5 Bscf/d 2 platforms 12 production wells drilled in a star configuration around each platformMultiphase transport via two sealines (70 and 90 km) to the gas processing plant at Ras-Laffan
Modeling dolomitization The scope of a reservoir model built in 2009 encompasses Dolphin, Qatargas 1 and Qatargas 2, three developments in which Total is a partner. Constrained by dynamic and seismic data, the model’s aim was to fine-tune the mapping of the highly permeable dolomitic drains created during the later diagenesis of the formation. Meanwhile, a highly innovative diagenesis modeling tool developed in-house by Total was applied for one of the first times on Dolphin to reproduce the process of dolomitization as one step toward optimizing the model of these carbonates and their complex dynamics.
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ABK FACT SHEET _operator: Total (75%)• 115 km2 of surface area • 1974: first oil• 1992: first gas • 19 platforms • 56 km of subsea flowlines• 107 wells drilled, namely: – 73 oil producers (deviated, horizontal, multidrain) – 1 water producer – 9 gas producers – 10 gas injectors – 14 water injectors
A mature oil field still in production thirty-five years after it was first brought on stream, Abu Al Bukhoosh (ABK) has benefited from the deployment of a steady stream of vanguard technologies to forestall its decline.
The field of Abu Al Bukhoosh (ABK) is located in Abu Dhabi in the southern part of an oil play, two-thirds of which lies beneath the Iranian waters of the Arabian/Persian Gulf. The field’s geology is typical of the Emirate, consisting of a stack of carbonate platforms formed in many different paleoenvironments. The wide variety of the sediments and their diagenesis — which caused considerable heterogeneity in terms of permeability and porosity — coupled with the structural complexity of the formations and the associated faults and fractures, has dictated a phased development plan with an ongoing effort to optimize production. As the field has gradually matured since it was first brought on stream in the 1970s, Total has continually improved recovery efficiency and expanded reserves, overcoming a host of technological challenges along the way. From an initial estimate based on about twenty years of production, the initial reserves have nearly tripled in the space of thirty years, and the oil is still flowing. Today, the field’s main reservoir boasts a recovery factor of 53%. Pursuing the development of ABK with efforts now focused on its tightest reservoirs calls for implementing the most advanced know-how available, sharpening the Group’s expertise in the area of mature carbonate reservoirs.
REFERENCES // experTise aT work
aBu al BukhooshPUsHInG rECOvEry TO THE lIMITs
1. 2. Platforms on the Abu Al Bukhoosh field, Abu Dhabi, United Arab Emirates.
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2
Age
MY Period
Pleistogene
EpochHolocene
Pleistocene Recent
PlioceneMiocene
Mishan Zibara
GachsaranOligocene Asmari
Dammam
Unayzah
Rus
Simsima
Sudair
HamlahIzhara
Fiqa
ShilaifRuwaid
a
Mishrif
Tuway
il
Halul / Ilam
MauddudNahr Umr
HabshanLekhwairKharaibShuaiba
MID. ANHYDRITE
Laffan
UmmEr Radhuma
Eocene
Paleocene
Upper
UpperLower
Upper
Araej
A
AC B
D
VIV
KD
KC
KB
KA
IIIBCD E
Tuwaig MiUpper Araej
UweinatLower Araej
FGH
Limestone
Argillaceous limestone
Dolomite
Anhydrite
Shale
Sandstone
Oil & gas
Oil
Gas
Source rock
Unconformity
Minjur
?
Marrat
IntrashelfBasin
Gulailah (Jilh)
Diyab (Jubailah) HanifaUpper
Middle
Middleto
Lower
Lower
Upper to Middle
Lower
Grou
pHa
saAr
uma
Gurp
iPa
bdah
Was
iaTh
amam
aSi
la
Khuf
fAs
ab HithArab
Neogene
Paleogene
Cretaceous
Jurassic
Triassic
Permian
Sour
ce ro
cks
Rese
rvoir
s
Formation Lithology
1.8
3333.9
55.8
65.5
89.3
112
145.5
161
200
251
255
Thamama (Lower Cretaceous) • Oil reservoir of 550 to 600 m thickness, limestone interbedded with dense layers of tight argillaceous carbonates containing stylolites• Tightest zones: porosity of 5 to 20% – permeability of 1 to 2 mD
Upper Arab (Upper Jurassic)• Oil reservoir of 80 to 120 m thickness containing 4 main plays formed of dolomitic sequences (1 to 7 m thick) separated by anhydrite barriers • Porosity: from 2 to 20% – average
to tight permeability with some more productive intervals
Lower Arab (Upper Jurassic)• Oil reservoir of 160 m thickness, made up of limestones and dolomites; the main producer of ABK• The best characteristics of the reservoir, in the dolomite layers, range from 10 to 28% for porosity and from 10 to 1,000 mD for permeability
Upper Khuff (Permo-Triassic)• Gas reservoir exploited on behalf of ADnOC
Four main reservoirs
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The Challenge of The sTruCTural ModelABK is one of the carbonate fields for which seismic surveys yield only mediocre-quality images that reveal little of the structure of the formations, especially the deepest ones. It is crucial to perfect the structural model of the field, particularly because the complex network of faults and fractures significantly affects production. The model has been continually refined since the first interpretation based on 2D seismic. An initial interpretation of a 3D OBC (Ocean Bottom Cable) acquisition shot in 1995, followed by a reprocessing of the data set in 2003 with PSTM (Pre-Stack Time Migration), then a new interpretation methodology in 2006 based on Total’s proprietary tool, SismageTM and finally by a 3D VSP (Vertical Seismic Profile) acquisition in 2008, have led to a more detailed mapping of the structure, with better detection of faults and their orientations.
Phased development1973-1978 – Primary recovery • Production of the main oil reservoir, in the Lower Arab formation, by primary depletion• Installation of electrical submersible pumps (ESP) for artificial lift, due to water breakthrough1978-1982 – Secondary recovery and gas lift • Development of the Upper Arab oil reservoirs with pressure maintenance
• Water flooding followed by gas lift1983-1991 – Field extension• Extension of the development of reservoirs in the Arab formation• Tertiary gas injection pilot • Increase in water flooding via three subsea injection wells by dumpflooding (direct, gravity-flow injections from an aquifer to a deeper reservoir) • Beginning of exploitation
of the tight Thamama reservoir (Lower Cretaceous) 1992-1996 – Infill drilling• Start of gas production from the Khuff formation (Permo-Triassic) on behalf of ADnOC, and continued development of the reservoirs of the Arab formation• First horizontal infill wells drilled in Abu Dhabi1997-2009 – Tertiary injections• Implementation of tertiary non-miscible gas injections on all reservoirs of the Lower Arab formation• Drilling of multi-lateral wells to produce the thin, low-permeability intervals of the Upper Arab formation, a first in Abu Dhabi Looking ahead • Continuing development of the tightest reservoirs using the most sophisticated techniques • CO2 flooding under study• Control of water influx by injections of Relative Permeability Modifiers (RPM) under study
Jan.1974
Jan.’78
Jan.’82
Jan.’86
Jan.’90
Jan.’94
Jan.’98
Jan.2002
Jan.’06
1,2001,0509007506004503001500
160,000140,000120,000100,000
80,000
60,00040,00020,000
0
Production primaire de l'Arab inférieur
pompes électriques fond de puits
Production secondaire de l'Arab supérieur :
Injection d'eau et gaz lift Développement du
réservoir de Thamama
Arab development ESP
PHASE 1Réservoirs de l'Arab : puits infill
horizontaux
PHASE 2Réservoir de l'Arab
supérieur : puits multidrains
PHASE 1Infill/productivity Horizontal wells
Upper Arab water injection + gas lift
Thamama development
PHASE 2Dedicated
development
Tertiary recovery
mechanism
GOR (v/v)Rate
(stb
/d)
A technician on one of the platforms of Abu Al Bukhoosh, Abu Dhabi. s s
n Water production n Oil production n Gas injection
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The most innovative technologies are being applied to improve understanding of the dynamic behavior of this atypical reservoir.
Discovered in Qatar in 1991 in the Cenomanian limestone of the Mishrif formation, Al Khalij ranks among the most difficult carbonate reservoirs operated by Total to date. A large portion of this atypical formation is located in a capillary transition zone where the oil is mixed with up to 60% water. It consists of mostly water-bearing porous but low matrix permeability limestone intervals, alternating with thin (1 to 3 m) highly oil-permeable layers. This heterogeneity, compounded by that of a fracture network and vugs interconnected during diagenesis, create preferential paths for rapid water influx, which are difficult to image using seismic techniques. Given the uncertainty relating to the dynamic behavior of this extremely complex field, Total opted for a phased development plan revolving around the use of innovative technologies. Successfully meeting the field’s key challenge of controlling the water influx detrimental to productivity, Total has steadily optimized the characterization and the dynamic modeling of the Al Khalij reservoir since it was first brought on stream. This now enables the Group to better predict water influx and deploy appropriate solutions for remedying and minimizing unwanted water breakthroughs.
REFERENCES // experTise aT work
al khalij THE COMPlEx PrOblEM OF wATEr InFlUx
Réservoir• 3DHR seismic acquisition (1999)• Advanced seismic reprocessing to better identify fracture corridors (2004 and 2009)• Construction of a reservoir model integrating all data on the field’s static and dynamic behavior (2007)• Construction of a new structural model for better integration of faults (2009)• Acquisition of extensive data to optimize the understanding of field dynamics (interference tests, Production Logging Tool [PLT], Modular Formation Dynamics Tester [MDT], Drill Stem Tests [DST], continuous fiber-optic monitoring of two wells, well seismic, injection water tracers, etc.)
Production• Unmanned platforms and multiphase export pipeline • Extended-reach horizontal wells (2,000 to 4,000 m)• Selective stimulations • Electrical submersible pumps with daily monitoring • Pilot swell packer completions to optimize the isolation of zones subject to water influx
State-of-the-art technologies
AL KHALIj FACT SHEET _operator: Total (100%)• 1997: first oil• Production: 37,500 b/d in 2008 (80% BSW)• Water injection: 170,000 b/d• 4 wellhead platforms• 3 satellite platforms• 1 production platform • 39 oil-producing wells • 2 water-producing wells• 6 gas-injection wells
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In Russia and Kazakhstan, Total is tackling the twofold challenge of understanding and modeling karsts.
Kharyaga, Russia’s first onshore field brought on stream under a Production Sharing Agreement, is located in the Timan-Pechora basin north of the Arctic Polar Circle, in the Nenets Autonomous Territory. The two reservoirs of this carbonate structure of “reefal” origin, which formed during the Primary era, bring into sharp focus the challenges of mastering their structural and sedimentary models, given the density and complexity of their fault and fracture systems coupled with their extensive karstification. Karsts and fractures are crucial parameters for understanding the dynamic behavior of the field, where pressure is maintained by water injections and electrical submersible pumps (ESP) provide artificial lift to compensate for its low energy. A major thrust of Total’s R&D effort is finding solutions to reduce the significant uncertainty that persists concerning the modeling of these networks of “cavities” with high potential permeability. Offshore Kazakhstan, in the Caspian Sea, the mapping of karstic zones also ranks among the key prerequisites for understanding the Kashagan field, slated to come on stream in 2012. As the fundamental heterogeneity of this carbonate platform, karstification is the source of the major uncertainty of this high-pressure field (800 bar), which also contains 15 to 20% H2S. The distribution of karstic zones is certain to have a decisive impact on the planned high-pressure reinjections of H2S, notably in terms of the risks of premature breakthrough and recycling of this sour gas.
REFERENCES // experTise aT work
kharyaga and kashaganTHE CHAllEnGE OF kArsTIFICATIOn
What is karstification?Karstification is an important physical-chemical phenomenon in carbonate diagenesis. It results in karsts – cavities created as limestone is dissolved by the action of the CO2-laden water circulating through the formation. Karstification significantly affects a field’s permeability: like fractures, karsts can create preferential paths for fluid migration.
KASHAGANFACT SHEET _operator: nCoC (North Caspian Operating Company), a consortium in which Total is a partner._geology:• 800 km2 of surface area• reservoir thickness: 600 m around Kashagan East-1 and 200 m around Kashagan West-1• matrix porosity: < 10%• matrix permeability: on the order of the millidarcy• karstic permeability: up to several Darcy • initial reservoir pressure: 800 bar_phased development plan:• Phase 1 in progress: first oil in 2012 for production of 350,000 b/d • Phase 2: first oil in 2018 for production of 800,000 b/d _plateau production (around 2023): 1.5 million b/d
1
2 3
Operating in extreme cOnditiOns Both Kharyaga and Kashagan are characterized by landlocked geography and by equally difficult climates. The first site imposes the rigors of Arctic conditions, with a temperature range of +35°C to -40°C; the work season is confined to winter, when the soil is frozen, to avoid the ground instability of summer. Although not as far north, Kashagan, in the Caspian Sea, is also synonymous with extreme climatic conditions. Summers are warm, but in winter, the waters covering the field (bathymetry from 2 to 10 m) are frozen over and swept by violent winds.
Kharyaga• 2005: Application of the first version of gOkarsttm, an in-house tool for modeling karstification• 2009: AVAZ (Amplitude Versus Azimuth) reprocessing of 3D seismic data carried out by E&P teams at head office to reduce uncertainty associated with fracture network orientation.
Kashagan• 2008: a pilot 3D 4-component dataset with specific processing to measure the anisotropy of the field and determine the fracture orientation• 2009: request for proposals for a similar full-field acquisition
Sophisticated tools
1. The Kashagan field in Kazakhstan. 2. Operators at the Kharyaga project inside the Arctic Circle, Russia. 3. Some of the facilities at Kharyaga. KhARyAgA
FACT SheeT_Operator: total (50%)_partners: Norsk hydro (40%), Nenets Oil Company (10%)• 1999 : first oil _phase 2 development complete:• 10 production wells• 5 water injection wells _phase 3 development in progress:• 20 wells (producers and injectors)
reconstructing sedimentary history based on seismic images, outcrops, cores and thin sections.
The abundant diversity of living organisms whose fossilized remains ultimately led to the formation of carbonates poses huge challenges for characterization and modeling. integration of expertise from subsurface to production — both of the teams and of the tools they use — is the secret to understanding the many heterogeneities of these complex bodies. only comparative interpretations developed through a veritable “interpretation loop” can bring to light the most fundamental of all these heterogeneities — the one that will provide the key to field dynamics, reserve quantification and optimized production.
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Building a geomodel entails a geological “inquiry” carried out at scales ranging from the basin to thin sections. To model carbonate reservoirs, nothing short of true symbiosis among the various geosciences disciplines will do.
Understanding the carbonate reservoir behavior, predicting its reserve quantities and dynamic behavior, call for going back in geological time. This complex scientific investigation is a prerequisite for deciphering the geometry of the reservoirs’ sedimentary bodies. Step 1: Restituate the target carbonate object in its paleoenvironment. When and where did the sediments accumulate? Were they continental, lacustrine, marine, reefal in origin? What were the prevailing patterns of wind, climate and current? How much water covered them? What was the wave force? Answers to these questions are needed to determine which living organisms were the source of the accumulations. Based on that information, it becomes possible to predict the nature of the sediments, their organization and their potential diversity. For example, certain conditions are conducive to the accumulation of aragonitic shells, while others favor calcitic shells, and the former will stand the test of time better than the latter. These different factors lead to substantial lateral and vertical variability at both the basin and core scales… in other words, extreme heterogeneity.
froM Core To ConCepTual ModelIdentifying bioclastic sediments in a thin core section and situating them in a given paleoenvironment and paleobathymetric context is no job for amateurs. As one of the few oil majors to boast the presence of in-house carbonate specialists among its team of sedimentologists, Total thus enjoys a strategic edge. Based on just a few cores, the wellbores must be “clad” with their sedimentary or depositional environments in order to arrive at the conceptual sediment models, which in turn become the basis of geomodels. To scale up from the thin section observed
KNOW-HOW // aT The forefronT of TeChnology
defining and Modeling HETErOGEnEITIEs
What is dolomitization? It is the process by which calcite is transformed to dolomite. This occurs when the calcium ions of the calcite are replaced by magnesium ions, present in high concentrations in some of the fluids circulating within the rock.
Progress in karst modeling has been accompanied by growth in knowledge about the processes governing karst evolution, because reproducing the phenomenon required a deeper understanding — and especially, finding indices to rate a rock’s susceptibility to CO2 attack. This in turn led
to additional field investigations. A major study conducted in Southeast France focuses on a Middle East reservoir analogue. The data have been synthesized in a conceptual model of the Urgonian (Cretaceous rudist limestones) and its karstification.
From the model to the field
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under the microscope to the full-field accumulation, a series of hypotheses is established, drawing on numerous studies of modern reservoir analogues and fossil outcrops. The study of these formations is imperative to gain an understanding of the geometry of sedimentary bodies and the heterogeneities of depositional facies at various scales. Geophysicists, sedimentologists, structural geologists, micropaleontologists and seismic stratigraphers are actively involved in this essential process.
deTerMining The iMpaCT of diagenesis To CoMprehend reservoir dynaMiCs Diagenesis is a term referring to the dynamic and physical-chemical processes that transform sediment into reservoir rock as it is buried. The impact of diagenesis is particularly important in carbonate formations due to the chemical instability of the minerals that compose them, to the point of being able to profoundly alter their original properties in some cases. Cementation and compaction generally reduce the primary pore volume, while dissolution and dolomitization create porosity. Here also, the sequences and patterns of diagenetic events are sources of major lateral and vertical heterogeneities, both over an entire depositional sequence and in highly localized zones. Because diagenetic phenomena are key to understanding carbonate structures, they are a major focus of Total’s “Carbonates” research.
KNOW-HOW // aT The forefronT of TeChnology
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Millions of cells gOdiagTM and gOkarstTM provide a subgridding of the geological model. While the model distributes the facies and properties over a maximum of about one million cells, gOdiagTM and gOkarstTM treat 200 million cells. Perfecting these tools therefore required the development of upscaling tools to integrate their data into the scale of the gOcadTM (or other appropriate software) geomodeler mesh. Subsequent advances will allow these tools to benefit from the same progress as gOcadTM: heterogeneous cells to adapt to the reservoir geometry.
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innovaTive Modeling Although the dissolution of limestone by CO2-laden waters is one of the main contributors to improved reservoir characteristics (i.e., porosity, permeability), it is also a source of significant uncertainty due to the extreme difficulty of quantifying the process. In 2002, the Group began to develop gOkarstTM, a new-generation tool dedicated to modeling karstification, and applied it notably to the highly karstic Kharyaga field in Siberia, operated by Total. The purpose of the tool is to apply mathematical and statistical methods to arrive at a phenomenological representation of the process. Initiated on a sedimentological model still “untouched” by karstification, the simulation reproduces the steps of the phenomenon until it coincides with the dynamic data acquired at the wells. The model’s “deliverable” is a geometry of the karst and its large-scale properties (permeability and porosity). A particularly valuable feature is the integration of dynamic data into the modeling process, which enables a dynamic calibration of the reservoir model on the near-wellbore region and thereby a valuable reduction in uncertainty. gOdiagTM, a sequel to gOkarstTM spawned by in-house R&D in 2008, expands the model to include other important diagenetic phenomena related to fluid transport, notably dolomitization. The first application of this new module is a simulation of the late dolomitization of the North Field.
fraCTure neTworks: a Challenge overCoMe It is estimated that 80% of all carbonate reservoirs are fractured. This heterogeneity, which must be taken into account in addition to the others (sediment diversity, diagenetic sequences), results in the small-scale juxtaposition of two media (matrix and fractures) that exhibit highly different properties.Clearly, the ability to model fractured reservoirs has major implications for characterizing carbonates and predicting their dynamic behavior. A technological step-change was needed to make headway towards this goal. That challenge has been met with the development of gOfrakTM. Like gOkarstTM and gOdiagTM, this tool was developed as a module of the gOcadTM geomodeler, creating links between the various interpretation tools of the geosciences chain – tangible proof of the close integration of all geosciences disciplines to improve the characterization of carbonate reservoirs. gOfrakTM is implemented as part of a workflow parallel to the sedimentological and geological interpretation workflow. Its aim is to integrate all fracture-related data provided by numerous indicators (well imaging, cores, well logs, well tests, etc.), from the well to the reservoir scale, using geological, geophysical or geomechanical drivers. The result is a 3D distribution showing the fracture network density, with its dispersion and the calculation of local flows (effective permeability field). This is used to predict the dynamic impact of the fracture network at the reservoir scale.
A 3D view of a faulted/fractured reservoir. Fracture modeling using the gOfrak™ tool.
Modeling karstic channels with gOkarst™.
From the laboratory to the operating entities Developed by the Group from 2002, gOfrakTM has already been applied on Tempa Rossa (Italy), Pecorade (France), Al Jurf (Libya), Umm Shaif and ABK (United Arab Emirates), and is in the industrialization phase at Total. It will be deployed in the operating entities beginning in 2010.
Artists’s rendition of the future production facilities on the Tempa Rossa field, Italy.
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The task of evaluating the volume and predicting the flow of reservoir fluids is much more arduous in the heterogeneity of carbonate reservoirs than in clastic reservoirs. Reducing uncertainties — by definition numerous in these objects — requires more measurement data coupled with close collaboration between petrophysicists, geologists and experts in geophysical dynamics.
In carbonate reservoirs, the widely variable properties of the pore network (pore geometry, pore size and throat size) and its rapid spatial variations explain the huge complexity of evaluating the nature, volume and flow of the fluids.
inTerpreTing well daTaThe petrophysicist’s first task is to use well data to interpret the fluids and their volume. For carbonate formations, this fundamental step requires the use of more sophisticated tools than for clastic reservoirs because the binary sand/shale models used for clastic reservoirs will not suffice here: a greater variety of minerals must be taken into account. This multimineral analysis, which uses the Multimin platform, can lead to several equiprobable solutions. A number of different measurements are needed (such as neutron-density, gamma ray, photo electric factor, acoustic and electric measurements) to dispel ambiguities as to the quantity of each mineral phase present. Estimating the fluid saturation of the porous networks poses another problem: the laws governing the relationship between porosity and saturation in clastic formations are not applicable to carbonates. It is therefore vital to perform extensive interpretation work calibrated to data sets from cores, sediment analyses and numerous borehole acquisitions independent of resistivities (sonic, nuclear).
KNOW-HOW // aT The forefronT of TeChnology
THE DIFFICUlT TAsk OF prediCTing reserves
1. Kg/Phi distribution of petrographic rock types in a carbonate reservoir.
2. Micrite limestone from the Al Khalij field (photo made with a scanning electron microscope).
Porous network in sucrosic dolomite.
THE DIFFICUlT TAsk OF prediCTing reserves
sCaling up To The reservoir Upscaling from the well to the reservoir is the second crucial phase of the petrophysicist’s work. The challenge is to establish the distributions of porosity, permeability and saturation zones to calculate, via the geomodel and the reservoir model, the volumes of hydrocarbons in 3D. Reserve quantities are then calculated based on production simulations of the field. Here again, to ensure a reliable interpretation, multiple petrophysical measurements on cores are essential (porosity, permeability, capillary pressure, relative permeability, wettability, etc.). A further imperative is to rely on a highly detailed geological description of the cores. In some cases, this calls for resolution on the scale of a scanning electron microscope. Clearly, the interaction between petrophysicists and geologists is crucial for ensuring optimal coherence between the distribution of the field’s petrophysical behavior in 3D, and that of the geologic facies
siMulaTing fluid flowsThe challenge of modeling pore network complexities is compounded by the intricacies of flow simulation. Carbonates feature a diversity of facies, but their tendency to dissolve and crack makes fluid movements all the more difficult to understand. Achieving reliable predictions of reservoir behavior to determine the appropriate production scenarios demands an in-depth evaluation of these heterogeneities, the corresponding dynamic anisotropies and the rock-fluids interactions at various scales (matrix, fracture). Only models integrating the characteristics of this medium and its complex phenomena can achieve this. Simulating enhanced oil recovery (EOR) processes is especially difficult: such processes involve exchanges on multiple scales and in thermal, compositional and chemical multiphasic domains. Modeling them also requires non-standard matrix-fractures transfer equations.
Interpretation of a well test on a fractured matrix block.
Gravity fill in a block with diffuse fractures.
Hydrogen sulfide (H2S) is present in all petroleum basins and is especially prevalent in carbonate reservoirs, which often contain dissolved sulfates, the “raw material” of H2S. Characterizing this hazardous compound, which diminishes the value of natural gas even at low concentrations, is crucial for an accurate assessment of the H2S risk at the regional scale (exploration) and for appraising and developing hydrocarbon resources. At the field scale, characterization aims to identify the source of the H2S, evaluate its concentration, its distribution within the reservoir and its evolution during production.
At its laboratory dedicated to H2S, Total is equipped with the characterization tools needed (e.g., isotopic analysis, gas-phase chromatography, liquid chromatography, mass spectrometry) to determine the origin of the gas. The Group has also developed in-house capabilities to model gas souring reactions and the main mechanisms that result in their heterogeneous distribution in the reservoirs. It is noteworthy that the H2S concentrations in a given reservoir are more variable than the concentrations of any of the other compounds present. Improving the reliability
of predicting H2S concentrations and heterogeneity is a key area of research and one for which Total is participating in several partnerships. These include collaborative studies with the geological research institute Cregu (Centre de recherches sur la géologie des matières premières minérales et énergétiques), the University of Strasbourg, the IFP (French petroleum institute), Caltech (California Institute of Technology) and UCLA (University of California Los Angeles); and with École des mines in Paris on the mechanisms that lead to H2S heterogeneity.
Souring gas reservoirs
HScube and LIPS, “home-grown” innovations • HScube: This apparatus samples H2S as cadmium sulfide, a stable and non-hazardous solid form that vastly simplifies the transport of the sample from the field to the laboratory, where isotopic analyses can be easily performed. These analyses are vital to determining the origin of the H2S. • LIPS (Laser Induced Pyrolysis System): This high-power laser recently patented by Total can volatilize all organic compounds in cores (such as tarmats [bitumens], source rocks, heavy oils) Tar compounds are sometimes found in carbonate reservoirs, often associated with H2S, where they form permeability barriers.
The sulfur terminal at the port of Bayonne-Blancpignon, France, works closely with Total.
Middle East
Angola
Philippines
Indonesia
Libya
North Sea
Bangladesh
Thailand
Canada(Alberta)
France(Aquitaine)
China(Tarim)
China(Sichuan)
Kazakhstan(North Caspian)
Germany(Weser Ems)
Russia(Ural-Volga)
Congo(Offshore)
USA(Wyoming, Texas,
Mississippi)
30%
98%
16%
2%
10% 25%
6%
4%
30%
1%
1% 10%
4%6%
1%
1%40%
H2S > 10%
H2S 5-10%
H2S 1-5%Origin and distribution of H2S in petroleum basins
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Total dedicates its determined strategy of continuous innovation to improving the productivity of carbonate reservoirs by leveraging three technological parameters: well architecture, drilling and stimulation.
The same heterogeneity that makes carbonate reservoirs so difficult to characterize creates innumerable production hurdles. Drilling in these formations can present technological challenges of the highest order.
high-TeCh well sTeering for MulTilaTeral wells Multilateral technology, which Total was the first to implement in Abu Dhabi, was inspired by the very nature of one of the reservoirs of the ABK field (Upper Arab), a veritable “layer cake” with a stack of impermeable beds sealing off thin (2 - 5 meters) dolomitic intervals with widely varying permeabilities (from a few millidarcy to 100 mD). Developing the least permeable layers called for a horizontal well architecture. But a single drain would not be able to produce enough oil. The solution defined was to “stack” several laterals on top of one another in the various producing intervals, all branching out from a single “parent” borehole. To optimize production, it had to be possible to produce each lateral independently of the others. However, this option meant complex trajectories to ensure that the targets in the thin productive layers would be reached. The technology implemented to achieve this feat was the SismageTM geosteering module, the real-time well steering tool developed in-house by Total.
dealing wiTh fraCTures while drilling The fracture networks typical of carbonates pose unique challenges to drilling. More extensive and more frequent than in clastic reservoirs and difficult to detect by seismic imaging, these fractures bring sharply into focus the issue of controlling losses during drilling. In sandstone reservoirs, solids added to drilling mud (LCM–conventional Lost Circulation Material) can block fluid losses by sealing fractures as drilling progresses. This technique is usually ineffective in carbonate formations because the size of the materials, constrained by the bottomhole assemblies (MWD/LWD tools, etc.), is too small for the fractures encountered in carbonate formations. One possible alternative is to employ thixotropic compounds which, like cement, are liquid when agitated but solidify in the static state. Polymers, cements, foams or resins mixed with drilling mud and pumped into the fracture zone can avoid losses and allow drilling to continue, provided the mixture sets quickly enough after penetrating the crack. This condition cannot always be met, however, particularly if the fracture is very wide (log images revealed a record fracture more than 12.5 cm wide in Libya) or if it is connected to a larger fracture network through which
KNOW-HOW // aT The forefronT of TeChnology
opTiMizing PrODUCTIOn
Halul Island on the Al Khalij field, Qatar.
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the thixotropic mixture continues to flow. No robust or universal solution has been found to date. Through a number of joint Industry Projects (jIPs) and trials of new compounds, Total is pursuing its research in this area. Another alternative is currently being tested, this time based on mechanical principles. Developed by Enventure (United States), it involves sealing off the crack using an expandable casing with an elastomeric joint that “bonds” to the formation. The hole is enlarged in the casing zone to accommodate the expansion of the joint with no loss of hole diameter, to allow the pursuit of drilling.
effiCienT well sTiMulaTion Stimulation by acid pumping is the method most commonly used to remedy low matrix permeability in carbonate reservoirs, and Total implements a wide range of techniques. Extended-reach wells, one of the most critical configurations, raise the issue of homogeneous distribution of the treatment over distances of several thousand meters. For cased holes, solutions include mechanical diversion using ball sealers, or swell packers to partition the drain for a more targeted treatment applied in successive zones. Chemical alternatives also feature in the portfolio of solutions mastered by the Group. Two of these are Self-Diverting Acids (SDA), which combine acids and polymers, and the more recent Visco-Elastic Surfactants (VES), in which surface-active agents ensure an even distribution of the acidization treatment. The Al Khalij field and its extended-reach wells in Qatar offer a perfect illustration of how mechanical stimulation can be optimized. Initially, diversion by ball sealers was implemented on a massive scale, until the detection of a large fracture network during production prompted
Three drains (433 m - 771 m - 1,058 m) in tight layers.
KNOW-HOW // aT The forefronT of TeChnology
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a switch to straddle packers, which allow more precise placement of the treatment. The aim was to avoid treating faulted zones in which acidization using sealers had encountered the aquifer. However, although this option did avoid the preferential paths of water influx, it was only a partial solution to the problem due to difficulties with the cementation of the casing. The latter operation is always highly complex for long drains because casing is not always adequately isolated from the formation. To remedy this problem, Total launched a completion pilot to test stimulation using swell packers: an uncemented casing alternating preperforated and non-perforated zones is descended into the hole. The non-perforated sections prevent contact with water-saturated or faulted zones. They are isolated from perforated zones by the swell packers installed downhole ahead of the casing. Made of elastomer, these swell upon contact with an oil- or water-based fluid, inflating to the volume needed to effectively isolate the hole from the casing. The crucial advantage of this technique is to permit optimal placement and control of the stimulation treatment.
Chemical diversion • SDA (Self-Diverting Acids): The polymers added to the acid solution become cross-linked when the solution pH rises upon contact with the rock. The cross-linking results in a kind of “net” structure as the polymers viscosify the fluid. As it becomes more and more difficult for the more viscous fluid to penetrate the rock, it pursues its path along the drain. • VES (Visco-Elastic Surfactant): A surfactant is used in place of the polymers. Here again, the diversion is achieved by increasing the viscosity of the fluid, but viscosification is the result of the agglomeration of micelles due to the hydrophilic nature of the surfactant.
Reservoirs and horizontal wells on the Al Khalij field, Qatar.
Swell completion (swell packer).
The complex dynamics of carbonate reservoirs make nearly each one a special case. it will take significant r&d investments to achieve more complete mastery of this extremely complex field. at Total, a dedicated project team has been set up for the purpose. Tomorrow, geophysicists will have to work more closely with geologists and play a more direct role in the chain of expertise involved in characterizing carbonate reservoirs. looking farther ahead, the quest to optimize production will benefit from anticipated progress in the range of stimulation and water control technologies available.
A seismic survey in the Middle East.
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The multi-scale heterogeneity of carbonate reservoirs often combines with their geologic environments to obscure their seismic signature. A number of studies are under way to push back the limits of geophysics to improve the mastery of these complex objects.
The many obstacles to the quality of seismic images — and therefore to the seismic characterization of carbonate reservoirs — fall into two broad categories. One encompasses difficulties relating to the geological environment of the reservoirs, especially in the Middle East. The other stems from the heterogeneity of the sedimentary bodies, which is very difficult to characterize through seismic imaging.
froM The surfaCe…Sedimentary layers found near the surface and above the reservoirs, such as the anhydrite levels in the Middle East, generate numerous multiples* in addition to the primary reflections* of the seismic wave from the deeper geological layers. Compounding the complexity of these data is the very nature of the reservoirs, which also generate their own multiples. The challenge lies therefore in attenuating the multiples to retain only the primary reflection data. Effective solutions, such as SRME (Surface Related Multiples Elimination), have already been developed to eliminate free-surface multiples. This and other techniques have emerged from research programs and are now widely deployed, notably for offshore seismic. In contrast, techniques designed to attenuate internal multiples* have fallen short of expectations to date. Conventional multiple-elimination methods such as 1D predictive deconvolution have reached their limits. Research under way at Total aims to overcome these limitations through the development of multi-dimensional deconvolution algorithms. Other techniques like IMA (Internal Multiple Attentuation) are also being developed. These involve building a multiple model then applying a subtraction step. They require a precise characterization of the multiple-generating objects in the field; geophysical measurements in the wellbore (acoustic well logging, well seismic, etc.) could provide this characterization. Statics* constitute another obstacle to satisfactory imaging of carbonates and are therefore the focus of active research. Statics are the result of lateral variability in the near-surface layers of the subsurface, as a result of the presence of sand dunes, hard Sabkha plains, buried wadis, etc. Of variable thickness and therefore having a correspondingly variable impact on seismic data according to the position of the source and the receiver, statics degrade the image quality of the target reflectors.
TOMORROW // new Challenges ahead
overCoMing ObsTAClEs TO sEIsMIC CHArACTErIzATIOn
The tools developed by Total for analyzing and correcting residual velocity anisotropy deliver a structural image of far superior quality to conventional imaging tools.
1. Image without azimuth correction.
2. With constant correction in all six azimuth sectors.
3. Correction varying with azimuth.
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… To The deepesT reCesses of The reservoirThe main thrust of Total’s research in the field of seismic characterization of carbonate reservoirs is to identify fractured zones and heterogeneities. Fractured media lead to anisotropy* in seismic wave propagation, which translates to an azimuthal variation in wave propagation velocity and amplitude.Conventional processing does not take advantage of azimuthal velocity and amplitude anisotropy, because it stacks all the different azimuths* together. In partnership with CGGVeritas, Total has developed a range of processing tools that preserve azimuthal data during the processing sequence. For example, COV (Common Offset* Vector) migration* migrates the different offset and azimuth classes separately and is used to preserve the wavespeed and amplitude anisotropy data contained in a 3D wide-azimuth acquisition. This allows subsequent analysis of the variations in wavespeed and amplitude versus azimuth, for each reflector. The variations may be related to fracturation, although there are other possible causes of azimuth variation. These include artifacts inherent in processing and those that can be attributed to geology, and are the focus of additional research studies. To achieve the characterization of structural heterogeneities in carbonate reservoirs, a second research project aims to image reservoir heterogeneities (such as fractures and karsts) by analyzing the seismic diffractions* they cause. Diffraction imaging tools are currently being tested on synthetic datasets generated by numerical models of fractured media in order to identify the seismic clues to their presence. To generate these synthetic datasets, special seismic modeling tools were developed to allow explicit integration of the extreme heterogeneity of the media.
*See glossary.
TOMORROW // new Challenges ahead
The map with the colored background shows the magnitude of azimuthal variations observed on the reflected amplitude (red=high); the superimposed black ticks give the orientation of anomalies.
• Anisotropic: describes a material in which a physical property varies in value with the direction in or along which the measurement is made.• Azimuth: the angle between true north and the axis between the source and the receiver • Diffraction: generation of a seismic wave created by a localized
anomaly in the subsurface.• Internal multiple: the wave is not propagated directly between the source and the target or between the target and the receivers.• Migration: the phase in seismic processing during which the image of the subsurface is built.
• Offset : the distance between the source and the receiver. • Primary reflection: a wave propagated directly from the source, reflected by the target, and recorded by the sensors.• Static corrections: time corrections required to compensate for near-surface anomalies.
Glossary
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Conceptual models are the basis for understanding carbonate reservoirs. They are continually refined by numerous field and analogue studies aimed at determining the mechanisms involved in the formation and transformation of the reservoirs of Total’s exploration and production portfolio.
R&D relating to carbonate sedimentology revolves mainly around characterizing their heterogeneities. All research projects are based on the study of analogue reservoirs, which must be as numerous as they are diverse in order to reflect the extreme variety of geological configurations found in Total’s portfolio of Exploration & Production assets. Characterizing the heterogeneities of carbonate reservoirs means seeking to understand each one individually but also deciphering their potential interactions, with the ultimate aim of transforming the fragmentary core data into a reservoir model that minimizes uncertainty. Building conceptual sedimentological models based on the study of analogues is a fundamental phase of the work, for it is this that will permit an analysis of the 3D geometry of structures, and shed light on the phenomena that governed their organization.
five areas of inTeresTThe vast scope of this research is subdivided into several topics: • Microporosity: the porosity of many reservoirs is of nanometric magnitude. What processes are involved in the genesis and conservation of this microporosity? • Dolomitization: this re-arrangement of reservoir mineralogy is associated with a variety of diagenetic phenomena. Focus areas include dolomites related to faults and hydrothermalism typical of Khuff reservoirs.• Karstification: the goal is to comprehend the many mechanisms involved in karst formation and determine their impact on their geometry or their characterization. For example, superficial stratiform karsts are related to erosion over an entire sedimentary horizon, while vertical karsts are generally related to a fracture network. How do the rock properties change during the evolution of the karsts and with their distance from the fractures? • Lacustrine reservoirs and marine reservoirs of microbial origin: it is essential to arrive at a more in-depth understanding of this type of reservoir, found on both sides of the South Atlantic margin (Angola, Congo, Brazil, etc.). • Analogues of the main reservoirs of the Middle East: more studies of outcrop analogues are needed both in modern and in old formations (mainly of the Cretaceous and the jurassic).
TOMORROW // new Challenges ahead
enriChing COnCEPTUAl GEOlOGICAl MODEls
The Al Dakhirah lagoon in Qatar and its conceptual model.
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30 TOMORROW // new Challenges ahead
IMPrOvInG wEll perforManCe
1. The end of a core sample after acidizing.
2. Tubing equipped with packers for hydraulic fracturing.
There are several strategies for optimizing recovery from carbonate reservoirs, including: extending the available range of stimulation treatments, optimizing their placement along the drain and developing innovative solutions for controlling unwanted water influx.
The R&D initiatives dedicated to improving the effectiveness of well stimulation target two main goals: extending the range of possible treatments to match the variety of well architectures and productivity goals of each target reservoir, and determining the best position for these treatments as a key to optimal effectiveness. Carbonate reservoirs – particularly those of the Middle East – do not always require large-scale stimulation or extensive dissolution of the reservoir. However, the rapid reaction of hydrochloric acid on carbonates leads to rapid acid spending (or consumption), and the higher the reservoir temperature, the faster the reaction. This problem can even jeopardize treatment homogeneity by generating a “thief” zone that “steals” all of the stimulation fluid.
Tailor-Made sTiMulaTion One current research project is studying less aggressive, so-called “soft” acid formulas (namely organic acids with slow reaction kinetics), and self-generating acids. The latter family consists of formate or acetate esters which, mediated by temperature, generate a formic acid whose reaction kinetics are controlled by a retardant additive.Another focus of research is stimulation with chemical diversion in open-hole completions. In the absence of casing, chemical diversion cannot be controlled by a perforated liner that determines the number and position of entry points for the treatment along the length of the well-bore. Open-hole completions also provide a much larger contact surface. The idea behind this technique is to implement a “self-diverting” stimulation product. Pumped from the surface, it develops its diverting property as it advances through the drain, ensuring even zonal coverage of the treatment.
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31A further possible addition to the array of stimulation solutions is a carbonate version of hydraulic fracturing, which has been proven effective, especially in tight reservoirs. This “staged” fracturing process is achieved using a tubing equipped with packers that ensure zonal isolation of the drain. Each zone can be selectively isolated and selectively placed in communication with the drain via a system controlled from the surface. This allows an individualized treatment of each zone. Finally, the placement of the treatment determines how successful it will be. However, in most cases, the placement is determined is based on surface parameters (pressure, flow rate), which provide only a limited representation of the downhole conditions. To offset this weakness, Total is working on a fiber optic monitoring technique that will allow a real-time visualization of the injection flow rate and distribution throughout the well. The result will be optimized control of placement, as well as a valuable resource for validating the techniques and products implemented.
“inTelligenT” isolaTion froM waTer influx Isolation from water influx is conventionally achieved using polymer-based chemical treatments. One of the critical aspects of this method is ensuring accurate placement of the compounds, given that it is very difficult to locate the exact point of influx into the drain. This issue has prompted Total to evaluate mechanical options that are based on “intelligent,” self-regulating systems actuated only in zones where water influx is detected: in this case, there is no need to locate the exact point where water enters the drain.
The fuTure: eor applied To CarBonaTe reservoirs • Miscible gas injections The characteristics of CO2 (i.e., low miscibility pressure, viscosity of a gas and density of a liquid in reservoir conditions) make it conducive for use in hydrocarbon recovery as an advantageous alternative to hydrocarbon gas injections. Through its experience producing the Lacq acid gas field in southwest France (30% CO2, 16% H2S), Total has acquired solid know-how in the area of CO2 separation, capture and treatment. As the CO2 miscibility in oil being rarely instantaneous, the mobility will be controlled by WAG (Water-Alternating-Gas) injections. • Chemical EOR is in its infancy for carbonate fields. The temperature, salinity of formation water, reservoir permeability characteristics and geological complexity make for especially exciting research and development focusing on chemical injections to enhance oil recovery factors. Research is targeting two main areas of application.– Carbonate fields for which waterflooding results in improved recovery by pressure maintenance and the action of the water sweep. The water plus polymers and surfactants sweeping is particularly well adapted to the matrix predominant texture of carbonate rocks. Total’s physical chemistry experts are working on developing effective and economically viable formulas.– Fractured carbonate reservoirs generally present low matrix porosities and are often mostly oil-wet. It would be illusory to expect effective sweeping of such surfaces. By altering the wettability characteristics, minimizing surface tension and reducing capillary pressure, the oil trapped in the pores can be released. These avenues of research are being actively investigated by teams at Total in cooperation with specialized academic research teams.
1. Laboratory testing of acid injections into carbonates at Total’s scientific and technical center (CSTjF).
2. Core sample holder.
E&P Communications – Design-production: – Photo credits: AGIP/KCO, Castano, M. Dufour, DR Total, N. Galkin/Total, P. Marie/Total, L. Pascal, C. Rives/Merimages, M. Roussel/Total, Total Abu Al Bukhoosh – Infographics and map design: Idé – © Total – Novembre 2009.
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