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Probably the greatest event in the exploration history of the American petroleum industry was the discovery of oil at Spindletop, near Beaumont. Texas, on January 10, 1901. That historical find revolutionized industry and spawned the industrial development that the world enjoys today. It also focused the petroleum industry’s exploratory efforts on the search for other domes and anticlines. This search sustained the growth of our profession of petroleum geologists. The second great event that had significant implications for our profession and the industry we serve was the discovery of the East Texas field on October 5, 1930. On that day the discovery well (“Dad" Joiner’s Daisy Bradford 3), located in Rusk County, was completed as a 300 bbl/day producer. The East Texas field has two outstanding features: Its tremendous size and the simplicity of its geologic trap. It has produced 5,311,152,697 bbls through the year 2001, and probably will produce many more millions of barrels. Figure 1 shows that the trap is stratigraphic and occurs where the eroded edge of the Woodbine sand crosses regional nosing on the west flank of the Sabine uplift and is truncated between the overlapping Austin Chalk and the Wichita limestone below.
Front Matter
Abstract As part of the 1991 Annual Meeting of the AAP G in Denver, Colorado, two sessions titled “Giant Oil and Gas Fields of the Decade 1990-2000” were held. These sessions represented the fourth of a four-decade series, each commemorating important giant discoveries and resulting in the publication of AAP G Memoirs, rich in their geologic detail: • Oklahoma City, Oklahoma, 1968, Memoir 14 ( Halbouty, 1970 ) • Houston, Texas, 1979, Memoir 30 ( Halbouty, 1980 ) • Stavanger, Norway, 1990, Memoir 54 ( Halbouty, 1992 ) • Denver, Colorado, 2001, this Memoir Presentations made in Denver represented case histories of giant fields in 14countries ( Figure 1 ): Colombia, Australia, Kazakhstan, China, Brazil, Algeria, Russia, Indonesia, Mexico, Nigeria, Pakistan, the United States, Angola, and Yemen.
Abstract The world’s 877 giant oil and gas fields are those with 500 million bbl of ultimately recoverable oil or gas equivalent. Remarkably, almost all of these 877 giant fields, which by some estimates account for 67% of the world’s petroleum reserves, cluster in 27 regions, or about 30%, of the earth’s land surface. In this paper, we present maps showing the location of all 877 giants located on tectonic and sedimentary basin maps of these 27 key regions. We classify the tectonic setting of the giants in these regions using six simplified classes of the tectonic setting for basins in these regions: (1) continental passive margins fronting major ocean basins (304 giants); (2) continental rifts and overlying sag or “steer’s head” basins (271 giants); (3) collisional margins produced by terminal collision between two continents (173 giants); (4) collisional margins produced by continental collision related to terrane accretion, arc collision, and/or shallow subduction (71 giants); (5) strike-slip margins (50 giants); (6) subduction margins not affected by major arc or continental collisions (8 giants). For giant fields with multiphase histories, we attempt the difficult task of discriminating the single tectonic event/setting we consider to have the most profound effect on hydrocarbon formation, migration, and trapping. Our main classification criterion is the basin style dominating at the most typical stratigraphic and structural level of giant accumulations. Continental passive margins fronting major ocean basins form the dominant tectonic setting, which includes 3 5% of the world’s giant fields. Continental rifts and overlying sag basins, especially failed rifts at the edges or interiors of continents, form the second most common tectonic setting, which includes 3 1 % of the world’s giant fields. T erminal collision belts between two continents and associated foreland basins form the third setting, with 20% of the world’s giant fields. Other setting classes — including foreland basins at collision margins related to terrane accretion, arc collision, and/or shallow subduction; basins in strike-slip margins; and basins in subduction margins — are relatively insignificant; with 14% or less of the total basin population. Our tabulation indicates the importance of extensional settings formed during the early and late stages of oceanic opening for giant accumulations: The rift and passive categories combined account for two-thirds, or 66%, of all 877 giants. Our result differs significantly from previously published giant classifications in which collisional settings form the dominant tectonic setting for oil giants. We propose the following possibilities to explain the dominance of extensional rift and passive margin settings over all other tectonic settings: (1) localization of high-quality source rocks in lacustrine and restricted marine settings during the early rift stage; (2) effectiveness of the sag or passive margin section above rifts to either act as reservoirs for hydrocarbons generated in the rift section and/or to seal hydrocarbons generated in the underlying rift section; (3) tectonic stability following early rifting that allows hydrocarbon sources and reservoirs to remain undisturbed by subsequent tectonic events acting on distant plate boundaries. Trends in the discovery of giants in the period from 1990 to 2000 that we consider likely to continue into the 21st century include (1) the discovery of fields in deep-water basinal settings along passive margins such as Brazil, west Africa, and the Gulf of Mexico associated with nodes of high-quality source-rock areas and stratigraphic traps located using three-dimensional seismic reflection data, (2) continued discoveries of giants in known areas, including expansion of the Persian Gulf hydrocarbon province to the south into Yemen and the Arabian Peninsula and north into Iraq; expansion of the West Siberian Basin in the Arctic offshore area; radial expansion of the Illizi Basin of Algeria, (3) continued discoveries in Southeast Asia, where Cenozoic rift, passive margin, and strike-slip environments all coexist around the South China Sea or in the largely submerged Sunda continent, (4) along-strike expansion of elongate foreland trends in the Rocky Mountains, northern South America, the southern Andes, the Ural-Timan-Pechora and Barents Sea, and the North Slope, and (5) expansion of discoveries in the Black Sea-Caspian region associated with closure and burial of northern Tethyal passive margin or arc-related basins. Despite the association of giant fields with Cenozoic or Mesozoic plate edges (especially failed rifts trending at high angles to continental margins), the possibility always exists for further discovery of “lockbox-type” giants associated with now cratonic interior, but previous Paleozoic or Precambrian plate edges, as exemplified by known Paleozoic and Precambrian hydrocarbon giant clusters in the Permian Basin in the United States, the Illizi Basin of Algeria, and the Siberian Platform.
Reserve Growth of the World's Giant Oil Fields
Abstract Analysis of estimated total recoverable oil volume (field size) of 186 well-known giant oil fields of the world (>0.5 billion bbl of oil, discovered prior to 1981), exclusive of the United States and Canada, demonstrates general increases in field sizes through time. Field sizes were analyzed as a group and within subgroups of the Organization of Petroleum Exporting Countries (OPEC) and non-OPEC countries. From 1981 through 1996, the estimated volume of oil in the 186 fields for which adequate data were available increased from 617 billion to 777 billion bbl of oil (26%). Processes other than new field discoveries added an estimated 160 billion bbl of oil to known reserves in this subset of the world's oil fields. Although methods for estimating field sizes vary among countries, estimated sizes of the giant oil fields of the world increased, probably for many of the same reasons that estimated sizes of oil fields in the United States increased over the same time period. Estimated volumes in OPE C fields increased from a total of 550 billion to 668 billion bbl of oil and volumes in non-OPEC fields increased from 67 billion to 109 billion bbl of oil. In terms of percent change, non-OPEC field sizes increased more than OPE C field sizes (63% versus 22%). The changes in estimated total recoverable oil volumes that occurred within three 5-year increments between 1981 and 1996 were all positive. Between 1981 and 1986, the increase in estimated total recoverable oil volume within the 186 giant oil fields was 11 billion bbl of oil; between 1986 and 1991, the increase was 120 billion bbl of oil; and between 1991 and 1996, the increase was 29 billion bbl of oil. Fields in both OPEC and non-OPEC countries followed trends of substantial reserve growth.
Abstract The Barracuda and Roncador giant oil fields, located in the Campos Basin, southeastern Brazil, represent two of the most important worldwide discoveries in the last decade, containing estimated reserves of almost 4 billion BOE accumulated in siliciclastic turbidites. Both fields are located in deep and ultradeep waters, with water depth extending from 600 to 2100 m. The Barracuda field was discovered in April 1989 by the 4-RJS-381 well in a water depth of 980 m. It covers an area of about 157 km 2 , in water depths ranging between 600 and 1200 m. It produces from Tertiary turbidite reservoirs. Seismic attribute analysis discriminates oil-saturated Paleocene, Eocene, and Oligocene sandstones encased in shale and marls, mainly in stratigraphic traps. This giant oil field contains in-place volumes of 2.7 billion bbl, and the total reserves achieved 659 million bbl (for Oligocene reservoirs) and 580 million bbl (for Eocene reservoirs). The Barracuda field is under development along with the Caratinga field because of their geographic proximity. The development strategy foresees an ongoing pilot system (concluded in October 2002) and a definitive one (being implemented). The pilot system started production in 1997 through a floating production, storage, and offloading (FPSO)-type stationary production unit. Production by means of the definitive system is expected to start in the second semester of 2004 and comprises 20 production and 14 injection wells. The loading, processing, and offloading of the oil and gas from the field will be through an FPSO unit with processing capacity of 150,000 BOPD and 4.8 million m 3 /day of gas. The peak production is expected in 2006. The Roncador field, discovered in October 1996 by the 1-RJS-436A wildcat, is in water depths ranging from 1500 to 2100 m. This giant field contains large volumes of hydrocarbons (9.2 billion bbl of oil in place and total reserves of 2.6 billion BOE) accumulated in Upper Cretaceous (Maastrichtian) turbidite reservoirs. The discovery well found total net pay of 153 m of Maastrichtian reservoirs divided into five main zones, separated by interbedded shales. Only the uppermost reservoir zone shows a seismic amplitude anomaly that can be detected on seismic profiles. The other four reservoirs do not show acoustic impedance contrasts with the interbedded shales, and thus they have no amplitude anomalies. During the appraisal activities, different types of oil (18 - 31.5 ° API) and a high reservoir complexity were verified. The external geometry is defined to the north and east by dipping and to the south and west directions by pinch-out. The trap is a combined structural and stratigraphic trap. The field is cut by some major faults to form three main blocks: an upthrown southwestern block, an upthrown northern block, and a downthrown southeastern block. Because of the size of the field and large volumes of hydrocarbon production, development of the Roncador field is envisaged to occur in four modules. Production peak will reach 500,000 BOP D in 2011. Production module I is being implemented to produce oil from the northern and eastern blocks, including 21 subsea production and 7 subsea water injection wells. Module II will develop the western block [heavy oil); two production units are planned (one deep-draft caisson vessel [SPAR] and one floating production, storage, and offloading [FPSO] unit). Peak production is expected to reach 180,000 BOP D from 31 wells in 2 yr.
The Cusiana Field, Llanos Foothills, Colombia: Lessons Learned from the Rapid Development of a Giant Oil Field
Abstract The Cusiana field, a giant oil field in the Llanos foothills of Colombia, comprises three sandstone reservoirs: Eocene Mirador, Paleocene Barco, and Cretaceous Guadalupe. Al l contain light, compositionally variable oil with associated gas. Discovered in 1992, the Cusiana field was sanctioned for fast-track development in 1993 and, despite the security problems of the country, was successfully brought onto production in 1995, when the 1.2-bcfd gas reinjection facility started up. Peak production of 310 million BOPD was achieved in 1998. Later, 400 million bbl of production, 72 wells, and a 3-D seismic survey have yielded surprises, experience, and learning relevant to complex development projects elsewhere. Initially, poor reservoir communication and early water and gas breakthrough into producers were considered serious risks. Detailed sedimentologic descriptions were made, and a long-term test, coupled with aggressive static and dynamic pressure monitoring, was initiated. Since described by Cazier et al. (1995) , production experience has shown that a simpler reservoir description resulting from the integration of high-resolution biostratigraphy, sedimentology, geochemistry, and fracture studies with pressure and tracer data has been more successful in describing fluid movement than the earlier sedimentologic-based descriptions and has greatly simplified the task of modeling the dynamic reservoir behavior. The structural complexity revealed by well and 3-D seismic data is greater than original interpretations, resulting in a better quality, original oil-in-place estimate associated with a complex frontal imbricate and multiple oil-water contacts. Among the lessons learned to date is that long-term testing is very useful for demonstrating fieldwide connectivity, but it can lead to difficulty in unequivocal identification of original oil-water contacts. The greatest development challenges are not necessarily those originally predicted during the appraisal phase, so a balanced technical program is likely to be more successful than one focused at perceived, but not necessarily critical, issues.
Abstract The Cantarell field, discovered in 1976, is one of the largest oil fields in the world. It is located on the continental shelf in the southern part of the Gulf of Mexico, in the east-central part of the Campeche slope, 80 km from Ciudad del Carmen, Campeche, Mexico. This oil giant is a mature field that has produced approximately 7.861 billion bbl of oil during 22 years of exploitation. It is made up of four blocks: Akal, Nohoch, Chac, and Kutz. The most important one is Akal, which contains more than 90% of the oil reserves. A total of 223 wells produces both heavy oil and gas from Upper Cretaceous carbonate breccia, using primary and secondary recovery methods. The possibility of the existence of a prospective hydrocarbon trap located below the Cantarell field was recognized in 1990, but because of the quality of geologic and geophysical data and the structural complexity of the area, no exploratory drilling was carried out. The final exploratory results indicate that the new discovery, Sihil, surpasses all the expectations of the thrusted block, exceeding by far the quantities of oil reserves established by previous paradigms. This discovery allows Pemex Exploration and Production [PEP] to establish a strategic plan to add even more hydrocarbon reserves using data provided by investigation of other underlying blocks.
Abstract This paper presents the reservoirs of the Jujo- Tecominoacan oil fields located in Tabasco state, southern Mexico. The structure follows the regional trend of a big tectonic feature called Reforma-Akal Horst, where most of the southern Mexican onshore as well as offshore oil fields have been discovered. Although the Jujo field was discovered on October 1980 and the Tecominoacan field was discovered 28 months later, both were considered to produce from independent reservoirs until 1990, when their static pressure gradients were thoroughly compared to start their numerical simulation. Because the reservoir was represented by a thick sequence (>1000 m) of fractured dolomite of Late Jurassic and Late Cretaceous age, the aim of the study was to improve the geologic model and characterize the fracture system to support new infill drilling, volumetrics, and numerical simulation considering a compositional porosity model. Volumetrics resulted in more than 7000 million bbl of volatile oil in place (48º API).
Abstract A set of 11 fields of light oil and condensate (30-51° API) has been discovered since 1989 in the southern part of the Gulf of Mexico, in the area known as Litoral de Tabasco. This area is in the southwestern part of the Campeche Sound, Mexico's most important petroleum province. Maximum water depth in the Litoral de Tabasco is 35 m, and the main reservoirs are Kimmeridgian dolomitized oolitic banks and Cretaceous fractured carbonates deposited in an open platform. New three-dimensional (3-D) seismic surveys have led to new interpretations and appraisal studies that have defined properly the structure of the fields. As a result, reserves have increased from 670 to 2048 MMBOE . On the other hand, new concepts have led to a new exploration strategy in which the potential of the Tertiary siliciclastic section will be evaluated. This paper outlines the original concepts, guide discoveries, and new integrated models that have defined this new strategic area in the Campeche Sound.
Successful Exploration and Development of Significant Oil Fields in the Deep-Water Gulf of Mexico
Abstract The Gulf of Mexico has been a center of deep-water exploration and development activity since the early 1980s. Shell Exploration and Production has five tension-leg platforms in the deep water with combined volumes in excess of 2 billion BOE and a daily production of more than 550 thousand BOE/day. What advances in geologic concepts, technologies, engineering, and operational capabilities have led to the successful exploration and development of Auger, Mars, Ram Powell, Ursa, and Brutus? What are the implications for the next generation of large deep-water discoveries? The presentation in Denver focused on the key strengths of regional geologic frameworks, subsurface understanding through improved seismic imaging and reservoir modeling at both the exploration and the development scales, and engineering innovation for facilities and high rate and high ultimate well design. These capabilities contribute to cost and value leadership throughout the asset life cycle. Maintaining and growing a culture which values technological excellence, creativity, and sharing of knowledge will be essential to profitable developments, as projects move into progressively deeper and more complex environments.
Coalbed Methane in the Fruitland Formation, San Juan Basin, Western United States: A Giant Unconventional Gas Play
Abstract The Fruitland Formation (Upper Cretaceous) in the San Juan Basin, although an “unconventional” source of natural gas, surpasses many conventional reservoirs in production, reserves, and original resources. Production and reserve values confirm the San Juan Basin as the world's leading producer of coalbed gas, and they establish the Fruitland fairway as a giant gas field within the basin. Original coalbed gas in place in the Fruitland Formation was approximately 50 tcf (1.4 Tm 3 ), and coalbed-gas reserves were 7.8 tcf (223 Bm 3 ) at the beginning of 1998. In 1999, the Fruitland Formation produced 1 tcf (28.6 Bm 3 ) of coalbed gas, and production reached a peak or plateau. That same year, cumulative coalbed-gas production from the basin surpassed 7 tcf (200 Bm 3 ) . The San Juan Basin can be divided into three regions with markedly different coalbed-gas occurrence, resources, and production characteristics that result from variable depositional, structural, and hydrologic settings. Depositional setting controlled Fruitland coal occurrence, thickness, and geometry. The thickest coal deposits, with net coal thickness between 50 and 70 ft (15 and 21 m), occur in the northern part of the basin in northwest-trending, coastal-plain sediments that were deposited landward of the Pictured Cliffs wave-dominated deltaic and barrier shoreline sandstones. In the southwest part of the basin, back-barrier coal deposits are present, but equally important are northeast-trending coals, with net coal thicknesses of 30-60 ft (9-18 m), which were deposited as floodplain facies between Fruitland channel-fill sandstone belts. Laramide tectonism indirectly controlled the occurrence of thick coal deposits by affecting shoreline stillstands, resulting in aggradation in the northern part of the basin, northeast of a structural hinge line. Moreover, Laramide tectonism formed the San Juan Basin, which influenced thermal maturation patterns and hydrocarbon generation and set the structural framework for the present hydrologic system. Significantly, the structural hinge line is a no-flow boundary that divides the basin into provinces or trends with notably different hydrologic regimes, coalbed-gas compositions, and production performance. Three coalbed-gas production trends and several subtrends are recognized in the San Juan Basin. In Trend 1, north of the hinge line, the Fruitland Formation is a regionally overpressured aquifer. Most coalbed wells produce significant quantities (as much as 2000 bbl/day [318 m 3 /day] of low-chloride, high-alkalinity water, and coalbed gas is chemically dry (C1/C1-C5 >0.97) and contains 3-13% CO2. The most prolific coalbedgas wells in the world are in Trend 1 A, the fairway. Typically, peak production rates of fairway wells are l-6mmcf/day (28 ;000-l 70,000 m 3 /day]. The most effective fairway completion is the open-hole cavity. In Trends IB and 1C, peak gas production rates are generally less than 300 mcf/day (8500 m 3 ), and wells perform better when completed with cased holes and fracture stimulation treatments than when completed with open-hole cavities. In Trends 2 and 3, which cover much of the rest of the basin, the Fruitland Formation is underpressured, with local exceptions. Most coalbed-gas wells in Trend 2 produce no water or small volumes of NaCl-type waters. Coalbed gas in Trend 2 is chemically variable (wet to dry; C1/C1-C5 = 0.86-0.98) and contains less than 1.5% CO2. Typically, peak gas production rates in Trend 2 are less than 300 mcf/day (8500 m 3 ), but production may be as great as 700 mcf/day (20,000 m 3 ). Most wells are completed with cased holes and fracture stimulation. Trend 3 is a little-explored part of the eastern San Juan Basin that has less Fruitland coal and is inferred, from limited testing, to be an underpressured area having low-permeability coal beds. Understanding the unique reservoir characteristics of each region or trend, including the highly productive fairway, is essential to optimize coalbed-well completions, field development, and facilities design in the San Juan Basin.
Abstract The Sunrise-Troubadour fields, containing between 10 and 16 tcf of retrograde gas condensate, are located in the Timor Sea, 450 km to the northwest of Darwin, Australia. The 80-m-thick, Middle Jurassic siliciclastic reservoir is entrapped in a fault-bounded structural closure that has 180 m of vertical relief and covers an area of 75 x 50 km. The volumetric significance of this field was identified through an intense late 1990s appraisal campaign. This paper presents the geoscientific results of this campaign and their implications for project evaluation and development planning. Reservoir quality, continuity, and connectivity are the essential subsurface determinants of the size of these accumulations. These parameters were primarily controlled by depositional environment. Overall, the reservoir succession is of moderate net to gross (approximately 30%); however, most of the gas is contained in two high net-togross sublayers. The latter main gas-bearing subintervals are interpreted to have been deposited during lowstand episodes, the lower unit being represented by an incised valley complex and the upper by attached, forced-regressive shoreface deposits. Deposition in this limited accommodation setting has resulted in lateral reservoir continuity and broad sheetlike stratigraphy. Lithologically, the reservoir comprises very fine- to coarse-grained quartzarenites and sublitharenites that are interbedded with variably brackish to open-marine shales. The whole succession displays an overall upward increase in marine influence. The main phase of faulting and trap formation occurred during the Quaternary. Detailed fault modeling indicates a low likelihood of compartmentalization in this extensive structural high. Variations in both hydrocarbon maturity and condensate yield across the field indicate nonequilibration of the recently emplaced hydrocarbons that have been derived from a mature (1.3-1.4 %Ro) Middle Jurassic marine kerogen source rock. Pressure analysis indicates a tilted gas-water contact that sits above a dynamic aquifer. Reservoir geologic data have been matched to seismic amplitude variation with offset (AVO ) effects to constrain depositional modeling via statistical inversion techniques. This has then been fully integrated with mapped and probabilistically modeled subseismic faults into dynamic reservoir simulations. The work flow involved the identification of key uncertainties and the detailed, focused evaluation of these parameters. This in turn provides confidence in reservoir volumes and behavior, despite widely spaced well data. Development planning is in progress, with commercial production planned for this decade.
Abstract Since 1952, the Niger Delta has been explored primarily for oil. At the end of 2000,a least 5200 wells had been drilled on the delta. Initial reserves from this drilling total about 66,100 MMBOE . This has resulted in 240 producing fields. Current production fro these fields amounts to more than 2 million BOPD. Exploration of the offshore deep-water areas started in 1995 and has resulted in the discovery of four giant fields and other minor discoveries. Most publications on the Niger Delta refer to the area as an oil basin, but there exists a very large gas-reserve base. Gas statistics have been included here because of the increased importance of gas to Nigeria and its recognition of this as an important source of energy for the area. Al l of the data contained in this paper includes information gathered and updated to the end of the year 2000.
Kizomba, a Deep-Water Giant Field, Block 15 Angola
Abstract During the middle to late 1980s, Exxon Exploration Company embarked on a series of global integrated regional geologic studies, culminating in the discovery of several giant oil and gas fields. Aggressive acreage-capture strategies were initiated based on these studies, with early participation in opening tender rounds in the identified high-potential basins. From a position of having no acreage in the Congo Basin, offshore Angola, ExxonMobil rapidly became the largest deep-water acreage holder in Angola. Block 15 was included in the first tranches of deep-water acreage offered by the Angolan government and was awarded to a contractor group led by ExxonMobil's subsidiary, Esso Exploration Angola (Block 15) as operator. After early two-dimensional seismic acquisition to high-grade areas of interest, 4000 km 2 of high-quality, three-dimensional seismic data was acquired for prospect mapping. Wildcat drilling during 1997-2002 resulted in 13 discoveries in water depths ranging from 500 to 1400 m. Recoverable hydrocarbons are estimated to be in excess of 3.5 billion BOE, with significant undiscovered potential remaining on the block. Oil gravities range from 24° to 35° API. Four of the discoveries (Hungo, Chocalho, Kissanje, and Dikanza) make up the giant Kizomba field complex, with recoverable hydrocarbons of more than 2.0 billion bbl. Each of the discovery wells penetrated multiple high-quality, deep-water channel sandstones with oil-water contacts controlled by a combination of structural spill, fault leak, and top seal failure because of buoyancy effects of hydrocarbon columns approaching 1000 m. Reservoirs range from 500 to 1900 m below mud line. The hydrocarbons occur in combination structural-stratigraphic traps. The large north-trending structures are a result of Oligocene-Miocene extension with associated movement of Aptian salt, culminating in middle Miocene to recent diapirism. Lateral seal is provided by stratigraphic pinch-out and onlap of reservoir facies at the margins of the large west-trending channel complexes. Top seal is formed by overlying channel abandonment facies or by prograding slope shales. Reservoirs are early to middle Miocene in age and are dominantly turbidites with associated debris flows deposited in channel complexes on the middle to lower slope. Reservoir properties are excellent. Kizomba will be ExxonMobil's first operated Angolan oil development, with production start-up expected during 2004. The development will take place in approximately 1200 m of water. The first phase, Kizomba A, will involve about half of the Kizomba reserves(approximately 1 billion BOE). The primary drive mechanism for these relatively shallow reservoirs will be waterflood with injection of associated gas early in project life. Production will be via dry trees from a tension-leg platform with associated subsea facilities for injection wells. Oil will be produced to a floating production storage and offloading (FPSO) vessel, which will offload to tankers via a nearby catenary anchor-leg mooring buoy. The second phase, Kizomba B, will be developed by a similar combination of subsea and surface wellhead platform facilities tied to a second FPSO. The successful discovery of this giant field is a result of the application of leading-edge technologies systematically integrated into regional exploration experiences and strategies. The future will involve continued emphasis on innovative development technologies to maximize production in this challenging deep offshore environment.
Abstract Karachaganak field was discovered in northwestern Kazakhstan by Uralskneftegasgeologia in 1979 and first produced by KarachaganakGazprom in 1984. The shareholder group of Ente Nazionale Idrocarburi-Agip (ENI-Agip), BG Group, Texaco (now ChevronTexaco), and Lukoil operates the field under a 40-yr production-sharing agreement that was signed with the Republic of Kazakhstan in November 1997 to optimize technical and economic recovery. The Karachaganak reservoir (13 x 25 km) is a giant retrograde gas-condensate-oil reservoir with a 1650-m hydrocarbon column and in-place hydrocarbons of 17.78 billion BOE. In the field, 252 wells have been drilled, with 163 available for production. An ongoing workover program has restored previously declining production to historic maximum levels. The current optimization plan calls for a partial depletion and enhanced gravity-drainage strategy that involves partial pressure maintenance through gas recycling and development of the oil rim using horizontal wells. Heterogeneous biohermal and platform carbonates ranging in age from Late Devonian (Famennian) to Early Permian (Artinskian) comprise the primary reservoir section. From Late Devonian to early Carboniferous, the Karachaganak massif evolved from a ramplike setting into an isolated, atoll-like carbonate platform along the northern margin of the Pre-Caspian Basin. The Carboniferous platform consists of marginal bioherm and bioherm slope facies, with a relatively small internal lagoon dominated by skeletal grain-dominated facies. Permian pinnaclelike bioherms and bioherm slope facies overlie an erosional unconformity at the top of the Carboniferous. The regional seal for the reservoir is formed by Lower Permian (Kungurian) sulfates and evaporites that immediately overlie the Artinskian carbonates. Limestone and dolomite reservoirs are generally low porosity and low permeability (6% porosity cutoff corresponds to 0.2 md permeability). Whereas dolomitization locally enhances reservoir quality, there is no apparent correlation between dolomite content and effective porosity. Initial reservoir quality is adversely affected by diagenetic processes, including early-marine calcite cementation and later anhydrite precipitation. For the three production objects, average core porosities range from 9.67% to 11 .70%, and average core permeabilities range from 9.97 to 14.54 md.
Yuzhno Khilchuyu Field, Timan-Pechora Basin, Russia
Abstract The Yuzhno Khilchuyu field, located in the Timan-Pechora Basin, has four stacked limestone and sandstone reservoirs ranging from Lower to Upper Permian. Reservoir depths range between 2150 and 1704 m subsea. The principal reservoir is a Lower Permian (Asselian-Sakmarian) limestone that has an oil-in-place estimate of 1584 million bbl (214 million t) approved in 1985 by the Russian Central Reserves Com mittee. In addition, a minor amount of oil (16 million bbl [2.2 million t]) with a gas cap is present in an overlying Lower Permian (Kungurian) sandstone. Overlying Upper Permian sandstones also contain minor amounts of free gas totaling about 27 bcf (763 million m 3 ) gas in place. Available data indicate that the Asselian-Sakmarian reservoir has high productivity in the central part of the accumulation, with somewhat lower productivity on the flanks. Development of the field will require water injection for pressure maintenance.
The Masila Fields, Republic of Yemen
Abstract Masila Block 14, located in the Hadramawt Region in the east-central Republic of Yemen, is operated by Canadian Nexen Petroleum Yemen (a subsidiary of Nexen) on behalf of its partners, Occidental Peninsula and Consolidated Contractors International. Oil was first discovered in late 1990, with commerciality declared in late 1991. Oil production began in July 1993. There are now 16 known fields containing 56 pools. At year-end 2000, total proven ultimate recoverable oil reserves are 891 million bbl. Proven, probable, and possible reserve estimates are approaching 1.2 billion bbl of recoverable oil. The Masila fields are associated with the Upper Jurassic to Lower Cretaceous Say'un-Masila rift graben basin. Almost 90% of the oil reserves discovered are in the Lower Cretaceous upper Qishn sandstones, Qishn Formation, Tawilah Group. Oil also is found in seven other reservoirs consisting of Lower Cretaceous and Middle to Upper Jurassic elastics and carbonates as well as fractured granitic basement. This chapter focuses on the main oil-producing reservoirs, which are the informally named upper Qishn sandstones of the formal Qishn Clastics Member, Qishn Formation, Tawilah Group. The upper Qishn sandstones represent a transgressive sequence from braided river deposits into tide-influenced shorelines, overlain by subtidal and shelf deposits. The upper Qishn sandstone reservoirs have high porosity (15-28%) and high permeability ( 10 d). They are relatively homogeneous and continuous in the lower half of the formation and are more heterogeneous and discontinuous in the middle to upper sections. The uppermost marine sandstones are more homogeneous because they are texturally more mature. The major field accumulations are tilted, normal-fault block structures located over basement paleohighs and dependent on cross-fault juxtaposition against overlying Qishn Carbonates Member top seal. The carbonate-dominated pre-Qishn section, including the source rock, is not present on the paleohighs and is thickest in the basement lows. The main source rock is the Jurassic (Kimmeridgian) Madbi Shale, a Type II marine source that is mature in ''kitchens" adjacent to the structural highs. Secondary oil migration occurred upward along fault planes to the overlying traps. At year-end 2000, 2087 km (1304 mi) of two-dimensional seismic and four three-dimensional (3-D) seismic programs totaling 422 km 2 (165 mi 2 ) have been acquired in the confines of the current Masila Block 14 boundary. Seismic acquisition in the Masila Block has been challenging because of the remote location, rugged topography, and rocky desert terrain. The land surface is incised by deep wadis, or canyons. Processing and interpretation problems are significant because of a low-velocity surface layer, scattered seismic energy, poor signal-to-noise ratio from numerous canyon walls, and "fault-shadow" velocity anomalies overlying many of the tilted fault-block culminations. The biggest production challenge is water handling. Much water is produced along with the oil because of a combination of medium-gravity (15°-33° API) moderate-viscosity oil, high reservoir permeability, and a strong regional aquifer. The upper Qishn oil is undersaturated in gas (average gas-oil ratio is 3-7 scf/bbl), requiring electric submersible pumps to provide sufficient artificial lift for the large volumes of produced fluid. At the end of December 2000, the annualized daily production rate collectively for all fields was 230,000 BOPD, with 725,000 BWPD and 6.8 mmcf solution gas/day. Cumulative oil production is more than 500 million bbl. Initial average well oil-production rates vary by producing zone but range from 1500 to 20,000 BOPD, with a few wells producing from more than one reservoir zone by minor zone commingling. In the early production years, oil and water produced in the fields were transported via pipeline to the central processing facility (CPF), where most fluid separation occurred. More recently, the majority of the separation of oil and water is being performed at individual fields using field-based hydrocyclones before transporting the "clean" oil to the CPF for final processing. Produced water is reinjected into the reservoirs. The clean oil is transported to the southern coast via a 140-km (85-mi)-long, 61-cm (24-in.) pipeline over a 106-km (66-mi) distance. Export oil is then loaded onto tankers via a single buoy mooring system located 3.2 km (2 mi) offshore east of the coastal village of Al Mukulla.
Abstract The Peciko field is located in the prolific Kutei Basin (Indonesia, East Kalimantan), southward of the supergiant Tunu gas field, in water depths of about 40 m. The field produces gas from upper Miocene deltaic reservoirs. The lithology comprises a repetition of superimposed deltaic cycles (average thickness of about 30-50 m). The main pay zone of the Peciko field consists of a stacking of delta-front mouth bars. Based on flooding surfaces, the upper Miocene has been subdivided into eight main intervals (MF2-3 through MF8-9) . Later additional intervals have been proposed, related to both stratigraphy and pressure data. The main kitchen involved in the sourcing of the Tunu and Peciko gas fields lies in the syncline axis to the west. The main source rocks in the area are composed of organic-rich shales (gas prone) associated with the tidal deltaic plain and delta front (no coal). Hydrocarbon generation began 3 Ma and is still active today. The first exploration well (Peciko-1), drilled on top of a deep-seated structure in 1982, tested only marginal gas pay above the structural closure. It was not until 1991 that the giant gas accumulation was actually tested. Clastic influx from the north was already surmised prior to drilling, and a stratigraphic play concept had been worked out. The northwest Peciko-1 (NWP-1) well was then drilled in early 1991 6 km north of the initial test well along the crest of the structural nose. This success followed the conclusions and recommendations of a comprehensive regional study that stressed the potential trapping role of facies variations occurring between the shelf and the shaley overpressured prodelta. The following appraisal-drilling campaign and the intensive associated pressure-measurements program (more than 2000 repeat formation tester [RFT]/modular [formation] dynamic tester [MDT ] measurements) induced a comprehensive geologic model (with stratigraphic and hydrodynamic expressions) for this complex multilayered field. It consists of a 36-layer model, vertically isolated by seals (shales resulting from fifth-order flooding events). Each layer is 40 m thick in average, and it roughly corresponds to the individual thickness of a deltaic cycle, as previously defined. Within each of these layers, the pressure regime is homogeneous because the reservoirs are connected. The gas in communication with the aquifer to the north-northwest is in hydrostatic condition. The gas within disconnected sands to the south-southeast is in overpressure condition. The lateral extent of the individual gas accumulation is not only related to the shale-out and to faults (no faults are observed in the field) but is also controlled by hydrodynamic factors related to rapid burial. A deep hydrodynamic system evolved, in which the flow of compaction waters toward the more proximal, lower pressured deltaic deposits was forced along the stratigraphy by regionally extensive shale layers. This model and methodology developed for Peciko were later evolved significantly and applied to the neighboring Tunu field. This contributed to the understanding of this supergiant field (more than 16 tcf [2P] reserves) and extended its limits, both laterally and vertically, well beyond those of the initial recognized accumulation. More than 6 tcf (2P) of reserves is estimated to be present in the Peciko field. The production (about 0.8 bcf/day) started in October 1999 using two platforms, which increased the Peciko and Tunu potential to almost 3 bcf/day. This confirms their major long-term contribution to the largest liquefaction plant in the world.
Petroleum Geology of the Peng Lai 19-3 Oil Field, Bohai Bay, People's Republic of China
Abstract The Peng Lai 19-3 (PL 19-3) Oil Field, in the south-central Bohai Bay, People's Republic of China, was discovered in May 1999 with the drilling of the PL 19-3-1 well by Phillips China, Inc., a subsidiary of ConocoPhillips. The PL 19-3-1 intersected a 425-m gross hydrocarbon interval in Miocene-Pliocene sands at a depth of approximately 1000 m. The PL 19-3-2 appraisal well, located 1.6 km south-southwest of the discovery well, intersected a gross hydrocarbon interval of 525 m in the same reservoir interval. Subsequent drilling of an additional five appraisal wells has proved that a large oil accumulation exists. The oil quality ranges from 13° to 23° API, with low pour-point temperatures and low wax content. Gas-to-oil ratios are relatively low and range from 100 to 300 scf/stbo. The oil field is on the northeast extension of a large basinal high and is interpreted as a north-south-trending wrench anticline associated with a major north-south strike-slip fault system (Tan Lu fault). En-echelon northeast-southwest-trending normal faults are intersected by north-south-trending wrench faults that divide and compartmentalize the anticline. Reservoirs are a stacked sequence (600-700 m) of unconsolidated to semiconsolidated postrift fluvial-lacustrine sands of good to excellent quality in the lower portions of the Miocene-Pliocene lower Minghuazhen Formation and the Miocene Guantao Formation. Top seal consists of intraformational mudstones in the lower Minghuazhen. Source rocks are organic-rich lacustrine mudstones in the synrift Oligocene Dongying and Eocene Shahejie Formations located in adjacent subbasins. A significant portion of the oil field is masked seismically by the presence of shallow gas which covers approximately 30% (14 km 2 , or 3460 ac) of the crestal area of the structure. A four-component, on-bottom cable seismic survey was initiated in the spring of 2000 to enhance the seismic imaging of this portion of the anticline.