Recoverable Oil Reserves Research Articles

Iran’s crude oil reserves and production

ABSTRACT The Government of Iran estimates the country’s initial-oil-in-place and condensate-in-place are about 600 and 32 billion barrels (Gb), respectively. In 2004, the official estimate of the proved remaining recoverable oil and condensate reserves was about 132.5 Gb, of which crude oil accounted for about 108 Gb. Cumulative crude oil production is expected to cross the 60 Gb mark in 2007, implying that the estimated ultimate recoverable reserves of crude oil are about 168 Gb (cumulative production plus remaining reserves) and the total recovery factor is about 28%. The main Oligocene-Miocene Asmari and Cretaceous Bangestan (Ilam and Sarvak) reservoirs contain about 43% and 25%, respectively, of the total crude oil-in-place. Recovery factors for the Asmari range between about 10–60%, and for the Bangestan between 20–30%. Between 1974 and 2004 remaining recoverable reserves have increased from about 66 to 108 Gb, while the ultimate recoverable reserves have increased from 86 to 168 Gb. In contrast to 1974 when Iran’s production peaked at 6.0 Mb/d, production in 2005 averaged about 4.1 Mb/d. The 1974 peak occurred when production from most of the giant fields was ramped-up to very high but unsustainable levels. Current plans are to increase the crude oil production rate to 4.6 Mb/d by 2009. This is a significant challenge because this production capacity has to offset a reported total annual decline rate of 300–500,000 barrels/day (Kb/d). This high decline rate is attributed to the maturity of the giant fields, many of which attained their peaks in the 1970s and have produced about half or more of their estimated ultimate recoverable reserves. Therefore to achieve the 2009 production target within the next three years, Iran has to add about 680 Kb/d of capacity per year from its developed fields (infill drilling, recompletions, enhanced and improved oil recovery), while also adding net new surface facilities and well capacity from undeveloped fields and reservoirs.

Petroleum geology of the Melut Basin and the Great Palogue Field, Sudan

This paper overviews the framework, structural and petroleum geology aspects of the Melut rift Basin in Sudan. The data base is from mainly proprietary exploration work consisting of more than 20,000 km of seismic profiles, 2000 km 2 of 3D seismic, and more than 50 exploration wells. There have been more than 15 oil and oil and gas discoveries. The Melut Basin is a Meso-Cenozoic rift basin accompanied by the formation and development of the Central African Shear Zone (CASZ) on the pre-Cambrian crystalline and metomorphic basement of lower relief. Three stages of rift development and fracturing have been identified, stronger in the Early Cretaceous and Paleogene and weaker in the Late Cretaceous. Source rocks are the Lower Cretaceous lacustrine shales, whereas reservoirs and seals are both Paleogene and Upper Cretaceous. Dominant structural styles are large-scale anticlines in the Paleogene sequences and antithetic normal fault-blocks in the Upper Cretaceous and Paleogene. Heavy to light oils (8.87–61.5° API) and gas have been discovered in the Paleogene and only light oils and gas in the Upper Cretaceous pay zones. The primary pay zone in the Melut Basin is the Paleogene. The Great Palogue Field, with ultimate recoverable oil reserves of more than 900 million barrels, was discovered in the northern Melut Basin. The gentle slopes of each subbasin are favorable areas for petroleum accumulation and enrichment. The faulted anticlines within the Paleogene syn-rift sequences are the main trap types, whereas the antithetic fault-blocks of the Upper Cretaceous sequences are secondary.

Comments: Industry Legends

Often overlooked, some of the pioneers responsible for significant advancements in this industry have been getting recognition recently. At last month's SPE Russian Oil and Gas Technical Conference and Exhibition in Moscow, the closing session was devoted to "Legends of the Russian Oil and Gas Industry." Fourteen individuals representing industry, academia, and government were recognized. Russia has made numerous contributions to upstream technology development, from the invention of the electrical submersible pump to innovative applications of subsurface imaging and fracturing techniques. Among those honored was Rern Ivanovich Viakhirev, who was Chairman of the Board of Gazprom for almost a decade and who managed the company's growth through the Yeltsin presidency and the early years of the Putin presidency. A former First Deputy Minister of the Gas Industry of the Soviet Union, Viakhirev led the company through its privatization. Also honored was Anatoly N. Dmitrievsky, Director of the Inst. for Problems in Oil and Gas at the Russian Academy of Science. He helped found the institute, the leading Russian academic organization that studies how science and technology can benefit oil and gas production and development. During the 2006 SPE Annual Technical Conference and Exhibition in San Antonio in September, tribute was paid to "Legends of Hydraulic Fracturing." Receiving the honors were Claude E. Cooke Jr., Jacques L. Elbel, C. Robert Fast, Robert R. Hannah, Larry J. Harrington, Thomas K. Perkins, Michael Prats, H.K. Van Poollen, Francis E. Dollarhide, George C. Howard, J.L. Huitt, and Ronald P. Nordgren. The one-time-only reception was conceived of by an SPE committee formed by Carl Montgomery, Engineering Fellow for ConocoPhillips, and Mike Smith, President and Cofounder of NSI Technologies. Some estimate that hydraulic fracturing has increased recoverable oil and gas reserves in North America by as much as a third. "These pioneers, in essence, raised the current generations of hydraulic fracturing engineers," Montgomery said. "Their combined expertise represents the technology from its inception. Their legacy is a thorough comprehension of what came before and what might lie ahead. Debatably, I can't think of a single technology that has had a greater impact on the bottom line of every production company." And last month, a celebration was held marking the 30th anniversary of the Peng-Robinson equation of state at the birthplace of the mathematical milestone: Edmonton, Canada. Hosted by the Schlumberger Reservoir Fluids Center, the event included technical presentations, a commemoration ceremony, and the announcement that the center would change its name to the DBR Technology Center in honor of the late Donald Baker Robinson. It was Robinson who, as a professor of chemical engineering at Edmonton's U. of Alberta, developed the formula along with then-research associate Ding-Yu Peng, now a professor at the U. of Saskatchewan. The equation, published in 1976, enables engineers to make accurate predictions about the behavior of materials in variable pressure and temperature conditions, information critical in reservoir decision making. The formula quickly became known around the world. Robinson went on to form DB Robinson and Assocs. in 1980, a firm Schlumberger bought in 2003. Among those making presentations at the anniversary event chaired by Schlumberger New Venture Project Manager Ahmed Hammami were Jeff Creek of Chevron Energy Technology Co., Alan Mather of the U. of Alberta, John Carroll of Gas Liquids Engineering Ltd. of Calgary, Sanjoy Saha of Honeywell, Peter Englezos of the U. of British Columbia, Harvey Yarranton of the U. of Calgary, and Dan Zhang, Fluid Modeling Software Manager at the DBR Technology Center. Also on hand were Peng and members of Robinson's family.

The Persian Gulf Basin: Geological history, sedimentary formations, and petroleum potential

The Persian Gulf Basin is the richest region of the World in terms of hydrocarbon resources. According to different estimates, the basin contains 55–68% of recoverable oil reserves and more than 40% of gas reserves. The basin is located at the junction of the Arabian Shield and Iranian continental block that belong to two different (Arabian and Eurasian) lithospheric plates. Collision of these plates at the Mesozoic/Cenozoic boundary produced the Zagros Fold Belt and the large Mesopotamian Foredeep, which is a member of the Persian Gulf Basin. During the most part of the Phanerozoic, this basin belonged to an ancient passive margin of Gondwana, which was opened toward the Paleotethys Ocean in the Paleozoic and toward the Neotethys in the Mesozoic. Stable subsidence and the unique landscape-climatic conditions favored the accumulation of a very thick sedimentary lens of carbonate rocks and evaporites (up to 12–13 km and more). Carbonate rocks with excellent reservoir properties are widespread, while the evaporites play the role of regional fluid seals. Organicrich rocks, which can generate liquid and gaseous hydrocarbons (HC), are present at different levels in the rock sequence.

A Vision for a Secure Transportation System Without Hydrogen or Oil

A Vision for a Secure Transportation System Without Hydrogen or Oil

An overview of the petroleum system of Maracaibo Basin

The geologically complex Maracaibo Basin in northwestern Venezuela is one of the most prolific hydrocarbon basins in the world. Having a basinal area of 50,000 km2 (19,300 mi2), the basin has produced more than 30 billion bbl of oil, with estimated recoverable oil reserves of more than 44 billion bbl. The central elements of the petroleum system of the basin include (1) a world-class source rock (Upper Cretaceous La Luna Formation), deposited on a shelf-to-slope environment under anoxic conditions and modified by intermittent oxygenated periods and tectonic events; (2) high-quality clastic reservoir rocks deposited in Eocene and Miocene fluviodeltaic settings; (3) two main periods of rapid tectonic subsidence responsible for two pulses of voluminous hydrocarbon generation, first, during Paleogene Caribbean–South American oblique plate collision and, second, during the Neogene uplift of the Sierra de Perij–Mrida Andes; and (4) lateral and vertical migration of oil along strike-slip, normal, and inverted faults, as well as a regional unconformity of late Eocene–Oligocene age. The maturation, migration, and trapping of hydrocarbons were closely controlled by the tectonic evolution of the Maracaibo Basin. During the Paleogene, the development of a foredeep along the northeastern margin of the basin and the strike-slip reactivation of the rift-related Jurassic faults on the Maracaibo platform controlled the early structural setting of the source and reservoir rocks. Hydrocarbons migrated updip from source rocks beneath the north-northeastern margin of the basin along north-south strike-slip faults and into overlying Eocene clastic reservoirs in the south-central parts of the basin. The second period of the Maracaibo Basin petroleum system developed during subaerial exposure of most of the Maracaibo Basin during Oligocene–Miocene uplift of the adjacent Sierra de Perij and Mrida Andes. Uplift of mountain ranges surrounding the basin folded and depressed the interior of the basin to form the extensive Maracaibo syncline. Because of the formation of the Maracaibo syncline, oil generation began in the central and southern parts of the synclinal basin and migrated northward. Hydrocarbons migrated up the flanks of the Maracaibo syncline along reactivated strike-slip faults and into Miocene rocks adjacent to the uplifted mountain ranges. Escaping oil has formed numerous surface seeps along the edges of the Maracaibo Basin.

Coal gasification for sustainable development of the energy sector in Pakistan

Pakistan has 19.5 gigawatts (GW) of electric generating capacity. The total power generating capacity has increased rapidly in recent years, due largely to foreign investment, leading to a partial alleviation of the power shortages Pakistan often faces in peak seasons. Rotating blackouts are, however, still necessary in some areas. The rules of the game for generating electricity are changing rapidly. The country's remaining recoverable reserves of crude oil are estimated at 42.28 million tonnes (Mt) (310 million barrels; 1 barrel = 0.1364 t). Thus, there is no prospect for Pakistan to reach self-sufficiency in oil. Pakistan has 853.19 billion cubic metres (Gm 3 ) of proven gas reserves, and currently produces around 104.23 million m 3 (Mm 3 ) per day. While the energy demand is surging in Pakistan, at the same time pressure is building worldwide to reduce greenhouse gas emissions. Pakistan is looking forward to finding ways to overcome the disadvantages of coal resulting from its relatively higher moisture, sulfur and ash content, in order to use this readily-available, indigenous resource to generate clean, reasonably-priced electricity. One way to overcome this problem is to convert coal from a solid to a clean gaseous fuel, which can then be burned like natural gas. When linked with modern combined-cycle turbines, gasification is one of the most efficient and environmentally sound ways of producing electricity from coal. Coal IGCC (integrated gasifier combined-cycle) power plants offer numerous benefits for the environment, power producers and consumers. This technology can help diversify the fuel supply and help balance Pakistan's future dependence on foreign sources of energy.

An Environmentally-Friendly Process for Improved Recovery From Light Oil Reservoirs

Abstract The injection of flue gas is a promising cost-effective process for improving recovery from light oil reservoirs. The flue gas could be obtained directly from power plants or other surface sources. It could also be indirectly generated in situ from the spontaneous ignition of oil when air is injected into a high temperature, high pressure (light oil) reservoir. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible with the oil, thereby displacing it more efficiently. The efficiency of oil recovery during flue gas injection in light oil reservoirs was studied by flue gas displacements of light oil in a 2.44-m long Berea sandstone core at pressures up to 41.58 MPa and temperature of 116 °C in the laboratory. The laboratory results were history-matched using a compositional simulator. This study attempts to understand and explain the success achieved in field high pressure air injection projects in light oil reservoirs. The high oil recovery obtained from this study suggests that flue gas injection is a promising process for enhanced oil recovery from light oil reservoirs. The results show that the level of oil recovery was accompanied by the level of approach to miscibility between the flue gas and the oil. Both were found to increase with an increase in reservoir pressure, as well as an increase in the carbon dioxide content of the flue gas. When injected from a surface source, the sequestration of the carbon dioxide component of the flue gas (a greenhouse gas) makes the flue gas injection process an environmentally- friendly process. Introduction The solvent extraction and/or miscible-type processes are among the dominant enhanced oil recovery (EOR) methods in Canada(1). These processes include the injection of nitrogen, flue gas, carbon dioxide, hydrocarbon-miscible methods, and solvent extraction of mined, oil-bearing ores(2). They have the potential to add 300 to 400 million cubic metres (~50%) to Canada's remaining recoverable oil reserves(3) and multiples of this to the world's recoverable reserves. Other than compressed air, nitrogen and flue gas are the cheapest gases available(4). The potential for cost-effective oil recovery by flue gas injection from currently producing light oil reservoirs as well as depleted and mature waterflooded reservoirs is most important, especially for reservoirs with little or no water production and those with low porosity and low permeability(5–8) where water injection is not feasible. In recent studies carried out by the authors in a slim-tube apparatus(9–11), flue gas has been found to displace oil by mass transfer of intermediate components of the oil into the injected flue gas, and subsequent condensation of the higher molecular weight intermediates back into the liquid phase from the enriched gas phase through a multi-contact combined vapourizing-condensing gas drive mechanism(12). Although the flue gas may never displace the light oil in a truly miscible fashion because of this mechanism, the oil recovery in such a process is significant enough to make it cost-effective(10).

A successful 3-D seismic survey over Bahrain Island

ABSTRACT Environmental constraints are critical issues for land seismic operations and require the development of appropriate equipment and methods. In 1998, Compagnie Générale de Géophysique (CGG) acquired and processed seamless seismic data on behalf of the Bahrain Petroleum Company (Bapco) from a complex field on the Island of Bahrain. The operation ran smoothly in spite of the difficulty of working amongst pipelines, wells, and other oil and gas installations; scarps and sabkhas; urban areas; a zoo, golf course, and racecourse; an oil refinery and aluminum smelter; and other industrial and commercial facilities. The survey deployed a wide range of recording equipment including two sets of vibrators and a combination of radio and cable telemetry recording systems, and a fleet-management system. The successful completion of the survey was achieved through dedicated teamwork. The key elements were as follows: (1) collecting the correct baseline information; (2) detailed planning of the timeframe, human and material resources, adaptation of acquisition techniques to varying circumstances, and health and safety requirements; (3) continuous monitoring of external conditions and the impact of the operation on the environment, in full consultation with the appropriate authorities; (4) maximum flexibility in the field operations so as to allow for changing conditions and unforeseen events; and (5) close partnership between CGG and Bapco at all stages of the project. A joint CGG/Bapco team designed sophisticated processing methods, with top priority being given to the numerous surface heterogeneities. In particular, the recording of an intensive up-hole survey allowed a dedicated team at CGG in France to compute a robust subsurface model and a precise set of primary statics. Seven velocity layers from the Quaternary sandstone to the base of the calcareous and dolomitic Eocene were mapped. These showed significant lateral and vertical velocity variations within identified geological units. Surface-consistent signal processing with calibration to well data was used to compensate for the variations. Other critical processing steps included detailed velocity control, the application of dip moveout routines with acquisition-irregularity-compensation schemes, Radon demultiples and 3-D algorithms, designed for optimal de-noising and imaging. These combined efforts led to the delivery of a final 3-D migrated block. As a result, a complete reinterpretation of the area was possible that significantly increased the estimated recoverable oil reserves (particularly by-passed oil) in the Awali field.

ALSHARHAN, A. S. & SCOTT, R. W. (eds) 2001. Middle East Models of Jurassic/Cretaceous Carbonate Systems. SEPM Special Publication no. 69. iv+364 pp. Tulsa: SEPM (Society for Sedimentary Geology). Price US $140.00 (non-members), US $100.00 (members), plus shipping and handling; hard covers. ISBN 1 56576 075 1.

This is a volume in the prestigious SEPM ‘red-book’ series, based on an international conference held in Al Ain (UAE) in December 1997. There is no need to justify compiling a volume such as this because the Middle East contains two thirds of the world’s recoverable oil reserves and about one third of the recoverable gas reserves, most of which are held in Jurassic and Cretaceous carbonates. However, I have approached reviewing this book with a specific academic agenda which I feel more appropriate to the readership of this journal. My agenda focuses on an apparent anomaly. Despite the economic importance of these carbonates, and the vast research effort they have attracted, why have models derived from Middle Eastern carbonates made such a minor impact on the development of our understanding of carbonates, compared with a dozen other subsurface or exposed basins? Does this volume contain new models or approaches which can be used for interpreting carbonate deposystems or diagenesis, warranting a wider readership? The editors are very well …

Harding A Field Case Study: Sand Control Strategy for Ultra High Productivity and Injectivity Wells

Abstract The Harding field is the first horizontal well development by BP and partners in the highly unconsolidated Balder Massive Sandstone. The field development utilizes a TPG 500 Jack-up Drilling and Production Unit in conjunction with a concrete Gravity Base Tank (GBT), providing oil storage of 500,000 bbls. A combination of the highly permeable, unconsolidated formation with active water/gas drives and viscous oil creates a high coning potential. This means that achieving and maintaining sand free production through optimal completion design was critical to the overall success of the development. The first phase of horizontal wells was drilled and completed for sand free, ultra-high rate production, namely up to 30,000 BOPD per well with PIs in excess of 1,000 bbl/day/psi. High rate water injectors are required for voidage replacement and pressure support. Initial injection water requirements were provided by two dedicated aquifer source wells. This paper describes the strategy adopted and the factors considered in the development of the sandface completion design for Phase 1 of field life. The experience gained on Phase 1 has contributed to the design enhancements required for the more complex and challenging aspects of Phase II, which will include extended reach horizontal wells to neighbouring satellite pools. These enhancements have been engineered taking into account the variations in reservoir quality, physical installation challenges, and production profile requirements, in order to achieve continuing longevity and the high well PIs/IIs characteristic of the Harding Development. Introduction Harding lies 320 km northeast of Aberdeen in block 9/23b in the UK sector of the North Sea, at a water depth of 350 feet (see Figure 1). There are two main reservoirs: Central, which has some support from a large aquifer, and South, which has little natural pressure support. The reservoir is an Eocene submarine fan, lying between 5,300 ft. to 5,800 ft. TVDss, with porosity in the range 30 - 35﹪, permeability in the order of 8 - 12 Darcy, and a net-togross pproximately 98﹪. Recoverable oil reserves are estimated at 190 million barrels. The formations are highly unconsolidated and poorly cemented, and therefore downhole sand control is essential in all wells. Horizontal oil producers are used to maximize recovery and minimize gas and water coning. Preventing gas coning also reduces loading on the surface separation and gas compression equipment, which was initially sized to handle a GOR of 250 - FIGURE 1: Area map. 300 scf/bbl associated with the 64MBD design plateau. Horizontal wells have also increased well productivity and reduced well numbers, thereby increasing the cost effectiveness of the development. The reservoirs contain oil slightly above bubble point pressure, therefore water injection is required to maintain pressure support and improve sweep efficiency. To date, two deviated aquifer producers and three high angle water injectors have been completed, primarily utilizing open hole gravel pack technology. As there is currently no gas export facility, produced gas is reinjected into the top of the reservoir. The TPG 500 platform has process facilities currently capable of handling 93,000 BOPD.

Low-Field NMR Method for Bitumen Sands Characterization: A New Approach

Summary The nuclear magnetic résonance (NMR) signal obtained from conventional oil, heavy oil, and bitumen formations can consist of both hydrocarbon and water signals. Each NMR signal can further characterize both mobile and immobile fluids in the porous media. However, as the viscosity of the hydrocarbon phase increases and the NMR signal shifts toward lower relaxation times, the composite NMR signal for the hydrocarbon-bearing formation becomes very complicated. As the viscosity of the bitumen exceeds 100,000 cp (at natural conditions), the relaxation characteristics of bitumen become partially nondetectable by both the logging and laboratory NMR tools. As a result, the conventional methods of NMR detection fail to precisely recognize the hydrocarbon components. Laboratory NMR measurements of bitumen-bearing porous media under different temperatures were performed. This method delivered new information about bitumen reserves in situ. The results show that low-field NMR holds promise for the characterization of recoverable heavy oil and bitumen reserves. This new approach can be applicable for real-time monitoring of thermal extraction, including monitoring the efficiency of thermal recovery methods.

The State of the Global E&P Industry: Is the World Running Out of Oil?

This paper examines trends in recoverable oil reserves and performance measures in the global upstream petroleum industry for evidence to support or reject the view that the world is running out of oil. The performance measures discussed include the appreciation ratio of recoverable reserves; the replacement rate of produced reserves; reserves to production (R/P) ratios; and the equitable-depletion index. Empirical analysis of these indicators suggests a growing world abundance of crude oil and no strong evidence to support the imminent worldwide petroleum-exhaustion theory. The analysis shows that the global oil supply market is well positioned to support even a modest growth in world petroleum demand despite institutional and regulatory barriers on resource development in some of the more intensely explored and developed regions of the world. In fact, the current estimate of worldwide remaining recoverable reserves can sustain the current worldwide production rate for at least the next 2 to 3 decades, with all other factors remaining constant and assuming a tolerable reserve-life index of 20 years.

Northstar-Geology, Exploration History, and Development Status, Beaufort Sea, Alaska

Exploration for oil at Northstar has been long and costly. Northstar leases were first acquired in 1979 at a joint state and federal sale by Shell Oil, Amerada Hess, and Texas Eastern. The Northstar Unit is 6 mi offshore and about 4 mi northeast of the Point McIntyre Field. Oil was first discovered in Shell's Seal Island 1 in 1983. Five additional appraisal wells were drilled (1983-1986) from two man-made gravel islands in 40 ft of water. Early engineering estimates put the cost of development at $ 1.6 billion. In February 1995, BP Exploration (Alaska) acquired a 98 % interest in the Northstar Unit from Amerada Hess and Shell Oil. When developed by BP, Northstar will be the first oil produced from federal leases in Alaska. To date, the oil industry has invested in excess of $ 140 million in exploration and appraisal operations. An additional $ 90 million was spent on lease bonus bids. The giant Prudhoe Bay and Kuparuk Fields lie along the Barrow Arch. This arch is bounded to the north by a rift margin that deepens into the present-day offshore region. Northstar is located among a series of down-stepping faults off this northern rift margin of the Prudhoe Kuparuk high. The structure is a gently south-dipping northwest-trending faulted anticline. The crest of the structure is located near 10,850 ft subsea. The primary reservoir is the Ivishak Formation (325 ft thick) of the Sadlerochit Group. This is the same primary reservoir at Prudhoe Bay, approximately 12 mi to the south. At Northstar the Ivishak is a high-energy, coarse-grained conglomeratic facies of the Ivishak Formation. The primary lithology is a pebbly chert to quartz conglomerate with occasional sandstone. This very high net to gross reservoir appears to contain no regionally continuous permeability barriers. Cementation has reduced primary porosity to less than 15 %. Accurate porosity estimates are difficult to make due to the coarse-grained nature of the lithology and the presence of kaolinite and microporous chert. Permeability is highly variable, but averages 10 to 100 mDarcies. Oil is a very light and volatile 42 API crude with approximately 2,100 ft3 of gas per stock tank barrel of oil. This oil is very different from the heavier oils (26) found to the south in Prudhoe Bay. Estimated recoverable oil reserves range from 100 to 160 million barrels. A free-standing drilling rig is required at Northstar because the reserves are beyond extended-reach drilling techniques from shore-based facilities. The current development plan is to expand the existing Seal Island to about 5 acres. This is significantly less than Endicott's 40-acre island. The proposed drilling and produc tion island will be accessed by summer barges and winter ice roads. Oil, gas, and water will be processed at a stand-alone facility and then sent to shore via a subsurface pipeline. Northstar will have the first Arctic subsea pipeline in Alaska to transport oil to shore facilities (TAPS). Preliminary tests in Spring 1996 were very successful in demonstrating the technology to successfully bury a subsea pipeline safely in the Arctic.

The Hibernia Oilfield – effects of episodic tectonism on structural character and reservoir compartmentalization

The giant Hibernia Oilfield in the Jeanne d’Arc Basin, the first hydrocarbon development on the Grand Banks of Newfoundland, began production from an ice-resistant, concrete gravity base platform in November 1997. An estimated 615 × 10 6 BBL recoverable oil reserves are trapped in a highly faulted and south-plunging anticline. The tectonic stresses experienced on the western North Atlantic margin have largely controlled the density and size distribution of faults which limit and partition the Hibernia structure. More than 30 fault blocks have been identified at one major oil and gas reservoir alone, the fluvial–deltaic Hibernia Formation. Interpretations of relationships between the times of tectonism and changing stress directions with fault ages, orientations, and styles are based on comparison of a 1991 vintage 3D seismic survey along with data from one discovery, nine delineation and two development wells. There appear to have been three main episodes of extension that affected the oilfield. The first extensional episode spanned the Late Triassic into the Early Jurassic. Adjacent to the Hibernia Oilfield, initial rifting resulted in growth of NE-trending, en echelon faults that were subsequently amalgamated into the major basin-bounding Murre Fault. Deposition of the Hibernia Formation sandstones occurred during the second tectonic episode that spanned Late Jurassic into Early Cretaceous time. Faults of this vintage in the Hibernia Oilfield are normal and mostly formed synthetic to the re-activated Murre Fault in response to E–W oriented extension. The most marked fault growth occurred during the third tectonic episode. This late Early Cretaceous rift episode was co-eval with deposition of another major oil reservoir (the marginal to shallow marine ‘Avalon’ formation) which is targeted for development. Numerous normal faults formed orthogonal to the basin margin, thereby transecting and rotating the Hibernia structure. Fault development during the latest rift episode also responded to basin margin effects as a result of reactivation of the Murre Fault as a zone of oblique-slip. For example, the character of the large Rankin and Nautilus faults changes from relatively planar to distinctly listric moving from east to west. Additionally, sinistral deflections in the trace of the Murre Fault corresponding to linkages of the en echelon offsets formed during the first rift episode are interpreted to have controlled the location of the largest northeast dipping faults formed during the third rift episode. The largest faults formed during the third rift episode clearly compartmentalize the Hibernia reservoir while the sealing capacity of faults formed during deposition of the Hibernia sandstones remains unquantified.

Petroleum System of the South-Eastern Portion of the Maracaibo Basin: Ceuta-North Andean Flank: ABSTRACT

The South Eastern portion of the Maracaibo basin encompasses a giant field (Ceuta) that carries ultimate recoverable oil reserves of more than 2.5 billion barrels and areas with little or no drilling. Oil in the area has been found in Cretaceous and Tertiary sediments and, in seeps along the North Andean Flank, where oil-source rock correlation based on biomarker fingerprints relates the existing crude to the Cretaceous La Luna source rock. A main tectonic constituent of the area is represented by the Merida arch, controlling the sedimentation until the end of the Cretaceous passive margin. Also, the Middle Eocone rifting and its associated structures have determined important thickness variations of deltaic eocene prograding sediments. A significant sequence boundary is associated to compression, uplifting, erosion or non deposition from the late Eocene to the early Miocene. A gradual tilting towards the southeast developed as a consequence of the Andean foredeep in the southern area. Heat flow field is found to be different from one area to another, as given by estimations taking into account well temperature measurements, rock maturity and the calculation of thermal conductivities of the rock formations as a function of their lithologies, porosities and temperature. Kinetic modelling ofmore » the hydrocarbon generation indicates a complex history starting in the northeastern area during the Eocene with the generation of oil and still ongoing nowadays in the north Andean Flank with the generation of gas.« less

Salt tectonism in the Persian Gulf Basin

Abstract The Persian Gulf Basin is an elongate, margin sag-interior sag, sedimentary basin spanning the last 650 Ma along the northeastern subducting margin of the Arabian Plate and is the largest basin with active salt tectonism in the world. This basin is asymmetrical in NE-SW cross section with sediments thickening from 4,500 m near the Arabian Shield to 18,000 m beside the Main Zagros Reverse Fault. Halokinesis in the Persian Gulf Basin originates where major intersecting basement faults cut the buoyant salt beds of the Neoproterozoic Hormuz Series (1.5 to 2.5 km thick) and the equivalent Ara Formation of Oman where salt thickness reaches 4 km. Another source of salt is the Oligo-Miocene Gachsaran Formation, forming Lali salt plug. Major basement fault trends control salt tectonism in the basin, namely the extensional N-S Arabian Trend, the sinistral NE-SW Aulitic Trend, the dextral Erythaean Trend and the extensional E-W Tethyan Trend. The main types of salt structures in the Persian Gulf Basin are salt domes, salt pillows, salt walls, salt piercements, rim anticlines, turtleback structures, disharmonic folds, orogenic fold fillings and dissolution drapes. Diapiric oil fields, account for 60% of the 600 billion barrels of recoverable oil reserves of the Persian Gulf Basin and have grown continuously since Late Jurassic, or since Permian in some large structures, such as Bahrain.

Oil and Gas Markets, Companies, and Technology in the 90's and Beyond

Summary During the late 1990's and beyond, oil prices will be stagnant while costs increase, competition for markets and capital will be fierce, funds available for exploration and development will be limited, and environmental extremists will keep prospective areas off-limits. Higher taxes will limit growth in oil and gas demand and reapportion energy market shares. And a campaign to brand oil use as an "addiction" that must be cured will gather steam. But opportunities abound, too, even in the U.S. High-quality properties are available throughout the U.S., independents can find and develop reserves cheaper than the majors, and new tools are available to reduce risks both in the field and in the market. Gas prices are firming and natural gas is often labeled the "fuel of the future." To succeed in the petroleum industry of the 1990's, all companies must accept change, be creative, and take initiative. To prosper, oil and gas producers and refiners and those who supply and serve the industry must face the new realities of the market. They cannot mark time until the return of 4,000 active rigs and $40/bbl oil. Those days are never coming back. Never. Introduction To understand the wrenching change that has been sweeping through the international petroleum industry, it is necessary to look first at the fundamentals of the worldwide petroleum market. Those fundamentals - oil and gas supply and demand now and in the next 10 years - are the key to understanding what companies are doing now and to assessing the future role of technology in petroleum exploration and development. A look at the market outlook over the rest of the 1990's also brings a needed measure of reality to strategic planning. An objective look at petroleum-market fundamentals makes it clear that the old days of $40/bbl oil and 4,000 active rigs are never coming back. Never. Accepting that fact is the first step in planning a successful future. Making that plan work will require more innovation, more creativity, and more adaptability than ever before. Markets In the U.S. and elsewhere, the most important characteristic of oil and gas markets in the short and long term is plentiful supply. Proven recoverable world oil reserves of 1 trillion bbl represent a 45-year supply at current production rates. Reserves jumped 50% during the decade of the 1980's in spite of the consumption of more than 200 billion bbl. Including oil from shale, tar sands, enhanced recovery, and undiscovered reserves, one estimate puts the total world oil resource at 9 trillion bbl. Natural gas is even more plentiful. Proven world reserves of natural gas represent more than 60 years' supply. Demand will grow, of course. But a realization that supply will be adequate must be the foundation of any strategic plan. That does not mean oil supply and price will not fluctuate, sometimes dramatically, in the short term. It has been said that politics determines oil prices in the short term and economics determines prices in the long term. Another way to describe the world oil market is to make the distinction between productive capacity and reserves. Productive capacity influences prices in the short term; reserves influence prices in the long term. Increasingly, however, two other forces are acting on world petroleum markets: environmental pressures and taxes. As discussed later, these are intertwined in some cases.

Occurrence of Oil and Gas Fields and Source Rock Transformation in the West Siberian Basin and Barents Sea Platform

The West Siberian and Barents Sea basins contain the largest demonstrated reserves of gas in the world (more than 33 trilion m[sup 3]) and very large recoverable reserves of oil (about 19 billion tons). The main productive reservoirs are of the Jurassic and Cretaceous and are composed of marine and alluvial sandstones. Major gas fields of the West Siberian basin are located north of the Arctic Circle, from which they extend into the Yamal Peninsula and offshore into the Kara Sea. Oil fields of the basin are found mainly in the middle Ob region. Only one giant gas-condensate field has been found in the Barents Sea; however, this area has excellent potential for gas-condensate discoveries in the future. Both basins contain Kimmeridgian-Tithonian black-shale formations, which are prolific oil source rocks. In the Barents Sea basin, Kimmeridgian black shales contain 7 to 9% of organic carbon; total pyrolysis yield ranges from 5.3 to 84.2 mg HC/g rock, and hydrogen index ranges from 270 to 630 mg HC/g TOC. Our pyrolysis data and basin modeling (GALO version) indicate that the realization of the initial petroleum potential in the Shtokmanov field area has not begun because the volume of generated oil (about 8more » mg HC/g TOC) is insufficient to start expulsion (threshold of expulsion is equal to 96 mg HC/g TOC). The Bazhenov Formation shales in the central part of the West Siberian basin are characterized by extremely high values of pyrolysis measurements. The organic carbon content ranges from 10 to 25%; the residual petroleum potential varies from 50 to 190 mg HC/g rock; the maturity typically corresponds to the oil window zone; and the amount of expelled hydrocarbons ranges from 40 to 60 mg HC/g rock. The expulsion of oil commenced 90 to 35 m.y. In the northern part of the West Siberian basin, the Bazhenov shales are lean source rocks.« less

Effective Petroleum Source Rocks of the World: Stratigraphic Distribution and Controlling Depositional Factors (1)

Six stratigraphic intervals, representing one-third of Phanerozoic time, contain source rocks that have provided more than 90% of the world's discovered original reserves of oil and gas (in barrels of oil equivalent). The six intervals are (1) Silurian (generated 9% of the world's reserves), (2) Upper Devonian-Tournaisian (8% of reserves), (3) Pennsylvanian-Lower Permian (8% of reserves), (4) Upper Jurassic (25% of reserves), (5) middle Cretaceous (29% of reserves), and (6) Oligocene-Miocene (12.5% of reserves). This uneven distribution of source rocks in time displays no obvious cyclicity and the factors that controlled the formation of source rocks vary from interval to interval. Maps that show facies, structural forms, and source rocks were prepared for this study. Analysis of the maps indicates that several primary factors controlled the areal distribution of source rocks, their geochemical type, and their effectiveness (i.e., the amounts of discovered original conventionally recoverable reserves of oil and gas generated by these rocks). These factors are geologic age, paleolatitude of the depositional areas, structural forms in which the deposition of source rocks occurred, and the evolution of biota. The maturation time of these source rocks demonstrates that the majority of discovered oil and gas is very young; almost 70% of the world's original reserves of oil and gas has been generated since the Coniacian, and nearly 50% of the world's petrole m has been generated and trapped since the Oligocene. The term petroleum as used in this study includes oil, gas-condensate, and gas, but does not include bitumen and other solid and semisolid oil derivatives.