Feet Of Gas Research Articles

A geophysicist's view of the Nansen Discovery, Gulf of Mexico

Editor's note: This paper is reprinted with permission from the September 2003 issue of Sea Technology magazine.www.sea-technology.com The Nansen Field was discovered in May 1999 by Kerr-McGee Corporation and Ocean Energy, on East Breaks Block 602, deepwater Gulf of Mexico. The field is located about 150 miles to the south of Houston, in 3700 ft of water and it is part of the Greater Nansen-Boomvang Field which includes West, North, and East Boomvang as well as Nansen and Navajo Fields with total reserves up to 320 million barrels of oil equivalent (MMBOE). The Nansen Field is the largest of the five, with reserves up to 180 MMBOE (Figure 1). It was fast-tracked and the first production commenced on 28 January 2002, with the world's first truss spar. Daily production of the field is expected to ramp up to a peak of about 40 000 barrels of oil and 80 million cubic feet of gas. Figure 1. The Greater Nansen-Boomvang Field with time structure map of the Nansen Field. The Nansen prospect is located on a series of downthrown three-way closures against faults. These closures are on the west flank of a Pliocene-Pleistocene depositional center (mini-basin). The mini-basin is bordered to the west along a north-south trending salt-cored ridge. Most of the faults are trending NNE-SSW, down to the east with significant displacement; some of them reach more than 1000 ft dip-slip, and therefore facilitate large vertical separations down into the mini-basin. The prognosis targets are Pliocene sands situated on the three-way closures with amplitude support. These Pliocene sand reservoirs are tied to the pay intervals in wells Redding and Bate 1 and Kerr-McGee 1 in the North Boomvang Field located in East Breaks Block 643. To ensure exploration success, the importance of thorough fundamental geologic work and detailed seismic mapping can …

GIPPSLAND—NEW POTENTIAL FROM A MATURE BASIN

It is now 39 years since the first gas was discovered in Bass Strait’s Gippsland Basin. Advances in exploration and production technology mean that today Australia’s longest producing offshore basin is also one of Australia’s most prospective. Gippsland is now producing around 160,000 barrels of crude and 570 million cubic feet of gas per day. To date it has produced more than 3.5 billion barrels of oil and 5 trillion cubic feet of gas and the value of the infrastructure in place is estimated to be around A$16 billion.Australia’s evolving energy market means that gas demand continues to grow. Following the re-structuring of energy markets in southeastern Australia and the installation of new pipeline infrastructure, Gippsland gas now flows to Victoria, NSW, Tasmania and will supply into South Australia from 2004. To meet this growing demand the Esso/BHPBilliton joint venture partners are investing heavily and utilising a vast array of 3D exploration technology to unlock new opportunities. In 2002 they conducted the largest 3D survey ever undertaken in Bass Strait and expect to conduct another in early 2003. A program of exploration drilling is expected to commence in late 2003. With expanded market opportunities and a gas resource base of more than 5 trillion cubic feet, the future looks bright for Gippsland.

AUSTRALIAN GTL CLEAN DIESEL: A STRATEGIC OPPORTUNITY FOR AUSTRALIA’S STRANDED GAS RESERVES

Australia’s lack of gas supply infrastructure and market opportunities means that in the northwest of our nation more than 100 trillion cubic feet of gas remains uncommitted to customer contracts.Because of Western Australia’s relatively small domestic gas markets and the long transport distances to larger markets, the belief has been that only the LNG industry has the scale to monetise the large volumes of gas required to underpin greenfield developments and expansion of gas supply infrastructure.Changing fuel specifications around the world, combined with the limited opportunities for new LNG contracts, has renewed interest in gas-to-liquids (GTL) technology as an alternative to crude oil refining for a source of clean and efficient transport fuels. GTL is an exciting new market opportunity for Australian gas.Exploration interest in Australia appears to be waning. Declining opportunities for oil discoveries and the lack of markets for natural gas make investments in Australia’s upstream sector unattractive compared to other locations around the world.In addition, Australia has dwindling crude oil supplies and faces the prospect of increasing reliance on imported crude oil and refined products. An Australian GTL Clean Diesel industry can help overcome these hurdles by creating a designer blendstock and a valuable new GTL Clean Diesel export industry.A GTL Clean Diesel industry would not only help resolve many of Australia’s current upstream and downstream problems in the petroleum industry, but would also provide massive economic benefits to Australia.This paper will look not only at the making but also the marketing of this fuel of the future.

Review of Late Jurassic Depositional Systems and Potential Hydrocarbon Plays of the Northern Gulf of Mexico Basin

ABSTRACT Post-salt Upper Jurassic siliciclastic and carbonate rocks in the East Texas/North Louisiana/Mississippi region record the early post-rift evolution of the Interior Zone rift basins of the northern Gulf of Mexico Basin. Four major river systems were fixed in space but variable in supply rate; they carried sand and mud in from the northwest (ancestral Red River), the north (ancestral Ouachita River), the northeast (ancestral Mississippi River), and the east (ancestral Alabama River). Shoal-water carbonate deposits formed when siliciclastic inputs were low and shallow-water, high-energy conditions prevailed -- usually in association with basement highs, salt swells and abandoned deltaic shelf margins. Smackover shoal-water carbonates formed within an extensive carbonate ramp from south-central Arkansas to central Texas, and were influenced by initial salt movement. Subsequent Haynesville-age Gilmer carbonate shoals in Texas rimmed rift-related high blocks, as well as highs formed by early salt movement. Siliciclastic sedimentation progressively dominated east of Shreveport, and submarine fans developed in association with a lowstand episode. During early Cotton Valley time, a major southeastward advance of the ancestral Red River delta formed the Taylor and Bossier sand series; while to the east, lower Terryville shoreline began to prograde southward in front of an expanding lagoon. During late Cotton Valley time, continued clastic sedimentation formed wave-dominated deltas in Texas and upper Terryville strike-fed sandstones in north Louisiana. At the close of Cotton Valley deposition in the earliest Cretaceous, regional transgression allowed Knowles carbonates to colonize the abandoned shelf edge and form a thick shelf-edge reef complex on its seaward slope. The significant Calvin lowstand wedge of sandstones was deposited offshore of this edge in Louisiana during a subsequent major sea-level fall, and was then covered by Winn carbonates deposited during the subsequent sea-level rise. High-potential exploration plays remain in Upper Jurassic strata. Smackover and Buckner/Gilmer shoals have produced over 10 trillion cubic feet of gas (TCFG) and 750 million barrels of oil (MMBO) in East Texas and North Louisiana, but large segments of the complex atolls along the Sabine Uplift have not been defined. Complex shoals may rim old rift-related highs such as the Sabine and Wiggins highs. The Gilmer (Cotton Valley Lime) pinnacle reefs of the Robertson-Leon trend may develop (in one form or another) over a broad swath of east-central Texas into westernmost Louisiana. Haynesville-age submarine fans may extend eastward into Mississippi. Updip Cotton Valley is an established 10-TCF tight-gas sandstone play in Texas and Louisiana, but its basinward extensions have high untapped potential. Significant high-quality Upper Cotton Valley production similar to the North Louisiana blanket sands may still be found in central Mississippi. The earliest Cretaceous (Knowles/Calvin/Winn) margin is poorly tested. Calvin-like sandstones of the lowstand wedge should occur in east-central Texas and in southwestern Mississippi.

ABSTRACT: Two New Stratigraphic Field Discoveries in a Mature Area of Jefferson Parish, Louisiana

Abstract In 1997, The Louisiana Land & Exploration Company (now Burlington Resources) and Ocean Energy formed an area of mutual interest in the Little Lake area of southeastern Louisiana. The area encompasses four older, well-developed fields and generally had been thought to be picked-over, receiving little exploratory interest from the industry. The partnership acquired Geco-Prakla's new 3-D survey in the area, and in two locations observed high-amplitude reflectors on the seismic. In both cases, the events were located on regional dip, in synclines between fields. Detailed geological interpretation combined with seismic modeling and AVO analysis convinced the partnership that the events could be hydrocarbon indicators and plans were made to drill two wells. In April 1999, the Burlington Resources' LL&E Fee #1 well was drilled to a depth of 13,700 ft. It encountered gas pay in the Middle Miocene Textularia W zone TP1 sand. In July 1999, a second well was to a depth of 13,100 ft to test a separate anomaly five miles to the northwest. This well encountered 84 feet of gas pay in a high permeability, normally-pressured Textularia W zone sand. Both wells encountered the sands as predicted and both produced gas and/or condensate. The strength of the seismic amplitude varies across the reservoirs, giving a mottled appearance and suggesting that the reservoir is discontinuous in thickness and/or permeability. Understanding the nature of these variations will be the key to optimally developing the fields. End_of_Record - Last_Page 713-------

Abstract: Fifty Year Old Frio/Vicksburg Cage Ranch Field in Brooks County, Texas is Rejuvenated with 3D

ABSTRACT Suemaur Exploration undertook a 3-D seismic shoot in 1994 over the apparently depleted 50-year-old Frio/Vicksburg Cage Ranch Field in central Brooks County, Texas. This 3-D survey has rejuvenated the field with the 1995-96 drilling of six wells, with eight completions in both normal pressure Frio sands and abnormal pressure Vicksburg sands. Cage Ranch Field, discovered in 1947 by Shell, had produced 99 billion cubic feet (BCF) of gas and 850 thousand barrels of condensate (MBC) from 36 wells, in 64 completions. By 1994, production was less than one million cubic feet of gas per day and 16 barrels of condensate a day. The 3-D interpretation identified three major differences between our pre- and post-drill maps. The first was that there was no roll, or west dip downthrown to the Vicksburg flexure on the west at the Middle Firo. Suemaur then drilled the highest Frio wells to date in the field. Secondly, the crest of the underlying Vicksburg structure was not coincident with the overlying Frio structure, but was over a mile south enabling us to make the first commercial Loma Blanca Sand Vicksburg age completion in the field, with the 710-1 well completed for 4.6 million cubic feet of gas per day (MMCPD) and 175 barrels of condensate per day (BCPD). Thirdly, a major arcuate, down-to-the-south embayment Vicksburg age fault was identified on the southeast flank of Cage Ranch, enabling us to drill the discovery well for Hook Field.

Abstract: West Delta Block 107 Field: Hidden under a Mudflow

ABSTRACT West Delta Block 107 Field, located eight miles seaward of the Southwest pass of the Mississippi River of 235 ft of water, contains approximately 18 million barrels of oil (MMBO) and 70 billion cubic ft of gas (BCFG) (recoverable) in 19 Pliocene sands. Hydrocarbons are trapped in a three-way structural closure down thrown to a large down-to-the-southwest growth fault. Water Oil & Gas Corporation discovered the field in 1993 with its OCS-G 8736 no. 1 well, located within a large active mudflow lobe that has caused major difficulties in seismic and drilling exploration over the years. Due to effects of the mudflow, pre-1983 2-D seismic data did not adequately define the amplitude response or the structure of the prospect. Only after 1988 3-D seismic data were reprocessed with refraction statics corrections by Shell Offshore, Inc. in 1993 was it possible to interpret structure and amplitude correctly enough to discover the field. 1996 3-D survey has further improved data quality and has refined our understanding of the field. The field has been developed by seven wells. Five of those wells were drilled from a conventional platform site (West Delta 106 A platform) outside of the mudflow and two miles west of the field. The two other wells (including the discovery well) are active subsea completions. Field production rate since February 1995 has averaged 7200 barrels of oil and 17 million cubic feet of gas daily. The Block 107 Field was nearly found in 1968 by a Humble well and in 1983 by a McMoran well, each of which missed the main accumulation by less than 200 feet horizontally. End_of_Record - Last_Page 569-------

Black Shale Source Rocks and Oil Generation in the Cambrian and Ordovician of the Central Appalachian Basin, USA

Nearly 600 million bbl of oil (MMBO) and 1 to 1.5 trillion ft3 (tcf) of gas have been produced from Cambrian and Ordovician reservoirs (carbonate and sandstone) in the Ohio part of the Appalachian basin and on adjoining arches in Ohio, Indiana, and Ontario, Canada. Most of the oil and gas is concentrated in the giant Lima-Indiana field on the Findlay and Kankakee arches and in small fields distributed along the Knox unconformity. Based on new geochemical analyses of oils, potential source rocks, bitumen extracts, and previously published geochemical data, we conclude that the oils in both groups of fields originated from Middle and Upper Ordovician black shale (Utica and Antes shales) in the Appalachian basin. Moreover, we suggest that approximately 300 MMBO and many trillions of cubic feet of gas in the Lower Silurian Clinton sands of eastern Ohio originated in these same source rocks. Oils from the Cambrian and Ordovician reservoirs have similar saturated hydrocarbon compositions, biomarker distributions, and carbon isotope signatures. Regional variations in the oils are attributed to differences in thermal maturation rather than to differences in source. Total organic carbon content, genetic potential, regional extent, and bitumen extract geochemistry identify the black shale of the Utica and Antes shales as the most plausible source of the oils. Other Cambrian and Ordovician shale and carbonate units, such as the Wells Creek formation, which rests on the Knox unconformity, and the Rome Formation and Conasauga Group in the Rome trough, are considered to be only local petroleum sources. Tmax, CAI, and pyrolysis yields from drill-hole cuttings and core indicate that the Utica Shale in eastern and central Ohio is mature with respect to oil generation. Burial, thermal, and hydrocarbon-generation history models suggest that much of the oil was generated from the Utica-Antes source in the late Paleozoic during the Alleghanian orogeny. A pervasive fracture network controlled by basement tectonics aided in the distribution of oil from the source to the trap. This fracture network permitted oil to move laterally and stratigraphically downsection through eastward-dipping, impermeable carbonate sequences to carrier zones such as the Middle Ordovician Knox unconformity, and to reservoirs such as porous dolomite in the Middle Ordovician Trenton Limestone in the Lima-Indiana field. Some of the oil and gas from the Utica-Antes source escaped vertically through a partially fractured, leaky Upper Ordovician shale seal into widespread Lower Silurian sandstone reservoirs.

Abstract: Bobcat Run South Field, Orange County, Texas -- Oligocene Frio Formation Hackberry Sand Discovery Utilizing 3-D Seismic Data

ABSTRACT Bobcat Run South field is an Obligocene Frio Formation Hackberry sand discovery in Orange County, Texas. The discovery is the direct result of 3-D seismic application to hydrocarbon exploration. Highly anomalous amplitude anomalies, or bright spots, occur within the 3-D seismic data as direct hydrocarbon indicators. The EDC (Energy Development Corporation) #1 Bean Donner well was drilled on a 40-acre amplitude anomaly. The resulting discovery had a pay thickness of 42 feet with 31% porosity. The recoverable reserve estimate for the well has been calculated to be 3.8 BCF (billion cubic feet of gas) and 106 MBC ( thousand barrels of condensate). Significant Hackberry sand reserve additions have been made over the last three years utilizing 3-D seismic data. The success rate for drilling of Hackberry amplitude anomalies has been approximately 80% to date. End_of_Record - Last_Page 570-------

Reserve Growth in a Mixed Sequence of Deltaic and Barrier Island Frio Sandstones: Umbrella Point Field, Chambers County, Texas : ABSTRACT

ABSTRACT Umbrella Point field exemplifies bypassed hydrocarbon potential in a mature Middle Frio Sandstone play in the nearshore Texas Gulf Coast. Located in Chambers County near the northern shore of Trinity Bay, the field has yielded 17 million barrels of oil and 100 billion cubic feet of gas from 18 stacked Frio sandstones since discovery in 1957. Most of the 36 wells were abandoned in the 1970's, and little has been done to optimize drainage patterns, to control the encroachment of water, or to prevent gas-cap expansion. Stratigraphic analysis and geological mapping, combined with analysis of individual well-production histories, were used to locate underexploited areas within these reservoirs. Two modern log suites and limited core data were used to define criteria for estimating original hydrocarbons in place and drainage areas. The Middle Frio in the area consists of stacked distributary-channel, delta-front, shoreface, and shore-parallel bar sandstones interbedded with shales. Hydrocarbons are trapped in a rollover anticline in the footwall of a growth fault underlain by diapiric shale. Original hydrocarbons in place at Umbrella Point were calculated volumetrically at 60 million barrels of oil and 300 billion cubic feet of gas. Remaining recoverable hydrocarbon potential is estimated at 32 million barrels of oil and 173 billion cubic feet of gas. Average recovery efficiency is 28.2 percent for oil and 33.5 percent for gas. The best recoveries have been from the zones characterized by uniform sandstone deposits that were redistributed during small-scale transgressions between depositional cycles.

The Re-Discovery of White Kitchen Field, LaSalle County, Texas - A Tight, Heterogeneous Edwards Reef Gas Reservoir : ABSTRACT

ABSTRACT The primary development of the Edwards Reef productive trend in South Texas occurred in the 1950s and 1960s and resulted in the discovery of a small number of commercial gas fields and a large number of non-commercial fields. A secondary development of the trend began in the late 1970s with the advent of hydraulic fracturing technology, which could transform non-commercial fields into commercial producing properties. Successful secondary development utilizing this technology at Washburn and Word Fields precipitated the conceptualization of the White Kitchen Prospect. The White Kitchen Prospect utilized well-established Edwards Reef depositional models, coupled with reservoir principles pertaining particularly to tight, heterogeneous reservoirs, to develop a convincing case for the development of a heretofore unexploited reservoir along the Edwards Trend. The basic premise of the prospect was exceedingly simple and rooted in the most basic concepts of reservoir engineering; i.e., an early well drilled within the productive area of the field continued to display a pressure buildup of approximately 176 kg/cm2 (2,500 lb/in2) shut in wellhead pressure after 4.1 billion cubic feet of gas had been produced from the reservoir over 30 years of continuous production. With the presence of an active water drive being discounted by the depositional model and reservoir data, the conclusion that the reservoir was not depleted was inescapable. Seven new wells have now been completed on the prospect, and an incremental 17.3 billion cubic feet of gas will be produced as a result of this secondary development. The prospect provides an excellent model for additional prospects which can be developed along the trend and provides an excellent example of the potential for future exploration and development in tight, heterogeneous hydrocarbon reservoirs.

Permeability Structure of a Highly Heterogeneous Transgressive-Marine Complex: Tocito Sandstone, New Mexico: ABSTRACT

The Tocito Sandstone Member of the Mancos Shale is an Upper Cretaceous shallow-marine sandstone and mudrock complex deposited along the western margin of the Western Interior seaway. The Tocito is a major hydrocarbon producer in the San Juan Basin (approximately 117 million barrels of oil and 79 billion cubic feet of gas). Because of reservoir heterogeneity, ultimate Tocito oil recovery factors are low, generally between 10 and 20 percent. To enhance understanding of permeability heterogeneity in the Tocito, we have undertaken a detailed surface and subsurface investigation. A total of 2,697 permeability measurements have been made using minipermeameters. Permeability variation within the Tocito is controlled by two principal factors: lithofacies and burial/diagenetic history. Coarser grained and better sorted lithofacies have the highest permeability. The permeability values from outcrop and shallow subsurface cores are dramatically higher than those from deep subsurface cores. This is due to dissolution of grains and calcite cement, and decompaction that preferentially affected the outcrop and shallow subsurface. Correlation lengths for permeability values along horizontal transacts are typically less than 3 m, whereas those for vertical transacts are usually less than 0.6 m. These data suggest that small grid block sizes should be used during reservoir simulationsmore » if the investigator wishes to accurately capture the reservoir heterogeneity.« less

Regional Chronostratigraphic and Depositional Hydrocarbon Trends in Offshore Louisiana State Waters: ABSTRACT

ABSTRACT Successful exploration for hydrocarbons in the Northern Gulf of Mexico basin requires a systematic understanding of hydrocarbon producing trends, sand body geometries and the geologic, engineering and reservoir parameters of the producing sands. This study forms part of the Offshore Atlas project in progress at the University of Texas at Austin, Bureau of Economic Geology, Texas, in cooperation with the U.S. Department of Interior, Minerals Management Service, and the Geological Survey of Alabama, and is aimed at achieving this goal. In this study, 26 chronozones were grouped into 12 sub-groups. The chronozones were defined on the basis of the benthic foraminiferal biostratigraphic zones and were correlated across the Gulf using well and seismic data and were projected from the Federal offshore into the State waters. The chronozones on each well log in the 22 cross sections constructed from West Cameron area eastward to the Chandeleur Sound, Breton Sound and Main Pass areas, were subdivided as applicable into four depositional groups consisting of aggradational, progradational, transgressive and submarine fan facies based primarily on SP log shapes. In the Louisiana State waters there are 92 fields containing 685 reservoirs. This includes 214 oil, 347 gas, 33 condensate and 91 combination type reservoirs. Total combined cumulative production is 1,44l,091,263 barrels of oil, 117,641,457 barrels of condensate and 11,802,821,997 thousand cubic feet of gas. Total assigned production (1977-1995) shows the progradational facies to be most productive yielding 51.69% oil, 93.84% condensate, and 77.47% gas. The aggradational facies sands produced 46.98% oil, 1.70% condensate and 15.76% gas. The submarine fan facies yielded 1.21% oil, 4.45% condensate, and 6.74% gas. Production from the transgressive facies sands was less than 0.2% of the total assigned production of oil, gas and condensate.

Improved Reservoir Characterization of the Rose Run Sandstone on the East Randolph Field, Portage County, Ohio: ABSTRACT

ABSTRACT The East Randolph Rose Run field is located in Randolph Township, Portage County, Ohio. The field was discovered in 1992 as a down dip extension of the Randolph Gas field discovered by Belden & Blake Corporation a year earlier. Since its discovery, over 40 wells have been drilled in the East Randolph field that have produced an estimated 600,000 barrels of oil and 1.5 billion cubic feet of gas. Characterization of the productive upper Rose Run sandstone members is underway to determine the technical and economic feasibility of water flooding, gas pressure maintenance, or the possibility of infill drilling for oil in the East Randolph field. Core data and log data for each sandstone member was analyzed and mapped to determine their relationship with estimated ultimate recovery of oil and gas. The upper Rose Run sandstone can be divided into four distinct sandstone units characterized by bedding, mineralogy and log character. Each of the four sandstone units usually represents a fining-upward cycle of sandstone, sandy dolomite and dolomite. The uppermost unit (#1) consists of tightly cemented sandstone with quartz overgrowths, low permeability and low porosity, while the lowermost sandstone unit (#3B) is usually the most permeable (1.5 - 12.9 md) and porous (2.6 - 11.2 percent). This variation in porosity and permeability is predominantly controlled by grain size, amount and type of intergranular cement, and extent of secondary dissolution porosity. Most of the East Randolph field's oil production can be attributed to the reservoir development of the Rose Run #3A and #3B units. Gas production appears to be present in all four units, but seems to be best when good reservoir development is found in the #1 and #2 sandstone intervals. Volumetric calculations using new geologic models increase estimates of the amount of original oil-in-place at over 10 million stock tank barrels, more than double the initial estimates. The new geologic model will be used as input for reservoir simulation to optimize future locations of infill wells, and determine waterflood and/or pressure maintenance feasibility.

Undiscovered Petroleum of the Brazilian Interior Sag Basins

This paper, the second in a series dealing with undiscovered petroleum in South American basins (exclusive of Venezuela and Colombia), focuses on the four large intracratonic (or interior) sag basins of Brazil: the Solimoes, Amazonas, Parnaiba, and Parana. The smaller Chaco basin also is discussed, although in less detail. Preliminary estimates of undiscovered hydrocarbons in the five basins are 0.228 billion barrels of oil (BBO) and 11.870 trillion cubic feet of gas (TCFG). Because the mean values originally estimated by the World Energy Resources Program at the U.S. Geological Survey appear to be low when viewed in light of the recent (1983-1993) history of petroleum reserves in South America, the mean values were revised upward based on the original identified reserves. The recalculated mean values are 10.18 BBO and 20.52 TCFG. In general, exploration in these basins is in an immature stage. The Solimoes basin has the greatest initial estimated undiscovered reserves of oil (0.04 BBO), and the Parana basin has the greatest initial estimated undiscovered reserves of gas (5.08 TCFG). The most important plays in the Solimoes and structurally similar Amazonas basins are the fold and fault closures associated with the wrench systems found in the basins. The plays in the Parana basin are limited to possible structural traps linked to faultassociated closures, and possibly to some wrench-related features.

Undiscovered Petroleum of the Brazilian Interior Rift Basins

Brazil is estimated to contain 52% of the undiscovered oil and gas resources of South America, outside of Venezuela and Colombia. The Reconcavo, Tucano-Jatoba, and Tacutu interior rift basins of Brazil are investigated in this paper, the first in a series dealing with undiscovered petroleum of South America (exclusive of Venezuela and Colombia). Preliminary estimates of the undiscovered petroleum resources are 0.273 billion barrels of oil (BBO) and 1.234 trillion cubic feet of gas (TCFG) for the four basins. A review of the 1983-1993 history of petroleum reserves in South America indicated that an initial consensus estimate of 0.27 BBO and 4.15 TCFG (mean values) by the World Energy Program Group at the U.S. Geological Survey is too low. An adjusted range of probabilities is recalculated from original identified reserves, resulting in revised mean values of 0.29 BBO and 4.15 TCFG for the four interior rift basins. Of these four basins, the Reconcavo is in a mature stage of exploration with 80 fields; the ...

Using Production-Based Plays in the Northern Gulf of Mexico as a Hydrocarbon Exploration Tool: ABSTRACT

ABSTRACT The Minerals Management Service has described 72 production-based plays in the northern Gulf of Mexico Outer Continental Shelf encompassing approximately 1,100 fields and over 9,500 productive sands. Plays are defined by a combination of production, chronostratigraphy, lithostratigraphy, and structural style. Cumulative production from these plays as of December 1994 was 9.34 billion barrels of oil and 112.6 trillion cubic feet of gas, with remaining proved reserves of 2.52 billion barrels of oil and 29.3 trillion cubic feet of gas. The information associated with these plays can be used as exploration tools to highlight areas of potential exploration interest and to test the potential economic viability of both plays and individual prospects. Qualitatively, the play maps target areas for future exploration by (1) identifying conceptual deep-sea fan plays located downdip from plays established in sediments of shallow water depositional environments and (2) emphasizing areas for both future exploration and infill potential around and within established plays. The extensive data sets associated with each play provide valuable quantitative information that can be used to assess the possible number and size of undiscovered accumulations in a play. At the individual prospect level, data derived from play averages can be applied to each productive sand and pool to perform detailed geologic and economic evaluations.

Influence of Orogenesis in Basin Evolution in the Central Asian Republics of the CIS: ABSTRACT

A regional synthesis of the structural geology of the central Asia region of the CIS is presented, the study area lying between the Caspian Sea and China and stretching from the Aral Sea south to Afghanistan. Structural analysis of central Asia illustrates the creation of major regional faults that have acted as planes of weakness during the evolution of the region. These faults were repeatedly reactivated in phases of orogenesis, some of which were centred far from the study area. It is shown that the Eurasian Plate did not act as a rigid, unyielding lithospheric unit, but deformed internally as a response to compression at its margins. The influence of these orogenic events on the evolution of basins in the area is described by means of maps and serial sections. The role of major faults in governing the spatial distribution of structural traps in petroleum basins within the study area is also examined. These basins are largely gas-prone, and have ultimate recoverable reserves estimated at over 290 trillion cubic feet of gas and 27 billion barrels of liquids.

A Comparison of Undiscovered Oil and Gas Resource Estimates, Los Padres National Forest in the Ventura Basin Province, California: ABSTRACT

Two recent assessments of the undiscovered oil and gas resources of Los Padres National Forest lands in the Ventura Basin Province using different methodologies and personnel show remarkable coincidence of estimated resources. The 1989 U.S. Geological Survey assessment was part of a National appraisal. In the Ventura Basin Province, two separate plays were assessed and a percentage of resources from these plays was allocated to Federal lands. By this allocation, the undiscovered oil and gas resources of this part of the Los Padres National Forest are estimated to range from <10-140 MMBO (means probability 60 MMBO, million barrels of oil) and 10-250 BCFG (mean probability 110 BCFG, billion cubic feet of gas). In 1993, the U.S. Forest Service completed an oil and gas assessment of the entire 1.8 million-acre Los Padres National Forest as part of a Reasonably Foreseeable Oil and Gas Development Scenario. In those areas of the forest considered to have high potential for the occurrence of oil and gas deposits, a deposit simulation model was used. This method is based on a fundamental reservoir engineering formula in the USGS computer program, FASPU (Fast Appraisal System for Petroleum-Universal). By this method, the undiscovered oil and gas resource ofmore » this part of the Los Padres National Forest are estimated to range from 0-182 MMBO (mean probability 56 MMBO) and 9-233 BCFG (mean probability 103 BCFG). An additional 6 MMBO (mean probability) is allocated to forest lands with medium potential within this province but not to any specific prospects. The remarkable coincidence of estimate resources resulting from such different assessment methods and personnel is noteworthy and appears to provide an increased measure of confidence in the estimates.« less

Architecture, Internal Heterogeneity, and Resulting Drainage Efficiency of Upper Oligocene Frio Formation Inner-Shelf Sandstone Reservoirs in West Fulton Beach Field, Aransas County, Texas: ABSTRACT

ABSTRACT This study suggests that a significant volume of resources has been overlooked in inner-shelf sandstone reservoirs in the Frio Formation because of their complex architecture and the practice of focusing on thicker reservoirs during initial field development. Subregional and local geophysical well-log correlation, net sandstone and net pay mapping, petrophysical analysis, and mass-balance volumetric calculations were undertaken in West Fulton Beach field, Aransas County, Texas, to assess the reserve-growth potential of these reservoirs. To identify individual reservoir bodies, it was necessary to break intervals down to fifth- and sixth-order genetic stratigraphic units. Inner-shelf sandstone bodies range in thickness from 2 to 8 ft and form shore-parallel lenses up to 1.6 mi long and 0.6 mi wide. These lenses, which may be associated with prograding shorefaces, transgressive disconformities, and retrogradational shelf sequences, form laterally stacked, commonly vertically overlapping, and potentially amalgamated bodies. They average up to 32 percent porosity and 990 md permeability. Internal heterogeneity is low, and drainage efficiency is moderate. Gas completions can drain areas of 150 to 300 acres, whereas oil completions drain from 20 to 50 acres. Remaining resources identified within incompletely drained and untapped reservoirs of eight intervals in West Fulton Beach field total 11.8 billion cubic feet of gas and 315,000 barrels of oil, representing reserve-growth potential of 8 and 4 percent, respectively. Although much of this potential lies in small compartments containing from 50 to 500 million cubic feet each, several such targets can be identified in a vertically stacked arrangement such that a single wellbore can intersect 2 to 3 billion cubic feet of reserves. Projecting these results to the other fields of the play suggests that as much as 752 billion cubic feet of gas and 7 million barrels of oil remain as infill and recompletion targets. Because many of the Tertiary units of the Gulf Coast Basin share a similar depositional setting with the Frio Formation, significant reserve-growth potential is thought to exist in inner-shelf sandstones throughout the basin.