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Collaborating Authors
Phanerozoic
Abstract Carbonate reservoirs, particularly those of Tertiary age, contribute significantly to South-East Asia's oil and gas production. There is considerable potential for more carbonate fields to be discovered in the future, because much of the region is still under-explored. Well logs recorded in these formations can, in many cases, be very difficult to interpret. Limestones and dolomites are hydrocarbon-bearing in Indonesia and the Philippines, as well as having good potential for hydrocarbon reservoirs around the fringes of the Indian and Australian land masses. Specific examples of recent well logging problems and their possible solutions are drawn from these areas. The choice of optimum well logging suites, to maximize the amount of petrophysical information obtained from the carbonates, is discussed with petrophysical information obtained from the carbonates, is discussed with some of the new, as well as the traditional, interpretation techniques, used in many other areas of the world. Some recent advances in logging tool technology are featured, and a variety of interpretation techniques are shown to have good applications, particularly natural gamma ray spectroscopy and formation testing by wireline methods. Much of this advance has been in the last five years, in large part due to the advent of digital computer wellsite recording. Methods to identify fractures and permeability indication techniques are reviewed, as well as potential uses permeability indication techniques are reviewed, as well as potential uses of dip tools. Introduction Carbonate reservoirs, particularly those of Tertiary age, contribute significantly to South-East Asia's oil production. Many of these are reef structures which have grown only in shallow-water marine environments, with very little or no sediment input, and were extremely sensitive to water temperature and salinity. Platform carbonates are common off several of the area's continental margins, but no attempt is made to subdivide carbonate reservoirs for the purposes of this paper. Carbonate rocks, which require a carefully designed wireline logging programme and can be difficult to interpret, form important hydrocarbon reservoirs in Indonesia, the Philippines, and around the fringes of the Indian and Australian land masses. Specific examples of well logging problems are drawn from these areas. Figure 1 shows a profile across a typical carbonate shelf. Logging programmes aimed at maximising the amount of petrophysical information obtained from the carbonates are discussed. Interpretation techniques are evaluated and some limitations of well logs in reef environments highlighted. Field examples from recent wells in South-East Asia are shown, and possible applications of new and future well logging tools proposed. p. 6–1 p. 6–1
- Asia > Indonesia (0.54)
- Asia > Philippines (0.44)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (0.34)
Abstract In the Central Luconia area, offshore Sarawak, substantial gas reserves are present in Miocene carbonate buildups. The carbonates consist of present in Miocene carbonate buildups. The carbonates consist of limestones and dolomites with porosities ranging from 0 to 40 percent. From core analysis it became evident that there exists a potential problem with regard to the compaction of the carbonate reservoir matrix as a result of effective stress increase as the reservoirs are depleted. Triaxial compaction tests were carried out on core samples from several carbonate reservoirs. It was found that highly porous mouldic limestones show pore collapse at relatively low effective stresses. After pore collapse the uniaxial compressibility coefficient increases significantly. Reservoir compressibility parameters can be derived from core data, for collapsing as well as non-collapsing rocks. These can be used to calculate reservoir compaction from well logs for a particular pressure decline. An estimate of the expected surface subsidence can be made based on the theory of poro-elasticity and the nucleus of strain concept as described by Geertsma. Predicted subsidence figures have been taken into account in platform design. platform design. The gas reservoirs have large aquifers within the carbonate buildups. As these aquifers have not all been fully appraised, there exists some uncertainty concerning their actual compaction behavior. Introduction In the Central Luconia area off shore Sarawak substantial gas reserves are present in Miocene carbonate buildups. Sarawak Shell Berhad, operating present in Miocene carbonate buildups. Sarawak Shell Berhad, operating under a production sharing contract with PETRONAS, recently developed 2 gas fields (the E11 and F23 fields) in Central Luconia and the development of further fields is planned, supplying gas to a 6 million tons/annum capacity LNG plant located at Bintulu, Sarawak. The gas bearing carbonates consist of limestones and dolomites with porosities ranging from 0 to 40 percent. A considerable amount of reservoir rock consists of highly porous carbonates exhibiting a mouldic porosity. Mouldic porosity occurs when part of the rock matrix has been dissolved by fresh water leaching. The part of the rock matrix has been dissolved by fresh water leaching. The carbonates have Brinell hardness values (reference 7) ranging from as law as 1.6 kgf/mm2 in the highly porous mouldic limestones, to about 12 kgf/mm2 in dolomites. p. 4–27 p. 4–27
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.89)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.65)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.34)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Upper Rotliegend Formation (0.99)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Limburg Formation (0.99)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Central Luconia Province > Block SK 8 > F23 Field (0.94)
- Asia > Malaysia > Sarawak > South China Sea > Sarawak Basin > Central Luconia Province > Central Luconia Field (0.91)
Hiller, K., Head of Oil and Natural Gas Section Federal Institute for Geosciences and Natural Resources (BGR), Hannover, Federal Republic of Germany 1981–83, Head of German Geological Advisory Group with Petrobangla Dhaka, Bangladesh Abstract The Surma Basin in the Northeast of Bangladesh is a proven Miocene Gasprovince and was structurally stamped by the contemporaneous interference of two major tectonic movements, ie. the emerging Shillong Massif in the North and the West-prograding mobile Indo-Burman Fold Belt. Basin relief, structural elements, growth and style as well as geochemical data with respect to hydrocarbons, source rocks and maturity are discussed. Related to the clear cut pre- and post-early Pliocene situation, change of migration pattern and coincidence between hydrocarbon generation, migration, accumulation and trap growth are analysed. Finally, the further prospectivity of the Surma Basin is commented upon. prospectivity of the Surma Basin is commented upon. GEOLOGICAL SETTING The Surma Basin (Figure 1) is situated in the Northeastern-most part of Bangladesh and forms a portion of the late to post-geosynclinal Bengal Basin, subsiding from Oligocene or earlier times onwards (HOLTROP and KEIZER) with its peek of subsidence since Pliocene. The Surma Basin covers an area of roughly 2.5 million acres and is framed by the pre-Cambrian basement (PASCOE, WADIA) of the Shillong Massif and its skirting Barail Ranges in the North, by the Barail-Imphal Ridge in the East towards Assam, and in the South by the Tripura High. In the West, the Surma Basin ascends gradually towards the Eocene Hinge Zone, while passing into the Bengal Foredeep over a ridge at about 24 N latitude towards the Southwest (see Figure B-13, 2 at HOLTROP and KEIZER). Based on seismic control, the Surma Basin cumulatively comprises about 57000 ft from post-Eocene Sylhet Limestone to recent clastic sediments (Figure 2, 7), this thickness being in fairly good concurrence with the maximum 55500 ft post-Eocene thick sediments as compared to the adjacent Assam area (DAS GUPTA); Sylhet Limestone and older (Poleocene, ?Cretaceous) sediments may account for another few thousand feet of sedimentary fill.
- Asia > Bangladesh > Dhaka (0.54)
- Asia > India > Meghalaya > Shillong (0.47)
- Asia > Bangladesh > Sylhet (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.89)
- Asia > Bangladesh > Surma Basin (0.99)
- Asia > Bangladesh > Assam-Arakan Basin > Surma Basin > Badarpur Field (0.99)
From Jurassic through Early Miocene there was active rifting of the south China and north Australian continental margins. Magnetic anomolies of the marginal seas indicate that microcontinents were drifted as far as Borneo. Together with island arcs, these microcontinents formed the nuclei against which distal turbidites accumulated, with their source perhaps as for away as the Mekong Delta. The post Oligocene convergence of Australia and the Philippines against Indonesia, effected by subduction of extinct marginal sea lithosphere, resulted in uplift of the ancient microcontinents and their turbidite drapes to form new provenance landmasses for shallow water sedimentation in adjacent basins. Plate tectonic basin classification cannot be successful unless the Plate tectonic basin classification cannot be successful unless the important role of the microcontinents is recognised. Their presence in the Southeast Asian developing orogen hinders the formulation of an elegant classification. Introduction The need for classification is basic to all human fields of endeavor. The complexities of Nature prevent the formulation of a perfect classification and commonly the allocation of a classification name or symbol camouflages our ignorance. Just as no two orogenic belts are identical, so no two basins are identical. The dangers of worldwide classifications are well illustrated by attempts to force the Alpine orogenic ‘norm’ or the Appalachian geosynclinal ‘norm’ on the rest of the world. We now know enough to reelize that these attempts were misguided. Basic classification should not fall into this some trap. In applying a model which has been successful elsewhere, the local idiosyncrasies of Nature must first be fully evaluated. EXISTING S E ASIAN CLASSIFICATIONS Two brave attempts at classification appeared independently in 1975. The more detailed one by Murphy (1) subdivided the basins into "shelfal", "continental margin", "archipelagic" and "marginal seas". As broad general categories, they are satisfactory, but "shelfal" and "continental margin" categories are so broad as to fall short of usefulness. Soeparjadi et al used categories such as "outer arc", "foreland", "interior cratonic" and "open shelf on continental margin". Some of these terms are open to misinterpretation when compared with the rest of world. "Interioratonic" conjures up a vision of a stable craton of ancient ancestry and implies that the basin is unrelated to plate margin tectonics.
- Asia > Indonesia (1.00)
- Oceania > Australia > Western Australia (0.68)
- Asia > Malaysia > Sarawak > South China Sea (0.47)
- Geology > Structural Geology > Tectonics > Plate Tectonics (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > Timor Sea > Bonaparte Basin > Vulcan Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.99)
- (6 more...)
Summary Gas-production characteristics of naturally fractured Devonian shale have been quantified through a three well interference field test by use of an established producing well and two offsets placed on the primary and secondary regional fracture trends relative to the producer. Three individual shale zones were evaluated simultaneously by buildup, drawdown, and pulse tests to investigate reservoir gas flow characteristics, natural fracture properties, and gas storage and release mechanisms. Test results show severe permeability anisotropy, indicating elliptical drainage pattern with an 8:1 axis ratio. Essentially all gas is stored in a sorbed state in the shale matrix and is transported toward the wells through the native fracture system. Introduction The Devonian shales of the Appalachian basin underlie approximately 68,000 sq miles [175 000 km] from New York to Tennessee. These massive shales range in thickness from a few feet at the basin margin outcrops to thousands of feet at the basin center, and are made up of both organically lean ("gray") and rich ("brown") intervals. The shales contain natural gas in considerable quantity, primarily held in solution in solid organic constituents (kerogen) of the shale matrix, which makes the gas resource truly "unconventional." Recent resource estimates for the Appalachian basin shales range from 585 to 2,500 Tcf [16.5 × 10(12) to 70.8 × 10(12) m3] of natural gas in place, but because of the extremely low matrix permeability of the shale, gas is often not economically recover-able by conventional industry practice. The approximately 12,000 wells drilled to date historically have recovered only about 3 Tcf [0.08 × 10(12) m3] over the last 50 years. The Appalachian basin shales are considered blanket formations because discrete members are correlative over wide geographic areas. However, even though stratigraphically continuous and gas-containing across their extent, the Devonian shales do not produce uniformly when drilled. Current commercial production is a function of connecting the well with the primarily vertical natural fracture systems present in the shale, which form gathering and transportation networks to move gas from the matrix to the wellbore. Historical production has been limited to discrete areas where natural fracture density was high enough to support development. The Eastern Gas Shales Project (EGSP) is a long-term R and D effort by the U.S. DOE to improve overall gas recovery from the shale and to stimulate development of the resource by the private sector. An important part of the R and D thrust has been the development of a technical data base on shale characteristics and production behavior. The offset well test (OWT) described in this paper is a field experiment conducted to improve understanding of the basic gas-production mechanism of this unconventional reservoir. The test project was designed to investigate both qualitatively and quantitatively the gas-production characteristics of the shale in an area of natural fracturing and commercial development, and used a series of reservoir interference tests to achieve the test objectives. Specifically, the experiment addressed the following objectives. 1. Investigate the tow mechanics of gas in shale matrix and fractures. 2. Determine fracture orientation and distribution. 3. Determine how gas is stored in and released from the shale. 4. Verify the existence of directional drainage patterns and their impact on production practice. A three-well pattern was developed. consisting of an existing gas well with a 22-year production history and two newly drilled holes offsetting the producer by 120 and 90 ft [36.6 and 27.4 m], respectively, on the major and secondary directional fracture trends predicted for the test area. The interference series was conducted by perturbing the shale reservoir in the base well and monitoring the effects in the offsets. Fig. 1 shows a schematic of the OWT layout and instrumentation used during the interference testing. Earlougher provides a thorough description of interference testing, as well as many references on the subject. Site Selection The established producer (control well) used in the OWT formed an important part of the experiment and was carefully selected. During the test planning phase, design criteria were developed to define well parameters required for the planned interference tests. Table 1 lists these requirements. JPT P. 291^
- North America > United States > West Virginia (1.00)
- North America > United States > Ohio (1.00)
- North America > United States > Tennessee (0.94)
- (2 more...)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- North America > United States > West Virginia > Appalachian Basin > Huron Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Huron Shale Formation (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Summary Workovers and recompletions of old wells, evaluation and monitoring of reservoir behavior during primary, secondary, and ternary recovery, and exploration for bypassed oil in cased wells make the proper selection of cased-hole logs and/or optimal logging suites a necessity. Required information includes the integrity of the cement bond between casing and the formation, lithology identification, porosity, type and distribution of reservoir fluids, formation permeability, and anticipated watercut estimates. These data can be obtained from vitrious log responses, which include natural total and/or spectral gamma ray radioactivity measurements, radiation-type logs (density, neutron), pulsed neutron logs. acoustic measurements, etc. In addition. special time-lapse logging techniques monitor reservoir behavior and state of hydrocarbon depletion, whereas log-inject-log (LIL) techniques enhance the accuracy of residual oil saturation (ROS) estimates. Introduction Cased-hole logging capabilities and associated quantitative interpretation techniques have become very important in several applications, including, cased-hole exploration, completion, workovers. and the monitoring of hydrocarbon reservoirs under primary, secondary, or tertiary recovery schemes. Cased-hole well logging concepts are reviewed which are currently used (1) to explore for bypassed hydrocarbons in abandoned or old workover wells; (2) to work in fresh, brackish, or unknown formation water salinities; (3) to evaluate hydrocarbons in new wells in which openhole logs could not be run, (4) to monitor production behavior and depletion in reservoirs under primary driving mechanisms, breakthrough in waterfloods, chemical and micellar projects, C02, and steam- and fireflood projects; (5) for residual oil saturation based on LIL techniques, etc. Several field case examples and references are presented. Reservoir Characterization Lithology. Natural radioactivity measurements have phyed an important role in wireline logging operations since about 1935. Most of the natural gamma ray logging techniques applied in formation evaluation measure the total and/or individual contribution of gamma rays from potassium, uranium, and thorium series by means of standard gamma ray and/or spectral gamma ray logging. The fact that natural gamma-ray intensities vary as a function of lithology was recognized as early as 1939. Gamma rays are the radiations originating within an atomic nucleus. A nucleus gives off excessive energy (gamma rays) as the result of radioactive decay or an induced nuclear reaction. Radioactive decay consists of the emission or capture of elementary or composite particles with consequent transformations into daughter nuclei characterized by different atomic numbers and, in some cases, by different mass numbers. As early as the 1950's, field tests in boreholes were carried out to study the feasibility of detecting some of these nuclides by gamma ray spectroscopy techniques that identify characteristic gamma rays. Of particular interest are those of potassium and the uranium and thorium series. Both uranium and thorium are characterized by specific decay series. Potassium consists of three isotopes that exhibit masses of 39, 40, and 41 with abundames of 9318, 0.0119, and 6.9%. The only unstable isotope of potassium is the nuclide potassium-40, the major contributor, which emits a single, easily identifiable gamma ray at 1.46 MeV. Hence, in addition to total gamma ray counts, the Spectralog TM measures and records the gamma rays emitted by potassium-40 (40K) at 1.46 MeV, the uranium series nuclide bismuth-214 (214Bi) emanating gamma rays at 1.764 MeV and the thorium series nuclide thallium-208 ( 208Th) emanating gamma rays at 2.614 MeV. These nuclides are of particular interest to the oil industry since, in various amounts, all are found in subsurface formations as constituents of potential reservoir rocks. Table 1 illustrates the distribution of potassium (K, %), uranium (U, ppm), and thorium (Th, ppm) for several formation constituents detrimental to optimal reservoir rock conditions. Application of such spectral gamma ray data may be made either qualitatively or quantitatively. As is extensively documented in logging literature, natural spectral gamma ray logging assists greatly in geological studies (lithology identification, recognition of depositional environment, stratigraphic correlation, source rock evaluation, etc.), complex reservoir rock analysis (heavy minerals, mica, feldspar, glauconite, fractures, silt. etc.), shaliness estimates, in-situ clay typing, cation exchange capacity (CEC) estimates, and radioactivity buildup under dynamic fluid conditions (channeling behind pipe, high-permeability streaks, fractures. caverns, watered-out zones, etc.) and/or around perforations. JPT P. 249^
- North America > United States > Texas (0.47)
- North America > United States > California (0.28)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.95)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.89)
- North America > United States > Texas > Permian Basin > Spraberry Formation (0.89)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.89)
- (9 more...)
Summary In dipping reservoirs, such as those of the Louisiana gulf coast area, tertiary oil can be recovered by gravity-stable miscible CO2 solvent floods. Laboratory design of gravity-stable floods requires extensive experimental studies to select the proper composition and size of the injected CO2 solvent slug. In a gravity-stable process the injected CO2 solvent slug must be less dense than the oil and water under reservoir conditions. and the injected drive gas must be less dense than the CO2 solvent slug. Laboratory experiments showed that the CO2 solvent slug can be tailored to achieve the density required for a particular gravity-stable application by the addition of methane. Additional studies demonstrated that, if required, various hydrocarbons can be added to the CO2 solvent slug to ensure miscibility with the reservoir oil. Studies were performed to determine density and viscosity of the oil, CO2 solvent, nitrogen. and CO2 solvent/oil mixtures under reservoir conditions. A number of displacement tests at reservoir conditions were conducted in a 12.19-m [40-ft] slim-tube apparatus to determine the miscibility of various CO2 solvent mixtures with reservoir oil. Further floods were produced under reservoir conditions in a 3.66-m 112-ft] sandpack system. These floods were conducted at velocities less than the critical velocity to prevent growth of viscous fingers. The results show that after miscibility was achieved, the injected CO2 solvent mixture effectively removed all the residual oil left after waterflooding. The 3.66-m [12-ft] sandpack floods also provided data to determine dispersion parameters for the leading and trailing edges of the CO2 solvent slug. This information was used to estimate the CO2 solvent slug size for Texaco's gravity-stable CO2 solvent miscible flood in its Bay St. Elaine field, Terrebonne Parish, LA. Introduction A gravity-stable miscible CO2 process can be established in a dipping reservoir by updip injection of a properly designed CO2 solvent. Gravitational forces will stabilize the flowing front because of the density difference between the less dense injected CO2 solvent and the more dense displaced oil and water. A gravity-stable miscible CO2 process was designed at Texaco's Bellaire (TX) Research Laboratories for use in an EOR project at the Bay St. Elaine field. Terrebonne Parish, LA. The project is being conducted in the Miocene 8000 Foot Reservoir E Sand Unit (RESU). Table 1 presents sonic key reservoir data. Reservoir E is bounded on two sides by faults and is truncated updip by an unconformity. This reservoir, with its 36 degrees dip and confined nature. was determined a good EOR candidate for a gravity- stable CO2 miscible flood. Fig. 1 shows a cross section of Reservoir E between the CO2 Injection Well 22–26 and one of the downdip producers, Well 22–5. From the outset, the oil-recovery process envisioned was an updip injection of a CO2 solvent slug, followed by nitrogen drive gas. Once miscibility is established, an oil bank is formed, followed by an oil/CO2 solvent transition zone, CO2 solvent, the CO2 solvent/drive fluid (nitrogen) transition zone, and finally pure drive fluid. Various laboratory studies were performed to design and implement a gravity-stable process in the Bay St. Elaine field. These studies provided the necessary data to design the field project and to evaluate its feasibility and potential success. The laboratory studies conducted to obtain the design data for this project consisted of (1) a PVT study of the reservoir oil, (2) the CO2 solvent PVT properties at reservoir conditions, (3) the miscibility of the CO 2 solvent with reservoir oil at design conditions in slim-tube displacement tests, (4) the phase behavior of the CO2 solvent/oil mixture, and (5) sandpack floods to determine longitudinal dispersion coefficients and coninn miscible displacement of the reservoir oil by the selected CO2 solvent-that is, to determine linear displacement efficiency. This paper discusses each study. Laboratory Studies Reservoir Oil PVT Study. A PVT study of the Bay St. Elaine reservoir oil was performed to determine solution gas/oil ratio (GOR), bubblepoint pressure, formation volume factor (FVF), density. and viscosity as a function of pressure. For this project, the density and viscosity were the most important properties because of the basic design criteria for a gravity-stable flood. In late 1978, existing wells in the project area and adjacent segments were either off production in the 8000 Foot Sand or were not completed in this sand. Available wells producing from the 8000 Foot Sand in the nearby Segment 850 were on gas lift and could not be used to obtain an uncontaminated reservoir oil sample. JPT P. 111^
- North America > United States > Louisiana (1.00)
- North America > United States > Gulf of Mexico > Central GOM (0.74)
- North America > United States > Texas > Dimmit County (0.65)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Maverick Basin > Elaine Field > Anacacho Formation (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Eugene Island > Block 193 > Bay St. Elaine Field (0.99)
Response of North Cowden and Goldsmith Crudes to Carbon Dioxide Slugs Pushed by Nitrogen
Fischer, Daniel D. (Texas A and M U.) | Bilhartz, Dale (Texas A and M U.) | Holt, Charles (Texas A and M U.) | Johnson, Michelle (Texas A and M U.) | Breeze, B.J. (Texas A and M U.) | Aud, William W. (Texas A and M U.) | Crawford, Paul B. (Texas A and M U.)
Fischer, Daniel D.; Texas A and M U. Bilhartz, Dale; Texas A and M U. Holt, Charles; SPE, Texas A and M U. Johnson, Michelle; SPE, Texas A and M U. Breeze, B.J.; SPE, Texas A and M U. Aud, William W.; SPE, Texas A and M U. Crawford, Paul B.; SPE, Texas A and M U. Texas Petroleum Research Committee Summary Laboratory studies have been conducted to determine oil recovery of the North Cowden-Grayburg and Goldsmith 5,600-ft [1700-m] Clearfork crudes of west Texas when pushed by CO2 at various pressures. Studies were made at reservoir temperatures of 100 and 111 degrees F [38 and 44 degrees C] for the North Cowden and Goldsmith 5,600-ft [1700-m] crudes, respectively. At these temperatures, it was found that the oil recovery ranged from 57 to 99% as the CO2 pressure increased from 700 psi to 1,800 psi [4.8 to 12.4 MPa]. Normally the North Cowden crude gave a higher oil recovery throughout the pressure range. In recognition that CO2, may be in short supply, studies were made of the possibility of using a slug of CO2 pushed by nitrogen. For the slug tests the CO2 slugs ranged from 2.5% to 25% HCPV. All CO2 slugs were pushed by nitrogen. The oil recovery ranged from approximately 60 to 99% over this slug size. The data were obtained in slim-tube equipment ranging from 40 to 100 ft [12 to 30 m] in length. The miscible bank formed between the CO2 and the body of the crude oil was observed to be a clear strawcolored liquid. The analyses of the clear liquid and crude oil conclusively demonstratethat the crude oil undergoes a continuous fractionation process when miscibly displaced by CO2, the need for tong flow tests, and the inability to interpret most PVT cell data in terms of miscibility. Introduction Most U.S. reservoirs have been substantially depleted by primary production and many of these reservoirs are now in the terminal stages of waterflooding. If abandoned, these oil reservoirs may still leave more oil underground than they have produced. Tertiary oil recovery methods are being developed to recover a large fraction of the original oil in place. One of the enhanced recovery methods receiving consideration is a process whereby a slug of CO2 is injected to achieve miscibility with the crude oil and the CO2 slug is displaced with nitrogen. This method reduces the amount of CO2 required, stretches the CO2 supply, and usually reduces the cost. This would permit a wider application of the CO2 miscible recovery process and, we hope, recover additional oil from our reservoirs. Nitrogen may cost approximately one half as much per thousand cubic feet (Mcf) [28 m 3] as CO2. For many oil reservoirs, 1 Mcf 129 m3] of nitrogen may occupy about three times as much reservoir pore space as the same amount of CO2. Most of the known CO2 reserves are located in Colorado, New Mexico, Utah. and Mississippi. Much of the CO2 target oil is in the Permian Basin of west Texas and New Mexico. A pipeline will be required to transport CO2 to the prospective oil reservoirs. Several companies are moving forward with line construction. The hypothesized CO2 flood potential for west Texas alone has been estimated at 3 to 4 billion bbl [0.48 ⨯ 10(9) to 0.76 ⨯ 10(9) m3] of oil. This will require a lot of CO2. For a very thorough review of CO2 flooding, see Ref. 1, which cites more than 60 references. Whereas CO2 for miscible displacement is in short supply, nitrogen is plentiful. The nitrogen would be obtained from the air by a cryogenic process. In this process, air is compressed and subsequently cooled to approximately –300 degrees F [–184 degrees C]. At this temperature the air liquefies and permits fractionation and purification. The pure nitrogen is taken from the top of the fractionating column and warmed to a gaseous state near atmospheric temperature. The warm gaseous nitrogen is compressed for injection into the oil reservoir. JPT P. 96^
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
Summary Mitchell Energy Corp. has implemented a liquefied petroleum gas (LPG)/drive-gas miscible process in the Alvord (3000 ft Strawn) Unit in Wise County, TX, utilizing the U.S. DOE tertiary incentive program. The field has been waterflooded for 14 years and was producing near its economic limit at the time this project was started. This paper presents the results of the reservoir simulation study that was conducted to evaluate pattern configuration and operating alternatives to maximize LPG containment and oil recovery performance. Several recommendations resulting from this study were implemented for the project. On the basis of model predictions, tertiary oil recovery is expected to be between100,000 and 130,000 bbl [15 900 and 20 700 m3]or about 7% of the oil originally in place (OOIP) in the unit. An evaluation of the project performance through Dec.1981 is presented. This portion of the paper was written after drive-gas injection had just been initiated and represents only a preliminary evaluation of the project. In July 1981 the injection of a 16% hydrocarbon pore volume (HCPV) slug of propane was completed. Natural gas is being used to drive the propane slug. A peak oil response of 222 B/D [35.3 m3/d] was achieved in Aug.1981 and production has since been declining. This compares with a peak rate of 400 B/D [63.6 m3/d] during the waterflood, and an oil rate just prior to initiation of LPG injection of 7 B/D [1.1 m3/d]. The observed performance of the LPG flood indicates that the actual tertiary oil recovered will reach the predicted value, although the project life will be longer than expected. The results presented in this paper indicate that, without the DOE incentive program, the economics for this project would still be uncertain at this time. Introduction The Alvord (3000 ft) is approximately 10 miles [16 km]north of the town of Bridgeport in Wise County, TX(Fig. 1). The Alvord (3000 ft) Unit has been successfully waterflooded and was producing near its economic limit in Dec. 1979. A tertiary flood then was considered as an alternative to abandoning the field. Of the tertiary methods available, micellar flooding was eliminated from serious consideration because freshwater was not available and, according to published screening parameters, the calcium and magnesium concentrations were too high in the reservoir and supply water. CO2 was ruled out because of the question of miscibility at this depth and lack of supply. The LPG/drive-gas miscible process was chosen because miscibility could be achieved and convenient sources of LPG and natural gas were available. Economic risks were reduced because the DOE tertiary incentive program was available at that time. The LPG/drive-gas process has produced favourable results in waterflooded reservoirs in the past. The objective of this process in a waterflooded reservoir is to connect the residual oil with the injected LPG and displace it to the producing wells. The water must be displaced by the developing oil bank, the oil must be miscibly displaced by the LPG, and the LPG must be miscibly displaced by the drive gas. The mobility ratio is unfavorable at all flood fronts, and one should expect viscous fingering of the LPG into the oil bank and viscous fingering of the drive gas into the LPG bank. This is an important phenomenon and results in the rapid dissipation of small LPG slugs. When the reservoir is horizontal, the slug dissipation is faster because of stratification and gravity override. When the LPG slug is dissipated, the process reverts to an immiscible gas drive. In the early history of LPG flooding, the use of slugs that were too small probably prevented many projects from being as successful as expected. Several publications indicated that LPG slug sizes, on the order of 10 % HCPV or less, would be adequate for most reservoir situations. Later, others reported that because of viscous fingering, stratification, and gravity override, larger LPG slugs were needed. From the onset of this project it was felt that a successful project required a large LPG slug (about 20%HCPV). It was also recognized that a pattern flood configuration and operating procedure would have to be adopted that would prevent the mobilized oil and the displacing LPG solvent from migrating downdip into the aquifer. Thus a short simulation study was undertaken before embarking on the field project to evaluate alternative flood patterns and operating procedures and to estimate project recovery performance. General Field Description The field is in the central portion of the Fort Worth basin. It produces from an upper Pennsylvanian Strawn series sandstone, the Bryson sand, which was deposited by fluvial processes. A porous sand isopach of the Bryson sand is presented in Fig. 2. JPT P. 119^
- North America > United States > Texas > Wise County (0.44)
- North America > United States > Texas > Tarrant County > Fort Worth (0.24)
- North America > United States > Texas > Permian Basin > Midland Basin > Slaughter Field (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin > Parks Field > Pennsylvanian Formation (0.99)
- Asia > Middle East > Syria > Deir ez-Zor Governorate > Ward Field (0.99)
Summary This paper reviews implementation of a gravity-stable, miscible CO2 solvent flood in a reservoir located in the coastal marshes of south Louisiana. Key reservoir properties are presented, and field tests to determine residual oil saturation and to define reservoir limits and continuity are described. Unique equipment used to transport and inject the CO2 solvent is discussed along with the special instrumentation used for quality control. Also itemized are the regulatory agencies contacted and the permits acquired before the project could be implemented. Introduction Texaco U.S.A. initiated a gravity-stable, miscible CO2 solvent flood on Jan. 20, 1981, in the Bay St. Elaine field, Terrebonne Parish, LA (Fig. 1). The flood in the 8000 Foot Reservoir E Sand Unit (RESU) is being conducted to prove the effectiveness of gravity-stable, miscible CO2 solvent flooding in a steeply dipping, depleted sand. The results of this project will help to determine whether fieldwide CO2 flooding will be economical in similar south Louisiana reservoirs. The project consists of three wells-one injector and two producers. A structure map of the 8000 Foot RESU is shown in Fig. 2. Approximately 84.4 Mg/D [84.4 metric tons/d] CO2 solvent, consisting of CO2, methane, and normal butane, was injected into updip Well 22–26 over a 9-month period. The CO2 solvent slug occupied one-third of the reservoir PV. The CO2 solvent slug size and composition was designed by Texaco's Bellaire (TX) Research Laboratories. Nitrogen, used as a drive gas, is being injected into Well 22–26 to displace the CO2 solvent slug downdip in the reservoir. The CO2 solvent, as it moves downdip, will become miscible with the in-place residual oil. Production of tertiary oil will be from downdip Wells 22–5 and 22–31. An estimated 11 924.0 stock-tank m3 [75,000 STB] tertiary oil is expected to be produced from this depleted water-drive reservoir. The CO2 and n-butane were trucked in liquid states and off-loaded into storage tanks at Cocodrie, LA. These fluids were later transferred to similar storage tanks mounted on barges. The barges then were transported 11.3 km [7 miles] to the injection facility in the Bay St. Elaine field. The methane was obtained from the gas-lift system already in the field. The three components were mixed and injected into Well 22–26. Reservoir Description. The Bay St. Elaine field overlies a salt dome. The recoverable oil is found in numerous sands separated by shale layers. Fig. 3 is a typical electric log of the 8000 Foot Sand from Well 22–5. These sands dip steeply as a result of the upward movement of the salt dome. The 8000 Foot Sand is separated into segments by faults radiating from the salt dome. The 8000 Foot RESU varies in net sand thickness from about 9.1 m [30 ft] near the updip unconformity to about 30.5 m [100 ft] in the downdip portion of the project area. This Miocene sand exhibits high permeability and porosity. The reservoir oil has an 840-kg/m3 [36API] gravity and was produced at a normal GOR. The reservoir has a strong edgewater drive. Key reservoir parameters are presented in Table 1. The 8000 Foot RESU was determined a suitable candidate for a gravity-stable, miscible CO2 solvent flood for the following reasons. Well-Defined Reservoir. Reservoir E and Segment 790 are isolated from the rest of the 8000 Foot Sand by well-established faults. Well Availability. All wells in the two segments except Well 22–3 are completed in the 800 Foot Sand with no remaining primary or secondary potential. Well-Delineated Sand. The 12.7-cm [5-in.] log of Well 22–5 (Fig. 3) indicates significant shale breaks between the sands. The 8000 Foot RESU is not in communication with any other sand within the project area. Fairly Homogeneous Sand. The few shale streaks within the 8000 Foot Sand are not continuous, and the sand is uniform. Expansion Potential. Large reservoirs with millions of barrels of residual oil are adjacent to Segment 790 in both the 8000 Foot Sand and the 8050 Foot Sand (directly beneath the 8000 Foot Sand). The reservoir characteristics are quite similar and the same CO2 solvent flooding process can be used in these reservoirs. JPT P. 101^
- North America > United States > Texas > Dimmit County (1.00)
- North America > United States > Louisiana (1.00)
- North America > United States > Gulf of Mexico > Central GOM (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.94)
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.64)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Maverick Basin > Elaine Field > Anacacho Formation (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Eugene Island > Block 193 > Bay St. Elaine Field (0.99)