Abstract The Olympic oil pool is in Hughes and Okfuskee counties, Oklahoma, about 50 miles southeast of the center of the state. Oil in the Olympic sand was discovered in January, 1935, by the Manahan Oil Company's Dixon-A No. 1 in the northeast corner of the SW. j, NW. } of Sec. 12, T. 9 N., R. 8 E. Oil was discovered here in the Cromwell sand, however, in July, 1934, by the Olympic Oil Company's McCaslin No. 1 in the southeast corner of the NW. J, NW. } of Sec. 12, T. 9 N., R, 8 E. The oil-bearing Olympic sand is a lens; it has a plane base and a convex top. The sand body is approximately miles long and ranges from S to ii miles wide; it lies at depths ranging from 1,750 to 1,950 feet. The oil pool in the Olympic sand covers an area of 3,500 acres; 349 wells have been drilled and 17 producers have been abandoned. A total of 10,794,694 barrels of oil had been recovered from the pool by January 1, 1941. Three new wells have been drilled and completed in 1938 as gas-repressure wells and three oil wells have been converted into gas-repressure wells. Gas is being injected into the oil sand in each of these wells at the rate of 250,000 cubic feet per day.

Abstract The Teapot Dome oil field in the Powder River Basin of Wyoming has been proposed as a test site for experimentation with CO 2 sequestration as part of enhanced oil recovery. Because of the solubility and reactivity of CO 2 with formation waters, its migration will be attenuated. The increased pressure necessary for appreciable rates of gas injection will result in considerable potential for migration of CH 4 and light paraffins. Baseline measurements were made of gas microseepage at the Teapot Dome oil field with CH 4 and light paraffin seepage being found, which is generally associated with faults (Klusman, 2005 , 2006 ). Microbial oxidation of the hydrocarbons to CO 2 in the unsaturated zone is occurring, which mostly prevents leakage of hydrocarbons into the atmosphere. The interpretation of the processes operating was supported by isotopic measurements. A two-phase displacement model was used to simulate gas seepage to the surface at various pressures from the Tensleep, Second Wall Creek, and the Shannon formations to the surface. Hydrocarbon concentrations and fluxes at the top of the saturated zone were estimated, with fluxes increasing by a factor of seven for CH 4 and a factor of three for n-C 4 H 10 by increasing reservoir pressure from hydrostatic to 1.4 × hydrostatic. Concentrations at the top of the saturated zone increased only slightly with increasing pressure. Smaller changes in flux and hydrocarbon concentrations resulted in the pressurization of the shallower Second Wall Creek formation. The current underpressured condition of the Second Wall Creek allows for the significant attenuation of microseepage if the Tensleep formation was pressurized and used for CO 2 sequestration. The system is dynamic, responding to rates of change in reservoir pressures, and responding to the periods of time that pressures are held. The very shallow Shannon reservoir is also currently underpressured, but modeling indicates that it cannot withstand repressurization without significant gas seepage.

Abstract Laboratory flows, self-capped by high-viscosity fluid, exhibit vertical pressure gradients similar to those postulated within conduits feeding dome-building eruptions. Overpressure and pressure cycles exhibited at laboratory scale provide insight into the mechanism of tilt cycles at volcanic scale. Experimental pressure cycles correlated with the rate of gas escape, with pressure rise being controlled by diffusion of volatile into bubbles during times when gas escape from the flow was negligible. The increase in pressure continued until margin decrepitation created preferential pathways for rapid gas escape from permeable foam, thereby reducing pressure within the flow. As pressure reduced, the gas escape pathways sealed and diffusion repressurized the system. This implies that tilt cycles, such as those exhibited by the Soufrière Hills Volcano, Montserrat, result from a diffusively pumped process that oscillates around the viscous-elastic transition within the outer regions of the flow. Phases of open- and closed-system degassing result, with gas escaping through fractures created and maintained by the flow process itself. Fluid-dynamically, this mechanism generates an oscillation between Poiseuille flow and plug flow, with a 1-D model of plug motion giving a reasonable representation of observation in both experimental and volcanic cases.

ABSTRACT Surface subsidence due to reservoir compaction during production has been observed in many large oil fields. Subsidence is most obvious in coastal and offshore fields where inundation by the sea occurs. Well known examples are Wilmington field in California and Ekofisk field in the North Sea. In South Belridge field the Belridge diatomite member of the late Miocene Reef Ridge Shale has proven prone to compaction during production. The reservoir, a high porosity, low permeability, highly compressive rock composed largely of diatomite and mudstone, is about 1000 ft thick and lies at an average depth of 1600 ft. Reservoir compaction within the Belridge diatomite due to withdrawals of oil and water in section 12, T28S, R20E, MDB&M, was noticed after casing failures in producing wells began occurring and tension cracks, enlarged by hydrocompaction after a heavy rainstorm, were observed. Surface subsidence in section 12 has been monitored since April, 1987, through the surveying of benchmark monuments. The average annualized subsidence rate during 1987 was -1.86 ft/yr, -0.92 ft/yr during 1988, and - 0.65 ft/yr during 1989; the estimated peak subsidence rate reached -7.50 ft/yr in July 1985, after l½ yrs of production from the Belridge diatomite reservoir. Since production from the Belridge diatomite reservoir commenced in February, 1984, the surface of the 160 acres producing area has subsided about 12.50 ft. This equates to an estimated reservoir compaction of 30 ft in the Belridge diatomite and an average loss of reservoir porosity of 2.4% from 55.2% to 52.8%. Injection of water for reservoir pressure maintenance in the Belridge diatomite began in June, 1987, and has been effective in mitigating subsidence and repressurizing the reservoir to near-initial pressure. An added benefit of water injection has been improved recovery of oil from the Belridge diatomite by waterflood. The operation of four other water injection projects in South Belridge Field in the Belridge diatomite reservoir suggests that reservoir compaction and surface subsidence is a common occurrence in the field.

Abstract Carbonate reservoirs are characterized by extremely heterogeneous porosity and permeability. These heterogeneities are caused by the wide spectrum of environments in which carbonates are deposited and by subsequent diagenetic alteration of the original rock fabric. Pore systems range from thick, vuggy reservoirs in the coarse-grained skeletal-rich facies of the reef margin or platform margin to highly stratified, often discontinuous, reservoirs in the reef interior, platform interior, and nearshore facies. Eight fields from the western Canada basin have been selected to illustrate the variety of reservoir configurations which can be found. Boundary Lake field and Steelman field are thinly bedded sequences of cyclic nearshore carbonates which are best suited to pattern waterflood. Quirk Creek field is a thick, overthrusted open platform gas pool in which fractures associated with the leading edge of the structure provide high deliverability in an otherwise low permeability reservoir. Clarke Lake field is a fractured, dolomitized platform margin gas reservoir which is highly susceptible to water channeling. Golden Spike, Judy Creek, Norman Wells, and Redwater fields are reef bioherms which display the classic reservoir configuration of highly permeable reef margin facies enclosing strongly stratified reef interior sediments. With increasing reef size, the relative volume occupied by oil becomes smaller and the aquifer becomes larger and more effective. Golden Spike field was entirely filled with oil when discovered and early production was characterized by rapidly declining pressure. An initial gas flood depletion plan was followed by a gravity-controlled, gas-driven miscible flood. This was very effective until the miscible bank was broken up and dispersed by several thin impermeable beds in the reef interior, which proved to be barriers to vertical flow. Judy Creek field had a small ineffective original aquifer and was produced initially by a downdip peripheral waterflood. This ultimately proved to be ineffective in repressuring the discontinuous porosity in the reef interior and was supplemented with a pattern waterflood. Depletion plans for these pools require detailed, integrated geological-engineering studies to develop accurate reservoir models. These models are then used in computer simulation studies to forecast reservoir behavior under various depletion methods and to assist in ongoing reservoir surveillance studies.

Abstract Land subsidence due to fluid withdrawal has been reported from many parts of the world. It has de-veloped most commonly in overdrawn groundwater basins, but subsidence of serious proportions also has occurred in several oil and gas fields. Subsidence due to groundwater overdraft occurs in many places in Japan, where it has caused dangerous environmental conditions in several heavily populated areas. For example, in Tokyo, 2 million people in an area of 80 sq km now live below mean high-tide level; subsidence is only partially controlled, and the difficulties of achieving full control are great. The San Joaquin Valley in California is the area of the most intensive land subsidence in the United States. Subsidence, which affects 4,200 sq mi (10,875 sq km), reached 28 ft (8 m) in 1969. The total volume of subsidence to 1970 was about 15.5 million acre-ft. Surface-water imports to subsiding areas have reduced groundwater extractions and raised the artesian head, causing subsidence rates to decrease. In the Santa Clara Valley at the south end of San Francisco Bay, excessive pumping of groundwater between 1917 and 1967 caused as much as 180 ft (50 m) of artesian-head decline and maximum land subsidence of 13 ft (4 m). A fourfold increase in surface-water imports in 5 years has achieved a dramatic rise of artesian head—70 ft (20 m) in 4 years. Subsidence rates have decreased from as much as 1 ft (0.3 m) per year in 1961 to a few hundredths of a foot in 1970. Wilmington oil field, in the harbor area of Los Angeles and Long Beach, California, is not only the oil field of maximum subsidence (29 ft or 9 m) in the United States, but also the outstanding example of subsidence control by injection and repressuring. Large-scale repres-suring was begun in 1958 by use of injection water obtained from shallow wells. Subsidence of some bench marks was stopped by 1960. By 1969, when 1.1 million bbl of water per day was being injected into the oil zones, the subsiding area had been reduced from 20 to 3 sq mi (52 to 8 sq km) and parts of the area had rebounded by as much as 1 ft (0.3 m). Methods employed to measure the change in thickness of sediments compacting or expanding in response to change in effective stress include (1) depth-benchmark and counterweighted-cable or “free”-pipe extenso-meters with amplifying and recording equipment; (2) casing-collar logs run periodically in a cased well; and (3) radioactive bullets emplaced in the formation behind the casings at known depths and resurveyed by radioactive detector systems at a later time. In evaluation of potential land subsidence due to fluid withdrawal, an essential parameter is the compressibility of compactible beds. When effective (grain-to-grain) stress exceeds maximum prior (preconsolidation) stress, the compaction is primarily inelastic and nonrecoverable, and the virgin compressibility may be 50–100 times as large as the elastic compressibility in the stress range less than preconsolidation stress. If fluid pressures in a compacting, confined system are increased sufficiently to eliminate excess pore pressures in the fine-grained sediments, subsidence will stop. If fluid pressures continue to increase, the system will expand elastically and the land surface will rise.