Geopressured Reservoirs Research Articles

Paragenesis of an Orogenic Gold Deposit: New Insights on Mineralizing Processes at the Grass Valley District, California

Abstract The Grass Valley orogenic gold district in the Sierra Nevada foothills province, central California, is the largest historical gold producer of the North American Cordillera. Gold mineralization is associated with shallowly dipping north-south veins hosted by the 160 Ma Grass Valley granodiorite to the southwest of the Grass Valley fault and steeply dipping east-west veins in accreted oceanic rocks to the northeast of this major fault. Quartz veins from both vein types show well-preserved primary textural relationships. Using a combination of petrographic and microanalytical techniques, the paragenetic sequence of minerals within the veins and the compositions of ore minerals were determined to constrain the mechanisms of quartz vein formation and gold deposition. The veins are composed of early quartz that formed through cooling of hydrothermal fluids derived from a geopressured reservoir at depth. The early quartz shows growth zoning in optical cathodoluminescence and contains abundant growth bands of primary inclusions. The primary inclusion assemblages and myriads of crosscutting secondary fluid inclusions have been affected by postentrapment modification, suggesting that early quartz formation was postdated by pronounced pressure fluctuations. These pressure fluctuations, presumably involving changes from lithostatic to hydrostatic conditions, may be related to fault failure of the host structure as predicted by the fault-valve model. Fluid flow associated with pressure cycling took place along microfractures and grain boundaries resulting in extensive recrystallization of the early quartz. Deposition of pyrite, arsenopyrite, and first-generation gold from these hydrothermal fluids causing recrystallization of the early quartz occurred as a result of wall-rock sulfidation. The gold forms invisible gold in the compositionally zoned pyrite or micron-sized inclusions within pyrite growth zones. The latest growth zones in euhedral quartz crystals that formed in association with this stage of the paragenesis contain very rare primary fluid inclusions that have not been affected by postentrapment modification. The hydrothermal system transitioned entirely to hydrostatic conditions immediately after formation of the latest quartz, explaining the preservation of the primary fluid inclusions. The formation of minor quartz in open spaces was followed by the deposition of second-generation native gold and telluride minerals that are commonly associated with base metal sulfides. Ore formation at this stage of the paragenesis is attributed to the rapid decompression of hydrothermal fluids escaping from the geopressured part of the crust into the overlying hydrostatic realm. There is no fluid inclusion evidence that this pressure drop resulted in fluid immiscibility of the hydrothermal fluids. Fluid inclusion evidence suggests that the north-south veins formed at a paleodepth of ~8 km, whereas the east-west veins appear to have formed at ~10 to 11 km below surface, confirming previous inferences that the NE-dipping Grass Valley reverse fault accommodated a large displacement. The findings of the study at Grass Valley have significant implications for the model for orogenic gold deposits, as the reconstruction of the paragenetic relationships provides evidence for the occurrence of two discrete events of gold introduction that occurred at different conditions during the evolution of the hydrothermal system.

Modeling coupled convection and carbon dioxide injection for improved heat harvesting in geopressured geothermal reservoirs

Geopressured geothermal saline aquifers are an abundant low-enthalpy geothermal energy resource available in many coastal regions including the US Gulf of Mexico. In such geographic areas thick geopressured sandstones (up to several hundred meters thick) hold tremendous geothermal heat with conservative estimates of gross extractable energy approximately 0.2 EJ per cubic kilometer of the formation. Additionally, widespread geopressure in sedimentary deposits of the Gulf region preserves favorable petrophysical properties of unconsolidated sandstones such as high porosity and permeability, thus, enhancing productivity and economics of potential heat harvesting projects. In this study we investigate the potential of a typical geopressured reservoir in the US Gulf coast to deliver commercial quantities of geothermal heat with the possibility of simultaneous supercritical CO2 sequestration into the same formation. Specifically, we focus on numerical simulation study of heat extraction from a model based on the Camerina A sand of South Louisiana. In our numerical experiments, we consider both theoretical and practical implications of combining a traditional heat harvesting method with supercritical CO2 injection. Moreover, this study pays specific attention to the effect of natural convection due to the formation’s tilt and uneven heating at the reservoir boundaries and its impact on the forced convection due to geofluid withdrawal. The numerical simulation results suggest that introduction of supercritical CO2 might have an observable positive effect on the ultimate heat recovery and that a strategic injection/production well placement might further enhance density-driven flows inside the geothermal formation.

Results of Reservoir Modeling of the Operation and Production of a Recompleted Gas Well in a Geopressured/Geothermal Reservoir in the Wilcox Formation, Texas, for Electricity Generation

Abstract Reservoir modeling of production of hot geothermal fluid and natural gas from a geopressured reservoir in the Wilcox formation, Texas, for geothermal-electricity generation is carried out primarily on the basis of well-log data. The reservoir modeling takes into account operational considerations such as a constant target flow rate, a 30-year reservoir lifetime, and minimum wellhead pressure as well as uncertainty in reservoir parameters such as gas saturation and reservoir volume. The results of the reservoir modeling are presented and their relevance to other similar geopressured/geothermal wells with the potential for natural-gas production is discussed.

Long-Zone Squeeze Gravel Packs in Geopressured Reservoirs in the Gulf of Mexico

Summary Laboratory studies were conducted to determine the completion techniques for two wells in the Gulf of Mexico with well angles of 35 to 45°, completion intervals of about 400 ft, bottomhole temperatures of 222°F, and requiring a completion brine with density up to 17.0 lbm/gal. Three critical issues—fluid-loss control, pregravel-pack acid stimulation, and internal gravel packing—were studied. Laboratory studies showed that an activated hydroxyethyl-cellulose (HEC) pill could be designed to control the fluid loss for more than 30 hours, even at a bottomhole temperature of 222°R In addition, a high-rate acid stimulation could be employed to ensure that as many perforations as possible were open to accept gravel-pack sand. Physical model studies also showed that a high-rate squeeze waterpack provided the required effective perforation and annular packing for the target wells despite the long completion interval. These techniques were successfully implemented. Initial production data suggest that both wells, still under choke, are producing at expected rates, with low downhole drawdown.

A Type-Curve Matching Procedure For Material Balance Analysis Of Production Data From Geopressured Gas Reservoirs

Abstract The performance of a normally-pressured gas reservoir depends on gas compressibility effects and water influx. Generally, a straightforward material balance analysis is possible for a normally-pressured gas reservoir to estimate the initial gas-in-place. However, for an abnormally-pressured (or geo-pressured) gas reservoir, material balance analysis is not as simple. Factors complicating the performance of a geo-pressured gas reservoir are water and rock compressibility effects, and shale water influx.. These factors often cause an overestimated value of the initial gas-in-place from a p/z-Gp graph of the early production performance. Over the years, several corrections have been proposed to accurately estimate the initial gas-in-place. These corrections are based on different forms of material balance equation. This paper uses a material balance equation that applies to both normally-pressured and geo-pressured gas reservoirs. This material balance equation demonstrates that the non-linearity on a p/z-Gp graph for a geo-pressured reservoir is due to a term containing p2/z. A new type-curve matching procedure has been developed to analyze the production performance of a geo-pressured gas reservoir. An example application for using the new method is presented. Introduction A normally-pressured gas reservoir exhibits an initial pressure gradient close to the pressure gradient for water (generally about 9.7 to 11.3 kPa/m). The production performance of a normally-pressured gas reservoir depends on gas compressibility effects and water influx. The effects of water and rock compressibilities are usually neglected while analyzing the performance of a normally-pressured gas reservoir. However, an abnormally-pressured (super-pressured, over-pressured or geo-pressured) gas reservoir exhibits an initial pressure gradient far in excess of typical water column pressure gradient. Prasad and Rogers(1) report initial pressure gradient as large as 21.7 kPa/m for a geo-pressured gas reservoir. A typical geo-pressured gas reservoir may exhibit an initial pressure gradient between 14.7 to 19.3 kPa/m. Though geo-pressured gas reservoirs may be encountered in all parts of the world, several geo-pressured reservoirs exist in the Gulf Coast area of Louisiana and Texas(2,3), Andarko basin, Delaware basin, and the Rocky Mountain area of the United States(1). For a deep, geo-pressured gas reservoir, water and rock compressibilities may be close to gas compressibility during the initial stages of production. Thus, any material balance analysis of early production data from a geo-pressured gas reservoir must include water and rock compressibility effects. This study is limited to volumetric (no water influx or water production) normally- and/or abnormally-pressured gas reservoirs. This study uses a material balance equation that applies to both normally-pressured and geo-pressured gas reservoirs. This material balance equation forms the basis of a new type-curve matching procedure to analyze the production performance of a geo-pressured gas reservoir. Material Balance Equation for Volumetric Gas Reservoirs Bourgoyne et al.(4) derived a material balance equation for a geo-pressured gas reservoir as: Equation (1) (Available In Full Paper) Where: Equation (2) (Available In Full Paper) Equation (3) (Available In Full Paper) Equation (4) (Available In Full Paper) Equation (5) (Available In Full Paper) Equation (1) and the resulting type-curve (to be discussed later) only account for the non-linear aspects of the te

Gladys McCall Geopressured Reservoir Analysis—June 1987

The Gladys McCall geopressured reservoir consists of an interbedded sequence of relatively thick sands and thin shales. The lateral extent of the reservoir is not well defined. Gladys McCall Well No. 1 produced approximately 4.0×106 m3 (25×106 barrels) of brine from Sand Zone No. 8 from October 7, 1983 through May 1987. Analysis of the flow data from the well has led to the development of a conceptual model of the reservoir, which depends on cross-flow from sands overlying/underlying Sand Zone No. 8 for the observed pressure maintenance. The fluid source is remote from the well in the sense that the fluid from the neighboring sands must flow a long distance to find a vertical pathway around the intervening shale stringers in order to recharge Sand Zone No. 8. A reservoir simulation model based on the conceptual model provides an excellent match to the detailed downhole pressure buildup measurements made during the original Reservoir Limits Test and two subsequent short-term buildup tests. The model has also been employed to match the production history of the Gladys McCall No. 1 well and to predict future reservoir response. Nevertheless, the reservoir model employed is not unique and alternate models for pressure maintenance are also being investigated.

High-angle reverse faults, fluid-pressure cycling, and mesothermal gold-quartz deposits

Many mesothermal gold-quartz deposits are localized along high-angle reverse or reverse-oblique shear zones within greenstone belt terrains. Characteristically, these fault-hosted vein deposits exhibit a mixed brittle-ductile style of deformation (discrete shears and vein fractures as well as a schistose shear-zone fabric) developed under greenschist facies metamorphic conditions. Many of the vein systems are of considerable vertical extent (>2 km); they include steeply dipping fault veins (lenticular veins subparallel to the shear-zone schistosity) and, in some cases, associated flats (subhorizontal extensional veins). Textures of both vein sets record histories of incremental deposition. We infer that the vein sets developed near the roofs of active metamorphic/magmatic systems and represent the roots of brittle, high-angle reverse fault systems extending upward through the seismogenic regime. Friction theory and field relations suggest that the high-angle reverse faults acted as valves , promoting cyclic fluctuations in fluid pressure from supralithostatic to hydrostatic values. Because of their unfavorable orientation in the prevailing stress field, reactivation of the faults could only occur when fluid pressure exceeded the lithostatic load. Seismogenic fault failure then created fracture permeability within the rupture zone, allowing sudden draining of the geopressured reservoir at depth. Incremental opening of flats is attributed to the prefailure stage of supralithostatic fluid pressures; deposition within fault veins is attributed to the immediate postfailure discharge phase. Hydrothermal self-sealing leads to reaccumulation of fluid pressure and a repetition of the cycle. Mutual crosscutting relations between the two vein sets are a natural consequence of the cyclicity of the process. Abrupt fluid-pressure fluctuations from this fault-valve behavior of reverse faults seem likely to be integral to the mineralizing process at this structural level.

The Economic Potential of Reinjection Into Geopressured Aquifers

Summary This paper evaluates the technical potential, the energy balance, and the economics of reinjecting produced brines into geopressured/geothermal aquifers. This analysis of reinjecting brines shows that, depending on the hydraulic turbine technology, 50 to 90% of the power requirements of reinjection into the producing aquifer can be met by extracting the thermal and kinetic energy from the produced geopressured/geothermal brines. Moreover, the technically recoverable methane resource could be increased 20 times by reinjecting the brines into the producing formation, compared to using more conventional disposal options. In addition, the reinjection of brines would reduce the potential for environmental damage. Reinjecting the produced brines could enable geopressured aquifers to become economical in the future, particularly when the gas content of the produced bane is relatively large. In addition, the resource will become produced bane is relatively large. In addition, the resource will become more economical as real energy prices increase, since a reinjection-based system, to a large degree, will be independent of outside purchased power. However, because of high costs and risk, geopressured aquifers are not yet an economically competitive energy source. Introduction Geopressured aquifers have been estimated to contain an in-place resource of 1,800 Tcf [51 × 10 12 m3] of methane in Texas and 1,300 Tcf [37 × 10 12 m3] in Louisiana in the onshore sandstones. Another 2,600 Tcf [74 × 10 12 m3] is estimated in the offshore sandstones. Because of the large size of this unconventional gas resource, efforts have been directed toward establishing the amount of gas that is economically and technically recoverable and the alternative technologies for producing these high-pressure, high-temperature formations. This work has included efforts by the U.S. DOE to drill wells specifically for testing and producing geopressured formations (design wells) and to collect information on dry wells drilled in the search for oil or gas that have penetrated geopressured formations (wells of opportunity). Earlier studies on the economics of producing methane from geopressured brines have concluded that the resource is marginally economical because of high capital costs, unproved technology, and the small net energy gain associated with only capturing the dissolved methane. Further, since the reservoir energy is sufficient to produce only 1 to 4% of the water in place, a viable project requires giant reservoirs of 3 cu miles [12.5 km3] or more, containing more than 1 billion bbl [0.16 × 10 9 m3] of water in place. One way to increase the attractiveness of the geopressured aquifers is to use the associated thermal and kinetic energy to reinject the brines back into the producing aquifers. This total energy system would have the following benefits. 1. It would lead to a greater recovery of the resource. 2. Environmental effects, such as subsidence, would be minimized. 3. Reservoirs that are an order of magnitude smaller than the "giants"could become feasible resource targets. 4. The productive life of the geopressured reservoirs would be extended greatly. 5. The use of the thermal and kinetic energy would reduce the need to purchase outside power for reinjection. Fig. 1 is a line diagram of a total energy system. The produced geopressured brines initially are flowed through a hydraulic turbine. As the pressure is reduced, kinetic energy is converted into electric power, and the released methane is captured in a gas/water separator. The brines then flow through a heat exchange where the thermal energy is extracted before they are reinjected. This paper examines the use of such a total energy system and the technical and economic potential of reinjection into producing geopressured/geothermal aquifers. producing geopressured/geothermal aquifers. Sample Reservoirs The analysis is based on five actual geopressured aquifers (in Texas and Louisiana) on which data have been gathered. The reservoir parameters of these five sample reservoirs are shown in Table 1. These parameters are based on published values and personal communication. The geopressured waters were assumed fully saturated with methane, and the gas content was derived from published correlations, allowing for temperature, pressure, and salinity differences (Fig. 2). The geopressured reservoirs are all hydrocarbon-bearing reservoirs larger than normal, and have high temperatures, pressures, and salinities. The first three represent shallow geopressured, deep geopressured, and ultradeep geopressured reservoirs in Texas; the last two represent shallow geopressured and deep geopressured reservoirs in Louisiana. JPT p. 1164

Cenozoic Shelf Margins, Northwestern Gulf of Mexico: ABSTRACT

Syndepositional gravity tectonics in the northwestern Gulf of Mexico basin have obscured the geometry of Tertiary shelf-slope stratification and thereby inhibited the recognition of relict shelf edges. However, examination of the modern shelf margin, formed primarily by deltaic deposition during the late Pleistocene lowstand of sea level, can lead to alternative criteria for recognizing Tertiary shelf margins. Late Pleistocene shelf-margin deltas, in contrast to inner-shelf deltas, are characterized by rapid subsidence and growth faulting, thick progradational cycles, and steep clinoform stratification. High subsidence rates result from deep-seated gravity sliding of the continental slope, which creates a strongly extensional regime along the shelf margin. Many downdip Te tiary formations are similarly characterized by large growth faults with high expansion ratios in deltaic sequences; hydraulic isolation of shallow-water sandstones by large fault offsets leads to overpressuring. These structurally-complex downdip trends, typically with geopressured gas reservoirs, represent the shelf-margin megafacies. Mapping of these shelf-margin trends provides a concise summary of the Cenozoic depositional and structural history of the basin. Major influxes of sand to the shelf margin correspond to episodes of rapid progradation and are interpreted as large shelf-margin deltas. Pre-Pleistocene shelf-margin deltas do not appear to be synchronous across the basin, and therefore are probably a function of sediment supply rather than sea-level fluctuations. The three largest such Tertiary delta complexes can be correlated with major tectonic episodes in likely source areas in western North America: (1) the late Paleocene (lower Wilcox) Rockdale delta system in east Texas coincides with the major pulse of Laramide uplift in the southern Rockies; (2) the mid-Oligocene (Frio) Norias delta system in sou h Texas coincides with extensive ash-flow volcanism in the Sierra Madre Oriental; and (3) the Neogene ancestral Mississippi delta system in Louisiana coincides with reactivation of the southern Rockies and regional uplift. End_of_Article - Last_Page 1440------------

Geopressured Geothermal Energy--Geological Setting and Constraints to Development Along Northwestern Gulf Coastal Plain: ABSTRACT

Wide-ranging estimates of the magnitude and economic viability of the geopressured geothermal resource along the Gulf Coast have resulted in the establishment of significant research efforts in Texas and Louisiana. The energy resource consists of the heat and pressure of water, and the dissolved methane. The amount of methane in solution is directly related to the temperature, pressure, and salinity. Major questions being addressed by this research relate to prediction of subsurface fluid salinity and reservoir deliverability (size of contiguous sandstone unit, permeability, rock compressibility). Success of the geopressured geothermal resource development is dependent upon identifying large, geopressured sandstone reservoirs with high permeability (20 md or greater), high temperature (higher than 250°F or 121°C), and low salinity (lower than 60,000 ppm). Extensive studies in Texas and Louisiana show that areas with favorable combinations of all these parameters are difficult to find. Subsurface data indicate that thick sandstones of the main-sand depocenters are, in most areas, not geopressured. Geopressured reservoirs, for the most part, lie gulfward within growth-faulted, delta-front sequences consisting of thick shales and thinner sandstones. Most wells which penetrate this delta-front section show that fluid temperature and pressure increase, and salinity decreas s, with depth; sandstone reservoir thickness and permeability decrease with depth. Therefore, the ideal geopressured geothermal reservoir is an exception and a compromise must be made. Despite the limitations of locating an ideal reservoir, several short-term deep tests by industry have provided encouragement. More extensive long-term testing, now underway through the U.S. Department of Energy geopressured-geothermal Designed-Well Program, is providing answers to some of the questions. End_of_Article - Last_Page 897------------

Existence and Flow Behavior of Gas at Low Saturation in U.S. Gulf Coast Geopressured Brine Zones

The first geopressured brine well tested for the U.S. DOE produced gas and brine at a ratio far above the solution ratio for the gas in that brine. Potential explanations for that behavior are examined in this paper. Introduction The geopressured brine formations along the U.S. gulf coast contain an extremely large potential resource of heat and dissolved methane. These highly faulted formations are broken into thousands of individual reservoirs. Can these be exploited commercially for heat and methane? To help determine the answer to this question, the U.S. DOE is funding the conduct of sampling and flow tests in selected geopressured reservoirs. The purpose of these tests is to obtain sufficient data on the feasibility of commercial exploitation. The first well tested under the DOE program was Edna Delcambre No. 1 in Vermillion Parish, LA, in June 1977. This well had been a conventional gas producer from deep geopressured zones. It was plugged back and tested in two shallower zones by OHRW Engineering for the DOE. A very interesting and potentially very important phenomenon occurred during flow testing of this well. The well had been expected to produce geopressured twine, probably saturated with methane. However, both Sands 1 and 3 (Figs. 1 and 2) produced gas (mainly methane) at a gas/liquid ratio (GLR) far above the solution ratio. Only about 20 to 24 scf of produced gas could be dissolved in each barrel of produced water in laboratory recombination studies. However, both sands produced gas and water at ratios up to 50 to 60 cu ft/bbl for extended periods. A number of explanations have been advanced to explain this behavior. In the case of Sand 3, the streak of high resistivity rock near the top (the interval 12,873 to 12,876 ft in Fig. 1) is almost certainly gas bearing. Running of the TDT log and analysis of this log and the resistivity log has confirmed this first interpretation and has indicated that this interval is probably both tight and gas bearing. A more complete discussion of the behavior during flow testing is given in this paper. The behavior of Sand 1 is more puzzling. There is no evidence from logs that the sand is gas bearing. One possible explanation is that gas production is from the gas cap that exists updip of the top of the completion interval in Sand 1 (Fig. 3). Production of water could have "coned" the gas down into the well. It is also possible that gas from Sands 2 or 3 (Fig. 1) reached Sand 1 because of a poor cement job in the cemented liner that exists in the interval between Sands 1 and 3. Practice has shown that it is very difficult to obtain a perfect cement job when landing and cementing a liner at these depths. Rogers and Randolph believed the source of the gas produced in Sand 1 is from a prior blowout in a nearby well. Still another intriguing explanation of the gas production from Sand 1 is that gas exists throughout Sand 1 but at a very low saturation of about 2 to 5%. At such low saturation, the gas would not flow when there was no pressure gradient. However, when the well was placed on production and a pressure gradient established, it has been postulated that this gas might flow. This last explanation is examined in this paper. JPT P. 2214＾

Energy Resources of Water-Bearing Geopressured Reservoirs-Tertiary Formations, Northwestern Gulf of Mexico (Summary)

Estimates for the total gas resource in place in geopressured Tertiary sandstone reservoirs along the United States Gulf Coast range from 3,000 to 100,000 tcf 185 to 2,832 trillion cu m). This wide range in estimates was the incentive for initiative research effort in Texas and Louisiane to obtain more reliable data on all aspects of developing the available heat and hydraulic energy present in these aquifers in addition to the methane. All resource calculations are based on interpretations of total sandstone thickness, lateral extent of reservoirs, porosity and permeability, reservoir drive, salinity, temperature, pressure, and methane solubility. Diverse estimates arise from inadequate knowledge concerning these critical parameters. Regional and detailed local geologic studies have been conducted ta delineate prospective areas for testing the geopressured resource. A prospective area should have reservoir volume of 3 Cu mi (12 cu km), minimum permeability of 20 mD, and fluid temperatures of 300°F (150°C). A geothermal designed test well has been drilled in Brazoria County, Texas, in order to test the potential of producing up to 40,000 barrels of water per day from a geopressured reservoir. The reservoir consists of 250 to 300 ft (75 to 90 m) of sandstone with core permeabilities between 40 and 60 mD and fluid temperatures from 300 to 350°F (159 to 177°C). The test period will continue for a 2-year period and, with other designed tests in Texas and Louisiana will provide invaluable data concerning high-volume production over long periods of time.

The Technology and Economics of Methane Production From Geopressured Aquifers

Doscher, T.M., SPE-AIME, U. of Southern California Osborne, R.H., U. of Southern California Wilson, T., U. of Southern California Rhee, S.,* SPE-AIME, U. of Southern California Cox, D., SPE-AIME, Energy Consulting Assocs. Kuuskraa, V., SPE-AIME, Lewin and Assocs. This study of the economic potential of methane production from geopressured aquifers leads to the conclusion that profitable exploitation of such reservoirs is not likely to occur in the near future, mainly because of the great reservoir size required to sustain economic production rates and the cost of disposing of spent brines. Introduction The purpose of this study was to estimate the cost of producing methane (natural gas) from geopressured producing methane (natural gas) from geopressured aquifers inland from and along the coast of the Gulf of Mexico. No other economic values of the geopressured brines were considered for exploitation.There were several component tasks of such an overall analysis that had to be completed in order to arrive at the final conclusion.1. An estimate of the reservoir parameters of the geopressured aquifers: areal extent, net thickness of productive sand, porosity, permeability, and effective compressibility. These parameters determine the production rates and the total recovery that may be expected within an economic time frame.2. An estimate of the production rates and cumulative production of geopressured aquifers having reservoir properties in the range of values determined by the first task.3. An estimate of the operating and capital costs of drilling wells and producing such geopressured aquifers. A significant part of the operating costs is the cost of disposing of large quantities of produced brines following desorption of the methane.4. An estimate of the sales price of the recovered methane using appropriate discount rates.This study has revealed that the selling costs of methane recoverable from geopressured brines, before federal income taxes and the amortization of development costs prior to commercialization, would range from $4 to $15/Mcf and possibly higher.These results follow from the ranges of the values that could be attributed to the various reservoir parameters and the application of reservoir parameters and the application of reservoir engineering principles. A 15% rate of return was set as the reward for the capital investment before imposition of federal taxes and precommercialization development costs. Capital and operating costs are those prevailing during 1977, except for the direct cost of energy used in the field. The cost of Btu's was equated to that determined from the selling price of methane predicted by this analysis. The operation was assumed viable for a period of 20 years.It is impossible to determine the most likely price of the rather wide range of selling prices stated above. All but one of the parameters that affect productivity and, therefore, cost can be assigned a productivity and, therefore, cost can be assigned a most likely value as the result of our study. However, the value of one critical parameter can be set at this time only by analogy with the reported parameters of oil and gas reservoirs. That parameter is the area of the reservoir from which at least one well is required to drain the geopressured aquifer. JPT P. 1502

Testing Geopressured Geothermal Resource, Frio Formation, Texas Gulf Coast: ABSTRACT

Drilling of the first well designed to test geopressured geothermal resource for a sustained period of time was initiated in July 1978. Regional and site-specific geologic and engineering studies supportive of this site were conducted by the University of Texas Bureau of Economic Geology and Department of Petroleum Engineering/Center for Energy Studies with funds from the U.S. Department of Energy. The area sought during these studies needed reservoir volume of 3 cu mi (12.5 cu km), minimum permeability of 20 md, and fluid temperatures of 300°F (149°C). The Brazoria fairway, Brazoria and Galveston Counties, Texas, best met these specifications and the Austin Bayou Geothermal Prospect was developed in this fairway. Funds for drilling the Nos. 1 and 2 Pleasant Bay u geothermal test wells in the Austin Bayou Prospect were provided by DOE; the operator of the wells is General Crude Oil Co. The geopressured sandstone reservoirs are in the lower part of the Frio Formation between the depths of 14,000 and 17,000 ft (4,200 and 5,100 m). The sandstone units are at the top of at least seven progradational deltaic cycles; cumulative thickness of all permeable sandstone units is 250 to 300 ft (75 to 90 m). Each deltaic cycle is composed of a gradational vertical succession characterized by low-permeability prodelta and distal delta-front sandstone and shale at the base grading to permeable distributary-mouth-bar and delta-plain sandstone and shale at the top. Fluid will be produced from the 2 Pleasant Bayou well, stripped of methane and heat, then injected into Miocene sandstones at 6,000 to 7,000 ft (1,800 to 2,100 m) depth in the nearby 1 Pleasant Bayou disposal well. The produced water is expected to have salinities ranging from 50,000 to 80,000 ppm, temperature from 300 to 350°F (149 to 177°C), pressure from 10,000 to 15,000 psi (68,950 to 103,425 kPa) and 40 cu ft (1.2 cu m) of methane per barrel. The 2-year test period will evaluate the feasibility of long-term production of large quantities of water (ultimately 40,000 bbl/day) from geopressured reservoirs. End_of_Article - Last_Page 1595------------

Future Potential for Development of Geothermal Energy in Contiguous United States: ABSTRACT

Geothermal energy, long known for the tourist attractions it provided at Yellowstone National Park, is now being used for generating commercial amounts of electricity, for space heating, and as an aid to agriculture. Potential for development exists in many parts of the country in the form of geologic reservoirs of steam, hot water, warm water, hot dry rock, and deep geopressured reservoirs. Areas with the most obvious potential are related to hot springs, active faulting, active seismicity, and recent volcanism. Heat-flow and subsurface-temperature data are particularly useful in localizing areas of geothermal activity. Tectonic setting and physiography, together with the above data, provide the basis for dividing the United States into a series of geothermal provinces. To date, the western provinces have shown the greatest potential for electric power development. The Geysers steam field has a generating capacity of 502 Mw with an estimated eventual capacity around 2,000 Mw. Several hot water fields are being developed for electric power generation in the Salton Trough of California, with an estimated total potential of 5,000 Mw. One hot-water discovery has been made in western Utah and three tests of possible power development potential are indicated in widely separated parts of the Great Basin and one discovery has been made in the Rio Grande Rift. Research projects sponsored by the U.S. Department of Energy (DOE) are in progress to determine the feasibility of producing electricity from moderate temperature waters at Raft River, Idaho, and from hot dry rock at Fenton Hill, New Mexico. In the Gulf of Mexico province, DOE sponsored the testing of a well in Louisiana in 1977 and is currently drilling a 16,500-ft (5,029 m) test in Brazoria County, Texas, to evaluate geopressured reservoir potential. Warm water has been used for space heating in Klamath Falls, Oregon, western South Dakota, and Boise, Idaho, for many years and other direct utilization projects are planned or in progress for use in space heating and agriculture. The search for warm water has been extended to the southeast Atlantic coastal plain where the DOE plans a series of shallow temperature holes to provide data to locate one or more deep tests. Geothermal potential exists in broad areas of the western United States, where it appears capable of competing economically with other energy forms. Elsewhere the potential is lower but space heating and agricultural uses may become viable markets.