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Collaborating Authors
Oklahoma
SPE Members Abstract The traditional concept of coalbed methane production is one where the coal natural fracture system is initially 100% saturated with water and that this water must be produced to initiate gas production. This paper summarizes an investigation designed to reconcile measured relative permeability data with well test analysis results obtained during single-phase and multi-phase tests, and with reservoir simulation projections of gas and water deliverability as a function of bottom-hole pressure. Improved well test and relative permeability measurement procedures are summarized so that projections of future fluid deliverability made during the dewatering and early multi-phase production stages are more accurate. A variety of well tests were performed that included water slug tests, water injection tests, gas injection tests, and multi-phase production and shut-in tests. Estimates of absolute permeability obtained from these data were variable depending upon the test procedures. In addition, multi-phase and gas injection test analyses were strongly influenced by the relative permeability data used during the analysis. Based upon newly measured relative permeability data and by history matching multi-phase production data, it was possible to reconcile some of the differences in estimates of absolute permeability that were obtained from each of the test types. Finally, a new field procedure is proposed and demonstrated to measure permeability in wells producing both water and gas. Introduction The understanding and modeling of methane production from Coal bed Methane (CBM) wells has proven to be a particularly challenging task for the gas industry. Unlike conventional gas wells where the production is typically modeled as single phase gas flow, CBM wells require that water be produced to reduce lower reservoir pressure below the desorption pressure so that gas can be produced. A thorough understanding of relative permeability is necessary in order to predict gas and water production rates. Typically, most well tests are initially conducted when the reservoir is water saturated so that single phase analysis techniques can be used to evaluate permeability. Unfortunately, there are far too many cases where the initial measured water permeability did not predict the eventual gas flow rates. In order to study all aspects of CBM production, the Gas Research Institute, in conjunction with Taurus Exploration, has operated the Rock Creek Methane from Multiple Coal Seams pilot production site at Rock Creek in the Black Warrior Basin for the last 10 years. Here the required well tests have been conducted and field data, including production data, has been collected in a controlled manner so an understanding of CBM could be developed. P. 313
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.54)
- Geology > Geological Subdiscipline (0.46)
- North America > United States > Oklahoma > Arkoma Basin > Cana Woodford Shale Formation (0.99)
- North America > United States > New Mexico > San Juan Basin (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- (3 more...)
Abstract The Morrow formation in Hutchison County, Texas was long considered incapable of producing hydrocarbons at an economic rate. Most post-frac production rates were the same or less than pre-frac rates. Only high flow rate, non-stimulated completions were considered economic, but these completions were few in number. These facts lowered expectations for sufficient recovery of investment necessary to continue developmental drilling. Utilization of modern fracture model techniques, core analysis, fluid testing and stress data lead to a system of stimulation techniques, fluids and proppants that has created a cost-effective stimulation system for the Morrow formation. Lithology studies showed that the frac fluid was primarily critical to success. These studies lead to an unorthodox fluid. It contained two elements that would not be considered practical in any other formations or circumstances in the Western Anadarko basin. Proppant placement was identified as the second most important issue. Fracture height was found to be controlled by permeability, not stress. This led to the discovery that proppant convection did not allow for good proppant placement. Proppant staging methods were augmented to combat excessive convection and then acquire advantageous proppant placement. Proppant selection was identified as the third most important criteria. Reservoir stresses and modeling showed that high cost, high stress proppants were not necessary. Lower cost, larger sized proppants yielded much higher conductivity than in previous completions. These criteria were integrated into a solution which brought the post-frac production rate from a one fold to a ten fold increase. Introduction The West Arrington Morrow field of Hutchison County, Texas contains many producing horizons. One of which is the Morrow sandstone. This zone has been long overlooked for it's potential in supplying hydrocarbons due to problems in completions. Fortunately for Arrington CJM, Inc., their first three experiences with the zone were high flow rate, natural completions. Unfortunately, this was not the standard for completions to come. P. 129
- North America > United States > Texas (1.00)
- North America > United States > Ohio > Morrow County (0.25)
- North America > United States > Oklahoma > Red Fork Channel Sand Formation (0.99)
- North America > United States > Ohio > Morrow Field (0.99)
- North America > United States > Kansas > Anadarko Basin (0.99)
- (4 more...)
SPE Member Abstract This paper discusses possible explanations, based upon previous studies, for the hypothesis that multiple fractures at the borehole wall may be a common feature of the hydraulic fracturing process. It then uses field examples to show how we concluded that a type of low-concentration screenout common to three fields in Texas and Oklahoma was caused by multiple fractures. Next, it shows how we developed a completion that controls loss of the pad and slurry to multiple fractures. Finally, it discusses some of the implications of our experience for completion design in general. Since the symptoms of the low-concentration Screenout have been documented in the literature by other authors and appear to be quite common, our design techniques should be effective in other areas as well. The completion design combines unoriented, zero-degree-phased, big-hole perforations shot at low density; and small, high-concentration proppant slugs with clean spacer stages pumped very early in the treatment. These strategies were chosen (1) to limit the number of separate fractures that initiate from individual perforations, and (2) to screen out narrow fractures early in the treatment so that more width is developed in the remaining fracture(s). We have used these techniques to increase overall sand/fluid ratios (including the pad) from about 2.3 ppg (lbm added per gal fluid) to over 8 ppg, on modestly-sized treatments up to 200,000 lbm. Introduction In all the areas covered by this study it had been difficult to complete stimulations when we tried to reduce pad fractions below 40% and/or increase sand concentrations past 6 ppg. The proppant-induced pressure increase that leads to a near-wellbore screenout (Barree) was a common factor in all these attempts. These screenouts occurred even when we had designed the pump schedules on modern, three-dimensional (3D) fracture design simulators, using reliable input data. Even the most up-to-date simulators are notoriously unreliable design tools unless they are adjusted for the peculiar leakoff conditions of each well, either by a calibration treatment, or by a generous infusion of local knowledge. Uncalibrated simulations routinely predict ample width for slurry concentrations up to the operational limits of pumping equipment, but experienced engineers know that most treatments screen out at much lower concentrations. Unless fluid loss is increased by the modeler, or the screenout criterion is set very conservatively, design models do not predict fracture treatments should screen out at the low concentrations that they commonly do. These results are puzzling when one considers just how little sand is contained in slurries that frequently cause screenouts. For example, Fig. 1 shows that a 6 ppg slurry contains only about 35% sand on a bulk volume basis and 18 ppg still has 25% excess fluid. P. 69
- Geology > Geological Subdiscipline > Geomechanics (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- 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)
- (26 more...)
This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented. have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers. or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Permission to copy is restricted loan abstract of not more than words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Write Publications Manager. SPE. P.O. Box 833836, Richardson, TX 75083-3836 U.S.A. Telex, 730989 SPEDAL. Abstract The Sooner Unit produces a volatile crude oil from a low permeability Cretaceous sandstone reservoir. Primary production resulted in a gas saturation estimated to exceed 20% of pore volume. Modelling studies, analysis of similar reservoirs, and Sooner Unit production history have demonstrated a need to repressure the reservoir prior to displacement under "steady state" conditions. The principal -benefit to displacement at high pressure is derived from the ability to manage gas saturation and reservoir voidage and prevent early water breakthrough. The effect of reduced oil viscosity and lower mobility ratio at high pressure is of minor significance. pressure is of minor significance. Repressurization of the reservoir has been accelerated recently by the initiation of gas injection. Introduction The Sooner Unit Field is located in Weld County, Colorado near the town of New Raymer 100 miles northeast of Denver (Fig. 1). The Sooner Unit produces from a low permeability (25 md) Cretaceous sandstone reservoir. The field was discovered in December, 1985 when the Dixon No. 2-28 (Sooner Unit No. 10-28) was re-entered and completed in the "D" Sand between 6309 and 6334 feet. The "D" Sand reservoir in the Sooner Unit is a fine grained channel sand (Fig. 2), deposited on a gentle monocline. Regional dip is about 50 feet per mile. Hydrocarbons are stratigraphically trapped. There is no known aquifer. The reservoir oil was initially saturated, however, no significant primary gas cap is known to exist. primary gas cap is known to exist. The Sooner Unit includes 18 wells completed or capable of completion as oil wells. Field limits are defined by 12 dry holes (Fig. 3). A summary of reservoir properties is contained in Table 1. Table 2 properties is contained in Table 1. Table 2 shows the composition of the original reservoir fluid. The Sooner Unit Technical Committee estimated original oil in place (OOIP) at 6 million stock tank barrels (MMSTB) and original solution gas in place (DIP) at 3 billion cubic feet (BCF). PRIMARY DEPLETION PRIMARY DEPLETION Development of the field occurred between December 1985 and February, 1988 (Fig. 4). Primary oil production reached a peak of Primary oil production reached a peak of 50,000 STS in April, 1988. Average producing GOR started at about 600 SCF/ST8 and reached a peak of 4500 SCF/ST8 in April, 1988. peak of 4500 SCF/ST8 in April, 1988. Individual leases reached a maximum producing GOR in excess of 10,000 SCF/ST8. Production was voluntary curtailed beginning in 1988. The field was unitized for secondary recovery, effective October l, 1988. At the Unit effective date, cumulative production was 772,361 STS oil and 1,848,538 production was 772,361 STS oil and 1,848,538 MSCF gas or 13% of OGIP and 62% of OGIP. P. 211
- North America > United States > Texas > Colorado County (0.25)
- North America > United States > Texas > Dallas County > Richardson (0.24)
- North America > United States > Colorado > Weld County (0.24)
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Oklahoma > Anadarko Basin > M Formation (0.99)
- North America > United States > Nebraska > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract The exploration and development strategy can be strengthened with improved understanding of reservoir characteristics. For this purpose, the characteristics of low-permeability gas reservoirs in the Arkoma basin are examined in this paper by analyzing 75 wells in a seven county area. The study area covers portions of Crawford, Franklin, Logan, and Sebastian Counties in Arkansas, as well as Latimer, Leflore and Haskell Counties in Oklahoma. The examined reservoir characteristics included a geological background, reservoir fluid and rock properties, formation evaluation, and production performance. Of the three types of reservoirs classified in this paper, i.e. (I) relatively high porosity/high permeability, (II) relatively low porosity/low permeability, and (III) relatively high porosity/low porosity/low permeability, and (III) relatively high porosity/low permeability. Type III reservoirs are the most difficult to characterize permeability. Type III reservoirs are the most difficult to characterize because of a dual porosity system in the sandstone matrix. The matrix pore system is primarily composed of varying amounts of intergranular and pore system is primarily composed of varying amounts of intergranular and dissolution porosities. How to characterize this type of reservoir is the main effort of this paper. Introduction The Arkoma basin, one of the most prolific dry gas producing basins in the United States, is situated in eastern Oklahoma and western Arkansas. Commercial quantities of natural gas were first discovered in the basin in 1902. Currently more than 3100 wells, with an average deliverability of about 200 mcf per day, are producing in western Arkansas. A similar amount of wells are producing in the Oklahoma portion of the basin. Overall, around 9500 wells have been drilled in portion of the basin. Overall, around 9500 wells have been drilled in the entire Arkoma basin. Despite the maturity of the basin, there still is a scarcity of literature dealing with reservoir description. The objective of this paper is to provide an overview of the characteristics of the low-permeability dry gas reservoirs in the basin, with particular emphasis on the dual porosity sandstone reservoirs of the Pennsylvanian Atokan, and porosity sandstone reservoirs of the Pennsylvanian Atokan, and Morrowan series. Due to the limited information on the pre-Pennsylvanian formations, the Boone, Penters, Hunton, and pre-Pennsylvanian formations, the Boone, Penters, Hunton, and Arbuckle reservoirs will not be covered in this paper. GEOLOGIC BACKGROUND The Arkoma basin extends for approximately 260 miles in an east-west direction, and is 20โ50 miles wide from north to south. This long, arcuate trough is bounded on the south by the very complex, Ouachita overthrust belt, and on the north by the Ozark uplift. The stress associated with the Ouachita orogeny and the uplift of the Ozark dome resulted in extreme folding and faulting which created a series of long, narrow, east-west trending anticlines and synclines throughout the basin. P. 489
- North America > United States > Oklahoma (1.00)
- North America > United States > Arkansas > Sebastian County (0.24)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- North America > United States > Oklahoma > Arkoma Basin > Cana Woodford Shale Formation (0.99)
- North America > United States > Arkansas > Arkoma Basin > Cana Woodford Shale Formation (0.99)
Abstract An increasing number of gas wells that exhibit a large difference in reservoir pressure and fracture treating pressure pressure and fracture treating pressure recently have become candidates for hydraulic fracturing. When these reservoir conditions are encountered, the result is an abnormally high pressure differential driving the fluid leakoff mechanism during the hydraulic fracturing treatment. In some deep well applications, fluid loss differential pressures (FLDP) up to 10,000 psi have been witnessed. psi have been witnessed. Neither laboratory core testing nor conventional minifrac techniques have accurately predicted fluid loss behavior for fracturing treatments in these wells. Standard laboratory test procedures use differential pressures of 1,000 psi (as per API recommended test procedures) to determine fluid loss coefficients. Minifrac test methods and analysis techniques currently used for field application estimates of fluid loss parameters were modeled after data measured in gas reservoirs where normal fluid loss differential pressures occur. Laboratory fluid loss testing typically has predicted significantly less fluid loss than actually is encountered. Use of this data in computerized fracturing simulators to design the treatment has resulted in many premature screenouts. Conversely, minifrac premature screenouts. Conversely, minifrac tests tend to be pessimistic and overpredict the fluid loss in wells with very high FLDP's. A number of treatments have been completed successfully following minifrac tests that predicted screenouts for the jobs actually pumped. This paper reports on laboratory fluid loss tests conducted at differential pressures of up to 9,000 psi to determine pressures of up to 9,000 psi to determine the nature of the fluid loss occurring in these wells. significant spurt volumes have been observed even on cores of less than 1 md permeability with fluid systems that do not exhibit measurable spurt loss at the conventional 1,000 psi test pressure differential. Also, the fluid loss coefficients (C values) have varied little with escalating pressure differential, contrary to many published correlations. Results from actual field cases also are reviewed as illustrations where the observed FLDP was several thousand psi during fracturing. Introduction A high "fluid loss differential pressure" (FLDP) during hydraulic fracturing pressure" (FLDP) during hydraulic fracturing has been observed in many different gas reservoirs throughout the world. In these situations, one of the primary obstacles to correctly designing the treatment is prediction of the fluid loss expected during prediction of the fluid loss expected during the fracturing treatment. Three types of gas reservoirs have been identified where high FLDP's have been observed. Type 1: Wells in initially overpressured reservoirs of moderate to low permeability that do not require hydraulic fracturing but require stimulation after partial depletion.
- North America > United States > Texas > Anadarko Basin (0.99)
- North America > United States > Oklahoma > Anadarko Basin (0.99)
- North America > United States > Kansas > Anadarko Basin (0.99)
- North America > United States > Gulf of Mexico > Gulf Coast Basin > Wilcox Trend Formation (0.99)
Abstract There are several different types of reservoirs that have a high degree of natural fracturing. In these reservoirs, the fluid loss mechanisms are more complicated than those found in more coherent formations. The loss of fluid to intersecting fractures is especially important in the fracturing of coalbeds, Devonian type shales, limestones and naturally fractured sandstones. In many cases, the reservoir permeability is often such that the fluid loss to these fractures is the primary fluid-loss mechanism. Little is known primary fluid-loss mechanism. Little is known about how to handle this type of fluid loss in fracture simulation calculations, or the effects of this fluid-loss mechanism on pressure drop in the fracture. While the loss of fluid to intersecting fractures is not the only fluid-loss mechanism in naturally fractured sandstone reservoirs, it can dominate the fluid loss to the reservoir under some conditions. Examination of the problem from both a computer based modeling and laboratory standpoint is clearly warranted. Flow of fluid down a fracture in a sandstone reservoir is modified by the continual loss of fluid to the reservoir through the permeability of the rock. In a naturally fractured reservoir, fluid loss occurs mainly at points where the fracture intersects an existing fracture in the rock. This not only changes the nature of fluid loss in the fracture, but it also creates serious flow disturbances that can change the pressure drops in the fracture. It has been shown that flow into orifices placed perpendicular to the major axis of flow results in a highly extensional flow situation. Extensional flows have been shown to increase pressure drop in porous media using non-Newtonian fluids. In addition, it has been shown that two-phase fluids will separate to some extent when a branching of the flow path occurs. These factors have important implications in the flow of fracturing fluids in fracturing treatments in naturally fractured reservoirs. To study the flow effects, a computer model of a small section of a fracture with one intersecting fracture was setup. A commercial finite element analysis program (FIDAP) is used for the fluid flow calculations. This program is optimized for power law type fluids. Computations for several different values of the power law parameters coupled with different power law parameters coupled with different intersecting fracture widths and fracture width ratios will be presented. Conclusions about the nature of the fluid loss in naturally fractured reservoirs will also be made. Introduction P. 687
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Carnarvon Basin > Dampier Basin > Block WA-191-P > Fletcher Finucane Field > Fletcher Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Beagle Basin > Dampier Basin > Block WA-191-P > Fletcher Finucane Field > Fletcher Field (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Buda Formation (0.99)
- (6 more...)
Abstract An empirical correlation for predicting tubular friction pressure for CO -energized fluids has been derived from both pressure for CO -energized fluids has been derived from both field and laboratory data. This correlation takes into account the effect of crosslinking behavior of the liquid phase on friction pressure. Therefore, it can be used for treatments where pressure. Therefore, it can be used for treatments where CO2-energized fluids are used in conjunction with delayed or rapid crosslinked fluids. The correlation was incorporated into a real time computer program used to calculate bottomhole treating pressure on-site during fracturing treatments with CO2-energized pressure on-site during fracturing treatments with CO2-energized fluids. Several case histories were used to evaluate the correlation. The results presented in this paper have shown significant improvement in predicting the friction pressure for CO -energized fluids as compared to existing correlations being used in the oil industry. Introduction Co-energized fluids have steadily increased in use in fracturing treatments because of their advantages in reducing proppant and formation damage as well as in reducing cleanup proppant and formation damage as well as in reducing cleanup cost. Until now, the inability to accurately calculate friction pressure of these fluids made on-site prediction of treatment pressure of these fluids made on-site prediction of treatment diagnostics difficult and hindered treatment optimization. Accurate prediction of friction pressure is needed to obtain bottomhole treating pressure without the use of a reference string or bottomhole pressure tools. Correlations to predict friction pressure loss in the wellbore for conventional incompressible water-based fluids such as linear gel, delayed or rapid crosslinked fluids have been fully developed. These correlations can also be applied to predicting friction loss for fluids containing proppants. Friction pressure for CO -energized fluids, however, requires a more complex solution. It has been observed not only to be a function of surface variables but also greatly influenced by quality and other CO physical properties. The CO physical properties change as the foam travels through the treating string caused by changes in pressure and temperature gradients. Applications of CO -energized fluids in conjunction with time and shear dependent fracturing fluids as the liquid phase make the task of determining friction pressure even more complicated. This paper reviews the methods available to predict friction loss in pipe for CO -energized fluids. A general empirical correlation that can model CO -energized fluids with CO quality of 10 to 80% in all types of liquid phases, such as linear gel, delayed or rapid crosslinked fluid, is presented. This proposed model derived from both laboratory and fluid data provides a means for predicting turbulent non-Newtonian flow behavior of CO -energized fluids being used in a number of industry applications. The paper also discusses laboratory tests using a specially designed flow loop to simulate field conditions to investigate the time and shear dependent fluid behavior of the liquid phase. Laboratory data were used to account for the effect of crosslinking behavior of gel fluid on the friction pressure. Consideration of crosslinking behavior of liquid phase pressure. Consideration of crosslinking behavior of liquid phase is necessary because the application of delayed or partially delayed crosslinked fracturing fluids in conjunction with CO has increased greatly recently. Since it is very difficult to realistically simulate pumping of CO -energized fluids in the laboratory, field testing procedures were established and performed to collect field friction loss data. in collecting field data, the actual tubular friction pressure was monitored by means of bottomhole gauges or bottomhole memory gauges. The fluid tests were performed with fluids containing 10 to 70% CO. The application method of this correlation to obtain real time bottomhole treating pressure is provided in this paper with case histories. pressure is provided in this paper with case histories. REVIEW OF LITERATURE Since CO foam or CO -energized fluids were introduced into the fracturing industry in the 1980's, several authors have investigated rheological properties of foam fracturing fluids using nitrogen and carbon dioxide. P. 521
- North America > United States > Texas (0.93)
- North America > Canada (0.68)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Texas > Anadarko Basin (0.99)
- North America > United States > Oklahoma > Red Fork Channel Sand Formation (0.99)
- (5 more...)
Abstract This paper covers the geology of the Rocky Mountains, low permeable hydrocarbon producing permeable hydrocarbon producing formations and the problems associated with horizontal drilling tools in these regions. The paper includes representative horizontal well data from the Rocky Mountain region and low permeable hydrocarbon producing formations outside the United States. Oil producing trends with respect to fracture and formation are described as they pertain to horizontal drilling pertain to horizontal drilling tools. Where applicable emphasis is placed on solutions to problems associated with horizontal tools. Introduction The Rocky Mountain region is an area that extends from Canada through the western United States down to Mexico. The region includes nine major petroleum exploration petroleum exploration provinces; the Williston basin provinces; the Williston basin - Sioux uplift province, the Central Montana basin, the Big Horn basin, the Wyoming Utah - Idaho Thrust Belt, the southwestern Wyoming basins, the Wind River basin, the Powder River basin, the Sweetgrass Powder River basin, the Sweetgrass arch, and western Montana. The geology of these provinces and that of the Rocky provinces and that of the Rocky Mountains consists of igneous, metamorphic, and sedimentary rock. Igneous and metamorphic rock conditions in the Rocky Mountain region can be traced to volcanism. Volcanism associated with the tectonic activity of the Farallon, American, and Pacific plates. This tectonic activity may be associated with the Triassic age. The geology of the Rocky Mountain region was then subjected to large uplifts of the precambrian basement along with reverse faulting during the late cretaceous age. Fracture faults or fracture zones are believed to be extensions of structural weaknesses in the Precambrian basement rocks. Todays horizontal drilling tools experience most of their problems and most of their problems and most of their successes when dealing with the faults, fractures and cretaceous formations of the Rocky Mountain region. FRACTURE TRENDS The trend of fractures, the direction in which fractures line up one after the other, in the Rocky Mountain region is of special importance as secondary permeability is associated with these fracture trends. P. 575
- North America > United States > Wyoming (1.00)
- North America > United States > Montana (1.00)
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > Wyoming > Wind River Basin (0.99)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- (20 more...)
Introduction Many studies have been made relative to the gas resource potential of the Rocky Mountain region, but a search of the literature has revealed few forecasts as to what gas may be actually producible under a variety of wellhead price conditions. This study provides such forecasts and shows how the provides such forecasts and shows how the undedicated Rocky Mountain gas resources could compete with the Permian and Anadarko basins in the national gas market. The principal analytic tool used in this study was a model developed by ICF-Lewin Energy, Inc. entitled "The Oil and Gas Replacement Cost Analysis Model" (REPCO). This system provides the user with a resource base that is disaggregated by geographic depth, resource quality, and certainty that is served by a flexible decision oriented software package. The system was designed to assist producers, pipelines, distribution companies and large-volume industrial consumers to respond to the challenge of changes in the regulatory climate and falling product prices. product prices. The largest single factor on the horizon for the realization of the Rocky's deliverability potential is the Thermal Enhanced Oil potential is the Thermal Enhanced Oil Recovery (EOR) market in California. The need there for long term, reliable supplies of natural gas has been the subject of great interest to pipeline companies who are competing for that market. The geographic proximity of the Rocky Mountain region proximity of the Rocky Mountain region together with the large resource base makes the area the prime candidate for providing that supply. This study shows that the Rocky Mountain region holds the greatest potential for providing undeveloped and undedicated providing undeveloped and undedicated supplies of gas compared to the production which would be predicted by the REPCO model for basins competing for California EOR market, e.g., the Permian and Anadarko Basins. The study shows that the conclusion holds under a variety of gas price scenarios. The results of the REPCO study indicated that the bulk of the resource available in the Rockies comes from the "Tight" gas category (from formations with an average in-situ permeability of less than 0.1 md.) Two of permeability of less than 0.1 md.) Two of the six REPCO cases were checked against results obtained from the Tight Gas Analysis System (TGAS). DEFINITIONS The following definitions apply to the text and material contained in this paper: Tight Gas Resource is that as currently defined by Federal Energy Regulatory Commission standards, i.e., gas produced from formations proved to have permeability of 0.1 millidarcy or less. Possible Gas Reserves are those defined by the Potential Gas Committee's report entitled "Potential Supply of Natural Gas in the United States," December 31, 1986. Quoting from page 5 of the report, "possible potential supply is a less assured supply potential supply is a less assured supply because it is postulated to exist outside of known fields, but it is associated with a productive formation in a productive productive formation in a productive province. province. P. 319
- North America > United States (1.00)
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- Research Report > Experimental Study (1.00)
- Research Report > New Finding (0.88)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.97)
- North America > United States > Texas > Permian Basin > Yates Formation (0.97)
- (29 more...)