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Collaborating Authors
Utah
Abstract The success of a hydraulic fracture treatment is greatly enhanced by control of the created fracture geometry. This problem is most serious if the boundary lithologies are not highly stressed as compared to the pay zone and do not form an effective barrier to upward migration. Reservoirs with this nature are common in many areas, including the Douglas Creek Arch, Green River Basin, Uintah Basin, San Juan Basin, and Central Alberta. The Perforation Placement Optimization technique involves the determination of perforation locations such that the hydraulic fracture contact area within the pay zone is optimized. Where the upper boundary lithologies are not highly stressed as compared to the pay zone, the fracture will migrate predominantly upward into weak boundary lithologies. Where weak boundaries exist, the extent of the exposed fracture area that can be contained within the pay zone is strongly dependent on the location of the perforations and the gross height of the pay formation. Initiating the fracture below the pay sand (should lithology at the site be amenable to locating the perforations below the sand) can lead to greater fracture contact area within the pay sand and thus increased production. The work presented in the paper includes laboratory simulations performed on paper includes laboratory simulations performed on one meter cubic blocks, fracture design efforts, field implementation and transient pressure testing. The results of the laboratory tests helped in developing a model for optimizing perforation placement. This has been used in conjunction with placement. This has been used in conjunction with a pseudo three dimensional fracture geometry and a pseudo two dimensional fluid flow hydraulic pseudo two dimensional fluid flow hydraulic fracture model to design a field hydraulic fracture treatment. The treatment has been implemented in a well in the Douglas Creek Arch area, Colorado. In-situ stress measurements in the well and special core testing on retrieved core material were performed to evaluate this well and the reservoir properties. In-situ stress distribution indicated the absence of stress barriers as expected. Reservoir engineering studies indicated that a significant increase in post-stimulation production can be expected by the use of production can be expected by the use of perforation placement optimized hydraulic fracture perforation placement optimized hydraulic fracture treatment. The well was stimulated through perforations placed fifty feet below the pay zone and the perforations placed fifty feet below the pay zone and the created fracture was allowed to migrate upward into the pay zone. Post-stimulation transient pressure testing, fracturing fluid clean-up, and pressure testing, fracturing fluid clean-up, and gas flow data indicate that the technique has been successfully applied. This paper discusses the development, application, and evaluation of the modified hydraulic fracturing technique. This particular technique has been developed as part of a research program sponsored by the Gas Research Institute of Chicago and conducted by Terra Tek, Inc. of Salt Lake City and Chandler and Associates of Denver. INTRODUCTION AND BACKGROUND The success of a hydraulic fracture treatment depends on creating a large propped surface area in the pay zone. This requirement can be difficult to achieve where migration of the fracture into the bounding formations is not controlled by higher stresses in the boundary formation as compared to the pay zoner. Under these conditions where highly stress barriers do not exist, comparison of hydraulic fracture design lengths versus effective post-fracture lengths derived from production tests indicate that a high percentage production tests indicate that a high percentage of fractures indeed do not stay confined to the productive interval. For example, fracturing productive interval. For example, fracturing results from the Rio Blanco Field illustrate the problems. The post-fracture effective lengths for problems. The post-fracture effective lengths for four treatments at the Rio Blanco Field are in the range of 1 percent to 20 percent of the design fracture lengths. There is a clear need to devise better fracture treatment methods. P. 101
- North America > United States > New Mexico > San Juan County (0.44)
- North America > United States > Colorado > Rio Blanco County (0.28)
- North America > United States > Illinois > Cook County > Chicago (0.24)
- North America > United States > Utah > Salt Lake County > Salt Lake City (0.24)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Green River Basin (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- (7 more...)
Abstract Trends of subsurface structure, total sandstone isopachs and thickness variations are used to geologically characterize the depositional subdivisions of the non-marine part of the Mesaverde Group in the Rulison Field area of the southern Piceance Basin. Investigation of a gas production trend indicates that higher productivity may be controlled by structure induced fracturing productivity may be controlled by structure induced fracturing and is independent of thicker sandstone accumulations. In addition, over-pressured gas reservoirs in a non-marine part of the Mesaverde Group have not been fully evaluated and may be an important exploration target. Introduction Objective. The objective of this investigation is to integrate the geological and production characteristics of the Rulison Field area to obtain a more concise understanding of the factors which allow greater production from low-permeability, lenticular reservoirs present in the non-marine part of the Mesaverde Group. In present in the non-marine part of the Mesaverde Group. In addition, characterization of the subsurface geology and production should improve evaluations of the Department of Energy's MultiWell Experiment (MWX). The area investigated is located in Garfield County, Colorado, and includes the Rulison Field and Mamm Creek Field, hereafter referred to as the Rulison Field area. The study area is shown in Figure 1. Interval Investigated. The sediments characterized in this study are a part of the Mesaverde Group clastic wedge deposited during Late Cretaceous time as a series of delta systems which pregraded into an interior seaway. The base of the interval investigated is the top of the Rollins Sandstone Member of the Mesaverde Group. The top of the interval investigated is the top of the Ohio Creek Conglomerate (the top member of the Mesaverde Group). A generalized stratigraphic column, shown in Figure 2, illustrates a portion of the geologic section present in the southern Piceance portion of the geologic section present in the southern Piceance Basin. Methods. Data for this study includes logs from 44 wells with penetrations into the Mesaverde Group. Monthly production penetrations into the Mesaverde Group. Monthly production records for 29 of these wells were also acquired. A total sandstone isopach map was prepared which utilizes gamma ray logs run through the non-marine Mesaverde section to identify sandstone units. Sandstones were differentiated from siltstones and mudstones so the isopach map represents only the total thickness of relatively cleaner sandstone. Included in the isopach map were sandstone units having a gamma ray deflection less than 25 percent of the difference between the maximum and minimum gamma ray deflections in the non-marine Mesaverde section. The total thickness of cleaner sandstone per well was plotted on a base map and interpretively contoured. plotted on a base map and interpretively contoured. Coal units were identified in this investigation by interpreting responses from a combination of caliper, gamma ray, resistivity, density or neutron logs. MWX. Much of the regional geological data in the Rulison Field area has been made available through studies performed in association with the Multi-Well Experiment. MWX is a coordinated research effort to investigate means of stimulating production of natural gas from low-permeability, lenticular sandstone reservoirs. The MWX site, consisting of three closely spaced wells (MWX-1, MWX-2 and MWX-3) penetrating the non-marine Mesaverde section, is located in Section 34, T6S, R94W. STRUCTURE AND TOTAL INTERVAL THICKNESS The Rulison Field study area borders the Grand Hogback, a steeply dipping outcrop of rocks which forms the eastern structural and geographic boundary of the Piceance Basin. The tilted rocks of the hogback are a result of Laramide orogenic events occuring near the end of Mesaverde deposition in the basin. Paralleling the strike of the Grand Hogback in the southeast basin area are several major anticlines which influence the subsurface structure of the Mesaverde Group sediments. Most notably, these are the Divide Creek Anticline, Baldy Creek Anticline and Wolf Creek Anticline. The subsurface structure on the top of the Mesaverde Group in the Rulison Field study area is illustrated in Figure 3. The structure of the eastern one third of the mapped area is dipping approximately 3 (.052 rad) to the northwest. The subsurface structure here is possibly a continuation of the northwesterly plunging Divide Creek Anticline directly to the southeast of the plunging Divide Creek Anticline directly to the southeast of the mapped area. P. 47
- 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 > Utah > Uintah Basin > Wasatch Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Rulison Field > Mesaverde Formation (0.99)
- (4 more...)
Abstract The Multi-Well Experiment (MWX) is a research-oriented field laboratory whose objective is to develop the understanding and technology to allow economic production of the several years supply of natural gas estimated to be within the low permeability, lenticular gas sands of the Western permeability, lenticular gas sands of the Western United States. Features of MWX include:three closely-spaced wells (115โ215 ft, 35โ66 m) for reservoir characterization, interference testing, well-to-well geophysical profiling, and placement of diagnostic instrumentation adjacent to the fracture treatment; complete core taken through the formations of interest; a comprehensive core analysis program; an extensive logging program with conventional and experimental logs; determination of in situ stresses in sands and bounding shales; use of various seismic surveys and sedimentological analyses to determine lens morphology and extent; use of seismic, electrical potential, and tilt diagnostic techniques for hydraulic fracture characterization; and a series of stimulation experiments to address key questions. This paper presents the current MWX accomplishments resulting from the 1983 field season which featured the drilling of a third well and the first stimulation experiment. Introduction and Background For a number of years the United States government has engaged in research to enhance gas recovery from unconventional reservoirs, such as organically-rich fractured shale and discontinuous, lenticular, tight sandstones. Large quantities of natural gas are trapped in these formations, whose permeabilities are too low to permit economic permeabilities are too low to permit economic recovery by conventional technology. In the western United States, the Greater Green River, Piceance, Wind River, and Uinta basins have been identified as containing significant amounts of gas in thick sections of lenticular sands. The National Petroleum Council has appraised' these four basins Petroleum Council has appraised' these four basins to hold 136 TCF (4 TM3) of maximum recoverable gas in lenticular reservoirs. This sizeable resource is now being investigated by the U.S. Department of Energy (DOE) in the Piceance basin of western Colorado, where a field laboratory containing three closely spaced wells penetrating the lenticular Mesaverde formation has been constructed. This facility, near the town of Rifle, is the site of the DOE Multi-Well Experiment (MWX), which has been developed to determine the viability of the lenticular tight sands as a gas resource. Massive hydraulic fracturing has demonstrably increased gas production from tight reservoirs, but currently its performance in lenticular formations is unpredictable. This results from poor definition of reservoir properties, inadequate understanding of the physics controlling fracture propagation and proppant transport, limited ability to measure, proppant transport, limited ability to measure, describe, or evaluate the created fracture, and uncertainty as to the relationship of stimulation design variables (fluids, proppants, pumping rates) to the resulting fracture. These difficulties are compounded in the lenticular formations by the uncertainty whether multiple lenses, some remote from the wellbore, can be stimulated by a common treatment. Improved understanding, evaluation, prediction, and possible control of stimulation prediction, and possible control of stimulation technology are needed for effective development of tight lenticular reservoirs. The ultimate aim of the MWX is to determine the optimum stimulation technology for increasing the gas recovery from tight gas sand formations, specifically the tight lenticular formations of the basins of the western United States. Further discussion of the rationale, plans, objectives and activities can be found in References 2โ5. Experiments are now being conducted at the MWX site to 1) provide improved definition of the reservoirs through extensive core and log analyses, well and stress testing, and geologic and geophysical studies, and to 2) investigate the effectiveness of stimulation technology with diagnostic instrumentation and production performance testing. performance testing. P. 351
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- 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 > Colorado > Piceance Basin > Mesaverde Formation > Williams Fork Formation (0.99)
- North America > United States > Wyoming > Wind River Basin (0.94)
- (6 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Abstract Coalbed methane production is initiated by the removal of formation water in quantities sufficient to accomplish a large reduction of fluid pressure in the cleat, system. Pressure reduction causes gas to be desorbed from the coal; the cleat system channels this gas to the wellbore. The rate and quantity of water removal is limited by permeability of the cleat system which is usually stimulated to facilitate dewatering and gas production. Experiments were performed at IGT under in-situ conditions on coal from five U.S. basins. Results showed that water permeability of a given sample decreased by as much as two orders of magnitude over pressure ranges that, simulated normal dewatering and pressure ranges that, simulated normal dewatering and production cycles. production cycles. Knowledge of the behavior of permeability as a function of net stress allows a better understanding of the following realities of coalbed stimulation:a horizontal drill hole of a given length is much more productive than a propped fracture of the same length; in general, fractures induced in coalbeds are much shorter and wider than designed; and, frac pressures in coalbeds are abnormally high pressures in coalbeds are abnormally high significantly above overburden in many cases. Other consequences of a permeability-net stress functionality include:skin factor determinations from injection tests are necessarily more optimistic than those based on drawdown data; overbalanced drilling increases the invasion radius of drilling fluid filtrate, thereby creating the potential for more extensive formation damage than in conventional reservoirs; and, leakoff during fracturing operations is significantly higher than for "conventional" sandstone or limestone beds having identical pre-injection permeabilities. Introduction In 1983, IGT completed a laboratory study of drilling-fluid interactions with coal to characterize mechanisms of formation damage. To properly identify damaging agents, an understanding of "baseline" liquid permeabilities and functional changes with pressures permeabilities and functional changes with pressures which simulated normal phases of well development was required. Liquid permeability measurement were performed on samples from the San Juan, Piceance, and performed on samples from the San Juan, Piceance, and Appalachian Basins at simulated discovery, injection test and drawdown test pressures. Measurements were also conducted on samples from he Uinta and Warrior Basins, but only under discovery in-situ conditions Because the focus of this paper is the relationship between permeability and changes in net stress, results from these tests will not be included. APPARATUS All liquid permeability measurements were performed with the apparatus depicted schematically in performed with the apparatus depicted schematically in Figure 1. Plug samples were placed between 1-1/2 inch (3.8 cm) endcaps of a standard Core Lab coreholder-Neoprene or Teflon sleeves were used to isolate plugs from the confining liquid (water) which generated equal triaxial pressures. Confining pressure was generated by a Ruska pump shown near the top of the diagram. Fluid flow through the plug was maintained by a stepping motor, gear box, 9.0-CM3 positive-displacement, pump combination. The dynamic range of positive-displacement, pump combination. The dynamic range of the stepping motor was 0.2 to 22,000 steps per second, which corresponded to flow rates in the range of 2.2 ร 10-7 to 2.4 ร 10-2 cm3/sec. Three upstream and three downstream 1/8-inch (3.18 mm) diameter tubing loops permitted injection and withdrawal of different fluid permitted injection and withdrawal of different fluid types into the core with minimal cross contamination. Two 0 to 15,000 psia (0 to 103 KPa) quartz crystal pressure transmitters with 0.01 psia (0.07 kPa) resolution were used to measure fluid pressures resolution were used to measured fluid pressures upstream and downstream of the core. Readings from these instruments were used to calculate the pressure drop across the sample during flow measurements. Two 1-liter vessels on the downstream side of the core provided a constant pressure sink. About 5 00 cm3 of water was maintained in the bottom of these nitrogen-filled cylinders. The 9-cm3 pump volume added to these vessels raised the downstream pressure less than one percent. P. 253
- North America > United States > Colorado (0.48)
- North America > United States > Pennsylvania (0.35)
- North America > United States > Alabama (0.35)
- North America > United States > Wyoming > Uinta Basin (0.94)
- North America > United States > West Virginia > Appalachian Basin (0.94)
- North America > United States > Virginia > Appalachian Basin (0.94)
- (15 more...)
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA. May 16โ18, 1982. The material is subject to correction PA. May 16โ18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract Two research wells were drilled and completed in a known, yet heretofore unproductive tight sand gas reservoir in the Green River Basin. Although previous wells were drilled in the area and previous wells were drilled in the area and hydraulically fractured, there has been no commercial production. The consideration of advanced methods production. The consideration of advanced methods of stimulation design aid changing gas prices caused recent renewed interest. A systematic approach led to successful fractures of one zone in each of the two wells. Initial production rose from 107 to 4150 MCFD in one well and from 35 to 1450 MCFD in the second well after stimulation treatments. Introduction The Pinedale gas field is a large tight sand reservoir located in Sublette County, Wyoming (see Figure 1). The magnitude of this resource is indicated by a National Gas Survey Advisory Committee report of 1977 which lists in-place gas reserves of 37 trillion cubic feet. Eleven wells were drilled into the Fort Union formation of this field between 1939 and 1963. Six wells were subjected to conventional hydraulic fracturing. Three of these six wells later underwent massive hydraulic fracturing treatments during the period 1974 to 1976; however, these treatments failed to significantly increase the long-term production potential and there has never been commercial production from this field. Based on advances in the technology of tight sand production, Mountain Fuel Supply Company, with the production, Mountain Fuel Supply Company, with the technical assistance of Terra Tek Incorporated, initiated an extensive research and development program in the area. The program involved a critical review of all prior data, drilling of two 12,000-foot wells, flow testing of existing wells, extensive logging of the new wells, theoretical fracture design studies, and prestimulation and poststimulation flow testing of the new wells. The fracture design work included a critical investigation of in-situ stress and fracture orientation and propagation. The laboratory work included special core testing with candidate fracturing fluids and proppants. This paper presents details of the study and the associated laboratory and field results. Funding assistance was provided by the United States Department of Energy and the Gas Research Institute. Background The Pinedale gas reservoir is located on the west of an anticline with a northwest-southeast trend. It is 30 to 40 miles long and approximately 5 miles wide, with approximately 2,000 feet of vertical relief from the lowest to the highest structural elevation. The anticline was formed by compressional stresses resulting from the Wind River Uplift on the east and the Wyoming Overthrust on the west during the Laramide Orogeny (appx. 100 million years B.C.). Gas-bearing sandstone units are encountered at approximately 8,000 feet in depth and continue, interbedded with shale, downward to an undefined depth, but at least as deep as the total depth (19,300 feet) of the El Paso Natural Gas Company's Wagon Wheel well. Evaluation of the data obtained from that well indicates, however, that a significant portion of the presently known gas in the field is contained in the formation interval from 9,000 to 11,700 feet. The individual sandstone units range in thickness from a fraction of an inch to several tens of feet. Log information from other Pinedale wells and outcrop studies in the Green River Basin indicates that the Fort Union sands are lenticular with the total gross sand thickness from 500 to 700 feet. Core data measured from wells indicate porosities of 8 to 10 percent with 50 to 59 percent water saturation. El Paso Natural Gas Company investigations of the Pinedale reservoir characteristics, for samples with 8.8 percent porosity and 50.6 percent water saturation, showed permeability to gas of less than 0.001 millidarcy. P. 313
- North America > United States > Wyoming > Sublette County (0.69)
- North America > United States > Texas > Dallas County > Dallas (0.24)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.74)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Green River Basin > Pinedale Field (0.99)
- North America > United States > Utah > Green River Basin (0.99)
- North America > United States > Gulf of Mexico > Western GOM > West Gulf Coast Tertiary Basin > Keathley Canyon > Well No. 1 (0.98)
- North America > Canada > Alberta > Pinedale Field > Baysel Pinedale 6-7-54-16 Well (0.98)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.95)
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16-18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract Throughout the history of gas exploration and development in the U.S., potentially recoverable quantities of methane from unconventional sources potentially recoverable quantities of methane from unconventional sources such as coalbeds have been largely excluded from potential gas supply surveys. This is attributable to the lack of data about the resource, technology, and economics of its recovery. Tn order to provide answers, DOE initiated the Methane Recovery from Coalbeds Project (MRCP) to characterize the gas-in-place for various coalbeds and associated sediments. Preliminary results of the DOE Methane Recovery from Coalbeds Project reveal that many of the coal regions in the United States have significant volumes of coalbed methane. Preliminary gas-in-place resource estimates were made based on the volume of coal-in-place and on direct methane-desorption data. It has been conservatively estimated that 14 percent of the 48 conterminous states are underlain by coal-bearing rocks. percent of the 48 conterminous states are underlain by coal-bearing rocks. Over 50 wells have helped to update the estimates of methane in these various coal regions. The evaluation of 11 basins by the MRCP reveal that the total resource estimated in-place is between 57 and 285 Tcf. Those basins showing high potential include the Northern Appalachian, Arkoma, Piceance, Warrior, Illinois, and Greater Green River. Piceance, Warrior, Illinois, and Greater Green River Introduction Coal methane is a large resource known to occur within or near virtually all coal formations of the U.S., although the extent and volume of this natural gas has not been well defined or established. This source of energy has been virtually untapped. Most of the coalbed methane information available to date has been obtained from mining areas located in the eastern U.S. primarily because the coal seams in the eastern U.S. are generally well defined and coal mining operations have been quite extensive. Presently, most coalbed methane drainage systems vent the gas into the atmosphere. Approximately 250 million cubic feet (mmcf) of methane are vented daily in U.S. mining operations. The quality of gas evolved from virgin coal is comparable to that of natural gas recovered from gas reservoirs. The heat of combustion ranges from 950 to 1,000 Btu per cubic foot and the quality of gas ranges from 90 to 99 percent methane. The methane content of gas vented from mined areas, however, varies from 25 to 90 percent, depending on the venting techniques used. Current approaches for recovering coalbed methane are extraction from unmined seams, predrainage ahead of mining, and drainage from collapsed/ mined-out "gob" areas. The variation in methane quality, quantity, and location makes it clear that no single utilization system is appropriate for all cases. Current processing/utilization options include direct pipeline injection, liquefied natural gas (LNG) production, on-site power pipeline injection, liquefied natural gas (LNG) production, on-site power generation, heating applications, and petrochemical feedstock production. Much of the technology necessary to use this valuable resource exists today although some modification may be required to accommodate the requirements of specific applications. Background To curb the waste of coalbed methane and to provide for its recovery and utilization, the U.S. Department of Energy has directed the Methane Recovery from Coalbeds Project (MRCP) within its unconventional Gas Recovery Program. The Morgantown Energy Technology Center (METC) is the lead laboratory for this project. With major participation by industry in cooperative efforts, this project conducts a broad-based effort in resource engineering, full system development tests, and basic research designed to provide complete access to this resource by all elements of the energy provide complete access to this resource by all elements of the energy community. Most of the coalbed methane data available through the mid 1970's was from mining areas in the eastern U.S. where the coalbeds are well defined and mining is extensive. p. 99
- North America > United States > Colorado (1.00)
- North America > United States > Wyoming (0.93)
- North America > United States > Virginia (0.68)
- (4 more...)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Wind River Basin (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Hanna Basin (0.99)
- (29 more...)
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA. May 16โ18, 1982. The material is subject to correction PA. May 16โ18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract The San Juan Mountain igneous extrusive complex in southwestern Colorado is approximately equidistant from the southeastern Piceance, northern San Juan, and western Raton Basins. These areas are known to contain high-rank coals and to have high methane contents in those coals. Recent studies have shown that this area is the center of an anomalously high geothermal gradient, which may strongly influence the increased coal rank and therefore the gas content in those areas. Other, less extensive Tertiary igneous events locally influencing coal rank and methane content include the intrusives along the margin of southeastern Piceance Basin, northeastern San Juan Basin, and Piceance Basin, northeastern San Juan Basin, and the volcanic extrusives associated with the Spanish Peaks of the Raton Mesa. Peaks of the Raton Mesa. Coal samples collected in the Piceance Basin increase in gas content from west to east from approximately 200 cubic feet per ton (cf/t) (6.3 cubic centimeters per gramโcc/g) along the Colorado River in the vicinity of Cameo to greater than 1,000 cf/t (31.3 cc/g) in the vicinity of Coal Basin in the southeastern part of the basin near the Elk Mountain intrusives. Coal samples from the Fruitland Coal in northern New Mexico and southern Colorado in the San Juan Basin have been shown to contain in excess of 500 cf/t (15.6 cc/g). Samples collected by the USGS in the Raton Basin from the Vermejo Formation contain in excess of 500 cf/t (15.6 cc/g). It is suggested here that the anomalously high geothermal gradients induced by the intrusion of the San Juan Mountain complex and aided locally by other Tertiary events is substantially responsible for the high-rank coals observed in these areas, and therefore is principally responsible for the anomalously high methane content and the high potential for coalbed methane production from these potential for coalbed methane production from these areas. Introduction For the last four years, studies have been made on the potential for production of methane from coalbeds in numerous areas of the United States. Principal among those areas were the Piceance, San Juan, and Raton Basins of the Rocky Piceance, San Juan, and Raton Basins of the Rocky Mountain West. Two of these areas, the Piceance and San Juan Basins, have been identified as major dry gas-producing regions in the United States. While the San Juan Basin has been recognized as a major gas producer for a number of years, the Piceance Basin has only recently been identified as Piceance Basin has only recently been identified as a major gas province. Close examination of these individual basins indicates that the southeastern Piceance and the northern San Juan are Piceance and the northern San Juan are predominantly gas-rich. These two areas, along with the predominantly gas-rich. These two areas, along with the western part of the Raton Basin, have been identified as having characteristics suggestive of coalbed source for much of the dry gas. This paper will present a discussion of the development of gas resource in the subject basins and why the particular portions of those basins are gas-rich. particular portions of those basins are gas-rich. THEME: DIFFERENTIAL HEATING OF BASIN COALBEDS CREATES METHANE EXPLORATION TARGETS High-rank coals and their attendant high gas contents have been observed during testing of coalbeds in parts of the southeastern Piceance and northern San Juan Basins in Colorado and New Mexico. Generally, areas of high coalbed methane potential can be identified on the basis of: potential can be identified on the basis of:Depth of burial Thickness of coal Rank of coal In the particular areas of interest, all of the requisite characteristics were observed except depth of burial. In both the Piceance and the San Juan, coal rank and observed gas content tend to increase in the shallower coals located in the southeastern and northern portions of the respective basinsโโtoward the same center. P. 151
- North America > United States > New Mexico > Colfax County (1.00)
- North America > United States > Colorado (1.00)
- North America > United States > Texas > Dallas County > Dallas (0.24)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.24)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Rock Type > Igneous Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.97)
- Energy > Renewable > Geothermal (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.49)
- North America > United States > Texas > Maverick Basin > Somerset Field (0.99)
- North America > United States > Texas > Fort Worth Basin > Denver Field (0.99)
- North America > United States > New Mexico > San Juan Basin > Mesa Field (0.99)
- (18 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Non-Traditional Resources > Geothermal resources (1.00)
NMR Logging Tool Development: Laboratory Studies of Tight Gas Sands and Artificial Porous Material
Brown, Joseph A. (Los Alamos National Laboratory) | Brown, Lee F. (Los Alamos National Laboratory) | Jackson, Jasper A. (Los Alamos National Laboratory) | Milewski, John V. (Los Alamos National Laboratory) | Travis, Bryan J. (Los Alamos National Laboratory)
The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16โ18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract We report proton longitudinal relaxation (T1) measurements on water-saturated samples of Western Tight Gas Sand Core mid artificial porous materials. The artificial samples, with well-characterized and porous materials. The artificial samples, with well-characterized and nearly uniform pore structure, serve as a calibration standard for preliminary efforts at inverting the Nuclear Magnetic Resonance relaxation preliminary efforts at inverting the Nuclear Magnetic Resonance relaxation data on the Gas Sand core samples to obtain a distribution of pore surface-to-volume ratios. The distributions obtained show good to excellent agreement with those obtained by mercury porosimetry on the same samples. Various possible effects sire discussed, which could account for the discrepancies observed. Introduction Nuclear Magnetic Resonance (NMR) measurements on fluid-saturated porous media yield several kinds of information that can be of use in porous media yield several kinds of information that can be of use in characterizing the pore structure of these materials. A "standard" NMR experiment on the nuclei of the saturating fluid can yield three quantities of interest: the free induction decay (FID) amplitude, which is a measure of the total number of nuclei presentโโthus porosity times fluid saturation; the spin-lattice, or longitudinal, relaxation time (T1), which contains information regarding the environment of the nuclei in question; and the spin-spin, or transverse, relaxation time (T2), which yields information on the motion of and interaction between the nuclear spins, as well as environmental information. Direct measurements of these quantities in situ will be possible with the advent of the new NMR Logging Tool wider development at Los Alamos. The purpose of this paper is to describe NMR T1 measurements that have been made on several kinds of water-saturated porous materials, and the results of efforts to gain maximum utilization of the information obtained, in characterizing their pore structure. These laboratory studies are required to establish the limits of usefulness, as well as to investigate the range of expected response, of the new NMR logging tool. The concept of the new tool and a description of its development have been given elsewhere. The materials investigated include several samples of Western Tight Gas Sand (WGS) core, as well as several samples of artificial porous material of relatively well-characterized pore structure. The latter were used as "standards" to derive an empirical relationship between the NMR results and pore structure, as described below. In the following sections, we describe the measurements of T1 for WGS pore samples and artificial porous materials, and the extent to which the results qualitatively conform porous materials, and the extent to which the results qualitatively conform to theoretical expectations. We also show the results of a new method of extracting a kind of pore-size distribution from the NMR data, with comparisons to similar distributions obtained from the same samples, by more conventional methods. NMR MEASUREMENTS ON WGS CORE General discussions of the technique of pulse NMR and the measurement of in particular can be found in several texts. Briefly, what is measured is the time evolution, following a perturbation of the system away from equilibrium, of one vector component of the macroscopic magnetization of the sampleโโthat along the direction of the externally applied magnetic field, Mz. In this case, the magnetization arises as the vector sum of the individual nuclear moments of the protons on water molecules within the saturated core sample. For a homogeneous system, such as bulk water, the measured time evolution is given by, .............(1) where the longitudinal relaxation time, represents the characteristic time for return of the magnetization to its equilibrium value, Mo. p. 203
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The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16โ18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Introduction This paper describes a novel technique for measuring the directional permeability trends exhibitor by samples of sedimentary rock cores like permeability trends exhibitor by samples of sedimentary rock cores like those obtained from Western tight gas sands provinces. The technique is thought to be ingeneous, but in any case it finally does address an important laboratory measurement problem in a way that is free from some of the ambiguities associated with the several other methodologies previously referred to in the literature. The book by Bear and the earlier definitive monograph by Scheidegger contain sufficiently extensive review of the subject so that in what follows only the theory of the measurement method under discussion needs to be developed. PROCEDURE PROCEDURE It is assumed that core sample material is available that can be cut into plugs of uniform (say cylindrical) cross section, and therefore can be fit into a permeability core holder of the sort shown in Figure 1. As will be seen, the methodology to be described for measuring the permeability of anisotropic media is the same, in principle, both for single-phase and multiphase saturation and flow conditions. Similarly, the methodology is the same, in principle, regardless of what conditions of confining stress, pore fluid pressure and temperature are imposed. Even so, the data pore fluid pressure and temperature are imposed. Even so, the data presented below apply to single-phase gas flow conditions under ambient presented below apply to single-phase gas flow conditions under ambient laboratory conditions. By definition, in an isotropic medium, permeability is a simple scalar, and in consequence the effluent stream that egresses from a right-cylindrical core sample will be uniformly distributed over the outflow face as shown in Figure 2a. In contrast, the effluent streams for anisotropic media will not be uniformly distributed (see Figures 2b and 2d) unless the end-faces are shaped to make a very special angle with the core axis (see Figure 2c). Figure 1 shows how the effluent stream can be partitioned into upper and lower parts, respectively having flow rates Q UP and Q DOWN. If the sample is isotropic and has he shape of a right cylinder, Q UP = Q DOWN regardless of how the sample is placed along its axis in the core holder. On the other hand, reflection shows that for an arbitrary shaping of the end faces, an anisotropic core will display a Q UP/Q DOWN, ratio that is maximum (or minimum) only when the reference line, Z1 - Z2, shown in Figure 3 is uppermost in the core-holder as shown by Figure 4. Note that in these schematic presentations, it is implied that only a two-dimensional degree of anisotropy is involved - for example, as would be observed in bedded and cross-bedded sediments. In the theoretical discussion given below it is shown that there is always a particular way to shape the end faces of anisotropic cores such that the Q UP /Q DOWN ratio is unity (see Figure 2c), but that or a other arbitrary shapings the ratio is either greater (see Figure 2b) or less (see Figure 2d) than unity. The object of the laboratory method in fact is to discover what the shaping angle, , must be so that Q UP /Q DOWN is unity (i.e. = where A is the angle made by the driving force vector with the axis of the core sample). In order to choose under laboratory conditions the shaping of the end faces such that = (i.e. where Q UP / Q DOWN equals unity), a series of experiments are performed as suggested by Figure 5. For each shaping a permeability experiment is undertaken are measured. The and values for Q permeability experiment is undertaken are measured. The and values for Q UP and Q DOWN are measured. The ratios then are plotted versus the end-face angle in order to determine by trial-and-error the value of the angle A associated with the condition of uniform distribution of effluent fluid egressing from the end face of the core sample. Figure 6 shows that a semilog plot appears to be linear, meaning that a graphical interpolation can be trusted (at least for the cases so-far studied in the laboratory) in order to ascertain when the Q UP/Q DOWN ratio is unity (hence its logarithm is zero). p. 195
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The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16-18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206. Abstract In mid-1981, the Gas Research Institute (GRI) drafted comprehensive programs for research directed toward increasing the national supply of programs for research directed toward increasing the national supply of natural gas from unconventional sources. Low-permeability (tight) gas sands are one of these sources. GRI's predraft planning for the tight gas sands program was for a duration of about one year and included workshops with advisors from the natural gas industry. The resulting program plan for tight gas sands research is oriented to industry participation and field testing. Research results are freely distributed to a wide variety of users. The tight gas sands program is initiating in 1982 planning updates by GRI are on an annual cycle. GRI is proceeding with six projects for tight gas sands research, involving analyses for producing natural gas from tight blanket sands that are presently considered as non-commercial. The program plan is comprised of a sequence of projects relating to resource plan is comprised of a sequence of projects relating to resource identification, formation evaluation, fluids and proppants investigations, fracture design, reservoir modeling, and staged field tests with technology transfer. Accelerated research work is scheduled for 1983, with emphasis on field evaluations beginning in 1984. This paper describes the philosophy, objective, and content of the GRI program plan, which is currently scheduled through 1988. Accomplishment of program plan, which is currently scheduled through 1988. Accomplishment of the program is expected to provide for significant advances in tight gas sands research. GRI is a non-profit scientific organization which contracts applicable research work to others for benefit to the natural gas industry and to natural gas consumers. Introduction Significant quantities of natural gas exist in low-permeability (tight) sands across the United States. The recoverable gas potential of these tight sands is very large; a current estimate places recoverable reserves as high as 574 trillion cubic feet (Tcf.). However, a combination of economic uncertainties and technical limitations has prevented widespread commercial exploitation of this resource. The Federal Energy Regulatory Commission has issued a special incentive pricing mechanism for tight gas reservoirs, and has designated numerous formations as eligible for incentive pricing. However, this action has not encouraged uniform development and production of gas from tight sand formations. To date, resource development has occurred primarily in limited areas. In these areas, state-of-the-art technologies primarily in limited areas. In these areas, state-of-the-art technologies can be used in conjunction with a limited knowledge of the formation characteristics to stimulate economic production rates. Successful research and development in exploitation technology is necessary if the full potential of tight gas sands is to be realized. In recent years, the strategy of the Gas Research Institute (GRI) has been to perform research and development (R and D) in support of ongoing industry and government programs, and to take advantage of important opportunities not budgeted in R and D programs of others. With the advent of budget cuts in the U.S. Department of Energy, and the concurrent realignment of government priorities and objectives toward more long-term, high-risk research, GRI is shifting its strategy, and is taking a lead role in implementing a comprehensive program to develop the technology necessary for gas extraction from tight sand formations. RESEARCH OBJECTIVE The objective of this GRI program is to develop the technology necessary to achieve gas recovery from blanket tight gas sands that are not exploitable using current gas recovery methods and to maximize the potential through industrial cofunding and participation. potential through industrial cofunding and participation. THE GRI TIGHT GAS SAND PROGRAM The necessary R and D in tight gas sands present complex problems. The resource is dispersed over a large geographic area and occurs in a wide variety of geologic environments as indicated in Figure 1. p. 177
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