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Collaborating Authors
Wyoming
SPE-AIME member now with Schlumberger Well Services Abstract Hydraulic fracturing model using various sets of fracture flow/geometry equations are available in the industry. The majority of these models assume a constant fracture height selected at the start of the design, and simulate two-dimensional fracture geometry (width and length) and one dimensional fluid flow in both the fracture and the formation. The two-dimensional fracture geometry simulation can lead to optimistic estimates of fracture lengths and the one-dimensional flow may not allow adequate representation of proppant transport and fluid loss. Highly sophisticated hydraulic fracturing models are available that simulate three-dimensional fracture height and two-dimensional fluid flow throughout the entire fracture process. These models are versatile and are recommended for highly complex, layered, reservoirs where rock material properties, in-situ stress distribution, and flow properties are variable at the wellbore and also throughout the reservoir. For everyday use by the completion/production engineer, hydraulic fracturing models need to be generated that are more advanced than the "conventional" two-dimensional models but simpler approach and less costlier than the fully dimensional models. The hydraulic fracturing model present this paper can be classified as a pseudo three-dimensional fracture geometry accounting for simple two-dimensional fluid flow. Fracture height at the wellbore, width, and length are computed simultaneously. These calculated parameters are then compensated for two-dimensional fluid flow which accounts for friction pressure drop and gravity. An iteration process is set-up until a satisfactory convergence is attained. Knowledge of appropriate fracture geometry and two-dimensional fluid flow enhances the accuracy in fluid loss calculations and proppant transport. Special data required as input proppant transport. Special data required as input to this model include the in-situ stress and mechanical properties distribution in and around the pay zone. The paper presents hydraulic fracturing theory and the basis of the model under discussion. A detailed explanation of the model is also presented where field examples are used to illustrate its use and importance. INTRODUCTION AND BACKGROUND There are currently two basic types of hydraulic fracturing models available in the industry. One that simulates two-dimensional hydraulic fracture geometry and one-dimensional fluid flow (TWO- D). The other type simulates fully three- dimensional hydraulic fracture geometry and rigorous two-dimensional fluid flow (THREE-D). These models have their advantages and disadvantages and limitations in their application. The models are analogous to reservoir models. Some complex reservoirs may require equally complex hydraulic fracturing models, others do not. Equations used in TWO-D models, are based on descriptions by Geertsma and deKlerk, Khristianovitch and Zheltov, Barenlatt, Perkins and Kern Sneddon, Howard and Fast, Daneshy, and Nordgren. In a recent publication by Veatch' a detailed explanation of these models are presented. Basically these models can be grouped in two divisions based on their approach to calculating fracture width. The Geertsma and deklerk approach is based on width calculation in relations to the fracture length. The other approach is the Perkins and Kern, where the model begins with fracture width calculations in terms of fracture height. Both the approach and all of these models assume a constant height selected at the start of the design. The two-dimensional fracture geometry simulation can lead to optimistic predictions of fracture lengths because of assumed small fracture height. The one-dimensional flow may not allow adequate representation of proppant transport and fluid loss Reservoirs that are bounded by very strong barriers to fracture migration are only adequately represented by these models. Where strong barriers do not exist, as is the case with many reservoirs, the constant height assumption will provide overly optimistic fracture lengths and inappropriate fluid loss estimates and proppant transport phenomenon. phenomenon. Among the currently available THREE-D models are those presented by Clifton and Abon-Sayed Cleary, and Palmer. P. 463
- North America > United States > Texas (0.94)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.28)
- North America > United States > Wyoming > Green River Basin > Pinedale Field (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Arch Field (0.99)
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 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 (115–215 ft, 35–66 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 2–5. 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 × 10-7 to 2.4 × 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...)
Members SPE-AIME 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 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 A synthesis of treatment design parameters, treatment procedures in the field, quality control, and analysis of procedures in the field, quality control, and analysis of created fracture parameters is essential to improve and optimize hydraulic fracture treatments in a particular field. This paper provides a step-by-step approach to treatment design optimization that combines laboratory, field and analytical efforts. The laboratory program includes measurements of porosity, absolute and relative permeability, capillary pressure, elastic moduli, matrix permeability, capillary pressure, elastic moduli, matrix permeability and proppant bed sensitivity to fluid (reservoir permeability and proppant bed sensitivity to fluid (reservoir and treatment) all at simulated in-situ conditions and appropriate petrographic study. The field test program involves in-situ stress measurements (mini-fracs in the pay and surrounding formations), fracture orientation pay and surrounding formations), fracture orientation determination and transient pressure tests. Successful implementation of the optimized design is then carried out by monitoring of flow rate and bottom hole pressure during the job and change of design parameters as necessary to tailor the fracture geometry. This must be coordinated with a quality control program for both the equipment and materials used in the job. A brief review of the state-of-the-art of transient pressure analyses of fractured wells is also included in the paper to inform the practicing engineer of the advantages, disadvantages and limitations of each technique. Finally, a field example is presented that illustrates the step-by-step approach. Designed and created fracture parameters are critically compared to demonstrate the effectiveness of the procedure and show how such information can be used to further improve results. We gratefully acknowledge the Gas Research Institute (GRI) and the U.S. Department of Energy, which have funded some of the work presented here. Introduction Since the early mid-century, hydraulic fracturing has been proposed as the solution to economically increase oil/gas proposed as the solution to economically increase oil/gas production from the relatively low pressure, low permeability production from the relatively low pressure, low permeability reservoirs. Results to date of hydraulic fracturing treatments, however, vary from extremely successful to extremely disappointing failures. The disappointing failures and the recent global energy crisis have raised the need to critically understand the stimulation process and devise means of optimizing the effectiveness of these treatments. The study presented by Fast, et al. following their hydraulic fracturing experience at the Wattenberg Field was one of the first papers to critically outline some of the basic important parameters papers to critically outline some of the basic important parameters controlling the success of hydraulic fracturing. They emphasized pre-job planning and pre-stimulation well testing and noted a pre-job planning and pre-stimulation well testing and noted a requirement for further research and development. Since then, the data and tests needed for stimulation design have become more clearly defined. Simonson, et al., first defined the conditions needed for fracture containment and which since have been detailed by Cleary and Ahmed, et al.. Ahmed, et al. described tests that evaluate fracturing fluid damage to the reservoir matrix permeability and fracture conductivity and showed the importance of these tests when designing hydraulic fracturing treatments. Meanwhile, fracturing fluid proppant developments have greatly enhanced the opportunity of improving stimulation design. Recent literature contains increasing evidence of enhanced production and improved economics with better pre-job evaluation production and improved economics with better pre-job evaluation and planning. Besides the Wattenberg Field, job locations have included the Cotton Valley, the Anadarko Basin, the North Douglas Creek Arch, the North Sea, and the Fort Union Formation in the Green River Basin in Wyoming. The pre-job testing and evaluation was different for each of the projects listed; however, there was emphasis on the selection of fracturing fluid (to minimize residue accumulation and matrix permeability damage) and quantifying the fracture conductivity required to economically optimize treatments. P. 327
- North America > United States > Colorado > Denver County (0.68)
- North America > United States > Colorado > Weld County (0.54)
- North America > United States > Colorado > Larimer County (0.44)
- (6 more...)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.64)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- North America > United States > Wyoming > Green River Basin > Pinedale Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Oak Hill Field (0.99)
- North America > United States > Texas > Anadarko Basin (0.99)
- (4 more...)
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 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 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, held in Pittsburgh, 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, Texas 75206. Abstract This paper discusses the results of a study made to evaluate the effectiveness of sintered bauxite as a propping agent for Mesaverde fracture stimulations in Wyoming's Wamsutter Tight Formation Gas Area. It is generally accepted that bauxite should be used when closure pressure exceeds 8000 psi (55 MPa). Above this pressure, sand undergoes significant crushing resulting in very large reductions in permeability. However, in areas similar to Wamsutter, where the closure pressure ranges from 6000 to 8000 psi (41 to 55 MPa), it is not clear whether sand or bauxite should be used. A reservoir simulator and an economic model were used to optimize fracture length and to determine if bauxite should be used in Wamsutter. It was found that well performance can be accurately predicted with the simulator when a 0.1 in situ predicted with the simulator when a 0.1 in situ fracture flow capacity correction is made to laboratory measured fracture flow capacities. Over the range of permeabilities studies, (0.01 to 0.4 md) it was determined that bauxite should be used as the propping agent rather than sand. The economic benefits of using bauxite are greatest at the higher reservoir permeabilities. At a reservoir permeability of 0.4 md the optimum fracture length is 200 feet (610 m) when using bauxite, while at a reservoir permeability of 0.01 md the optimum fracture length is 5000 feet (1,524 m). Introduction Massive hydraulic fracturing (MHF) is the key to achieving commercial production from low permeability formations. Well economics are strongly dependent on MHF cost and performance. In areas like Wamsutter, MHF costs can account for up to 50 percent of the total well cost. Fracture performance is affected by both length and flow capacity. Therefore, in order to find them most cost effective fracture stimulation, both of these parameters must be optimized. Fracture flow capacity is largely determined by the type of proppant that is placed in the fracture. In Wamsutter, sand has historically been used as the propping agent, even though it has been known for several years that bauxite is a superior proppant. It has been shown that bauxite should proppant. It has been shown that bauxite should be used when closure pressures are greater than 8000 psi (55 MPa) due to the severe crushing of sand at these pressures. However, it is not clear whether formation is Wamsutter where the closure pressure ranges from 6000 to 8000 psi (41 to 55 MPa). pressure ranges from 6000 to 8000 psi (41 to 55 MPa).Even though bauxite is a superior proppant, it also costs approximately ten times more than sand. Therefore, the use of bauxite as the proppant at closure pressures under 8000 psi (55 MPa) can only be justified based on a detailed economic study optimizing fracture flow capacity and length. Fracture length and flow capacity were optimized using a reservoir simulator and an economic model. The reservoir simulator was used to predict production from various fracture systems incorporating production from various fracture systems incorporating different length fractures propped with either bauxite or sand. The economic model was first used to calculate the incremental economics associated with increasing fracture length for a given proppant, then secondly, to calculate the incremental economics associated with using bauxite in place of sand. This procedure was repeated for reservoir the optimum fracture length and proppant type were determined for each reservoir permeability studied.
- North America > United States > Wyoming (0.71)
- North America > United States > Texas > Dallas County > Dallas (0.24)
- North America > United States > Colorado > Piceance Basin > Mesaverde Formation > Williams Fork Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 210/24a > Lewis Field > Brent Group Formation (0.98)
- North America > United States > Wyoming (0.91)
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 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 A composite model for gas well performance evaluation and prediction has proven successful and efficient in analyzing gas wells producing from low permeability tight gas formations. By employing permeability tight gas formations. By employing analytic methods which model reservoir and fracture behavior, a model has been constructed which is capable of automatic regression for the descriptive reservoir parameters. The model is designed to treat producing and shut-in conditions ranging from a simple four-point test to several years of online pressure-production history. Once history-matched parameters are determined, the model is then capable of projecting future performance. Field examples of wells producing from tight reservoirs (Eagle; Medina; Niobrara) are presented to demonstrate the applicability of the model in both production performance analysis as well long term forecasting. These results are compared to finite difference simulation results to demonstrate the model's consistency. In addition, the computational needs of the model in terms of processing time are compared to those of a finite processing time are compared to those of a finite difference simulator. Introduction The commercial exploitation of low permeability gas reservoirs has required the application of sophisticated engineering techniques including fracture stimulation treatments in order to bring them into the realm of economic resource potential. Because of the radically different and changing nature of the flow regimes in a fractured tight gas well compared to conventional producing wells, traditional analysis techniques such as rate-time decline analysis or back-pressure analysis, especially when applied to the early life history of tight gas wells, have been shown to be unreliable in predicting future performance. More thorough predicting future performance. More thorough analysis of the total physical behavior of such reservoir systems has been necessary in order to interpret their behavior. This includes new methods of log analysis, petrographical studies and simulation modelling. In the area of simulation, good success has been obtained in the past with finite difference numerical simulation of vertically fractured wells. Such a method allows great modelling flexibility to the extent that anisotropic reservoir conditions and finite capacity fractures can be effectively handled. But as successful as it has been, the wide applicability of such an analysis technique is severely limited by its expense even when the finite difference simulator is thoroughly efficient. The need to find a way to establish reasonable parameters efficiently to reduce the cost of parameters efficiently to reduce the cost of simulation was the impetus for developing a simpler model. A radial transient flow model without a fracture was inadequate for the task of characterizing fractured tight gas wells. A practical yet sufficiently rigorous model that can be widely used in low permeability reservoir analysis has been constructed that obtains results comparable to finite difference simulation with much less computational expense. While it is more constrained and limited in its basic assumptions than a more complex simulator, the intent of this paper is to show that such a model provides an effective method for individual tight gas well performance analysis and prediction. Because of its performance analysis and prediction. Because of its efficiency, it can be widely applied and thus eliminates the need to use analog methods. The practical value of a simple approach cannot be overestimated. A general principle cited by Coats that should always be kept in mind in simulation is that one should "select the least complicated model and the grossest reservoir description that will allow the desired estimation of reservoir performance." performance." P. 481
- North America > United States > Wyoming (0.28)
- North America > United States > Colorado (0.28)
- North America > United States > Texas > Dallas County > Dallas (0.24)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.24)
- North America > United States > Wyoming > Niobrara Formation (0.99)
- North America > United States > Nebraska > Niobrara Formation (0.99)
- North America > United States > Kansas > Niobrara Formation (0.99)
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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 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)
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- 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)
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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 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 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 gram—cc/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 basins––toward 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)
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- 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)
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- 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)