Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Summary To obtain optimal results from the fracturing process, several new fracturing technologies can be applied to prevent inappropriate stimulation designs and catastrophic fracture-fluid problems. Despite industry awareness of these technologies, they are not applied routinely because of their added expense. In addition, the benefits are difficult to quantify and often are not clearly understood. In this paper, we present an economic assessment of fracture-treatment quality control, in-situ stress profiling, and 3Dfracture-propagation models that indicates that these technologies increase gas reserves by 10% to 20% for a 5% to 10% increase in the well cost. The application of these technologies is profitable when the formation gas permeability is between 0.001 and 0.3 md. Introduction In recent years, hydraulic fracturing research performed by the Gas Research Inst. (GRI) and other industry organizations has generated a wealth of new technology, including the GRI Mobile Testing and Control Facility, the GRI Rheology Unit, FRACPRO (a 3D fracture design program), the Treatment Analysis Unit, procedures for developing in-situ stress profiles, and microseismic processing techniques to determine fracture height and azimuth. Also, field experiments performed on Cooperative Research and Staged Field Experiment (SFE) wells have provided comprehensive data sets for developing and testing new ideas. Our field research shows that the in-situ stress contrasts between rock layers and fracture-fluid viscosity are often quite different from the values assumed or estimated by the design engineer. Errors in assumed values of the in-situ stress contrast lead to inaccurate reservoir descriptions and inappropriate stimulation designs. Fracture-fluid problems compound the situation through poor proppant transport or fracture plugging with unbrokengel.
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Mississippi > Travis Peak Formation (0.99)
- North America > United States > Louisiana > Travis Peak Formation (0.99)
- (4 more...)
Summary Wells drilled to produce methane from coal seams are completed with either a perforated casing method, a stable cavity method, or an openhole method. The perforated casing method followed by hydraulic fracturing works best in most coalseam wells. In high-permeability, high-pressure coal seams, the stable cavity method may be preferred, To design the optimum completion, a completion engineer must consider the unique aspects of producing methane from coal. Introduction Methane produced from coal seams is an important energy source in the petroleum industry. The increased development of coal-seam reservoirs can be attributed to (1) U.S. income tax credit that is associated with producing coalbed methane, (2) Gas Research Inst. (GRI) research funding to improve technology, and (3) an increased awareness in the industry concerning the importance of coalbed methane. Geologic assessments of coalbed methane reservoirs have been funded by the U.S. DOE and the GRI. Currently, resource assessments are available on the Arcoma basin, Black Warrior basin, Cahaba and Coosa coal fields, Central Appalachian basin, Greater Green River coal region, Illinois basin, Northern Appalachian basin, Pennsylvania anthracite fields. Piceance basin, Powder River basin. Raton basin, Richmond and Deep River basins, San Juan basin, Uintah basin, Valley coal fields, Western Washington coal region, and the Wind River basin. On the basis of detailed studies of these coal areas, GRI estimates that 300 to 400 Tcf of gas in place is contained in the U.S. Table 1 contains the details concerning the gas in place for each basin. Most methane recoverable from coal seams will be in reservoirs that are less than 5,000 ft deep. The low-cost drilling associated with the shallow depths makes coalbed methane development suitable for independent producers. In addition, the need for large acreage positions and the technical challenges involved with producing gas from coal seams also provide incentives for big producing companies to pursue coalbed methane development actively. Because of these inducements, a wide variety of companies develop coalbed methane reservoirs. Several papers on completing wells in coalbed methane formations have been published. In 1980, Steidle et al. published a paper concerning completion techniques from vertical published a paper concerning completion techniques from vertical methane drainage boreholes in Virginia. Lambert et al., Logan et al., and Clark et al. have discussed specific completion problems in specific coalbed methane areas. Lambert et al. problems in specific coalbed methane areas. Lambert et al. discussed completion alternatives that have been evaluated in the Black Warrior basin. Logan et al. and Clark et al. discussed coal-seam well completions in the San Juan and Piceance basins. Much of the published information on coal seams has evolved through research projects sponsored by the GRI. The objective of this paper is to explain the various completion options that are available to an operator developing a coal-seam reservoir. On the basis of the unique properties of coal, the engineer must develop a completion strategy. The strategy should include specific details concerning the site of the perforations and the stimulation treatment needed to maximize gas perforations and the stimulation treatment needed to maximize gas recovery.
- North America > United States > Mississippi (1.00)
- North America > United States > Alabama > Tuscaloosa County (0.69)
- North America > United States > Wyoming > Wind River Basin (0.99)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Powder River Basin (0.99)
- (30 more...)
Summary This paper presents results from research conducted on the third Gas Research Inst. (GRI) staged field experiment (SFE) well. Research well SFE No. 3 was drilled as part of a field-based research program conducted in east Texas during the past 7 years. Most of the work before SFE No. 3 involved the Travis Peak formation; however, the Cotton Valley sandstone was the primary research target for this well. SFE No. 3 is the last in a series of research wells planned for east Texas. A fourth SFE planned for east Texas. A fourth SFE is being conducted in the Frontier formation of southwestern Wyoming. Data on SFE wells are collected from whole cores, open hole geophysical logs, in-situ stress measurements, production and pressure-transient production and pressure-transient tests, fracture stimulation treatments, fracture-diagnostic measurements, and postfracture performance tests. These data then are analyzed by research scientists, geologists, and engineers to describe the reservoir and hydraulic fracture fully. Introduction GRI has sponsored a field-based research program in east Texas during the past 7 program in east Texas during the past 7 years. A major effort of this program has been the SFE project, in which wells were drilled specifically to conduct research in the analysis and stimulation of tight gas sands and to validate technologies under development in other GRI research projects. The first two SFE wells have been completed and the results published in various reports and technical papers. The fourth SFE project, in the Frontier formation of project, in the Frontier formation of southwestern Wyoming, was completed in late 1991. This paper presents the results from the third SFE well. Data on SFE wells are collected from whole cores, openhole geophysical logs, insitu stress tests, production and pressure transient tests, fracture stimulation pressure transient tests, fracture stimulation treatments, fracture-diagnostic measurements, and postfracture performance tests. The main purpose of collecting such a comprehensive set of data is to describe the reservoir and hydraulic fracture fully. Our goal is to obtain the most accurate analysis possible to provide a better understanding of the possible to provide a better understanding of the hydraulic fracturing process. We hope that this work will lead to better treatment designs and additional gas production from tight gas sands, which we believe can be achieved through the practical application of new technologies and more rigorous analysis techniques with numerical models. Unless these models and tools can be applied on a more routine basis by the practicing engineer or geologist, however, technology transfer will not be accomplished. The development of practical and useful tools and methods that will benefit the natural gas industry is of primary importance to this research project. SFE No. 3 was drilled and completed in late 1958 and 1989. The lower Cotton Valley (Taylor) sand was the primary interval of completion and stimulation in this well. In this paper, we summarize the work performed and data collected on SFE No. 3 and performed and data collected on SFE No. 3 and present results from the data analyses. present results from the data analyses.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Texas > East Texas Salt Basin > Whelan Lease > Waskom Field > Lowe Paluxy Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation > Bossier Shale Formation (0.99)
- North America > United States > Louisiana > East Texas Salt Basin > Cotton Valley Group Formation > Bossier Shale Formation (0.99)
- (7 more...)
Summary In spite of the proliferation of well-test analysis literature in recent years, many pressure-transient tests are still being misinterpreted, partly because a logical procedure is lacking and incomplete analysis is partly because a logical procedure is lacking and incomplete analysis is performed by nonexpert analysts. The time and difficulty involved in hand-analysis techniques often discourage a complete, consistent analysis. A properly designed computer program that uses interactive graphics can improve the accuracy of test interpretations by enabling the engineer to perform thorough and consistent analyses quickly and easily. Microcomputers are ideally suited for such a program because of their computing power, portability, and relatively low costs. The development of microcomputers and well-test-analysis software places "expert" interpretive capabilities within the reach of most engineers. Introduction The development of powerful microcomputers is having a profound influence on pressure-transient test analysis of oil and gas wells. Computer-aided well-test analysis is not new; many papers have been written in the last several years describing software packages for well-test analysis with either conventional techniques or automated history-matching methods. Until the recent development of inexpensive, powerful microcomputers, however, these programs were usually available only to companies with mainframe computers and software development staffs. With the microcomputer and welltest analysis software. a sophisticated set of analysis tools has become available to most petroleum engineers. Well-test analysis is an ideal application for microcomputers. The reasons are many.Microcomputers take the "dogwork" out of hand-calculation techniques. Many of the calculations involved are difficult enough to discourage hand calculation, yet are not so time-consuming that they cannot be performed easily and quickly on a microcomputer (unlike reservoir simulation at the present time). In addition, another time-consuming part of hand-analysis techniques, plot generation, is easily performed by the microcomputer. Microcomputers encourage the use of more-sophisticated analysis methods, as in the use of pseudopressures and pseudotimes for gas well-test analysis. In many cases, these plotting pseudotimes for gas well-test analysis. In many cases, these plotting functions are not used because of the difficulty and time required to generate them. Maintaining a microcomputer program makes it easy to stay current with the latest well-test-analysis technology. The interactive graphics capabilities of the microcomputer are ideal for well-test analysis. A complete analysis with many techniques can be performed very quickly with interactive graphics. By hand, it is tempting to stop after one or two techniques have been tried. This can sometimes lead to an incorrect interpretation. Microcomputers are portable. which means that they can be used at the test site to analyze the test while it is being conducted. This minimizes test duration, which can result in substantial cost savings. Microcomputers and available well-test-analysis software are relatively inexpensive. This makes quality well-test interpretation available to many more engineers. The improved quality of well-test interpretation industry-wide can only increase the acceptance and use of pressure-transient testing as a reservoir-defining tool. The objective of this paper is to present ideas on the design of a well-test analysis program that best takes advantage of the capabilities of the microcomputer. A philosophy on how to analyze a well test properly is discussed, because it is an integral part of the design of the program.
Summary Severe fracture-conductivity damage can result from proppant crushing and/or proppant flowback into the wellbore. Such damage is often concentrated near the wellbore and can directly affect postfracture performance. Most of the time severe fracture-conductivity damage can be minimized by choosing the correct type of proppant for a particular well. In many cases, however, this is not enough. To minimize excessive crushing or to prevent proppant flowback, it is also necessary to control carefully the flowback of the well after the treatment. Specific procedures can be followed to minimize severe fracture-conductivity damage. These procedures involve controlling the rates at which load fluids are recovered and maximizing backpressure against the formation. These procedures require much more time and effort than is normally spent on postfracture cleanup; however, the efforts could result in better performance. Introduction Because of the ever-increasing development of low-permeability oil and gas reservoirs, hydraulic fracturing has become one of the most important aspects of a a well completion. A fracture treatment can account for 10 to 50% of the total well cost. Thus, significant emphasis should be placed on optimizing the treatment design, especially the selection of proppant. However, there is another aspect of the treatment that is just as important, but is often overlooked or taken for granted - i.e., the flowback and cleanup of the well immediately after the fracture treatment has been pumped. The detrimental effects of reduced fracture conductivity on well performance have been documented in the petroleum literature. Such damage can result primarily fromfracture plugging resulting from gel residue, fluid loss additives, or formation fines; severe proppant crushing; or proppant flowback in the wellbore. Severe crushing and proppant flowback are the major topics of discussion in this paper. These factors have been found to cause drastic reductions in fracture conductivity, particularly near the wellbore. In many cases, the damage has occurred as a result of flowing the well too hard in an attempt to produce more oil or gas. A brief review of inflow performance relationships, however, illustrates that very little additional production will result from this additional drawdown. Most of the time, this near-wellbore damage can be prevented by choosing the correct type of proppant and by carefully controlling flowback after the treatment. Even though a growing number of engineers now recognize this fact, there appears to be a need for further awareness in the field, where many of these operations are controlled. Basically, there is a lack of case histories in the literature that document fracture-conductivity damage on actual wells and that illustrate and emphasize to industry the severity of the problem. Foremost, there are no guidelines and procedures that are generally accepted by industry on how to minimize this damage. This paper presents field examples in which severe crushing and the production of proppant into the wellbore have occurred. In each of these cases, the problems can generally be attributed to flowing the wells too hard. Finally, techniques are discussed and procedures are recommended for minimizing these effects. Postfracture Pressure Decline Several papers have been written that describe techniques for analyzing fracture-injection pressures during the job and the pressure decline after the treatment is over. These techniques can be used to determine a variety of parameters that help to quantify a fracture and the fracturing process in general. One of the most significant variables determined from postfracture pressure-decline analysis is the fracture-closure pressure, which is important because it is approximately equal to the least principal stress. The fact that the fracture has closed, however, is critical from the standpoint of trapping the proppant before it has a chance to settle in the fracture. In addition, the fracture should be closed before the well is opened for cleanup. Measurement and detection of fracture closure require that an accurate pressure gauge be left on the wellhead or in the hole after the treatment is completed. The rate of pressure decline will depend on the leakoff characteristics of the formation. Thus, in permeable formations, the pressure may fall off rapidly, allowing the fracture to close in a relatively short period of time. Discussion of Field Case Histories. Fig. 1 presents the pressure-falloff data for a gas well in Indonesia, which illustrate such a high-permeability case. These pressure data are plotted vs. the square root of shut-in time. For this example, the reservoir permeability was about 1.5 md and the fracture closed at a square root of time equal to 0.53 hours or about 17 minutes. The fracture-closure pressure determined from these data was 6,930 psi [47.8 MPa] at the surface, which was equal to 13,000 psi [89.6 MPa] at bottomhole conditions. The value of closure stress gradient (0.95 psi/ft [21.5 kPa/m]) determined from these falloff data was approximately equal to other values obtained in this field from in-situ stress tests. This example illustrates fairly rapid fracture closure, and in such cases, one would not be too concerned about proppant settling. In low-permeability reservoirs, however, 12 to 24 hours may be required before the pressure declines sufficiently to allow fracture closure. In these instances, it may be necessary to flow the well back slowly on a 2/64- or 3/64-in. [0.8- or 1.2-mm] choke to bleed off pressure from the well and to assist fracture closure. In doing so, some proppant may be produced into the wellbore; however, because of the low flow rates that are recommended (5 to 10 gal/min [0.019 to 0.038 m/min]), only a small amount of proppant is likely to be produced. After fracture closure is detected or when the pressure is bled down to below the known value of closure pressure, then the well should be shut in to allow the gel to break. Discussion of Field Case Histories. Fig. 1 presents the pressure-falloff data for a gas well in Indonesia, which illustrate such a high-permeability case. These pressure data are plotted vs. the square root of shut-in time. For this example, the reservoir permeability was about 1.5 md and the fracture closed at a square root of time equal to 0.53 hours or about 17 minutes. The fracture-closure pressure determined from these data was 6,930 psi [47.8 MPa] at the surface, which was equal to 13,000 psi [89.6 MPa] at bottomhole conditions. The value of closure stress gradient (0.95 psi/ft [21.5 kPa/m]) determined from these falloff data was approximately equal to other values obtained in this field from in-situ stress tests. This example illustrates fairly rapid fracture closure, and in such cases, one would not be too concerned about proppant settling. In low-permeability reservoirs, however, 12 to 24 hours may be required before the pressure declines sufficiently to allow fracture closure. In these instances, it may be necessary to flow the well back slowly on a 2/64- or 3/64-in. [0.8- or 1.2-mm] choke to bleed off pressure from the well and to assist fracture closure. In doing so, some proppant may be produced into the wellbore; however, because of the low flow rates that are recommended (5 to 10 gal/min [0.019 to 0.038 m/min]), only a small amount of proppant is likely to be produced. After fracture closure is detected or when the pressure is bled down to below the known value of closure pressure, then the well should be shut in to allow the gel to break.
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > Anadarko Basin (0.99)
- North America > United States > Oklahoma > Red Fork Channel Sand Formation (0.99)
- (7 more...)
Summary The Wilcox (Lobo) trend of Webb and Zapata counties, TX, is a series of geopressured, low-permeability sands with average depth from 5,000 to 12,000 ft [1525 to 3660 m]. More than 1,000 wells have been drilled in this prolific trend during the last 10 to 12 years. Although actively developed earlier, the trend became even more attractive after its classification by the Federal Energy Regulatory Commission (FERC) as a "tight" gas formation. Essentially, development of the Wilcox (Lobo) has been successful because of modern technological advances. This paper presents the results of several years of study involving the geologic history, completion methods, massive-hydraulic-fracture (MHF) stimulation treatments, reservoir evaluation, and numerical analysis of hydraulically fractured wells in this trend, all of which illustrate the application of this modern technology. Introduction Low-permeability gas reservoirs have been developed actively in the U.S. during the past 10 to 15 years. Three of the most important criteria for the successful development of any area are (1) gas market availability, (2) gas prices adequate to justify the risks involved, and (3) proper prices adequate to justify the risks involved, and (3) proper application of modern technology. A key element is the development and transfer of the technology necessary to develop low-permeability gas sands economically. Many authors have contributed to the transfer of technology during the past few years by presenting papers concerning fracture fluids, fracture design equations, pressure-transient analysis, and other specific topics, pressure-transient analysis, and other specific topics, Papers that describe a field case history are normally Papers that describe a field case history are normally quite useful to most petroleum engineers. This paper presents the results of several years of work involving the geopressured Wilcox (Lobo) formation in Webb and Zapata counties, TX, including the geologic history, completion techniques, hydraulic-fracture stimulation techniques, and reservoir evaluation of the Lobo formation. In the 1960's, several wells were drilled and tested in the Wilcox (Lobo) formation. Because of low gas prices and a lack of pipelines, however, the area was considered uneconomical and remained inactive for several years. Successful production from the Wilcox (Lobo) sands in Mexico renewed interest in this trend in the early 1970's. Consolidated Oil and Gas Co. drilled its N.H. Clark Well 1 directly across the Rio Grande from established production in Mexico. This well produced at rates of up to 7.0 MMcf/D [198 ร 10(3) m3/d] and officially discovered the Wilcox (Lobo) trend in the U.S. Early exploratory drilling, which was concentrated near the U.S./Mexico border, soon established the Wilcox (Lobo) trend as a major gas-producing horizon. As drilling progressed farther from the border, the Lobo was encountered at greater depths and the productive extent of the Lobo was expanded to include an area of at least 1,800 sq miles [4660 km2]. Even though the shallower sands near the border seem to produce at higher initial rates than the deeper sands, virtually every well drilled in the Lobo trend is fracture-stimulated to increase gas flow rates and recoverable reserves. As a result, MHF technology has been used quite extensively, particularly in the deeper areas. Because fracture stimulation costs can amount to a significant fraction of the total well costs (10 to 20%), it is important to optimize this phase of the completion. State-of-the-art analysis techniques, such as numerical history-matching simulation, have been used by many operators in an effort to optimize and to ensure effective fracture stimulation treatments. Even though more than 1,000 wells have been drilled, the Lobo sands are far from being completely developed. The productive limits of the trend are still being explored, with wells being drilled farther to the north, east, and south of the U.S./Mexico border. In these directions, the sands dip to depths of approximately 10,000 to 12,000 ft [3050 to 3660 m]. Because of the abnormally high pore-pressure gradients associated with these depths, the pore-pressure gradients associated with these depths, the drilling and completion techniques must be well integrated.
- North America > United States > Texas > Kleberg County (1.00)
- North America > United States > Texas > Zapata County (0.81)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Lobo Field (0.99)
- South America > Argentina > Tierra del Fuego > Magallanes Basin > South-central > Zapata Formation (0.97)
- North America > United States > Texas > Sligo Field > Sligo Formation (0.89)
- (4 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
Introduction Long hydraulic fractures are usually required to optimize recovery from low-permeability gas reservoirs. Since these fractures can be quite expensive to create and since there is still a great deal of "art" associated with fracture design and creation, it is frequently helpful to use pressure-transient tests to determine created fracture properties. In this way, optimal fracture treatments can be developed for a given area. Fast et al. 1 and Kozik and Holditch presented examples showing the potential benefits of such an approach. In addition, Veatch demonstrated the effectiveness of combining the efforts of operations and research personnel to characterize and then to improve stimulation treatments in specific areas. The specific task of the engineer is to estimate propped fracture length and effective fracture conductivity for treatments in a given geological formation, If the reasons for success or failure of previous fracture treatments can be determined, the engineer can then do a better job in the future when designing fracture treatments for the same area. There are currently four basic techniques used to analyze postfracture pressure-transient tests:semilog (pseudoradial flow) analysis, square-root-of-time (linear flow) analysis, type-curve analysis. and reservoir simulator history matching. The strengths and weaknesses of each technique were discussed by Lee and Holditch. No existing technique is without problems or possible ambiguity in some applications; thus, there is a need for still other techniques that may succeed in some situations for which existing techniques are inadequate. The purpose of this paper is to introduce such a new technique for analyzing postfracture pressure-buildup tests. This technique can be particularly helpful when analyzing data from wells in which a finite-conductivity fracture has been created. Proposed Technique The pressure-buildup test analysis technique proposed in this paper requires that the analyst prepare a semilogarithmic graph and a square-root-of-time graph of the test data. The technique also requires use of two correction curves developed from the analytical solutions for finite-conductivity fractures presented by Cinco-Ley et al. The analyst chooses a single straight line on each of the graphs prepared for the test data and solves for fracture length, formation permeability, and fracture conductivity with an iterative procedure. Semilogarithmic Graph As a first step in understanding the basis for the proposed method, consider Fig. 1. JPT P. 981^
- North America > United States > Colorado > DJ (Denver-Julesburg) Basin > Wattenberg Field (0.99)
- North America > United States > Texas > East Texas Salt Basin > Fallon Field (0.94)
Summary This paper shows that mud-filtrate invasion prior to drillstem testing in low-permeability gas formations can cause significant reduction of gas flow rate observed during the test. In addition, apparent gas permeabilities determined from test data can be much lower than the true values. These conclusions are supported by simulator results and field data. Introduction Interpretation of drillstem tests (DST's) in low-permeability gas formations is difficult. and this difficulty leads to uncertainty in identifying formations that, when stimulated, could become commercial completions. Operators have tong suspected that mud-filtrate invasion into these low-permeability formations could contribute to these uncertainties because of significant alterations in relative permeability and capillary pressure. These uncertainties led us to a study of the effects of mud-filtrate invasion on response in a DST; this paper reports the results of that study. In this investigation, we used a two-phase, two-dimensional, fully implicit reservoir simulator to model DST's. The input data for the simulator were obtained from special core analyses. openhole tops, and DST's from the Falher sandstone in western Canada. Model Description The two-dimensional, two-phase model used in this study has been described previously in the literature. The model simulates the flow of gas and water in the formation using a simultaneous determination of saturations and pressures from finite-difference approximations of the gas and water flow equations. Capillary pressure and relative permeability data are input into the model; the model is therefore capable of simulating imbibition, water blocking, and cleanup effects. These effects are potentially important in DST performance. To simulate a DST, uniform initial pressures and saturations were established in the model for all reservoir cells. To model the imbibition of filtrate into the formation prior to the DST, the pressure in the wellbore was set equal to (and maintained at) the hydrostatic mud pressure, and the water (filtrate) saturation was maintained at 100%. Water saturations and pressures around the wellbore increased during the imbibition period as filtrate moved into the reservoir. To model a mud filter cake, the permeabilities in the formation adjacent to the wellbore were reduced. Following the imbibition period, a flow period was simulated. During the flow period, the pressure in the wellbore was maintained at a fixed pressure and the wellbore volume was set equal to the value of a typical drillpipe open to flow. Following the flow period, a pressure buildup test was simulated, with the wellbore volume set equal to a typical volume below the shut-in valve in a DST tool assembly . JPT P. 299^
- North America > Canada (0.88)
- Europe > Norway > Norwegian Sea (0.25)
- North America > United States > California > Sacramento Basin > 4 Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin (0.99)
Summary This paper presents theoretical and practical aspects of methods used to determine formation permeability, fracture length, and fracture conductivity permeability, fracture length, and fracture conductivity in low-permeability, hydraulically fractured gas reservoirs. Methods examined include Horner analysis, linear flow analysis, type curves, and finite-difference reservoir simulators. Introduction The purpose of this paper is to summarize the theoretical background of methods that we have attempted to use to determine formation permeability, fracture length, and fracture conductivity permeability, fracture length, and fracture conductivity in low-permeability, hydraulically fractured gas reservoirs. This summary is intended to emphasize the major strengths and weaknesses of the methods studied. These characteristics have not always been emphasized in the original literature and, in some cases, have remained obscure to the practicing engineer. The paper also includes examples from 13 wells in which postfracture-treatment pressure buildup surveys have been analyzed in detail. Test analysis methods discussed in the paper include (1) a method applicable only after a pseudoradial flow pattern is developed in the pseudoradial flow pattern is developed in the reservoir, (2) a method applicable when linear flow dominates in the reservoir, (3) published type curves, with emphasis on those that include finite- conductivity fractures, (4) a modification of linear- flow techniques useful for finite-conductivity fractures, and (5) use of finite-difference reservoir simulators in a history-matching mode. Pseudoradial Flow Pseudoradial Flow Russell and Truitt pioneered application of methods based on the assumption of pseudoradial flow in a fractured reservoir for determination of formation permeability and fracture length. A working permeability and fracture length. A working definition of pseudoradial flow is that sufficient time has elapsed in a buildup or drawdown test so that bottomhole pressure (BHP) varies linearly with the logarithm of flow time (drawdown) or the Horner time group (tp + delta t)/ delta t (buildup), as expected for radial flow in an unfractured reservoir. In an infinite-acting (unbounded) reservoir, the analysis technique is based on the use of skin factor, s, which can be calculated from (1) and the observation that, for infinitely conductive vertical fractures, (2) Eqs. 1 and 2 can be combined to avoid the intermediate step of calculating s: (3) In principle, we can plot buildup test data on a conventional Horner graph, determine the slope m, and thus estimate formation permeability (k = 162.6 qgBga mu a/mh) and determine fracture half-length, Lf from Eq. 3 (see Fig. 1). JPT P. 1776
Summary This report summarizes the results of an active stimulation program on the Cotton Valley Lime as evaluated using reservoir production and pressure transient data. Using standard economic parameters and reservoir permeabilities determined by history matching, a detailed study was made to determine the well spacing and fracture length radius necessary for optimum development of the Fallon and North Personville fields. Introduction Considerable emphasis has been placed in recent years on recovering gas from "tight-gas" basins. One step that shows promise for unlocking tight gas is massive hydraulic fracturing (MHF). A case in point is the evolution of the stimulation in the Cotton Valley Lime at Fallon and North Personville fields, about 10 miles southeast of Mexia in Limestone County, TX (Fig. 1).The Jurassic Cotton Valley group on the west flank of the East Texas basin generally consists of a succession of about 1,000 ft of terrestrial and marine sands and shales, 800 ft of dark (Bossier) shale, and 300 to 500 ft of limestone at the bottom known as the Cotton Valley Lime or Haynesville. The group covers more than 250,000 sq miles in the East Texas basin and adjacent parts of Louisiana and southeast Arkansas.The Cotton Valley Lime in the Fallon and North Personville area has been a known gas area since its discovery in 1969. However, its poor permeability pay at a depth of about 11,000 ft had produced at rates too low for commercial development under the price schedules and technology of the past decade. Due to fracture porosity, beginning rates were moderately good (1 to 4 MMcf/D), but the natural fracture system was not sufficient to maintain the high rates of flow; consequently, the rates dropped to 0.200 to 0.500 MMcf/D in less than 2 years.Lately, advances in stimulation technology and improved economic incentives renewed interest in this area. Conventional acid stimulations and small fracturing jobs brought some improvement. Bigger fracturing jobs brought further improvement, but MHF appears worthwhile.These are the objectives of this report:1. Document the evolution of stimulation technology of the Cotton Valley Lime at the Fallon and North Personville fields.2. Using a computer reservoir simulator, history match the production and pressure transient data of the Muse No. 1 well before and after MHF and determine the uniqueness of this solution.3. History match the production of the Muse-Duke No. 1 after a super-MHF treatment.4. Optimize the development of the Cotton Valley Lime reservoir with respect to fracture length and well density using reservoir data and economic guidelines.5. Document the design of a super-MHF job (see Appendix). Reservoir Characteristics Rock Parameters The Cotton Valley Lime formation is generally gray, massive, oolitic to pistolitic, and finely crystalline to micritic. The better porosities appear to be related to the oolitic zones, ranging from 2 to 12% with some local thin zones of 14%. JPT P. 229^
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.74)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.45)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation > Bossier Shale Formation (0.99)
- North America > United States > Louisiana > East Texas Salt Basin > Cotton Valley Group Formation > Bossier Shale Formation (0.99)
- North America > United States > Arkansas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- (3 more...)