Use of F-overlays to evaluate air-drilled Devonian shale wells simplifies recognition of subtle variations in log response between productive and nonproductive intervals. Combinations of F-curve overlays, called F-pairs, are plotted on a logarithmic grid and normalized in an interval thought to be unfractured. Anomalous response behavior becomes useful in choosing fracturing intervals.
Most Devonian shale production in the eastern United States consists of gas, but in Wirt, Ritchie, and Pleasants counties of northwestern West Virginia, considerable quantities of oil also are being produced from this unit. Potentially oil-productive produced from this unit. Potentially oil-productive Devonian shale covers approximately 300 square miles (777 sq. km.) in these counties. The prospective pay interval is generally from 2500 to 3500 feet pay interval is generally from 2500 to 3500 feet thick (762-1067 m), and consists of interbedded shales and siltstones.
Within the study area, shales and siltstones are characterized by low primary porosity and permeability, and most production is believed to come permeability, and most production is believed to come from naturally occurring fractures associated with the Burning Springs anticline. The reservoir quality of these naturally occurring fractures can be enhances by hydraulic fracturing to increase production rates.
Most wells are air-drilled to minimize formation damage, and a typical logging suite consists of gamma ray, induction, density, sidewall neutron, and temperature logs.
Log interpretation of fractured reservoirs is difficult. Fracture porosities tend to be very low, normally in the .5 to 1.5 percent range, and only subtle differences, if any, in log responses may distinguish a productive from a nonproductive interval. Some operators simply "shoot in the dark". They pick a shallow zone where oil is likely, or they try to "frac" all the zones at once. This procedure is subject to error and can be needlessly expensive.
Eliminating those intervals where production is unlikely would reduce the number of perforations needed, as well as the number and size of the fracture treatments. This can result in considerable savings without raising fears of having missed commercial intervals.
This paper presents a qualitative, quick-look evaluation technique using gamma ray, induction, density, and sidewall neutron logs. It points to a means of identifying intervals in any given well which are most likely to support commercial hydrocarbon production. It also attempts to identify those intervals from which only oil production is probable. probable. "F-overly techniques are devised for use in conventional log analysis to quickly eliminate from further detailed evaluation all nonproductive intervals. Applied to fractured shale reservoirs, the method uses all F's available to take advantage of different tool responses to lithology and fluid changes.
The induction log measures conductivity which then is converted to resistivity for log presentation. Measurements are made in horizontal loops, presentation. Measurements are made in horizontal loops, and the tool is thought of as being relatively unresponsive to vertical fractures and to hydrocarbon filled horizontal fractures will provide an easy current path and should register as intervals of reduced resistivity.
Devonian shales in the area under consideration produce hydrocarbons without any water, so if newly produce hydrocarbons without any water, so if newly logged wells show any fractures at all, it can be assumed that the section will contain hydrocarbons.
Independent oil and gas copies such as Belden and Blake continue to search for new sources of hydrocarbon reserves. In many instances this has resulted in a re-evaluation of reservoirs that were considered depleted or of higher risk. The Trenton Limestone reservoir, located in the northwestern part of Ohio, is a case study of such an occurrence.
Through an extensive three-year evaluation of this area, both geologically and from an active drilling program, it was found that the area still contains vast amounts of hydrocarbons located in various types of geologic traps. While large amounts of oil and gas exist in this reservoir, ultimate production is sensitive to well completion and production practices. More specifically in the case of natural gas, pressure transient tests were conducted to pressure transient tests were conducted to determine whether gas reserves were sufficient to consider pipeline construction. Results of the reservoir tests verified the Trenton formation to be of low permeability in the range of one millidarcy, and porosity between 2 and 4 percent. An economic evaluation was then percent. An economic evaluation was then performed to determine what reservoir flow performed to determine what reservoir flow capacities, well spacing and economic criteria were required for successful engineering and economic development.
Conclusions of the case study showed (1) the need for high grading the well site selection through geological interpretation in order to and the "sweet spots," (2) a need f or stimulation treatments designed to enhance production, (3) a marginal return on investment production, (3) a marginal return on investment with current economics, and (4) that gas pipeline construction should be delayed until pipeline construction should be delayed until larger reserves are found or until a more favorable gas marketing climate develops.
In 1980, Belden and Blake made a concerted effort to find new sources of oil and gas reserves. This was brought about from the influx of investment dollars in the search of domestic hydrocarbon production. Starting in 1975, Belden and Blake began drilling wells at an ever increasing number each year. Drilling approximately 30 wells per year in 1976 and 1977, they doubled this amount by 1979, and by 1980, were drilling approximately 75 wells per year. with this large increase in well drilling, new developmental and exploratory acreage was actively being acquired to supporting this ever increasing well development program.
Northwest Ohio was one of the areas selected to explore for new sources of hydrocarbons. Activity in this part of Ohio was relatively sparse at the time; however, operators such as Pioneer Drilling Company Inc.. were continuing to Pioneer Drilling Company Inc.. were continuing to explore for commercial oil and gas production. The target was those areas in juxtaposition to the Old Trenton Field which produced over 500 million barrels of oil and about 1 trillion cubic feet of gas in the late 1800s and early 1900s. Ail of this production was found at shallow depths of less than 1,500 feet below the surface. Unlike the old reservoir which was a vast, highly prolific oil and gas formation, these new reservoirs appeared as smaller fields and were complex and difficult to delineate.
Working with Pioneer Drilling copy Inc., Belden and Blake then began an active drilling program starting in 1980 and continuing through program starting in 1980 and continuing through 1983. During this time 50 wells were drilled in the Northwestern Ohio area. This paper will highlight these field results and illustrate the complex nature of this reservoir with emphasis on the natural gas production and testing program. program. P. 311
A new log interpretation system called TITEGAS has been developed to analyze the reservoir characteristics and producibility of tight gas sands. The system is based upon equations which define the response of conventional logging tools. A basic log suite of density, neutron, and resistivity are the only logs required by the system, however TITEGAS also allows for utilization of various other logs including photoelectric effect, spectral natural gamma, micro-resistivity, microwave travel time, dielectric constant anacoustic travel time.
The new system includes several innovative analytical procedures:
A technique to compute porosity in zones having variable gas saturation and clay content.
A new method to quantify gas saturation in the zone investigated by the density and neutron tools.
An improved method using the gamma ray to determine clay content in compacted sands composed predominately of illite-type clays.
An improved method to determine clay content from the sonic and density log when illite is not the dominantclay type.
A new non-geometric mathematical model using neutron and density logs to calculate clay content. This equation makes it possible to refine the clay log response constants.
A new technique for the interpretation of formation water resistivity. This procedure is useful in thick sand-shale sequences where water salinity is variable.
New methods to refine matrix density of the reservoir. Matrix is dealt with as a foot-by-foot variable rather than as a constant.
A new technique to analyze invasion profile and qualitative formation permeability.
New methods to detect natural fractures through the modeling of logs that are generally available.
The TITEGAS system is applied to the DOE/Sandia MWX wells. Comparisons are made between the TITEGAS system results and the high-quality core data and well test data from these wells. The comparisons indicate that the system is a powerful new procedure for the analysis of tight gas sands. procedure for the analysis of tight gas sands
Operators who try their hand at tight gas sand well completions generally find themselves involved in a "learning experience". Well performance is inconsistent with log analysis prediction. performance is inconsistent with log analysis prediction. During the past four years, a new computer log analysis system has been developed to solve the logging problems characteristic of the tight gas sand (TGS) resource. The "TITEGAS" system has been applied successfully to TGS sequences in Texas (Cotton Valley and Canyon Sands), New Mexico (San Juan Basin), Colorado (Piceance Basin), Wyoming (Green River Basin), Utah (Uinta Basin), and Ohio (Appalachian Basin).
The objective of this paper is to describe the TITEGAS log analysis system. Several major points are discussed:
* New analytical procedures;
* The computational process - the criteria for interval selection, logic for refinement of constants, and the mechanism for human interaction with a modular computer log analysis system;
* Typical output presentations using field examples;
* Applications of the system for improved reservoir characterization and for geological studies.
THE BASIS FOR THE MODEL
There are many physical reasons why conventional log analysis methods are not able to predict which tight gas sands are capable of gas production.
Porosity, gas saturation, and permeability interpretation using Porosity, gas saturation, and permeability interpretation using conventional techniques is not adequate, even if great care is taken.
Hydraulic fracturing in rock masses involves complex and coupled processes of fractures propagating in discontinuous media and of fluid flow in discrete channels. The Unconventional Gas Program at Lawrence Livermore National Laboratory is actively developing numerical models to gain insight in the physics of these coupled processes. However powerful and versatile these models are, they must be verified against analytical solutions and/or physical experiments. This paper describes the current status of the FEFFLAP code, which models fluid-driven discrete fracture propagation in jointed media. We also discuss the results of a preliminary series of physical tests in which hydrofractures were driven across slanted interfaces between dissimilar materials, in blocks loaded in biaxial compression.
Hydraulic fracturing is employed both for the stimulation of tight hydrocarbon reservoirs, and for estimating in-situ stresses in rock. It involves a complex and coupled process of fracture propagation and fluid flow. In rock masses, the interaction of induced fractures with natural joints and interfaces adds another level of complexity to the problem of predicting the behavior of the hydrofractures, i.e., predicting the behavior of the hydrofractures, i.e., extension, and containment, or lack of it. To gain insight in this problem, the Unconventional Gas Program of the Lawrence Livermore National Laboratory Program of the Lawrence Livermore National Laboratory has an active effort in the development of numerical models [this paper]. Numerical methods are emphasized because of their power and versatility in handling complex physics. Still, numerical models, however powerful they are, must be verified against analytical solutions or physical experiments before they can be fully exercized and trusted.
This paper describes the current status of development and testing of the FEFFLAP code (Finite Element Fracture and Flow Analysis Program). FEFFLAP represents the coupling of the FEFAP discrete fracture propagation code and of the JTFLO program, a propagation code and of the JTFLO program, a LLNL-enhanced version of an earlier code for analysis of fluid flow in rock fractures. We also present the results of a preliminary series of physical tests in which hydrofractures were driven across slanted interfaces between dissimilar materials, in blocks loaded in biaxial compression.
THE FRACTURE AND FLOW MODEL: FEFFLAP
Discrete Fracture Propagation: FEFAP
The foundation for the solid fracture analysis described here is the Finite Element Fracture Analysis Program (FEFAP) developed at Cornell University. FEFAP analyzes planar and axisymmetric structures for crack initiation and growth. The program combines linear and non-linear fracture program combines linear and non-linear fracture mechanics theory, the use of interactive computer graphics, and a unique, automatic remeshing capability to allow the user to initiate and propagate up to ten discrete cracks simultaneously.
FEFAP has been used for a variety of applications involving crack growth in rock, concrete, and metal structures. An example of a large scale problem is that involving the cracking of the problem is that involving the cracking of the Tennessee Valley Authority's Fontana Dam [101. Figures 1 and 2 show meshes before and after crack propagation modeling. A comparison between propagation modeling. A comparison between predicted and observed crack paths is shown in Figure 3. predicted and observed crack paths is shown in Figure 3. The salient capabilities implemented in the present version of FEFAP are:
. Complete interactive-graphical execution of the program. Each analysis step is directed by the user with alphanumerical and graphical feedback of the results of this step. After any complete crack propagation step, the analysis can be terminated and restarted from the previous step. The emphasis in the program design is on providing versatility to the analyst. One is not locked into a batch-produced result via the initial data input.
. Automatic, discrete crack nucleation at arbitrary points and angles on an edge or in the interior of a domain, as specified by the analysis.
When a continuous sand is bounded by zones of higher, but unequal, minimum in-situ stress, a vertically asymmetric hydraulic fracture results. The modeling is much more difficult than in the symmetric case mainly because the width equation is harder to formulate and solve. In this paper we present the principal components of the modeling, which includes principal components of the modeling, which includes non-Newtonian flow, leakoff with spurt loss, and "storage" of fluid due to volume expansion. The assumption is that the fracture is highly elongated, i.e., stress contrasts between pay and bounding zones are relatively large (>few hundred psi). Vertical gradients of minimum in-situ stress and fluid pressure can be included in the modeling. To illustrate. the results, we present design calculations for a 30,000 gallon fracture, which was the first stimulation in the Multi-Well Experiment. The 80 ft fracture interval in the Paludal zone has at its upper edge a 520 psi stress contrast, and at its lower edge a 1195 psi contrast. Computed fracture height growth above and below the perforated interval, bottomhole pressure, and width perforated interval, bottomhole pressure, and width profiles in vertical sections are displayed. profiles in vertical sections are displayed. Comparison is made with diagnostic measurements of fracture length, height, and bottomhole pressure.
At depths of a few thousand feet or more, induced hydraulic fractures will normally be vertical. Height growth containment is important so that the fracture will reach farther along the payzone, and so that the chance of vertical penetration into, for example, a water-bearing zone will be reduced. Although many factors influence height growth, the most important one appears to be the stress contrast between pay and bounding zones, where by stress we mean minimum in-situ stress. Here we study fracture height growth by developing a model for an expanding hydraulic fracture applicable when the fracture is highly elongated, with length along the payzone much greater than height. However, vertical variations in elastic parameters are not considered. The fracture shape in this paper is self-determined, in contrast to that in which an elliptical shape is chosens and the corresponding height or semi-minor axis determined. A variable-height fracture model has been intensively studied by Cleary and co-workers. The so-called "pseudo-3D" model treats the fluid flow as a dominant ID flow along the payzone, plus an auxiliary ID flow in the vertical direction. Although the models of Nolte and Palmer and Carroll take the vertical flow to be Palmer and Carroll take the vertical flow to be zero, thus simplifying the problem considerably, the general formulations are similar enough to Cleary's to be included under the rubric "pseudo-3D." In all these models, the fracture width is approximated by dividing the fracture into a number of vertical sections, and applying 2D elasticity theory to each vertical "line" crack. Thus the fracture is assumed to be highly elongated with length/height ratio >5. Finally, 3D modeling, with proper 2D fluid flow, is under development, but the problem is formidable and the computer run time enormous. In the interim we can learn much from pseudo-3D models. In general, the bounding layer stresses will not be equal, leading to a fracture which is vertically asymmetric, and furthermore both the minimum in-situ stress and the fluid pressure will vary with depth. This is the principal modification we make to the symmetric model, described previously. Other additions are: (i) spurt loss has been included in the leakoff, i) non-Newtonian flow is included. An extended model for the symmetric case, which has essentially the same components as herein, is described elsewhere. In that paper, a comparison is made between published results in three pseudo-3D models, some discrepancies are pointed out, and suggestions for reconciling the models are made. In the asymmetric model of this paper, calculation of fracture width is the most difficult task. We give most of the details here. Theoretical calculations of asymmetric fracture shapes have been reported by Settari and Cleary, but they appear to emphasize low stress contrasts (< couple hundred psi). Nolte gives one asymmetric width profile in a vertical section, but no method of calculation, nor any resultant fracture shapes, were given. Finally, to illustrate the results of the asymmetric model, we use the model to predict fracture height, pressure, and width for the first stimulation of the Multi-Well Experiment (MWX) carried out in December 1983. This prediction is compared with available fracture diagnostic measurements.
Pre-fracture pressure buildup tests in tight gas formations can be extremely difficult to analyze correctly, particularly when large pressure drawdowns precede the shut-in period. A major source of difficulty is the wellbore storage coefficient, which changes continuously throughout the test and which can change by one to two orders of magnitude from beginning to end of the test. This change causes particular problems in type-curve analysis; in turn, this can cause serious difficulties in recognizing when, if ever, the semi-log straight line with slope related to formation permeability appears. As a result, buildup test analysis results can be the subject of great controversy and uncertainty.
This paper summarizes research which shows conditions under which changing storage coefficient causes interpretation problems and which also shows how the use of Agarwal's pseudo-time function can resolve the difficulties. Simulated buildup test analyses are used to show the problem and its solution. Several actual tests from tight gas formations also illustrate the difficult-to-analyze shapes suggested by theory, and the correct analysis of these tests is presented.
In a gas well buildup test that follows a high drawdown, slopes greater than the theoretical maximum unit slope often occur. Fligelman et al. studied this problem and suggested that the change in fluid and rock properties is the probable cause for the steepening of slopes. Lee and Holditch found that increasing slopes in a gas well buildup test type curve are caused by a change in wellbore storage which is influenced by changing fluid properties in the wellbore. They pointed out that properties in the wellbore. They pointed out that attempting to match a buildup test dominated by a changing storage coefficient with existing type curves often leads to a misleading, if not an impossible, match.
Many authors have proposed techniques to analyze gas well buildup tests using solutions to the diffusivity equation for liquid flow drawdown. Al-Hussainy and Ramey- recommended use of pseudo-pressure, psi, to account for the variation in gas psi, to account for the variation in gas properties. Agarwal showed that the additional properties. Agarwal showed that the additional application of pseudo-time, t , linearizes the gas flow equation more completely. To analyze buildup data with drawdown type curves more correctly, Agarwal suggested the use of "effective time." Lee and Holditch clarified the fundamental basis for analyzing gas wells in a form identical to that developed for slightly compressible liquids when both pseudo-pressure and pseudo-time are used.
An important development from the use of pseudo-time is often overlooked by transient test pseudo-time is often overlooked by transient test analysis. Pseudo-time, besides partially accounting for changing fluid properties in the formation, also takes into account the changing wellbore storage coefficient. Lee and Holditch introduced a new storage coefficient, C , when interpreting a gas well buildup test with pseudo-pressure and pseudo-time. This storage coefficient remains pseudo-time. This storage coefficient remains constant in an isothermal wellbore. The problem of increasing slopes is thus resolved, and significant improvement is experienced in type-curve analysis.
Much has been written in the literature concerning the theoretical use of pseudo-pressure and pseudo-time. However, there is a lack of technical papers which include examples of how these techniques can be applied to actual gas well pressure buildup tests. Changing wellbore storage pressure buildup tests. Changing wellbore storage coefficient is one situation in which pseudo-pressure and pseudo-time help to correct analysis pseudo-pressure and pseudo-time help to correct analysis problems. The purpose of this paper is to present problems. The purpose of this paper is to present a systematic study of buildup tests from situations with changing wellbore storage coefficient and to present examples of how pseudo-pressure and present examples of how pseudo-pressure and pseudo-time can be used to analyze these tests with pseudo-time can be used to analyze these tests with greater accuracy and greater confidence.
A two-dimensional, single-phase reservoir simulation model was used in this study.
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: (1) 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; (2) complete core taken through the formations of interest; (3) a comprehensive core analysis program; (4) an extensive logging program with conventional and experimental logs; (5) determination of in situ stresses in sands and bounding shales; (6) use of various seismic surveys and sedimentological analyses to determine lens morphology and extent; (7) use of seismic, electrical potential, and tilt diagnostic techniques for hydraulic fracture characterization; and (8) 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
It is widely recognized that U.S. gas reserves can be substantially increased if gas from tight reservoirs can be more economically developed. One of the main problems hindering the development of tight problems hindering the development of tight reservoirs is the general lack of adequate reservoir description. one of the best techniques for reservoir analysis is pressure buildup testing. In tight gas pressure buildup testing. In tight gas reservoirs, a buildup test which will adequately describe a large portion of the reservoir requires that a well be shut in for several week or months. Many operators run these long pressure buildup tests both before and after a well has been fracture treated. if such tests are run, an acceptable description of the reservoir and fracture can be obtained using reservoir simulation history-matching techniques .
Even when the pressure buildup tests are correction run and interpreted, it is difficult to determine the areal extent of reservoir drainage. To determine drainage area, several year of production data are normally required. Therefore, to completely define a tight gas reservoir, the information obtained from the analysis of prefracture pressure buildup data, prefracture pressure buildup data, post-fracture pressure buildup data, and, post-fracture pressure buildup data, and, long-term production data must be combined.
The most important problem to be solved in the development of a tight gas reservoir is determination of the optimum fracture length. The optimum fracture length is a function of reservoir permeability, gas in place, and future net revenues- and can best place, and future net revenues- and can best be quantified as a fraction of the drainage radius. To determine the optimum fracture length, it is necessary to predict future well performance as a function of effective propped fracture length. The effective propped fracture length. The effective areal extent of a reservoir must be known or estimated in order to accurately predict future well performance. Thus, knowledge of drainage area is critical in the determination of the optimum fracture length.
Many reservoirs are lenticular. if such a reservoir only covers ten or twenty acres, the gas in place in the lens may be so small that the optimum fracture length is zero and the zone is uneconomic to develop. In blanket reservoirs, the cost of drilling a well must be compared with the cost of fracture treating the well; both the fracture treatment and the well spacing can then be optimized by computing expected well performance as a function of various well performance as a function of various well spacings and fracture lengths.
After determining the optimum fracture design on paper and performing a fracture treatment, it is essential that a post-fracture formation evaluation be performed post-fracture formation evaluation be performed to determine if the actual reservoir and fracture conditions conform to the assumptions used during the design of the treatment. It is important to know whether or not the assumed drainage area and designed fracture length are representative of the effective drainage area and propped fracture length influencing actual field performance.
To calculate the effective propped fracture length and fracture conductivity,
long-term post-fracture pressure buildup test data can be analyzed using semi-log techniques, square-root-of-time techniques, type-curve techniques and finite difference reservoir. simulation history-matching techniques. The only method of determining effective drainage area is to analyze long-term production data along with perhaps several additional pressure buildup tests.
The techniques described above will work and provide an operator with a detailed reservoir description that can be used to optimize development.
Tailored-pulse loading is a gas well stimulation technique that is promising for particular situations. The key factor in determining the probability of success is the interaction of the loading probability of success is the interaction of the loading history with the material properties and in situ stresses of the geologic formation. On the basis of theoretical and experimental studies, tailored-pulse loading is expected to be successful if (a) the rock is fairly competent, (b) the yield stress is greater than about 100 MPa, (c) the overburden pressure is less than about 100 MPa, (d) the natural fracture or joint spacing is less than several meters.
The use of propellants or low-energy release rate explosives to stimulate oil or gas wells has been studied extensively during the past several years in programs funded by the Morgantown Energy Technology programs funded by the Morgantown Energy Technology Center (METC), other agencies of the Department of Energy, and the Gas Research Institute (GRI). The postulated advantages of the technique include the postulated advantages of the technique include the ability to create radial cracks at the borehole wall without causing rubblization and to drive the cracks by internal gas pressurization into the formation with their orientation unaffected by in situ stresses. During a recent GRI-funded program, Sandia National Laboratories Albuquerque (SNLA) demonstrated the practical feasibility of the tailored-pulse loading (TPL) technique in well is at Rowan County, Kentucky, and Meigs County, Ohio.
The purpose of this paper is to discuss the expected limitations of the TPL technique and to describe the laboratory tests required to both properly assess the potential of a given formation for TPL stimulation and to roughly predict the extent of permeability enhancement that is expected. To accomplish permeability enhancement that is expected. To accomplish this objective, we use the results of a three-year METC-funded program at SRI. During that program, SRI worked with SNLA, Science Applications, Inc., the University of Maryland, and Los Alamos National Laboratories (LANL) to perform laboratory experiments, to develop computer models of the fracture process, and to use the models to predict the process, and to use the models to predict the results of field experiments performed at the Nevada Test Site.
LIMITATIONS OF THE TPL TECHNIQUE
The scenario for a TPL stimulation is illustrated in Fig. 1. If the rise time of the pulse produced at the borehole wall is shorter than the time required for a sound wave to run around the borehole circumference, then multiple cracks can be produced by the circumferential tensions. However, several other requirements restrict the applicability of the technique. First, the circumferential tensions must be greater than the tensile strength of the rock. This requirement is easy to meet for moderate overburden pressures. However, two additional requirements are pressures. However, two additional requirements are that the peak radial compressive stress be lower than the compaction strength of the rock if it is porous and that the radial compressive stress also porous and that the radial compressive stress also be lower than that required to cause the rock to yield. If the above requirements are not met, the compaction and/or flow around the borehole will form a "stress cage" that tends to seal off the borehole from the fractured formation.
Although it is relatively easy to produce TPLs that fulfill one or two of the above requirements, it may in some formations prove difficult to fulfill all of them simultaneously. Fortunately, in Devonian shale the porosity is low, the tensile strength is not excessive, the yield stress is relatively high, and SNLA was able to successfully create radial cracks in the formations in the Rowan and Meigs County stimulations where the overburden pressures were not excessive (less than 40 MPa).
Another requirement for successful application of TPL is that the radial cracks be driven far enough by the gas pressurization to intersect the natural fractures in the formation. The importance of gas penetration into the cracks is illustrated in Figs. penetration into the cracks is illustrated in Figs. 2-4, which show the results of laboratory experiments in Plexiglass blocks containing scale model boreholes loaded by a low-power explosive. In one case the borehole was sheathed to prevent gas penetration, whereas in the other case the explosive penetration, whereas in the other case the explosive gases were allowed free access to the radial cracks. The gases drove the cracks 5 to 10 times farther than did the stress waves alone.
Producers currently develop Devonian shale gas fields by drilling wells which offset a high productivity well. Remote sensing as well as productivity well. Remote sensing as well as various geophysical and geochemical techniques are sometimes used to site wells. Yet, productivity of the development wells can be highly variable. In an attempt to improve the production potential of these wells, the Gas Research Institute has undertaken a research program aimed at developing a better understanding of the geological features which control production in the shale, and which a wellbore must intersect or communicate with in order to result in higher productivity. A better understanding of these geological production controls is necessary to develop an exploration or stimulation methodology which will enable the producer to better locate and stimulate wells, and producer to better locate and stimulate wells, and thus improve overall productivity of the field.
An analysis of production figures from the Devonian Shale suggests that there is a need to concentrate on how to find the most productive areas in a given field, and to develop better stimulation design criteria to enhance productivity. It is not unusual for a small number of productivity. It is not unusual for a small number of wells, say 15%, to be responsible for nearly half of the total production in a field. The best producers in a field rarely require stimulation producers in a field rarely require stimulation while marginal and submarginal wells must be stimulated to achieve economic production. A variety of stimulation techniques are typically used ranging from shooting to hydraulic fracturing. However, the best strategy for choosing a particular stimulation technique in a particular particular stimulation technique in a particular set of conditions is not fully understood.
Studies under the Eastern Gas Shales Program (EGSP) of the Department of Energy have shown that gas is contained in the rock matrix throughout the Appalachian basin. However, economic production of this gas requires the development of permeable pathways, and the ability to intersect these pathways, and the ability to intersect these pathways from a wellbore. It is most likely t pathways from a wellbore. It is most likely t the variations in production which are observed many shale fields are the result of the interrelationships of the specific permeable pathways which are intersected by the wellbore. However, other factors could contribute to the observed variability in production including pressure depletion of the reservoir, and drilling and completion practices. These factors must be taken into account practices. These factors must be taken into account in any analysis.
In order to improve existing exploration and production strategies it is therefore necessary to production strategies it is therefore necessary to establish a better understanding of the permeable pathways which allow gas to migrate from the pathways which allow gas to migrate from the matrix to the wellbore. These permeable pathways could include such geological features as fractures, silts and interbedded laminae and bedding planes. In addition gas diffusion from the matrix planes. In addition gas diffusion from the matrix will contribute to the production characteristics of a shale wells.
Considerable work has already been carried out in this area, in particular in the development of dual porosity models which include the effects of a fracture dominated permeability and a matrix porosity. However, a better understanding of the porosity. However, a better understanding of the relationships of the various storage and permeability elements of a shale reservoir is still permeability elements of a shale reservoir is still needed for a number of reasons. Thus:
Existing fracture porosity shale gas models can require a fracture area greater than 109 sq ft/sqmi to account for observed productivity. This fracture area may be greater than has been observed in nature.
Planes of enhanced permeability, such as bedding planes and silt laminae, are frequently observed. The existence of these planes can greatly reduce the fracture area required to account for observed production from a fractured reservoir.