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Well Completion
Abstract A tight gas reservoir is commonly defined as a reservoir having less than 0.1 milliDarcies permeability. Because of the very low permeability, hydraulic fracturing is usually carried out in efforts to establish commercial production. There are several basic concepts and field cases of different well tests in tight gas reservoirs in the literature. In this paper, we gather information and provide a guide to some of the most important tests. Generally because of low permeability, a well will not flow initially at measurable rates and conventional well testing cannot be applied. We review procedures for design of pre- and postfracture tests in single and dual porosity reservoirs. The prefracture test permits estimating preliminary values of reservoir permeability and initial pressure. The post-fracture test provides data for estimating fracture half length and conductivity. We also review the application of convolution/deconvolution methods to analyze well tests with significant wellbore storage. Because of economic and environmental reasons, short duration procedures are preferred. However, although effective in many instances, these methods also have their own limitations. Introduction Unconventional reservoirs (tight gas, coal bed methane, shales gas and gas hydrates) will be an important pat of the global energy mix for decades to come. Large reserves, long-term potential, costs and gas prices and some other factors account for the great influence of these resources on the future of energy. There is no formal definition for "tight gas." A commonly used definition, describes tight gas reservoirs as those having permeabilities smaller than 0.1 milliDarcies. Well testing is generally done as an aid to estimate gas in-place and recoverable volumes. Initial pressure (pi) is a critical parameter not only for estimating gas in-place, but also for determining how much field development is required and whether or not the field is overdeveloped. In addition to pi, well testing provides an estimate of permeability and skin. A problem associated with well testing in tight gas sands is that usually long times are required to reach radial flow, due to their extremely low permeabilities. Therefore, conventional well tests cannot be applied to these reservoirs. Because of initial uneconomic rates, fracturing is usually required. Lee(2) has suggested procedures for pre- and post-fracture tests design. In order to have measurable gas rates for pre-frac testing, often a breakdown with acid, KCl water or N2 is necessary.
- North America > United States (1.00)
- North America > Canada (0.69)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.54)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Dominant Considerations for Effective Hydraulic Fracturing in Naturally Fractured Tight Gas Carbonates
Arukhe, J.O. (Schulich School of Engineering, University of Calgary) | Aguilera, R. (Schulich School of Engineering, University of Calgary) | Harding, T.G. (Schulich School of Engineering, University of Calgary)
Abstract This study examines the results of laboratory work to establish rock strength data, acid solubility, fracture fluid selection and mineral identification of a fractured tight gas carbonate reservoir. Basic to a successful acid fracture design are acid etching and rotating disc tests which show for a given acid system, conductivity at a given stress (etched width or how much rock is eaten away) and parameters necessary to determine acid reaction rate, reaction order, rate constant and energy of activation at a given temperature. These tests address the measurement of mass transfer and diffusion with or without leak off in carbonates, and also enable the prediction of reactivity versus temperature for various acid strengths. Dynamic fluid losses are measured experimentally and laboratory data are converted to an estimate of in-situ leak off. The leak off profile and wall building coefficients enable a consideration of fluid loss additives for fracturing fluids to build up pressure for fracture opening. In the fracture conductivity tests, closure stress is applied across a test unit for sufficient time to allow the proppant bed to reach a semi-steady state condition while test fluid is forced through the bed. At each stress level, pack width, differential pressure, and average flow rates are measured as fluid is forced through the proppant bed. The proppant pack permeability and conductivity are then evaluated and compared. Introduction A discussion of dominant considerations for effective hydraulic fracturing in naturally fractured tight gas carbonates is presented along with the results of laboratory work to establish rock mechanical properties data, acid solubility, fracture fluid selection and mineral identification for a selected naturally fractured tight gas carbonate reservoir. The carbonates under consideration are located in the Western Canadian Sedimentary Basin (WCSB) in what is usually known as the "Deep Basin" of Alberta (Figure 1). The core samples studied come from the Savannah Creek field (Figures 2) and correspond to the Rundle group Mississippian Mount Head and Livingston carbonates (Figure 3). These carbonates were deposited in a shallow marine ramp setting. These are upward-shallowing cycles ranging from crinoid / bryozoan shoals to lagoonal mud facies. The reservoirs comprise dolomudstones and wackstones with an average pay of approximately 35 m. Reservoir zones can be discontinuous due to lateral facies changes and minor faulting. The presence of natural fractures in the tight formations considered in this research is corroborated by cores and thin sections. Notice the presence of calcite cemented fractures in the whole core and plugs displayed in Figure 4. The thin section shown on Figure 5 presents calcite-filled fractures (pink strip running from upper left to lower right) that have been re-fractured (thin blue streak). The thin section work corroborates that it possible to re-fracture existing healed fractures. General Considerations There are many mechanisms that contribute to the final created geometry (fracture height, fracture width, hydraulic or created fracture length or effective fracture length)2–8 and its evolution in naturally fractured tight gas carbonates. Pump rate, volume injected, fluid viscosity, fluid loss and proppant scheduling combine with static and dynamic rock properties.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > Texas > Harris County > Houston (0.28)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.45)
- North America > United States > Texas > Permian Basin > Delaware Basin > Sullivan Field (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
Abstract A tight gas reservoir is commonly defined as a reservoir having less than 0.1 millidarcies permeability. There are several basic concepts and field cases of different well tests in tight gas reservoirs in the literature, but not presented as a general guide. In this paper, we gather valuable information and provide a useful guide to the most important well tests in tight gas reservoirs. Generally due to low permeability of these reservoirs, a well will not flow initially at measurable rates and conventional well testing cannot be applied. Therefore, fracture stimulation must be considered. Many authors present procedures for design of pre and post-frac tests. The pre-frac test permits calculating preliminary estimates of reservoir permeability and initial pressure. Because of economic and environmental reasons, short duration procedures are of interest. Hence, prime candidates are pre-frac, short time, small volume, closed chamber tests. These tests have to be analyzed by special methods to provide improved values of reservoir parameters. In this study, we also present a review of some aspects in tight gas well testing like pressure-dependent permeability, estimation of pseudo-time at the average pressure of the region of influence, supercharge effect, the problem of treating the pressure-dependent product µct during pre-frac test analysis and the concept of instantaneous source response Introduction Large decreases in production and increases in demand for fossil-fuels cause the economic gas production from unconventional resources (tight gas, coal bed methane (CBM), and gas hydrate) to be a great challenge. Huge reserves, longterm potential, low gas prices and some other factors account for the great influence of these resources on the future of energy. There is no formal definition for "Tight gas". Commonly used definition, describes tight gas reservoirs as those having permeabilities less than 0.1 millidarcies. Recently, the German Society for Petroleum and Coal Science and Technology (DGMK) defined tight gas reservoirs as those with average effective gas permeability of less than 0.6 mD. "Ultra tight" gas reservoirs may exhibit permeabilities down to 0.001 mD. To improve the recovery of this resource, GFREE research program has been created at the University of Calgary. GFREE stands for:Geoscience aspects (G) Formation evaluation by petrophysics and well test (F) Reservoir drilling, completion and stimulation (R) Reservoir Engineering (RE) Economics and long run supply curves (E) As a part of the activities of this research program, we have concentrated on Formation evaluation (F) by well testing, and conducted a literature survey which is presented in this paper. Well testing is generally done to estimate hydrocarbon (here gas) in-place and recoverable resources. Initial pressure is a critical parameter not only for estimating gas in-place, but also for determining how much field development is required and whether or not the field is overdeveloped. In addition to pi, well testing provides an estimate of permeability. A problem associated with well testing in tight gas sands is that usually long times are required to reach redial flow, due to their extremely low permeabilities.
- North America > United States > Texas (0.68)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.25)
- Overview (1.00)
- Summary/Review (0.88)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract The tank material balance (MB) equation for undersaturated and saturated reservoirs has been written taking into account the effective compressibility of matrix and fractures. The solution is presented in finite difference form to achieve a quick convergence of the iteration process. Historically, compressibility has been neglected when carrying out MB calculations of conventional reservoirs producing below the bubble point. This assumes that the reservoir strata are static. It is shown however, that under some conditions, fracture compressibility can have a significant impact on oil rates and recoveries of naturally fractured reservoirs (NFRs) performing below the bubble point, as the fracture permeability and fracture porosity are stress-dependant. Other stress-sensitive properties discussed in this paper include the partitioning coefficient and the exponent for the shape of relative permeability curves. The use of the MB finite difference equations is illustrated with an example. Introduction Forecasting the performance of naturally fractured reservoirs (NFRs) is a major challenge. Various authors have tackled the problem throughout the years using MB calculations. To the best of my knowledge, the effect of fracture compressibility below the bubble point has been usually ignored in MB equations for saturated reservoirs. The work presented in this paper is not meant to replace a detailed reservoir simulation, which is the best way to try to solve the problem provided that reservoir characterization and quality of the pressure and production data is good. The objective is to have a tool that can provide a quick indication with respect to potential oil recoveries from stress-sensitive NFRs. Pirson pioneered efforts to try to explain the high GOR associated with many NFRs once the bubble point is reached. He considered the reservoir to be made of two porosity and permeability systems in parallel and visualized production as a succession of equilibrium stages. Jones-Parra and Seijas-Reytor studied the effect of gas-oil ratio on the behaviour of fractured limestone reservoirs using a two-porosity model. They assumed that gravity segregation took place freely and resistance to fluid flow was very small in the fracture network. In the matrix or fine porosity system, there was high resistance to flow and no segregation. Aguilera used combined log analyses and MB to try to explain the high gasoil ratios observed in many NFRs. More recently, Penuela et al. presented a MB for calculating oil-in-place in matrix and fractures taking into account the compressibility difference between matrix and fractures. This paper presents MB equations for predicting oil recovery and rates of undersaturated and saturated reservoirs. The equations are written taking into account the effective compressibility of matrix and fractures. Stress-sensitive properties such as fracture porosity, fracture permeability, partitioning coefficient, and exponent for shape of relative permeabilities are taken into account. The solution is presented in finite difference form to achieve a quick convergence of the iteration process.
- North America > United States (0.93)
- North America > Puerto Rico > Peñuelas > Peñuelas (0.24)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (3 more...)
Abstract The tank material balance (MB) equation for undersaturated and saturated reservoirs has been written taking into account the effective compressibility of matrix and fractures. The solution is presented in finite difference form to achieve a quick convergence of the iteration process. Historically, compressibility has been neglected when carrying out MB calculations of conventional reservoirs producing below the bubble point. This assumes that the reservoir strata are static. It is shown however, that under some conditions, fracture compressibility can have a significant impact on oil rates and recoveries of naturally fractured reservoirs (nfr's) performing below the bubble point, as the fracture permeability and fracture porosity are stress-dependant. Other stress-sensitive properties discussed in this paper include the partitioning coefficient and the exponent for shape of relative permeability curves. The use of the MB finite difference equations is illustrated with an example. Introduction Forecasting the performance of nfr's is a major challenge. Various authors have tackled the problem throughout the years using MB calculations. To the best of my knowledge, the effect of fracture compressibility below the bubble point has been usually ignored in MB equations for saturated reservoirs. The work presented in this paper is not meant to replace a detailed reservoir simulation, which in my opinion is the best way to try to solve the problem, provided that reservoir characterization and quality of the pressure and production data is good. The idea is to have a tool that can provide a quick idea with respect to potential oil recoveries from stress-sensitive nfr's. Pirson pioneered efforts to try to explain the high GOR associated with many nfr's once the bubble point is reached. He considered the reservoir to be made of two porosity and permeability systems in parallel and visualized production as a succession of equilibrium stages. Jones-Parra and Seijas-Reytor studied the effect of gas oil ratio on the behavior of fractured limestone reservoirs using a two-porosity model. They assumed that gravity segregation took place freely and resistance to fluid flow was very small in the fracture network. In the matrix or fine porosity system, there was high resistance to flow and no segregation. Aguilera used combined log analyses and MB to try to explain the high gas oil ratios observed in many nfr's. More recently, Penuela et al. presented a MB for calculating oil in place in matrix and fractures taking into account the compressibility difference between matrix and fractures. This paper presents MB equations for predicting oil recovery and rates of undersaturated and saturated reservoirs. The equations are written taking into account the effective compressibility of matrix and fractures. Stress-sensitive properties such as fracture porosity, fracture permeability, partitioning coefficient and exponent for shape of relative permeabilities are taken into account. The solution is presented in finite difference form to achieve a quick convergence of the iteration process. General Observations Regarding Oil Recovery In general, if we make a comparison of 2 identical undersaturated reservoirs in every respect, except that one is fractured and the other one is unfractured, we find that the fractional recovery is larger in the undersaturated nfr.
- North America > United States (0.68)
- North America > Puerto Rico > Peñuelas > Peñuelas (0.24)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (3 more...)
Abstract The Aguarague field is located in the Devonian Basin, NW of the Province of Salta, Argentina. Gas production is obtained from clastics of the Huamampampa formation through an intense network of natural macro and microfractures. The reservoir is in a North-South trending symmetrical anticline. Five high-deliverability gas wells watered-out between 1991 and 1994 and as a result the field gas production decreased substantially. This triggered a study in 1995 to try to find a means of enlarging the life of the reservoir. The study indicated that without any modifications gas production could be expected to lapse at most to 1999. This paper describes how a detailed fracture characterization led to a dewatering project using gas lift, which significantly reduced the gas decline of the reservoir. The project also brought back to gas production some of the wells that had previously watered-out. The 1995 forecast is compared with the actual production performance to date. Introduction Argentina deep drilling (about 4500m) and discovery of hydrocarbons in NOA Basin, Serranias de Aguarague, Baja de Oran, and Ipaguazu, and in the Devonic and Carbonic sub-basins started in 1951 with the discovery of Campo Duran, a gas condensate reservoir, in the Serrania de Ipaguazu. Madrejones field, north of Campo Duran, was discovered in 1952. The field also produced gas and condensate. A shallower well was drilled in Pena Colorada in 1968. The well produced small oil quantities from the top of the Los Monos formation. Ramos field was discovered in the Serrania de San Antonio in 1977. The field produced gas and condensate from the Huamampampa formation. The Aguarague field, object of this study, was discovered in 1979 with the drilling of well Cu.x-1. The field went on production in 1979 with well Cu.x-2, which produced initially at about 500,000 m/day from the Huamampampa formation. To date, 16 wells have been drilled, out of which 13 reached the Huamampampa formation. The field reached a production of over 4 million m/day in 1985. However, five high-deliverability gas wells watered-out between 1991 and 1994 and as a result the field gas production decreased substantially. Figure 1 shows a structural map on top of the Huamampampa formation. Water was advancing from the north in such a way that wells Cu.x-2 and Cu.x1 had watered out by May 1991, well Cu.x-3 by May 1993, well Alo.x-1 by June 1994 and well Sa.Ag.-4 by January 1995. Water was also advancing from the south and well Tr.x-1 watered out in January 1986, well Tr.x-206 in August 1991 and well Tr.x-199 in September 1992. Without any modifications all the wells were going to water out by 1995. Location and Geology The Sierra de Aguarague field is located in the Devonian Basin, NW of the Province of Salta (Figure 2), west of National Route No. 34 near the city of Tartagal.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.67)
- South America > Argentina > Salta > Santa Cruz Basin > Ramos Field (0.99)
- South America > Argentina > Salta > Santa Cruz Basin > Aguarague Field > Huamampampa Formation (0.99)
- South America > Argentina > Salta > Noroeste Basin > Sierra De Aguarague Field (0.99)
- (2 more...)
Abstract A new method is presented for estimating fracture porosity in coalbed methane formations from the Dual Laterolog. Historically, well logs have been useful for providing qualitative information of coal seams. However, very little has been published regarding quantitative evaluation of fracture porosity from logs. A theoretical model indicates that for coalbed formations, the value of the fracture porosity exponent, mr, should be very small and close to 1.0. Actual log data from the San Juan Basin in New Mexico tends to corroborate this finding. For evaluation purposes, a model has been used that assumes matrix and fractures are connected in parallel. Based on this model, the Dual Laterolog provides an ideal tool for evaluating porosity of vertical and sub vertical fractures. In addition to the mathematical solutions, charts have been developed for estimating fracture porosity in those cases in which the fractures contain either zero or 100% water saturation at original conditions. For illustration purposes, the quantitative estimate of fracture porosity in a well of the San Juan Basin (New Mexico) is presented in detail. In addition, methods are presented for estimating fracture aperture, fracture spacing, and fracture permeability for the same well. The methods should prove valuable to Alberta companies in the future as more than 45% of the province is underlain by coal bearing formations. It should also prove valuable internationally in other countries such as the U.S.A., China and Hungary. Introduction Evaluation of coalbed methane reservoirs is becoming more important every day. This investigation was undertaken to try to find reliable means of detecting and evaluating fracture porosity from the Dual Laterolog. It appears from various cases analyzed to date that the resistivity from the shallow laterolog should be smaller than the resistivity from the deep laterolog, provided that a highly conductive mud is in place while logging the well. At the same time it appears that the separation of the two resistivity curves provides a reliable way of estimating fracture porosity. An excellent paper by Hoyer presented estimates of fracture aperture in coalbed seams of the San Juan Basin based on knowledge of the mud conductivity, and deep and shallow laterolog responses. The estimates utilized an equation developed originally by Faivre and Sibbit. This paper presents a different approach that allows direct estimates of fracture porosity. Under favorable conditions the method permits calculation of fracture spacing and fracture permeability. FIGURE 1: Cleat system determined for coal seam in the Fruitland formation, San Juan Basin (after Jones et al.). (Available in full paper) Physical Principles Figure 1 shows a schematic of micro fractures in a 8.9 cm (3.5 inch) diameter core. The fractures are approximately vertical and perpendicular to bedding. The coalbed methane industry follows the tradition of British mining engineers and calls the micro fractures in coal seams cleats. The larger dominant micro fractures are called face cleats. The smaller micro fractures that go perpendicular to face cleats are called bun cleats. They are very short and usually are interrupted at the face cleats.
- North America > United States > New Mexico > San Juan Basin > Fruitland Formation (0.99)
- North America > United States > Colorado > San Juan Basin (0.99)
- North America > United States > Arizona > San Juan Basin (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Coal seam gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract This case history discusses the Palm Valley gas field in Central Palm Valley gas field in Central Australia Production is obtained from a naturally fractured sandstone characterized by a very low matrix permeability (km less than 0.1 md). permeability (km less than 0.1 md). An integrated study including detailed geology, core and log analyses, well testing and numerical simulation led to a good history match of a 33 hour interference test and over 7 years of production. The conclusion was reached that 98% of the gas was stored in a very tight matrix and that the prolific production was only possible via a production was only possible via a network of natural fractures. The methodology used to reach a history match in this case history is presented in detail together with presented in detail together with discussions of critical parameters such as fracture spacing, fracture porosity, and fracture permeability. porosity, and fracture permeability Introduction The Palm Valley Gas Field is situated in the central-northern Amadeus Basin, Northern Territory, Australia (Fig. 1), approximately 120 km. southwest of Alice Springs. The structure is an arcuate anticline mapped from surface expression and seismic data (Fig. 2). The western and eastern plunges of the anticline are poorly defined, however, the anticline poorly defined, however, the anticline axis can be traced for over 40 km. Production from the field commenced in August 1953 with the completion of an 8" pipeline to Alice Springs. Natural gas has been used as a replacement for liquid fuels in electricity generation. Gas production from the field has increased production from the field has increased steadily, currently averaging 141,000 standard m3/d (5 MMSCFD) to Alice Springs. In September 1986 a fourteen inch trunk pipeline was completed connecting the field to the city of Darwin, 1300 km to the north, and to several major towns en-route. Production for this pipeline has Production for this pipeline has reached 622,000 standard m3/d (19 MMSCFD) and again has been used as a liquid fuel replacement in electric power generation. power generation. Development of the field has followed the definition of reserves and during the past 24 years, estimation of the gas reserves has been the subject of many studies; the most significant being by Strobel et al. in 1976; a reservoir simulation study by van Poollen and Associates in 1985 and a recent reserves study by Servipetrol Ltd. in 1990. P. 345
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.85)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.53)
- Geophysics > Seismic Surveying (0.69)
- Geophysics > Borehole Geophysics (0.66)
- Oceania > Australia > Northern Territory > Amadeus Basin > Palm Valley Field > Stairway Formation > Lower Stairway Formation (0.99)
- Oceania > Australia > Northern Territory > Amadeus Basin > Palm Valley Field > Pacoota Formation > Lower Stairway Formation (0.99)
- Oceania > Australia > Northern Territory > Amadeus Basin > Palm Valley Field > Horn Valley Formation > Lower Stairway Formation (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (5 more...)
Abstract Constant producing pressure semianalytical solutions have been developed for decline curve analysis of hydraulically fractured wells with finite or infinite conductivity in dual-porosity systems. The solutions have led to the identification of the following flow periods:A linear flow periodcharacterized by a straight line with a 0.5 slope in a log-log crossplot of qD vs. tD. This occurs in the case of an infinite conductivity vertical fracture. If the fracture has finite conductivity, the early straight line has a slope equal to 0.25. A transition period due to flow from the matrix into the fractures. A pseudo radial flow period toward the hydraulic fracture. A pseudo steady state flow period when the outer boundaries of the reservoir are reached. It is concluded that recognition of these flow periods can lead to calculation of fracture permeability, hydraulic fracture half-length, distance between natural fractures, and the parameters omega and lambda. Type curves have been developed to facilitate reservoir characterization. Their use is illustrated with an example. Introduction Hydraulic fracturing has been used for many years to improve production capabilities of wells that might have been damaged during drilling operations and reservoirs with very low permeabilities. A type curve for decline analysis of hydraulically fractured wells in conventional single-porosity reservoirs was published by Locke and Sawyer in 1975. published by Locke and Sawyer in 1975. This type curve was generated by numerical and semi-analytical techniques to facilitate reservoir characterization from constant-pressure, declining-rate reservoirs. The present paper extends Locke and Sawyer type curve to the case of dual-porosity systems that are hydraulically fractured. P. 541
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract Equations are presented for evaluation of linear flow in naturally fractured reservoirs represented by dual-porosity systems. The problem has not been treated previously in the petroleum engineering literature. This situation might happen, for example, in the case of drawdowns or buildups in dual-porosity systems which are hydraulically fractured or semi-infinite dual-porosity systems which are bounded by two parallel linear discontinuities. The equations apply only for oil systems. The extension to gas wells, however, is straightforward. The model assumes flow from the matrix into the fractures. There is no flow from a matrix block into another matrix block. It is shown that a conventional cross plot of log of delta p vs log of time should result in two parallel straight lines with a slope equal to 0.5 and a transition period which depends on the type of inter-porosity flow (pseudo steady-slate, transient or gradient) and the shape of the matrix blocks. This plot allows determination of the storativity ratio, omega, fracture porosity and distance between natural fractures. A conventional cross plot of delta p vs square root of time on Cartesian coordinates should result in two distinct straight lines. The first straighr line has a slope bigger than the second straight line. The ratio of these slopes squared gives the storativity ratio omega. The analysis also permits calculation of the hydraulic fracture length. Introduction Naturally fractured reservoirs have been the object of intensive research during the last few years in the geologic as well as the engineering fields. Transient pressure analysis has received particular attention. Barenblatt and Zheltov and Warren and Root handled naturally fractured reservoirs by assuming pseudo steady-state inter-porosity flow in a model made out of cubes with spaces in between. Flow toward the wellbore was assumed to be radial via the natural fractures. Their work led to the conclusion that a conventional cross plot of pressure vs log of time should result in two parallel straight lines with a transition period in between. The separation of the two straight lines allowed calculation of the storativity ratio omega, i.e. the fraction of the total storage within the natural fractures. Kazemi used a numerical model of a finite reservoir with a horizontal fracture under the assumption of unsteady state inter-porosity flow and substantiated Warren and Root's conclusion with respect to the two parallel straight lines. The transition period, however, was different due to the unsteady rather than pseudo steady-state inter-porosity flow assumption. de Swaan developed a diffusivity equation and analytical solutions to handle the first and last straight lines. His method, however, could not analyze the transition period. Najurieta developed analytical solutions of de Swaan's radial diffusivity equation which could handle the transition period as well as the first and last straight lines. Streltsova used a gradient flow model and indicated that the transition period should yield a straight line with a slope equal to ½ the slope of the early and late straight lines.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)