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Collaborating Authors
Ambastha, A.K.
Abstract Decline curve analysis using type-curve matching has become an established engineering tool to evaluate long-term production characteristics of oil and gas reservoirs producing under various drive mechanisms. Decline curve analysis is often used to satisfy various regulatory requirements, to establish reserves, and to evaluate the success or failure of operational changes made during a reservoir's producing life. In this study, a detailed investigation of production decline data from 78 Western Canadian Sedimentary Basin oil pools under waterflood conditions is presented. This study demonstrates that the majority of the waterflooded oil pools follow a hyperbolic decline with decline curve exponents ("b") less than 0.5. The decline exponent "b" does not exhibit any obvious functional relationship to the type of rock, oil density, geographical area, and/or geological formation. Nonetheless, such a study provides a basis for "b" values to be expected for Canadian oil reservoirs under waterflood conditions. Introduction Decline curve analysis is one of the oldest and most extensively used methods of predicting the future performance of a producing well, a lease, or a depleting reservoir. The purpose of this study is to present an analysis of the production declines of a group of waterflooded oil pools in Western Canada to establish any obvious decline trend. All of the pools selected are located in the Western Canadian Sedimentary Basin, which covers northeastern British Columbia, the southern half of Saskatchewan, and most of Alberta. This study uses a type-curve matching technique based on the general hyperbolic decline equation: Equation 1 (available in full paper) Previous Studies Fetkovich reported that in a predominantly solution-gas-drive reservoir in Texas, both the primary decline and the waterflood decline appeared to have the same decline exponent "b" of 0.3. Reasons for this phenomenon were uncertain to him. Schuldt et a l ., indicated that waterflooded oil reservoirs are generally expected to follow hyperbolic decline behaviour, but they neither explained why this should be so nor indicated their source of information. Mead wrote that pools under different producing mechanisms, waterflood or water influx, should follow exponential or hyperbolic decline with decline exponents in the range of 0 to 0.2. Lijek showed that if a plot of log (WOR) versus cumulative oil produced is linear, the decline curve of the pool is either hyperbolic or harmonic, depending on whether the gross rate is constant or variable. From his experience, he concluded that the decline exponent is very close to one (that is, harmonic decline) at a constant gross rate. Currier and Sindelar's work was similar to that of Lijek. They used log (WOR) versus cumulative oil recovery and a frontal advance cross-plot to aid them in establishing waterflood production decline trends from early data of a waterflood field in Alaska. Their study also showed that waterflood declines are harmonic or hyperbolic with a decline exponent much higher than those presented by Mead. In their study, cases with a straight line log (WOR) versus cumulative oil produced yielded decline exponents between 0.6 and 0.7.
- North America > Canada > Alberta (1.00)
- North America > Canada > British Columbia (0.90)
- North America > Canada > Saskatchewan (0.90)
- North America > United States > Alaska > North Slope Borough (0.28)
Abstract A new generalized transient flow model for a compartmentalized system in three-dimensional coordinate system with N compartments has been developed analytically. Each compartment may have distinct rock and fluid properties and may produce through a number of partially-penetrating wells. A partially-communicating fault or barrier causing poor hydraulic communication between a pair of adjoining compartments is modeled as a thin skin at the interface. Production rates and conditions at the extreme boundaries are considered time-variant. The solution has also been validated. An example problem with stacked channel realization has been studied with the new solution. A simple method for detecting the poorly-drained compartments from the extended drawdown data has been developed. This has also lead to an estimation of hydrocarbon volume in each compartment. Introduction Compartmentalized reservoirs are made up of a number of hydraulically-communicating compartments or regions. The communication between these compartments may be poor due to the presence of faults or low-permeability barriers. Evidence of reservoir compartmentalization both in oil and gas reservoirs has been presented in the literature. The idea of compartmentalization has been developed initially from the observations of discontinuities in producing fields. Reservoir compartmentalization has been observed in both areal and vertical extent. The horizontal barriers may be due to the presence of shales, micaceous streaks or stylolytes while the vertical barriers may be due to the presence of faults or of stratigraphic changes. In the mathematical models for transient flow in areally-compartmentalized reservoirs, the effects of gravity are neglected. However, in the presence of massive vertical compartmentalization, such effects are important. In this study a generalized model for transient flow in compartmentalized reservoirs in three-dimensional Cartesian coordinate system is presented. This new solution takes care of the effects of gravity by formulating the entire problem in terms of potential, rather than in terms of pressure. The new solution has been further generalized by considering time-dependent production rates and Cauchy-type conditions at the extreme boundaries. Since various types of boundary conditions are encountered in the field, the time-dependent Cauchy-type of boundary conditions are capable of dealing with wide ranging situations. For instance, the Cauchy-type conditions can yield the Dirichlet- and Neumann-types as special cases. The Dirichlet-type condition arises if an extreme boundary is maintained at a constant potential and the Neumann-type condition arises if the extreme boundary is closed to communication of any fluid. Here, we consider that there are N compartments that might be arranged vertically and areally for the purpose of developing the solution. This kind of formulation has been considered particularly for the purpose of evaluating reservoir properties and of detecting complex geological structures of compartmentalized systems including cellular system, stacked channel realization, and aeolian dune sand realization. In these kinds of geological structures, the areal models, as developed in Refs. 3 and 4, will not be adequate to describe the mechanics of flow because of high degree of compartmentalization in vertical extent. Ref. 6 has used the solution from Ref. 4 for evaluating the communication resistance between a system of a small compartment (producing) in communication with a big compartment (supporting) from extended drawdown data. A number of models based on the material balance technique have been proposed in the literature for studying compartmentalized reservoirs. However, these models work reasonably well for the gas reservoirs having permeability in the range of moderate to high (greater than 5 md). Ref. 9 also concludes that these material balance models are not appropriate for formation permeability being less than 5 md. Thus, it is obvious that the criterion for using such models will be much more restrictive in oil reservoirs. P. 317^
- North America > United States > Texas (0.28)
- North America > Canada (0.28)
Abstract To analyze well test data from thermal recovery projects, reservoirs have mostly been assumed to consist of two regions with different, but uniform, reservoir and fluid properties, separated by a sharp interface. In reality, the interface separating the two regions is not sharp. Instead, there is an intermediate region between the inner and outer regions, which is characterized by a rapid, yet smooth, decline in mobility and storativity. As an improvement over the two-region model, three-region and multi-region composite reservoir models have been proposed. However, these models still have the problem of abrupt changes in mobility and storativity in the intermediate region. This paper presents a new analytical well test model for thermal recovery processes, which accounts for the smooth changes in mobility and storativity ahead of the flood front. In this study, a thermal recovery process is modeled as a three-region, composite reservoir, in which mobility and storativity in the intermediate region decrease as power law functions of radial distance from the first discontinuity boundary. This allows for smooth changes in mobility and storativity in the intermediate region. Mobility and storativity are allowed to vary with different power law (spectral) exponents. A sensitivity study is presented on the effects of the spectral exponents for mobility and storativity on the pressure derivative behavior of the composite reservoir. As well, the effect of the size of the intermediate region on the pressure behavior of a thermal recovery process is investigated. This model, which accounts for smooth changes in mobility and storativity ahead of the flood front, is a more realistic representation of a thermal recovery process than the sharp-front idealizations of the traditional two and three-region composite reservoir models currently available. It also offers a significant improvement over the multi-region, composite reservoir model by avoiding abrupt changes in fluid properties. Introduction Most of the composite reservoir models used to analyze thermal recovery well-test data consist of two regions with different, but uniform, reservoir and fluid properties, separated by a sharp interface. In reality, the interface separating the two regions is not sharp. Instead, there is an intermediate region between the inner and outer regions, which is characterized by a rapid decline in mobility and storativity. The quest to improve on the two-region, composite reservoir models, has led to the development of three-region, composite reservoir models (Onyekonwu and Ramey; Barua and Horne; and Ambastha and Ramey). In these models, the intermediate region is represented by a uniform set of mobility and storativity values that lie (in magnitude) between those in the inner region and the outer region. To represent secondary recovery processes more realistically, analytical multi-region, composite reservoir models have been proposed (Nanba and Horne; Abbaszadeh-Dehghani and Kamal; Bratvold and Horne). In these studies, analytical multi-region, composite reservoir models were used to analyze injection and pressure falloff test data following cold water injection, to yield estimates of temperature-dependent mobility's in the flooded and un-invaded regions, as well as oil and water relative permeabilities.
Abstract This study uses interference test data from an analytical solution for a horizontal well in a closed reservoir to estimate the effective length of a producing horizontal well. Interference data are generated for observation points along the horizontal well, and at other points away from the horizontal well. Effective well lengths are estimated from data corresponding. to the early radial, early linear and late pseudo-radial flow regimes for several observation points along the horizontal well. Assuming an accurate knowledge of relevant reservoir data, analysis of the well test data shows that the early radial flow dataprovide accurate, but slightly underestimated, values of horizontal well length, except when the pressure recorder is located at the end of the well. Estimates of the well length made fromthe early linear and late pseudo-radial flow data vary significantly, depending on the location of the observation point along the well. Interference tests at observation points away from the well do not exhibit the early radial and early linear flow regimes, except when the observation point is very close to the active horizontal well. For observation points that are very close to the active horizontal well, accurate estimates of the effective horizontal well length may be obtained from horizontal well interference test data. Estimates of the effective horizontal well length are found to bemore accurate for longer horizontal wells. Introduction A knowledge of effective horizontal well length is important to assess formation damage around a horizontal well and to identify the productive section of the well length. Horizontal wells may be several times more productive than vertical wells, due to the larger area of contact of a horizontal well with the reservoir. Among other things, horizontal wells are particularly advantageous in thin reservoirs, reservoirs with a significant bottom water zone or gas cap, and reservoirs with natural fractures. However, the several advantages of horizontal wells over vertical wells may not be realizedf a significant portion of the horizontal well is damaged or completely plugged off. Plugging of portions of the horizontal well often' occurs due to the flow of sand into the wellbore. Production logs run in 'a horizontal well can identify what segments f the well are contributing to the production. However, an independent estimate of effective horizontal well length from a pressure transient test can assist in assessing formation damage around a horizontal well and in identifying the productive section of the well length. This study uses interference test data from an analytical solution for a horizontal well in a closed reservoir to estimate the effective length of a producing horizontal well. Analytical solutions for the pressure behaviour of uniform-flux, as well as, infinite-conductivity horizontal wells have been discussed in the literature. Using successive integral transforms, Goode and Thambynayagam presented a solution for an infinite-conductivity horizontal well located in a semi-infinite, homogeneous and anisotropic reservoir of uniform thickness and width. Ozkan et al. compared the performances of horizontal wells and fully-penetrating vertical fractures. For the horizontal wellbore, both infinite-conductivity and uniform-flux boundary conditions were used.
Abstract Compartmentalized reservoirs are usually analyzed using the models that are based on the material balance technique. These models have neglected the effects of internal resistance to flow, contrasts of rock and fluid properties and shape of the reservoir. However, this study concentrates on the effects of rock and fluid properties using an analytical solution for transient pressure of compartmentalized reservoirs. It is also shown that the reservoir parameters including those related to the geologic structure of a compartmentalized system can be estimated using transient-pressure data. Considering its ability to demonstrate more features than the pressure responses, the pressure-derivative analysis is also considered for drawdown responses. A compartmentalized system of a small compartment in communication with a big one is considered which is one of the very important aspects of reservoir compartmentalization. Time criteria are developed for the end of the infinite-acting radial flow period and the start of the steady-state flow period. Introduction A compartmentalized reservoir is considered to be made up of a number of hydraulically-communicating compartments or regions. This hydraulic communication between adjoining compartments may be poor due to the presence of faults or low-permeability barriers. Compartmentalization of reservoirs is evident in both oil and gas reservoirs. Understanding the pressure behaviour of compartmentalized reservoirs is very important to assess the long-term production performance. Therefore, it is required to identify the reservoir compartmentalization if there is any. In the case of detection of an unexpected compartmentalization in a reservoir during production, sometimes it becomes essential to drill more wells and facilities which could force re-evaluation of the whole development project based on economics. An unexpected detection of the presence of any compartment with a high gas-oil ratio might cause oil production rates to be constrained due to the limited capacity of the gas-handling facilities located it surface. Therefore, it is a good idea to have as much information about the compartmentalization of a reservoir as possible to avoid any unpleasant surprises in future. A number of compartmentalized reservoirs have been discovered in different regions around the world. These include Texas Gulf coast, North sea and South Australia. A parameter in relation to the inter-compartment fluid communication has been termed as barrier transmissibility in Ref. 3. Assigning low values of barrier transmissibility has been the means in Refs. 3 and 4 to simulate the poor communication of fluid between these compartments. This parameter of barrier transmissibility allows a restricted amount of fluid that can cross the interface boundary depending on the difference of average pressures of the adjoining compartments. But in this study, the poor communication of fluid between two adjoining compartments is considered as due to the presence of a thin skin at the interface between the compartments following the ideas in Refs. 5 and 6. This means that the resistance to flow of fluid at an interface is expressed in terms of skin factor which is an inverse but more comprehensive approach in comparison to the use of barrier transmissibility. Moreover, this way any inconsistencies in the definition of barrier transmissibility, as dealt with in material balance techniques, are eliminated. Ref. 4 has presented the material balance equations for different compartmentalized systems based on the assumption that the pressure over each compartment is uniform. This work has also assumed that the resistance to flow of fluid has been lumped into the barrier transmissibility. However, in Ref. 7, it has been observed that the tank models work reasonably well for gas reservoirs having permeability in the range of moderate to high (greater than 5 md). It has also been concluded that these tank models are not appropriate for formation permeability being less than 5 md. Hence, it is obvious that the criterion of using such tank models will become much more restrictive for oil reservoirs. In Ref. 8, it is suggested that the interpretation of transient pressure by the use of analytical models leads to a simplified description of the geological heterogeneities around the well. P. 519^
- North America > United States > Texas (1.00)
- Europe (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract This paper presents a detailed analysis of pressure profiles as modified by gas property variations across a rectilinear system nder large pressure-drop situations. Required numerical solutions for this study have been obtained by including the non-linear pressure gradient-squared term in the partial differential equation for linear flow of gases under steady-state and transient conditions. This study shows that neither a pressure-averaged nor a volume-averaged compressibility-like term can adequately describe the effects of gas property variations on actual pressure profiles for all situations. Numerically-simulated gas flow data under large pressure-drop conditions have been analysed using traditional approaches to quantify the effects that resemble a "velocity coefficient" (ฮฒ) as a result of gas property variations. A brief investigation of transient pressure profiles is also presented to suggest a time criterion for the attainment of steady-state conditions for gas flow in linear systems. Background Often, for gas flow under high-velocity conditions, observed pressure drop is larger than that predicted by Darcy's law. It is necessary to include a non-linear, quadratic term in Darcy's law to account for the additional pressure drop. Thus, the extra pressure drop for high-velocity gas flow situations can be modelled using a differential form of the Forchheimer(l) equation as derived by Green and Duwez: Equation Available In Full Paper. An integrated form of Equation for linear flow of gases in a core of length L, assuming constant gas viscosity and deviation factor, is: Equation Available In Full Paper. Equation suggests that a Cartesian graph of (p1 - p2)/qsc vs. qscwill be a straight line whose slope and intercept are related to ฮฒ) and k, respectively. Equation has been widely-accepted for evaluating the velocity coefficient ฮฒ) (also known as inertial resistance coefficient, turbulence factor, etc. in the petroleum literature) using experimental data under high-velocity gas flow conditions. Velocity coefficient (ฮฒ)) is regarded as a rock property. Also, ฮฒ) is considered to be independent of the flowing fluid properties and the geometrical dimensions of the porous medium. Some of the key studies related to high-velocity gas flow appear n References through . Temeng and Home developed some analytical solutions for the flow of gases in a rectilinear porous medium including the non-linear term in the pressure form of the diffusivity equation. The diffusivity equation was obtained by using Darcy's law as the appropriate rate equation and universal gas law as the equation of state. The non-linear coefficient multiplying the pressure-gradient squared term in the diffusivity equation used by Temeng and Home contains the effects of gas property variations across a linear system. They used a pressure-averaged compressibility-like term to obtain a constant coefficient for the pressure-gradient squared term in the partial differential equation. They solved analytically the following two steady-state problems:Constant rate inlet condition as per Darcy's law and constant pressure outlet condition, and Constant pressure at both the inlet and the outlet.
Abstract A compartmentalized reservoir is considered to have a number of hydraulically-connected compartments. In this study a generalized, transient-pressure model for areally-compartmentalized reservoirs is developed analytically. A compartmentalized system with two-dimensional, parallelepiped compartments has been considered. The interface-boundaries between adjoining compartments are due to low-permeability vertical barriers or partially-communicating faults and are modeled as thin skins. The conditions at the extreme boundaries of the reservoir are considered to be time-dependent to deal with any changing situations at these boundaries. An integral-transformation technique has been used to derive the solution for the dimensionless pressure in terms of dimensionless time and space. The new analytical solution has been validated by comparing simplified cases with those available in the literature. A number of practical applications of the new model are also discussed. Introduction Due to the geologic processes, most hydrocarbon reservoirs are subject to heterogeneity. As evident in the literature, some of these reservoirs are compartmentalized. A compartmentalized reservoir is considered to have a number of hydraulically-connected compartments. The interfaces between adjoining compartments are usually partially-communicating due to the presence of faults or low-permeability barriers. This kind of compartmentalized behaviour becomes prominent in the pressure history at late times when the other hydraulically connected compartments start contributing. For the sake of understanding the long term behaviour of a compartmentalized reservoir, it is important to characterize the intercompartment fluid flow as a function of time. Running a reservoir simulator to understand the behaviour of a compartmentalized reservoir is not realistic before identifying and quantifying major flow units and barrier resistance. The main objective of this study is to develop a simple analytical model that would be able to provide useful information about a compartmentalized reservoir which could be used for the purpose of designing development schemes. Presently, a compartmentalized reservoir is analyzed by using models that are based on material balance techniques ignoring the reservoir geometry. The amount of fluid that communicates between any two neighbouring compartments is estimated based on the difference in average pressures of the compartments. However, the amount of communicating fluid can be estimated more effectively if the reservoir is modeled for the transient-pressure responses. The mathematical formulation developed in Ref. 2 is based on the assumption that the fluid flow between adjoining compartments occurs under steady-state conditions. Therefore, this model could be used where the hydraulic diffusivity is very high so that transient effects dissipate very quickly. In Ref. 3, an analytical model has been developed based on single-phase material balance equations. Here, the concepts of boundary-pressure time delay and desuperposition are used to predict bottom-hole pressures over different flow regimes. Diagnostic techniques are presented in Ref. 4 for detecting and quantifying poorly drained compartments using material balance equations and a numerical simulator. A generalized transient-pressure model for compartmentalized systems in linear flow has been developed in Ref. 5. Here, poor hydraulic communication between adjoining compartments is modeled as thin skins. The mathematical model for two-dimensional compartmentalized systems as developed in this study is an extension of the model presented in Ref. 5. It is important to have a transient-pressure model that is capable of providing useful information about compartmentalized systems with areal extent. In this study a generalized, transient-pressure model for areally-compartmentalized reservoirs is developed analytically. A compartmentalized reservoir with two-dimensional, parallelepiped compartments has been considered. Each compartment may have a number of line-sink wells producing at time-dependent rates. P. 137
- North America > United States (0.93)
- North America > Canada > Alberta (0.46)
- Research Report (0.75)
- Overview > Innovation (0.34)
Abstract Fluid flow in narrow reservoirs or aquifers is predominantly linear. However, this linear-flow system may possess variations in rock and fluid properties and/or presence of faults due to a number of geological phenomena. Such systems are modeled as linear, compartmentalized systems. In this study, a new generalized transient-flow model has been developed analytically for an n-region compartmentalized system. Each compartment or region may have distinct rock and fluid properties. A time-dependent production rate from each compartment is modeled in a general way. The conditions at the extreme boundaries of this compartmentalized system are taken as non-homogeneous, time-dependent, Cauchy-type that can be modified to Dirichlet- or Neumann-type as a special case. A possible situation of poor communication between neighboring compartments has been incorporated into the model by considering the presence of a thin skin at each interface. A generalized solution for the dimensionless pressure has been derived using an integral transformation technique. This solution deals directly with the situations like production rates and extreme boundary conditions being time dependent without the need for using the principle of superposition in time and/or Duhamel's principle. Some limiting cases of this new solution have been used for validation purposes. Several advantages and practical applications of this model are also discussed in detail. With some example problems, the utility of the new solution has been shown for the situations where the transient and compressibility effects of the reservoir are not negligible while calculating the cumulative water influx through the reservoir-aquifer interface. INTRODUCTION Fluid flow in narrow reservoirs or aquifers is predominantly linear. Because of the geological processes, the rock and/or fluid properties in these linear systems may be non-uniform. Levorsen mentioned that the extent of a reservoir boundary may be sharp or it may be gradational as is more often the case. This heterogeneous character of a reservoir makes it difficult to model. To alleviate the mathematical difficulties of modeling such a system, the concept of compartmentalization may be used. Using this concept, a heterogeneous system is assumed to be comprising a number of homogeneous compartments. The communication of fluid between adjoining compartments may be hindered due to the presence of faults, permeability pinch-outs or any other flow barriers. This study presents a generalized, analytical solution for transient-pressure responses that incorporates a number of useful features. In the literature, most of the studies on linear systems are related to homogeneous reservoirs or aquifers. However, several studies with two-region, composite systems with or without a linear discontinuity have been reported. Bixel et al. developed a mathematical model for a composite system with two regions having a fully-communicating interface with the well located near it. Ambastha and Sageev obtained an analytical solution using Laplace transformation for a linear, composite system of a finite region and an infinite region being separated by a boundary skin. Yaxley presented a mathematical model for a homogeneous system with a linear, partially-communicating fault of finite thickness and finite conductivity.
Abstract Pressure derivatives have been shown to be more sensitive to disturbances in the reservoir than pressure signals; resulting in more detail on derivative graphs than is apparent on pressure graphs. The semilog pressure derivative is widely used in well test analysis. One reason for its popularity is that, for radial systems, the response appears as a horizontal line during the infinite-acting radial flow period, resulting in easier identification. However, when the semilog pressure derivative is applied to flow geometries other than radial, the responses are not horizontal; making identification of flow regimes more difficult. Thus, a generalized pressure derivative is necessary to simplify the identification of flow regimes in any flow geometry. In this study, a generalized pressure derivative is defined and used to identify the various flow regimes for composite systems in radial, elliptical, linear and spherical geometries. This generalized pressure derivative is of the power law type, alld is characterized by a different exponent for each of the flow geometries. Using well test data from analytical solutions for radial, elliptical, linear and spherical composite reservoirs, a graph of the generalized pressure derivative versus time, for any of the flow geometries appears as a horizontal line during the primary flow regime characteristic of that geometry. Design and analysis equations, based on the generalized pressure derivative, are presented for well testing of composite reservoirs in various flow geometries. Reservoir parameters estimated using these equations will add to the degree of confidence in the estimated parameters based on pressure analysis. The generalized pressure derivative is also used to investigate differences and similarities among the four flow systems. Results from this study confirm that for radial and elliptical systems, the long term pressure derivative behavior is influenced only by the mobility ratio between the inner and outer regions of the composite system. For linear and spherical systems, however, long term derivative behavior is governed by both the mobility ratio and the storativity ratio. This finding has a significant impact on the development of type curves for either manual or automated type curve matching for the various flow geometries. Introduction Pressure derivatives have been shown to be more sensitive to disturbances in the reservoir than pressure signals. This results in greater detail on a derivative graph than is apparent on a pressure graph. Pressure derivatives were first introduced by Tiab and Kumar, who presented the derivative of pressure with respect to time. Later, Bourdet et al. introduced the semi-log pressure derivative, defined as the derivative of the well pressure with respect to the natural logarithm of time. The semilog pressure derivative response appears as a horizontal line during the infinite-acting radial flow period, resulting in an easy identification of the radial flow regime. As a result the semilog pressure derivative is widely used in well test analysis of not only homogeneous, but also composite reservoirs. To analyze well tests for thermal recovery projects, reservoirs have been idealized as composite reservoirs.
Abstract There are numerous heavy oil reservoirs in Canada which are underlain by bottom-water zones and are undergoing steam injection. Steam may be injected in the reservoir or the bottomwater zone, depending on the injectivity considerations. Due to gravity override effects, zones swept by steam in these reservoirs may have irregular shapes. Using a new analytical solution for a multi-layer, composite reservoir model, this study investigates transient pressure responses for partially-penetrating, steam injection wells with irregularly-shaped fronts in the presence of infinite or finite bottomwater zones. Pseudosteady-state crossflow is allowed among adjacent layers to model the vertical flow of fluids. Pressure and pressure derivative responses have been studied to determine the effects of penetration ratio, crossflow parameters, mobility ratio, storativity ratio, and dimensionless front radii in different layers. Results of this study demonstrate the variety of well-test responses expected in such complex scenarios. Also, this study outlines the difficulties associated with the traditional pseudosteady-state approach to estimate the swept volume in the presence of bottom-water zone effects. However, this analytical transient-pressure model should prove helpful in automated (or automatic) type-curve matching analysis of well-test data obtained from thermal recovery operations with and/or without bottom-water zone effects. Introduction Steam injection process is widely used in heavy oil recovery operations. As a result of steam injection, at least two regions of different fluid properties are created and the reservoir resembles a composite reservoir. Because of gravity override effect, an inclined fluid front is created between the hot and the cold zones. Many times, heavy oil reservoirs are accompanied by a bottomwater zone. The purpose of this study is to investigate the transient pressure behaviour of a steam-stimulated heavy oil reservoir under bottom-water conditions. A reservoir undergoing a thermal recovery process has been idealized as a composite reservoir for a long time. But most of the studies consider-piston-like movement of the fluid front, neglecting the gravity override effect. Satman used the concept of a tilted (inclined) front in pressure transient analysis of a two layer, composite reservoir. He proposed that fluid front would propagate at different rates in different layers. For steam flooding, Satman and Oskay considered the discontinuity boundary as a tilted front to account for the gravity override effect and modelled the reservoir as a multi-layer, composite reservoir without crossflow. They concluded that the tilted-front model is a better representation of the actual reservoir. According to published reports on steam-drive projects, gravity override effect is a common phenomenon which results in a tilted front between the swept and the unswept zones. If gravity override effect is not taken into consideration, the predicted performance of the steam flooding project may be quite different than the actual performance. Singhal conducted some scaled physical model studies of steam-flood in a pool containing heavy oil. He presented some temperature profiles obtained from his model which showed very strong gravity override effect. Blevins et al. discussed the application of steam-flooding for light oil reservoirs.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)