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Keywords: Pressure Buildup data

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Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, October 9–11, 2017

Paper Number: SPE-187223-MS

... testing buildup test ball valve buildup real time system

**Pressure****Buildup****data**flow rate operation analysis technique log-log plot DST valve buildup period packer permeability Current trends in the petroleum industry are focused on developing shorter, less costly, safer, and more...
Abstract

For more than a decade, optimal value testing (OVT) has been advocated as a methodology that, in most cases, can replace conventional drillstem testing (DST) for in-situ permeability measurement. The term OVT refers to any pressure-transient test during which live hydrocarbons do not have to be produced directly to the surface ( Elshahawi et al. 2008 , 2012 ). Three primary types of well tests have been considered as part of the OVT toolbox: injection testing, wireline formation testing, and closed-chamber system testing with cleanup and repeat surges, which is a proprietary analysis technique. This paper reviews the earliest OVT case studies retrospectively, with the benefit of several years of production. These cases include the first successful multicycle well testing/fluid-sampling closed system testing operation with near-emission-free and real-time data transmission to surface in deep water. Operations were conducted from a moored vessel without the use of a subsea test tree, setting a world record at the time for the maximum depth at which any vessel had been moored. The operation successfully gathered all crucial data; the overall test duration was shortened; and most importantly, safety and formation fluid handling were enhanced with no hydrocarbons offloaded or flared. Data collected during all phases of the testing process were analyzed. These included the perforation, subsequent surge into the testing chamber, initial cleanup of flow/buildup, optimized closed-chamber surge flow, and final cleanup of flow/buildup. Standard techniques were used to analyze the traditional DST, but specialized techniques and software were developed to help plan and analyze the closed-chamber surge testing during perforation and surge testing. Data from the testing phase were used to generate an earth model to forecast production from the field. Several years of observed production confirm the early testing results and validate the OVT philosophy and the closed-chamber testing technology. This paper discusses the testing protocols, optimized system design, and novel analytical techniques employed. It also compares pressure transient analysis (PTA) results obtained from surge testing, standard DST, and formation tester. The consistency of formation pressure and permeability measurements obtained from the various testing techniques and the agreement with actual production performance lends credibility to the results and confirms their viability for replacing conventional DSTs in many cases. Particularly in deep water, where cost and environmental constraints limit the feasibility of conventional DSTs and where early data gathering is essential, such techniques can provide a powerful complement—and often a viable replacement—to well tests.

Proceedings Papers

Mehdi Azari, Waqar Khan, Venkat Jambunathan, Hamid Hadibeik, Fady Iskander, Mayank Malik, Derek Nash, Bobby Kurniawan

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 26–28, 2016

Paper Number: SPE-181638-MS

... analysis at the lowest-possible cost to the operator. Upstream Oil & Gas microbuildup analysis formation tester drillstem/well testing Thickness pumpout pay zone location Drillstem Testing

**Pressure****Buildup****data**pressure buildup period microbuildup permeability wireline formation...
Abstract

Historically, drillstem tests (DSTs) have been considered the standard for establishing the productive capacity of oil and gas reservoirs, providing measurements, such as formation pressure, permeability, and skin factor. In a recent study, the possibility of obtaining similar results was investigated by using wireline formation testing tool. The pressure-transient data obtained during the fluid-sampling cleanout operation was used to obtain reservoir properties. Of particular interest, spherical and radial flow models were successfully fit to very short buildup times (on the order of a few minutes) after pumpouts. To obtain similar formation properties from the shorter duration buildup times associated with flowline surging to clean debris (on the order of seconds), a process referred to as "sneezing" was investigated, yielding comparable results. Sneezing is performed several times during the fluid pumpout and sampling operation. Repetitive analyses of these microbuildups along with other pressure buildup periods in one pumpout location can help reduce uncertainty with respect to the estimation of formation properties. This paper presents three examples, including both oil- and gas-bearing formations, ranging in terms of lithology, permeability, and pressure. Formation permeability, skin damage, and reservoir-pressure values were evaluated from pressure-transient analyses during pumpouts. Results clearly demonstrate that zonal thickness, permeability, and anisotropy are key contributors to microbuildup analysis. Evaluation of reservoir properties is performed in real time with this approach to help optimize field-development plans. Analyzing these microbuildups is a unique method for supplementing/replacing the standard longer-duration pressure-transient analysis at the lowest-possible cost to the operator.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, October 9–12, 2005

Paper Number: SPE-95571-MS

... that we would be able to obtain the downhole flowrate data at sufficiently accuracy such that we could "remove" wellbore storage effects. Figure 7a Validation Case 3: B-Spline deconvolution results for validation case 3 (ONLY final

**pressure****buildup****data**are used for deconvolution) (dimen- sionless...
Abstract

Abstract This work presents the development, validation and applica-tion of a novel deconvolution method based on B-splines for analyzing variable-rate reservoir performance data. Variable-rate deconvolution is a mathematically unstable problem which has been under investigation by many researchers over the last 35 years.We believe that this work is an important addition to existing well test/production data analysis methods where few deconvolution methods are practically applicable. We use B-splines for representing the derivative of unknown unit-rate drawdown pressure and numerical inversion of the Laplace transform is utilized in our formulation.When significant errors and inconsistencies are present in the data functions, the direct and indirect regularization methods (i.e., mathematical "uniformity" processes) are used.We provide examples of under and over-regularization, and we discuss procedures for ensuring proper regularization. We validate our method with synthetic examples generated with and without errors (for this work we provide cases with 10 percent error, but we have considered cases with as high as 40 percent error).Upon validation, we then demonstrate our deconvolution method using a variety of field cases — including traditional well tests, permanent downhole gauge data as well as production data.Our work suggests that the new deconvolution method has broad applicability in variable rate/pressure problems — and can be implemented in typical well test and production data analysis applications. Objectives The following objectives are proposed for this work: To develop and validate a new deconvolution method based on B-spline representations of the derivative of unknown constant rate drawdown pressure response (i.e., the undistorted pressure response). To create a practical and robust deconvolution tool that can tolerate relatively large (random) errors in the input rate and pressure functions. The proposed process should also be capable of tolerating small systematic errors in the input functions (via calibrated regularization). To apply this new method to traditional variable-rate/ pressure problems, such as wellbore storage distortion, long-term production data, permanent downhole (pres-sure) gauge data, and well tests having multiple flow sequences. Introduction The constant-rate drawdown pressure behavior of a well/reser-voir system is the primary signature used to classify/establish the characteristic reservoir model.Transient well test proce-dures are typically designed to create a pair of controlled flow periods (a pressure drawdown/buildup sequence), and to convert the last part of the response (the pressure buildup) to an equivalent constant-rate drawdown via special time transforms.However, the presence of wellbore storage, previous flow history, and rate variations may mask or distort characteristic features in the pressure and rate responses. With the ever increasing ability to observe downhole rates, it has been long recognized that variable-rate deconvolution should be a viable option to traditional well testing methods because deconvolution can provide an equivalent constant-rate response for the entire time span of observation.This po-tential advantage of variable-rate deconvolution has become particularly obvious with the appearance of permanent down-hole instrumentation.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, October 6–9, 1991

Paper Number: SPE-22684-MS

... Abstract This study documents a procedure used to analyze

**pressure****buildup****data**from coal gas methane wells In the San Juan Basin, New Mexico. Because these test data am Influenced by both fracture linear flow and wellbore afterflow, our analysis procedure uses rate normalization or...
Abstract

Abstract This study documents a procedure used to analyze pressure buildup data from coal gas methane wells In the San Juan Basin, New Mexico. Because these test data am Influenced by both fracture linear flow and wellbore afterflow, our analysis procedure uses rate normalization or deconvolution, fractured well solutions and both single-phase and two-phase pseudo-pressure approaches. pseudo-pressure approaches. Results obtained from the study demonstrate that this procedure is adequate for complete analysis of the buildup procedure is adequate for complete analysis of the buildup data from coal gas wells. The use of rate normalization and pressure-rate deconvolution and enhance the identification of pressure-rate deconvolution and enhance the identification of the radial flow period. Also, because the wells analyzed were hydraulically fractured. the fractured well models permit the analysis of early time data. Finally, the two-phase pseudopressure method allows the calculation of absolute pseudopressure method allows the calculation of absolute formation permeability. We used this procedure to analyze pressure buildup data from several wells in the Rincon Unit. Results from the analysis am used in reservoir simulation studies of these wells. Simulation model results agree closely with observed well test and field performance. Introduction Active coal gas production has been carried out in the U.S. over the past decade. Some 6000 coal gas wells were estimated in production by the end of 1990. In 1991, nearly half of the new gas wells completed in the U.S. are coal gas wells. The rapid growth of coal gas activity is not limited to the U.S. alone; it is also significant in other parts of the world; such as, Canada, France, Poland, U.K., Australia and Indonesia. The mechanism of coal gas production 15 not the same as that of conventional gas wells. The gas in place is not only stored as free gas in the fracture cleat systems but also adsorbed on the micropore walls of the coal matrix. Upon pressure decline, absorbed gas is released from coal matrix. pressure decline, absorbed gas is released from coal matrix. becomes mobile and often flows to the well together with saturated water. The desorbed gas diffuses through the coal matrix according to Fick's law until it reaches the cleats where It flows to the well following Darcy's law. Because of the combined mechanism of diffusion and gas flow in porous media. the aspects of well test analysis and performance forecast for coal gas wells are difficult Many performance forecast for coal gas wells are difficult Many papers have been presented over the last ten years to model papers have been presented over the last ten years to model the flow of gas in coal seams and to analyze pressure transient data from coal gas wells. Although the use of well test results in reservoir modeling is important in practice, It is sometimes overlooked. The purpose of this study is to show that this practice is quite useful in reservoir management of coal gas wells. Specifically, we present a procedure to analyze the early-time pressure buildup data that are influenced by wellbore afterflow pressure buildup data that are influenced by wellbore afterflow effect and fractured well behavior. Our procedure Is then verified by using the well test results in reservoir simulation to reproduce the well test data. Once the match is obtained, the fine-tuned reservoir/well model is then used to predict the well performance. Our procedure Is consistently applied to 16 performance. Our procedure Is consistently applied to 16 wells In the Rincon Unit and Is found to be practical. useful and accurate. THEORY In this section, we present theoretical considerations pertinent to the discussion of our study. Definitions of different dimensionless time and pressure group are first provided for reference. The use of both single-phase gas and two-phase pseudopressures to analyze coal gas well tests is pseudopressures to analyze coal gas well tests is discussed. P. 265

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, October 8–11, 1989

Paper Number: SPE-19817-MS

... graph of analysis, (pi-pwf)/qn versus Lqi*f(t-ti). The last step is well docu- mented in references 5, 6, 9, 10, and 13-16. ANALYSIS OF

**PRESSURE****BUILDUP****DATA**. The pressure buildup is the most frequently used test because the bottomhole pressure is measured under constant flow rate (q=O) conditions (Fig...
Abstract

Abstract The superposition time function has been used as a tool to analyze transient pres sure data measured under the influence of a variable flow rate. This function is usually defined assuming that radial flow equations are valid, however, in practice there are cases that exhibit several flow regimes (i.e. fractured wells, partially penetrating wells, etc.). The present work penetrating wells, etc.). The present work examines the limitations of the superposition time concept as applied to buildup tests. It appears that, regardless of the flow regimes exhibited by the well reservoir system the derivative function with respect to the radial flow superposition time for a buildup test follows, at early time, the drawdown curve for the pressure first derivative function t*dp/dt, then, after a transition period, it follows the drawdown curve for the pressure second derivative function t2 * abs(d2p/dt2). Introduction Well testing has proved to be one of the most reliable tools to evaluate flow characteristics of a well-reservoir flow system. A large number of publications on this subject was presented in the last four decades. The original theory for pressure transient test analysis in the petrol pressure transient test analysis in the petrol eum industry was developed for constant well flow rate conditions. Later several authors presented methods to take into account the rate variations in well test interpretation. More sofisticated techniques of interpretation were developed recently to take advantage of advances in the technology to measure flow rate and pressure simultaneously with good resolution. The application of the pressure derivative function t*dp/dt for type curve matching and flow regime identification has become a standard for well test interpretation in the last few years. Several pressure derivative type curves are now available; most of them were developed for drawdown tests and are applied to the analysis of pressure buildup tests through the use of pressure buildup tests through the use of the superposition time concept. It has been suggested that this concept can take into account the variation of the flow rate before shut-in; however, experience has shown that this technique produces distortions in the calculation of the derivative function when the pressure data are under the influence of a flow regime other than radial. The objective of the Present work is to examine the advantages and limitations of the application of the superposition time concept on the interpretation of pressure build-up tests through the use of specific graphs of analysis (pws vs f(q,t)) and type curve analysis of the derivative function. ANALYSIS OF VARIABLE RATE PRESSURE DRAWDOWN DATA. Let us consider a pressure drawdown rest under variable flow rate conditions (Fig. 1) where the flowing bottomhole pressure is a function of both flow rate and time. As mentioned before, the original theory for inter pretation assumes constant flow rate pretation assumes constant flow rate conditions; hence it is necessary to take into consideration the variation of the flow rate. P. 477

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, October 8–11, 1989

Paper Number: SPE-19844-MS

... drillstem/well testing flow geometry

**pressure****buildup****data**approximation interpretation reservoir straight line drillstem testing spherical flow permeability upstream oil & gas discontinuity skin effect type curve equation society of petroleum engineers slug test reservoir...
Abstract

Abstract Analysis of field data obtained from pressure transient testing, may not always be performed with methods based on plane radial flow. A well is often subjected to physical conditions which may lead the flow phenomena to be better represented by different flow patterns, such asspherical flow (near wellbore effects in patterns, such as spherical flow (near wellbore effects in partially penetrating wells) or linear flow (short term tests in partially penetrating wells) or linear flow (short term tests inartificially fractured wells). Large-scale heterogeneities, which can be represented by faults or radial discontinuities in rock or fluid properties, may cause anomalous behaviour in wellbore pressure. pressure. An approach which models a drillstem test (DST) as a changing wellbore storage problem, originally developed for plane radial flow, has been extended to the following conditions which may affect short term testing: 1 - linear flow, 2 - spherical flow, 3 - well close to a linear sealing fault, 4 - radial flow in a composite reservoir. New wellbore pressure equations for both flow and shut-in periods of drillstem tests have been derived. These equations have periods of drillstem tests have been derived. These equations have been used to develop new specialized methods for analysis of pressure buildup data of drillstem tests. pressure buildup data of drillstem tests. New derivative type curves, which may be employed for interpretation of drillstem test flow periods (" slugtests"), are also presented. The method of Laplace transformation has been used to obtain the solutions described in this work. In some cases, inversion from Laplace spaced has been carried out numerically by standard algorithms. Introduction A drillstem test (DST) is usually a short-term test, in which wellbore pressure behaviour may be strongly affected by near wellbore conditions. Interpretation of drillstem pressure data employing radial flow models, may provide an estimate of formation properties and wellbore damage. properties and wellbore damage. We have considered the case in which produced fluids continuously fill the drill string, causing a gradual increase in the bottomhole pressure and a decrease in the flow rate. During the shut-in pressure and a decrease in the flow rate. During the shut-in phase, fluids entering the wellbore are compressed below the phase, fluids entering the wellbore are compressed below the shut-in point (usually a bottomhole valve). These concepts permit to recognize a drillstem test as a "slug test" in which, the wellbore storage mechanism shifts abruptly from changing liquid level during production to fluid compressibility during the shutin phase. Although this condition has been originally devised to be used in connection with a homogeneous radial flow model, it may be promptly extended to other flow patterns. Among others, the effects of linear and spherical flow geometries on pressure behaviour of drillstem tests ought to be investigated. Also, the use of the linear fault and composite reservoir models with a DST condition can improve the techniques for detection of reservoir discontinuities by transient testing. The main purpose of this paper is to investigate the effects of linear and spherical flow, and large scale heterogeneities such as faults and radial discontinuities, on drillstem test pressure. p. 763

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 27–30, 1987

Paper Number: SPE-16802-MS

..., SPE, P.O. Box 833836, Richardson, TX 75083-3836. Telex, 730989 SPEDAL. ABSTRACT Analysis of the pressure response obtained from a drill stem test (DST) provides important additional information for deciding whether it is economical to complete a well. Interpretation of DST

**pressure****buildup****data**has...
Abstract

SPE Members Abstract Analysis of the pressure response obtained from a drill stem test (DST) provides important additional information for deciding whether it is economical to complete a well. Interpretation of DST pressure buildup data has been based on the Horner method. The basic assumption of the Horner method is that the well is produced at a constant rate before the shut-in. When rate changes with time, a cumbersome application of the superposition principle is required to analyze the pressure buildup data. Furthermore, the solution of the diffusivity equation for a constant production rate gives a declining flowing pressure with time, but most DST's show an increasing flowing pressure during production. Therefore, the application of the Horner method may lead to inconsistent results in the interpretation of DST pressure buildup data. An original approach was used to model the DST problem. A DST can be characterized as a changing wellbore storage problem following an instantaneous pressure drop at the well. During production the wellbore storage coefficient is given by the rate of fluid accumulation inside the wellbore. After the shut-in of the well the wellbore storage mechanics change due to the compressibility of the fluid below the bottom hole valve. Therefore, using this concept, the flowing and the pressure buildup phases are modeled with a single inner boundary condition. In this paper an analytical solution correct for both the flowing and shut-in periods was obtained by solving the diffusivity equation with a single inner boundary condition which included the mixed conditions for flow and buildup. Both a skin effect and wellbore storage were considered. Solution was obtained by Laplace transformation. The solution was used to develop methods of interpretation for the pressure buildup period of drill stem tests. Application of these new methods of interpretation to DST field data may provide the initial reservoir pressure, the formation permeability and the skin effect. The interpretation methods are based on graphical analysis of the data and are easily applied in the field. The interpretation methods are generalized to include multiple production-shut-in cycles, including step changes in the wellbore storage coefficient due to changes in the drill pipe diameter and/or due to variations in fluid properties. Unlike the results obtained from the application of the Horner method, interpretation of field data using these new methods show excellent agreement between the parameters obtained from the analysis of the first and second shut-in periods of short term double-cycled DST'S. Field examples are presented. Introduction The drill stem test (DST) has been used as a primary method of formation evaluation since its introduction in 1926. In the early stages of its development, the DST was mainly used to identify reservoir fluids. Although methods of analysis for pressure buildup data were proposed as far back as 1928, it wasn't until the early 50's that DST's were properly designed to obtain reliable pressure buildup data. The DST is normally run during the drilling phase of a well, and when properly performed it may give valuable information about the reservoir zone being tested prior to well completion. A DST can be viewed as a temporary completion of the well. The DST tool is run into the mud-filled wellbore in order to isolate the interval of interest from the surrounding zones, and a sequence of alternating production and shut-in phases is performed. The bottomhole pressure is continuously recorded and a typical DST pressure-time chart is sketched in Figure 1. The test starts with the opening of a bottom-hole valve, allowing the formation fluids to enter into the drill string, which may be empty or partially filled with a liquid cushion. In some cases, the drill string may also contain pressurized gas. The first flow period is usually short, and often the produced fluids do not reach the surface by the time of the shut-in of the well. However, after the well is shut-in, a pressure recovery takes place in the reservoir, due to the fluid withdrawal during the production phase. Analysis of pressure-time data obtained during the shut-in phase may provide the initial reservoir pressure, and an estimate of the formation permeability and wellbore condition. Before the produced fluids reach the surface, which may not happen in most DST'S, the flow rate is not controlled. P. 529^

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, October 5–8, 1986

Paper Number: SPE-15579-MS

...) production phase step function production time drillstem/well testing laplace transform flow rate pressure buildup ramey wellbore storage unit step function boundary condition diffusivity equation drillstem testing straight line upstream oil & gas type curve

**pressure****buildup****data**...
Abstract

Abstract A new approach was used to solve the problem of pressure buildup following constant bottom hole pressure production. Previous methods of solution involve finite difference solution or Previous methods of solution involve finite difference solution or numerical evaluation of the superposition integral. An analytical solution correct for both the flowing and shut-in periods was obtained by solving the diffusivity equation with a single inner boundary condition which included the mixed conditions for flow and buildup. Both a skin effect and wellbore storage were included even though the production period was at constant wellbore pressure. Solution was production period was at constant wellbore pressure. Solution was obtained by Laplace transformation. The procedure presented in this paper may be used to solve other interesting problems. One example presented is the joint solution of constant rate production and shut-in with wellbore storage and skin effect. The procedure used does not involve superposition. Introduction Pressure transient tests in wells have been extensively studied during the past three decades and a number of analytical solution methods have been presented for analysis for field data. Most methods have been based upon constant-rate production. However production rates are not often controlled. Flow rate monitoring is not production rates are not often controlled. Flow rate monitoring is not always performed (or even possible) despite the fact that constantrate test interpretations have become standard in the industry. A pressure buildup test is one sort of test most likely to result in a pressure buildup test is one sort of test most likely to result in a constant rate—a zero rate. Analytical interpretation methods can be based upon superposition of constant rate solutions. In many cases the production phase is better represented by a constant-pressure flow period and in such cases the use of superposition may not be practical. A drill stem test (DST) is a typical example where the flow rate is not controlled and interpretation of pressure-time data by means of methods developed for the pressure-time data by means of methods developed for the constantrate case may produce uncertain results. Methods of interpretation for practical well test analysis are based upon solutions of the diffusivity equation, considering a wide range of boundary conditions. As for the pressure buildup case, sometimes a well is subject to physical situations that lead to a mathematical description of the phenomenon represented by a timedependent boundary condition. If, after a given time, the boundary condition changes to a different kind, then the solution to the problem is usually difficult and is often handled by finite difference problem is usually difficult and is often handled by finite difference methods. The main purpose of this paper is to present a method of solution for problems represented by time-dependent boundary conditions. The method was used to handle pressure buildup following both constant-rate and constant-pressure production phases, and the solution for the constant-pressure case is developed in detail. The method can be used to solve a variety of other interpreting problems. Thus another purpose is to present new transforms and problems. Thus another purpose is to present new transforms and operational rules useful for other problems. CONSTANT PRESSURE PRODUCTION FOLLOWED BY SHUT-IN In this section we present the mathematical formulation for pressure buildup following a constant-pressure production phase. pressure buildup following a constant-pressure production phase. The radial flow of a constant viscosity and small compressibility single phase fluid through a homogeneous, isotropic and constant thickness reservoir, is described by the diffusivity equation, which in terms of dimensionless variables is: ..........................................(1) ..........................................(2) ..........................................(3) ..........................................(4) The initial condition is established by assuming that the entire reservoir is at the initial pressure pi, or: ..........................................(5)

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 22–26, 1985

Paper Number: SPE-14312-MS

... developed to characterize the heterogeneity using the pressure data which deviates from the infinite-acting ideal case. Using the method of imaging developed by Horner,

**pressure****buildup****data**were generated for semi-inifinite**pressure****buildup****data**were generated for semi-inifinite systems for the following...
Abstract

Abstract A technique has been developed to identify the effects of no-flow boundaries by using the deviation of pressure build data from the inifinte-acting case. A dimensionless pressure depletion group consisting of pressure depletion group consisting of the measured initial reservoir pressure, the extrapolated pressure from the Horner plot and slope of the infinite acting data on the Horner plot is used as a parameter. The ratio of the late time slope to the middle time slope on Horner plot is plotted against the Horner plot time. For a given value of the dimensionless pressure depletion group, these data are matched against the curves for a given boundary configuration. Analysis of actual field data has been included to illustrate this technique. Introduction Pressure transient testing is one Pressure transient testing is one technique used to obtain reservoir description. Reservoir heterogeneities complicate interpretation by causing analamous pressure buildup behavior. Therefore, identification of a heterogeneity by the pressure transient response of a dual flow/dual shutin test is accomplished by a process of elimination. The technique presented in this paper has been developed to characterize the heterogeneity using the pressure data which deviates from the infinite-acting ideal case. Using the method of imaging developed by Horner, pressure buildup data were generated for semi-inifinite pressure buildup data were generated for semi-inifinite systems for the following: Single, no-flow boundary; and two orthogonal, no-flow boundaries. The Horner method forms the basis for this method of analysis. The Horner plot is divided into three regions as depicted in Figure 1: an early time, where a wellbore and near wellbore effects dominate; a middle time, where infinite acting reservoir effects dominate; and late time, where effects of a reservoir heterogeniety dominate. A properly designed and conducted dual flow/dual shutin production test is required for accurate assessment of reservoir configuration. That is, the measurement of the initial reservoir pressure become critical for interpretation of test results since reservoir limits or boundaries are identified by comparing the initial reservoir pressure pi to the extrapolated pressure p*. The technique described in this paper offers advantages over the previous technique for drawdown data. DERIVATION OF METHOD A dimensionless pressure depletion parameter for this method has been derived from the diffusivity equation. Given certain standard assumptions, the pressure buildup behavior for a homogeneous, infinite reservoir is described by Equation 1. Pws=pi-m log ............................(1) Pws=pi-m log ............................(1) If the reservoir has a linear, no-flow boundary as depicted in Figure 2, the pressure buildup response is given by Equation 2. ...........................................(2)

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 16–19, 1984

Paper Number: SPE-13079-MS

..., Drawer 64706, Dallas, Texas 75206 USA. Telex 730989 SPEDAL. Summary This paper examines applicability and limitations on the use of rectangular hyperbolas to analyze

**pressure****buildup****data**, with emphasis on the**pressure****buildup****data**, with emphasis on the determination of average pressure and flow...
Abstract

The paper was presented at the 59th Annual Technical Conference and Exhibition held in Houston, Texas, September 16–19, 1984. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write SPE, 6200 North Central Expressway, Drawer 64706, Dallas, Texas 75206 USA. Telex 730989 SPEDAL. Summary This paper examines applicability and limitations on the use of rectangular hyperbolas to analyze pressure buildup data, with emphasis on the pressure buildup data, with emphasis on the determination of average pressure and flow capacity. It is shown that the method can be used with confidence only if it is applied to data that can also be analyzed by conventional semilog methods, and that it for such data is essentially equivalent to the conventional methods in terms of information needed and information obtained. If we use semilog data, then we can determine the flow capacity from the slope of the hyperbola, and we can determine the average pressure indirectly from the asymptote, provided we pressure indirectly from the asymptote, provided we know the drainage area and the MBH function of the reservoir. Following stabilized flow we only need the shape factor in addition to the area. If we use the direct approach, and assume that the asymptote is equal to the average pressure, then we need the same type of information to make a proper choice of interval where the hyperbola should match the buildup curve. For the direct approach we will normally get an estimate of average pressure that is less than m/1.151 psi (kPa) above the last wellbore pressure being used in the analysis, where m is the conventional semilog slope. Moreover, if we use only semilog buildup data following pseudosteady-state flow, then we can only get an accurate estimate of average pressure by this approach if the shape factor is close to 21, or higher. If nothing is known about the reservoir, then the hyperbola method can be used to get a rough estimate of the average pressure, but with a high degree of uncertainty if we only have data from a short buildup period. This claim follows from the many examples period. This claim follows from the many examples included in this paper of asymptotes determined from hyperbolas matched to dimensionless synthetic buildup data plotted vs. interval midpoints. Introduction The Miller-Dyes-Hutchinson (MDH), Matthews-Brons-Hazebroek (MBH), and Dietz methods can be used to determine the average, or static, reservoir pressure for closed reservoirs, and the method of Kumar and Ramey can be used for constsant-pressure squares. These methods are based on an indirect use of exact pressure solutions, and hence require knowledge of the size and shape of the drainage area, and of the outer boundary condition. For a given test, all or part of this information might be missing, in which part of this information might be missing, in which case approximation must be used to carry out the analysis. This leads to uncertainties in estimates of average pressure and other parameters that depend on this information. A different approach to pressure buildup analysis was suggested by Mead. He observed that pressure buildup curves closely resemble rectangular hyperbolas, and therefore asserted that the average reservoir pressure should be equal to the horizontal a sympotote of a hyperbola matched to a buildup curve. Mead supported his assertion by examples. Hasan and Kabir explored Mead's empirical results further, and presented a theoretical justification for the hyperbola approach to buildup analysis when both the drawdown and buildup transients are in the inifinte-acting period. Their work was based on a truncated series expansion of the logarithmic solution. Hasan and Kabir successfully and flow conditions, and concluded that the rectangular hyperbola approach can generally be used to determine the average, or static, reservoir pressure directly from field data, and also that good pressure directly from field data, and also that good estimates can be obtained for flow capacity and skin. This without prior knowledge of the size, shape, and type of the reservoir being tested. An analysis of the inherent limitations on the method was not included in Ref. 6. The general conclusions in Ref. 6 attracted criticism from Humphreys and Bowles and White. In their replies, Hasan and Kabir acknowledged the superiority of Horner analysis of infinite acting reservoirs, but reaffirmed the validity of the method for other cases, again supported by examples.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 16–19, 1984

Paper Number: SPE-13183-MS

... analyzing

**pressure****buildup****data**.. The Ivishak formation of the Sadlerochit Group in the Prudhoe Bay Unit is a layered reservoir, dipping slightly south by southwest. The formation is such that the deeper strata typically have lower permeabilities than middle and upper layers. A.s much as an order of...
Abstract

Abstract Pressure buildup tests from wells of a very large reservoir are analyzed using McKinley Early Time Analysis as extended by Streltsova-Adams and McKinley (1982) to account for partial completion. other recent papers which address the issue of partial completion are briefly summarized also. Because the wells are directionally-drilled and partially-completed, a configuration pseudo-skin equivalent is determined for each well using correlations developed by Cinco-Ley, Ramey and Miller (1975). This quantity, which is a function of completion ratio and location., hole angle, and dimensionless formation thickness, corresponds to a Streltsova-Adams and McKinley (1982) partial completion factor. The configuration pseudo-skin equivalent varies from zero to one and is used for type curve selection in the same manner as the partial completion factor. partial completion factor. This work presents a procedure for the determination and application of the configuration pseudo-skin equivalent and demonstrates its use in pseudo-skin equivalent and demonstrates its use in early time analysis. Data from twelve pressure buildup tests on five Prudhoe Bay wells are analyzed and the results are presented with a discussion. It is shown that by accounting for all pseudo-skin effects due to well configuration, pseudo-skin effects due to well configuration, Mckinley Early Time Analysis can be generally applied to yield consistent and reliable results, allowing valuable information to be obtained from conventionally uninterpretable pressure buildup tests. Background Methods used by operating companies for analyzing Prudhoe Bay pressure buildup data may be divided into two categories: those which utilize middle time region data and those which utilize early time data. Tn general, analyses of the first category are considered more reliable, while analyses of the second category are applicable in a wider variety of cases. A knowledge of reservoir characteristics in the vicinity of a given well is required when selecting the appropriate technique for analyzing pressure buildup data. The Ivishak formation of the Sadlerochit group in the Drudhoe Bay Unit is a layered reservoir, dipping slightly south by southwest. The formation is such that the deeper strata typically have lower permeabilities than middle and upper layers. As permeabilities than middle and upper layers. As much as an order of magnitude in permeability variation exists throughout the thickness of the reservoir. Towards the north and northeast portions of the field, oil is found in the lower portions of the field, oil is found in the lower zones with moderate and low permeabilities while towards the south and southwest, oil is found in higher zones with moderate and high permeabilities. The gas cap is concentrated in the permeabilities. The gas cap is concentrated in the upper zones of the northeast. Finally, the aquifer occupies lower zones in the southern periphery of the field. Well location within this nonhomogeneous reservoir affects the approach to pressure buildup data interpretation but is not the only consideration. The presence of extensive shale complexes between the gas cap and the producing interval of a well will also impact the selection of an analysis technique. Pressure buildup tests from a well In communication with the gas cap frequently have no usable middle time region data because of the rapid emergence of constant pressure boundary effects, thereby necessitating the application of early time analysis. Having established some important concerns for the selection of an analysis technique, it is now appropriate to examine some of the techniques which are used. Because Prudhoe Bay wells are almost invariably partially-completed, the following discussion is limited to methods which attempt to account for this effect. Streltsova-Adams and McKinley (1981) studied the effects of partial completion and found that when wellbore storage effects are short-lived, data corresponding to two semi-log straight lines can be identified. Tn a graph of pD versus log tD, the first straight line to develop has a so-called early time slope m1.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 21–24, 1980

Paper Number: SPE-9289-MS

... indiscriminately to analyze both pressure drawdown and buildup data. Moreover, the limitations of drawdown type curves, to analyze

**pressure****buildup****data**collected after short producing times, are not well understood by the practicing engineers. This may often result in an erroneous interpretation of such buildup...
Abstract

Abstract Currently, type curve analysis methods are being commonly used in conjunction with the conventional methods to obtain better interpretation of well test data- Although the majority of published type curves are based on pressure drawdown solutions, they are often applied indiscriminately to analyze both pressure drawdown and buildup data. Moreover, the limitations of drawdown type curves, to analyze pressure buildup data collected after short producing times, are not well understood by the practicing engineers. This may often result in an erroneous interpretation of such buildup tests. While analyzing buildup data by the conventional semi-log method, the Horner method takes into account the effect of producing time. On the otherhand, for type curve analysis of the same set of buildup data, it is customary to ignore producing time effects and utilize the existing drawdown type curves. This causes discrepancies in results obtained by the Horner method and type curve methods. Although a few buildup type curves which account for the effect of producing times have appeared in the petroleum literature, they are either limited in scope or somewhat difficult to use. In view of the preceding, a novel but simple method has been developed which eliminates the dependence on producing time effects and allows the user to utilize the existing drawdown type curves for analyzing pressure buildup data. This method may also be used to analyze two-rate, multiple-rate and other kinds of tests by type curve methods as well as the conventional methods. The method appears to work for both unfractured and fractured wells. Wellbore effects such as storage and/or damage may be taken into account except in certain cases. The purpose of this paper is to present the new method and demonstrate its utility and application by means of example problems. Introduction Type curves have appeared in the petroleum literature since 1970 to analyze pressure transient(pressure drawdown and pressure buildup) tests taken on both unfractured and fractured wells. The majority of type curves which have been developed and published to date were generated using data obtained from pressure drawdown solutions and obviously are most suited to analyze pressure drawdown tests. These drawdown type curves are also commonly used to analyze pressure buildup data. The application of drawdown type curves in analyzing pressure buildup data is not as bad as it may first appear. As long as the producing time, t, prior to shut-in is sufficiently long compared to the shut-in time, Delta t [that is (t +Delta t)/t 1], for liquid systems, it is reasonable to analyze pressure buildup data using drawdown type curves. However, for cases where producing times prior to pressure buildup tests are of the same magnitude or only slightly larger than the shut-in times [that is, (t + Delta t)/t »1], the drawdown type curves may not be used to analyze data from pressure buildup tests. The above requirement on the duration of producing times is the same for the conventional semi-log analysis. If pressure buildup data obtained after short producing pressure buildup data obtained after short producing time are to be analyzed, the Horner methodic is recommended over the MDH (Miller-Dyes-Hutchinson)method. The MDH method is generally used to analyze buildup data collected after long producing times, whereas the Horner method is used for those obtained after relatively short producing times. Although pressure buildup tests with short producing times may occur often under any situation, they are rather more common in the case of drill stem tests and prefracturing tests on low permeability gas wells. Thus, there is a need for generating buildup type curves, which account for the effects of producing time. Some limited work has been done in producing time. Some limited work has been done in this regard. McKinley has published type curves for analyzing buildup data for a radial flow system.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 21–24, 1980

Paper Number: SPE-9456-MS

....

**Pressure****buildup****data**were recorded for all five wells. A consistent reservoir description was developed from geological and engineering data. Interference and production history data were history-matched with an XYZ simulator and**pressure****buildup****data**were modeled with an RZ simulator. The upper shale...
Abstract

Abstract An improved reservoir description of a Prudhoe Bay field water injectivity test site was obtained by simultaneously history-matching interference, pressure buildup and production history data with a pressure buildup and production history data with a black oil simulator. Water is currently being injected in a Sadlerochit reservoir inverted, five-spot pattern on the east side of the field. Pressure data were obtained prior to starting water Pressure data were obtained prior to starting water injection. Interference testing was conducted by successively shutting in and producing each of the four corner wells, which are field production wells, and observing the pressure response at the water injection well in the center of the pattern. Pressure changes, varying from 2 to 8 psi, were Pressure changes, varying from 2 to 8 psi, were measured with a downhole, high-sensitivity, quartz-crystal pressure transducer. While small, the pressure changes were measurable because two major pressure changes were measurable because two major shale complexes exist between the test interval and the large Prudhoe Bay field gas cap overlying the test area. Well spacing varied from 1600 to 2400 feet. Pressure buildup data were recorded for all five wells. A consistent reservoir description was developed from geological and engineering data. Interference and production history data were history-matched with an XYZ simulator and pressure buildup data were modeled with an RZ simulator. The upper shale complex is sealing, while the middle shale complex, lying immediately above the observation well perforations, allows some vertical communication. Type-curve matching the interference test gave much greater krokh/mu values for the tested interval than the XYZ history match. This occurred primarily because the interference test actually investigated zones above the tested interval. Introduction Interference test data were part of the information used to develop a reservoir description of a water injection test area in the Prudhoe Bay field. This reservoir description will be used in a waterflood performance simulation. Prior to starting water injection, interference testing was conducted between the water injection well (W-1 in Figure 1) and the four offset wells. Interference testing was conducted by successively shutting in and producing each of the five-spot's four corner wells, producing each of the five-spot's four corner wells, which are field production wells, and observing the pressure change at well W-1. Even with the pressure change at well W-1. Even with the overlying gas cap, which has a compressibility sufficient to reduce the amplitude of the interference test pressure response, measurable pressure changes occurred because major shale complexes partially shield the test area. Production history and interference test data were matched with an XYZ sequential simulator and pressure buildup data were matched with an RZ pressure buildup data were matched with an RZ version of the simulator. An initial reservoir description was formulated from all previous geological and engineering data. By trial-and error modification of the initial description reservoir permeabilities, shale boundaries, and shale vertical transmissibilities, a final reservoir description was obtained that matched all geological and engineering data. Reservoir heterogeneities resulting from the nonmarine alluvial depositional environment were evident as permeability trends run in a north-south direction. permeability trends run in a north-south direction. This paper describes the procedures and results for the interference test and the reservoir simulation study. The simulation results are compared with analytical analyses of the pressure buildup and interference tests. GEOLOGY The Prudhoe Bay structure is a west-plunging anticlinal nose bounded on the north by faulting and truncated on the east by an unconformity.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 21–24, 1980

Paper Number: SPE-9460-MS

... Reservoir Surveillance

**Pressure****Buildup****data**oilwell tirre Drillstem Testing voluile rrethod new technique production monitoring drillstem/well testing dp dt prover production control Upstream Oil & Gas liquid level recorder gas volurre equation bottorrhole pressure...
Abstract

Abstract A mathematical model has been developed on the principle of mass balance of the gas component for an oilwell (pumping or flowing) which enables one to calculate the annular gas volume, including gas bubbles in the oil column. The knowledge of annular gas volume at a given instant of time can then be used to find the pseudo length of both oil and gas columns and hence the bottomhole pressures. This technique can be used to obtain pressure buildup data. In addition the flowing bottomhole pressure prior to the shut-in can be determined in the same manner to allow calculation of productivity index (PI) and to evaluate pumping well performance. The proposed method has distinct advantage over the conventional acoustic well sounder (AWS) technique which measures the actual gas-liquid interface in the annulus. Experience has proven that the AWS technique becomes inconsistent and difficult to interpret, particularly when the oil has foaming tendencies. The AWS method requires knowledge of the gas-cut oil column gradient (estimated by an empirical correlation) when the flowing bottomhole pressure is below the saturation pressure. The advantages of the new method over the use of bottomhole recorders in a pumping oilwell is the cost saving (pump and rods need not be pulled), flexibility of data gathering and the obtaining early time data (e.g. p ws @ Î"t for type curve analysis). A field test has been conducted using high resolution pressure transducers to demonstrate the applicability and accuracy of the proposed method for a flowing oilwell. Introduction Pressure buildup tests in pumping oilwells are conducted either by running bottomhole pressure recorders after pulling the pump and rods or by measuring the fluid level by acoustic well sounders. Both methods have limitations. Bottomhole pressure recorders give reliable pressure data, but the early time data must be sacrificed due to the time involved in pulling the pump and running pressure recorders. This time lag can be especially important in wells intercepting high transmissivity reservoirs where pressure may stabilize rapidly 1 . In such cases semilog analysis may not be possible. In deep wells the time lag may be large enough to prevent the extrapolation of pressure data to zero time. As a result, the flowing bottomhole pressure (P wf ) cannot be obtained for type curve analysis. The use of an acoustic well sounder (AWS) device to measure the length of oil column is considerably cheaper. Although the use of an automated AWS system 2 can improve the monitoring of test data, the method fails to work accurately where the oil has foaming tendencies 3 . In addition, the liquid level determined by an AWS needs to be multiplied by a modified gradient when the well pressure is below the saturation pressure. This liquid gradient can be estimated by empirical correlations presented in the literature 2–5 . The proposed method of obtaining bottomhole pressures is based on the principle of gas mass balance. A simple procedure for obtaining a pressure buildup profile for a well in an undersaturated reservoir is presented. The method has the advantage that pressure data can be monitored at the surface like the AWS method while maintaining a high degree of accuracy comparable to bottomhole recorders. The method has the limitation that where gas volume in the annulus changes rapidly with time, bottomhole pressure tends to be underestimated. A modification of the proposed method is suggested to circumvent this limitation.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Technical Conference and Exhibition, September 23–26, 1979

Paper Number: SPE-8279-MS

.../well testing fracture length gas well mhf gas well Upstream Oil & Gas

**Pressure****Buildup****data**drawdown data pressure drawdown Pressure Buildup analysis buildup data real gas pseudo-time type curve hydraulic fracturing shut-in time compressibility dimensionless time reservoir pressure...
Abstract

Abstract A new time function has been defined which considers variations of gas viscosity and compressibility as a function of pressure, which in turn is a function of time. This function appears to be similar to the real gas pseudo-pressure, m(p) of Al-Hussainy et al., which takes into account the variations of gas viscosity and z-factor as a function of pressure. However, this is an approximate function as opposed to m(p). This time function will be referred to in this paper as the real gas pseudo-time, t a(p). This function has aided in pseudo-time, t a(p). This function has aided in post-treatment-pressure buildup analysis of post-treatment-pressure buildup analysis of fractured (including MHF) gas wells by type curve analysis. Results of computer simulated pressure buildup analysis indicate that the use of t a(p) provides satisfactory values of computed fracture provides satisfactory values of computed fracture lengths in fractured gas wells. In this paper the real gas pseudo-time is described and its application is demonstrated by means of example problems. Although the discussion in this paper is limited to pressure buildup analysis of vertically fractured gas wells, the utility of this function is not meant to be restricted to such wells only. Introduction In recent years, type curve analysis methods' have become well known in the petroleum industry for analyzing both pressure drawdown and buildup data in oil and gas wells. These methods are meant to be used in conjunction with the conventional methods whenever possible. Exceptions appear to be MHF gas wells with finite flow capacity fractures where conventional methods are not readily applicable and, at least to date, only type curve methods appear practical to determine fracture length and fracture flow practical to determine fracture length and fracture flow capacity. Although the majority of published type curves, including those for MHF wells, are based on the pressure drawdown solutions for liquid systems, they can be used in an approximate fashion to analyze pressure data from real gas wells. The first requirement is that the dimensionless pressure and time variables are appropriately defined for gas wells. For example, to use the liquid system type curves for an MET gas well, dimensionless variables are defined as follows: Dimensionless pressure, (1) (In SI units, the numerical constant is 128 × 10(-3)) Dimensionless pressure, for a gas well, may also be expressed in terms of Delta (p) or Delta p. Dimensionless time, (2) (In SI units, the numerical constant is 3.6 × 10(-9)) The definition of dimensionless fracture capacity remains the same. (3) Note that in Eq. (1), the real gas pseudo-pressure, m(p) of Al-Hussainy et al. has been used to take into account the variations of gas viscosity and z-factor as a function of pressure. In Eq. (2), viscosity-compressibility (mu c t)i is shown to be evaluated at the initial reservoir pressure. pressure.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the SPE Annual Fall Technical Conference and Exhibition, October 3–6, 1976

Paper Number: SPE-6020-MS

... Upstream Oil & Gas West Texas

**Pressure****Buildup****data**Drillstem Testing fracture length west texas fractured interpretation straight line shut-in time afterflow shut-in pressure wellbore permeability drillstem/well testing buildup test linear flow fracture square root...
Abstract

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract This paper is designed to develop a procedure to analyze pressure buildup curves procedure to analyze pressure buildup curves where radial flow theory does not apply. In a vertically fractured system, which is present in most West Texas carbonate reservoirs, present in most West Texas carbonate reservoirs, flow in the region nearest the fracture is essentially linear, whereas, further out in the formation, radial flow normally prevails. Historically, interwell flow capacity, fracture length, wellbore damage and static pressure have been determined using the late time slope from pressure log time curves. This solution is pressure log time curves. This solution is based on a radial flow model and, as a result, most of the computed reservoir parameters are in error. A set of guidelines are established to allow uniform interpretation of pressure buildup curves and to determine the best workover candidates for fractured oil reservoirs. Field examples representing four basic cases are also presented. presented Introduction The presence of natural or induced fractures will influence the flow behavior in oil reservoirs. In a fractured system, flow in the region nearest the fracture is practically linear, whereas farther away from the fracture, essentially radial flow prevails. Thus, transient pressure analyses based on radial flow theory are incorrect when applied to reservoirs where linear flow predominates. In the past few years, the slope and position of the straight-line portion from position of the straight-line portion from transient pressure vs the logarithm of shut-in time plot has been used exclusively to determine the flow capacity, condition ratio and static pressure for oil wells with natural or induced pressure for oil wells with natural or induced fractures. In most cases, the straight lines used have not been the proper ones. A stable pressure gradient was never reached in these pressure gradient was never reached in these cases; however, equations based on conventional radial flow theory were used. This resulted in the improper calculation of a condition ratio greater than one, of higher than actual interwell flow capacity, and of an improved wellbore condition where, in actuality, wellbore damage might exist. The calculation procedure presented in this paper enables the user to detect the conditions paper enables the user to detect the conditions around the wellbore and aids in determining whether the well is a good candidate for workover.

Proceedings Papers

Publisher: Society of Petroleum Engineers (SPE)

Paper presented at the Fall Meeting of the Society of Petroleum Engineers of AIME, October 3–6, 1971

Paper Number: SPE-3592-MS

... sulfide and the use of recommended safety equipment.

**Pressure****buildup****data**, obtained by wireline,**Pressure****buildup****data**, obtained by wireline, is successfully used to determine stimulation requirements and obtain other reservoir information. Inexpensive corrosion-monitoring techniques are utilized to...
Abstract

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 46th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in New Orleans, La., Oct. 3–6, 1971. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The normally-pressured reservoirs of the Mississippi-Alabama Jurassic Trend are usually produced with allowable rates of 300 to 500 BOPD per well. Gas produced with the oil frequently contains one to four percent hydrogen sulfide. Because of the high producing rates and the presence of hydrogen sulfide, completion and production practices have been designed to provide practices have been designed to provide both a safe and economical method of depletion. A review of these practices is the objective of this paper. In addition to the application of successful completion techniques used elsewhere, an increase in curing time has improved primary cementing. Current cement bond logging practices, which incorporate acoustic scope logging, have eliminated unnecessary squeeze-cementing and have contributed greatly toward reduced completion expense. The placing of acetic acid opposite the productive zone prior to perforating has minimized completion perforating has minimized completion time and reduced pump-in pressures if further stimulation is necessary. Production personnel are thoroughly trained in the hazards of hydrogen sulfide and the use of recommended safety equipment. Pressure buildup data, obtained by wireline, Pressure buildup data, obtained by wireline, is successfully used to determine stimulation requirements and obtain other reservoir information. Inexpensive corrosion-monitoring techniques are utilized to improve equipment design and reduce failures. Introduction The Jurassic Trend of Mississippi and Alabama consists of sandstone and carbonate reservoirs extending southeastward from Jackson, Mississippi. A map of the Jurassic Trend in the Mississippi-Alabama area is presented in Figure 1.