A knowledge of the average reservoir pressure ( p ¯ ) and its changes as a function of time or cumulative production is essential to determine the oil-in-place (OIP) or original gas-in-place (OGIP), to estimate reserves and to track and optimize reservoir performance. The common practice of determining p ¯ in moderate permeability reservoirs has been to run pressure buildup tests. In the current economic environment, buildup tests are almost non-existent except for very expensive exploratory wells. Moreover, time required for a pressure buildup test to reach p ¯ in low permeability reservoirs is prohibitively long. Fortunately, flowing pressures and rate data are continually collected from oil and gas wells. Data quality and quantity is usually good especially from wells installed with permanent pressure gauges. Such data for gas wells is currently being analyzed by assuming OGIP and estimating p ¯ required for calculating pseudo time. This is done in an iterative manner for using advanced decline curve analysis methods. The purpose of this paper is to discuss a new finding that will enable direct estimation of p ¯ using flowing pressures and rate data obtained from oil and gas wells during the pseudo steady-state flow period. In theory, pseudo steady-state flow requires that a well is produced at a constant rate. However, this limitation can be easily removed based on the work published in the SPE literature by this author and others whereby variable rate data can be converted to constant rate production data. The significance of the subject paper is that it will permit: a) direct determination of p ¯ using flowing wellbore pressures and rate data thus facilitating estimates of OGIP and OIP, b) estimation and/or validation of the value of the initial reservoir pressure ( p i ), which is normally suspect, and finally, c) enhancement or possible elimination of the current iterative process used for determining OGIP by advanced decline curve analysis methods.

Abstract This paper presents new production decline curves for analyzing well production data from radial and vertically fractured oil and gas wells. These curves have been developed by combining Decline curve and Type curve analysis concepts to result in a practical tool which we feel can more easily estimate the gas (or oil) in place as well as to estimate reservoir permeability, skin effect, fracture length and conductivity, etc. Accuracy of this new method has been verified with numerical simulations and the methods have been used to perform analyses using production data from several different kinds of gas wells. Field and simulated examples are included to demonstrate the applicability and versatility of this technology. Decline curve analysis methods, in a variety of forms, have been used in the petroleum industry for more than fifty years to analyze production data and forecast reserves. Type curve analysis methods have become popular, during the last thirty years, to analyze pressure transient test (e.g. buildup, draw-down) data. Pressure transient data can be costly to obtain and may not be available for many wells, while well production data is routinely collected and is even available from industry data bases. In the absence of pressure transient data, a method that cause readily available well production data to perform pressure transient analysis would be very beneficial. The result is the development of these new production decline type curves. These new production decline type curves represent an advancement over previous work because a clearer distinction can be made between transient and boundary dominated flow periods. The new curves also contain derivative functions, similar to those used in the pressure transient literature to aid in the matching process. These production decline curves are, to our knowledge, the first to be published in this format specifically for hydraulically fractured wells of both infinite and finite conductivity. Finally, these new curves have been extended to utilize cumulative production data in addition to commonly used rate decline data. P. 585

Abstract To fully develop producing acreage in low permeability gas plays, infill reserves must be permeability gas plays, infill reserves must be assessed and development areas rust then be identified. Currently in Texas, at least 25 Major tight gas plays have been recommended for tight gas formation designation to the Federal Energy Regulatory Commission, and at least 10 of these have been approved for incentive gas pricing. In the East Texas Basin alone, there are at least 10 major field areas in a tight gas sand play. All of these plays and fields within them will require study to determine the feasibility of infill development. A technique for selecting potential infill locations is outlined below. Critical reservoir and fracture parameters are investigated by determining each parameter's effect on the incremental reserves from an infill well. The most important parameters are: formation flow capacity, hydrocarbon pore volume, fracture length, and pay continuity. These parameters are used to obtain simulated rate data for well groups from a tight gas reservoir simulator. Recoverable gas is determined from a plot of the simulated data as scalar curves relating well rate and cumulative production data to tine, normalizing the curves to the above critical parameters. Potential infill reserves are assessed for East Texas Cotton Valley wells using the results from the above curves in an expression for incremental infill reserves. The variation of incremental reserves with fracture length for varying permeabilities is investigated to obtain an economic limit on incremental reserves for a general area and to deter-mine the range of permeabilities justifying reduced well spacing. This two-well analysts approach assumes separate, non-interfering drainage blocks and may introduce error in high permeability areas. Moreover, this analysis technique assumes no time delay in drilling the infill well on a unit. Static pressure measurements in the first infill wells must be obtained to evaluate potential interference as well as gain experience in potential interference as well as gain experience in drainage radii for the original wells on a unit. Introduction The development of low permeability reservoirs such as the East Texas Cotton Valley Sand has reached a critical point in many field areas. Further field development is limited to drilling on reduced well spacing. Currently, field rules for most areas in the play require initial development on 640-acre gas units. However, in some fields, reduced well spacing to 320 acres has been accepted and, in many cases, improperly applied. Because field rules may further reduce required well spacing to 160 acres or less, a method for prudently selecting potential infill locations is necessary. potential infill locations is necessary. The technique utilizes a tight gas reservoir simulator to obtain rate and cumulative production data for a group of tight gas wells. The production data for a group of tight gas wells. The data is then normalized to critical fracture and reservoir parameters, and recoverable gas is determined graphically from a plot of the normalized rate and cumulative production data with time.

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.

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.