New correlations for density of methane-free sodium chloride brine and solubility of methane in sodium chloride brines, valid over wide ranges of pressure, temperature, and salinity, are presented. Both correlations agree with the best available measurements within experimental error over most of the range of validity. These new correlations are combined with published correlations for methane partial molar volume to provide accurate and internally consistent estimates of brine density, specific volume, formation volume factor, and coefficient of isothermal compressibility at pressures above or below the bubble point pressure. The brine density correlation is valid for temperatures from 0 to 275 ° C (32 to 527 ° F), pressures from 0.1 to 200 MPa (14.5 to 29,000 psi), and sodium chloride content from 0 to 6 moles/kg H2O (0 to 26﹪ by weight). The methane solubility correlation is valid for temperatures from 20 to 360 ° C (68 to 680 ° F), pressures from 0.9 to 200 MPa (130 to 29,000 psi), and sodium chloride content from 0 to 6 moles/kg H2O (0 to 26﹪ by weight). A modification of an existing correlation for brine viscosity is also presented, extending its range of applicability to temperatures between 20 and 300 ° C (68 to 572 ° F), pressures between 0.1 and 200 MPa, and salinity between 0 and 5.4 moles NaCl/kgH2O (0 to 25﹪ NaCl by weight). Introduction Oil companies today produce in excess of 33 million cubic metres of water per day (210 MMbbl/day). The associated cost of handling this water production is estimated to exceed $40 billion per year(1). Understanding and dealing with these costs requires accurate knowledge of the water properties. Properties such as density, viscosity, and solubility affect the volume and movement of water through the reservoir, in the well bore, and at the surface facilities. As water production continues to increase, so does the importance of our understanding of the properties of the produced water. Many experimental studies of the behaviour of systems comprising water, sodium chloride, and methane have been reported in the physical chemistry literature during the last 25 years. By and large, the results of these studies have not been widely disseminated within the petroleum engineering community. In this paper, we present new correlations based on the published data for estimating those properties of primary interest to the petroleum engineer, namely the density, specific volume, methane solubility, formation volume factor, coefficient of isothermal compressibility, and viscosity. The next two sections of the paper discuss the development of the new brine density and methane solubility correlations. The third section shows how the brine density and methane solubility correlations may be combined with previous work to calculate internally consistent values for reservoir brine density, specific volume, coefficient of isothermal compressibility, and solution gas-water ratio at pressures above or below the bubble point pressure. The final section presents a modification of a published brine viscosity correlation, extending its range of applicability to temperatures of 300 ° C (572 ° F) and pressures of 200 MPa (29,000 psi).

Pressure Transient Testing presents the fundamentals of pressure-transient test analysis and design in clear, simple language and explains the theoretical bases of commercial well-test-analysis software. Test-analysis techniques are illustrated with complete and clearly written examples. Additional exercises for classroom or individual practice are provided. With its focus on physical processes and mathematical interpretation, this book appeals to all levels of engineers who want to understand how modern approaches work.

An algorithm has been developed for computing the pressure response for a well with constant wellbore storage and non-Darcy skin factor across the completion. The algorithm has been used to generate type curves for drawdown and buildup tests. The builduppressure-derivative response for a well with non-Darcy flow across the completion exhibits a much steeper slope during the transition out of wellbore storage than that of a well with constant skin.No reservoir model with constant wellbore storage and skin can reproduce this steep derivative. Thus, if it is present in a buildup test, the well is experiencing either decreasing wellbore storage or decreasing skin factor, or both.With the new type curves, under favorable conditions, both Darcy and non-Darcy skin components may be estimated from a single buildup test following constant-rate production. The new algorithm also may be used to model a test sequence comprising multiple flow and buildup periods. IntroductionNodal production-system analysis 1 is one of the primary tools for optimizing production and predicting well performance. In nodal analysis, reservoir performance is described through the inflowperformance-relationship (IPR) curve. To construct accurate IPR curves for gas wells, both Darcy and non-Darcy skin components must be known.The non-Darcy skin is traditionally estimated by performing a multirate test. The effective skin factor is then graphed as a function of flow rate, allowing the Darcy and non-Darcy components to be determined from a straight-line fit through the data.When multirate tests are not available, the non-Darcy flow coefficient may be estimated from correlations. However, the resulting values may be in error by as much as 100%. 2 The behavior of a pressure-transient test with infinite-acting radial flow with constant wellbore storage and skin factor is well known. 3,4 Other authors have considered the case of variable wellbore storage with constant skin factor. 5,6 This paper examines the behavior of a well with constant wellbore storage and rate-dependent skin factor for drawdown and buildup tests. Buildup tests with non-Darcy skin factor exhibit a much steeper pressure derivative during the transition out of wellbore storage than those with Darcy skin factor, as seen in Fig 1. The new type curves provide three significant contributions to the industry: (1) they allow the test analyst to recognize non-Darcy flow from a log-log diagnostic plot of pressure change and pressure derivative; (2) they provide estimates of both Darcy and non-Darcy components of skin factor from a single buildup test, allowing construction of IPR curves based on well performance instead of correlations; and (3) they help identify the cause of high skin factors.High-rate wells with high skin factors represent excellent candidates for stimulation. 7,8 However, because of the risks involved in any workover, there often is a reluctance to stimulate such a well. Given that high-rate wells are the ones most likely to exhibit non-Darcy skin, the new type curves will...

J.P. Spivey* and M.E. Semmelbeck* Abstract A procedure is presented which allows forecasting long range performance of dewatered coal and fractured gas shale reservoirs having nonlinear adsorption isotherms, using constant pressure solutions to the flow equation for slightly compressible liquids. A correlation is presented to show the range of applicability of this procedure. Introduction Production decline curves are routinely used by engineers to predict the future performance of oil and gas wells. Because the results of decline curve predictions are used for calculating asset value and estimating future revenue, they are one of the most important tools reservoir engineers use. There are numerous variations on the basic exponential or hyperbolic decline analysis method. Fetkovitch and others have extended the decline curve analysis method to handle gas wells properly and to be able to estimate reservoir properties from the analysis of these data. However, there has been considerable drilling activity in the last 10 years into unconventional reservoirs whose wells do not follow the traditional production decline characteristic shapes. Among these problem reservoirs are coalbed methane and fractured shale reservoirs. Two factors complicate the prediction of future gas production rates in many coalbed methane and fractured shale reservoirs such as the Devonian Shale of the Appalachian Basin, the Antrim Shale of Michigan and the New Albany Shale in Indiana. The first factor common in Antrim and New Albany reservoirs is high initial water saturation and essentially zero gas flow rate at the beginning of production. The second factor common to all fractured gas shales is desorption of gas from organic material within the reservoir rock. Both of these factors can result in well behavior that is not properly predicted by conventional decline curve methods. Because of the complex production behavior of coalbed methane and fractured gas shale wells, the best way to predict performance is to use a numerical reservoir simulator which accounts for all of the mechanisms occurring during production. However, use of reservoir simulation may not be practical for all situations, particularly when many wells must be analyzed rapidly or when reservoir simulation is not available. This paper presents a rapid analytical solution that can account for production from reservoirs undergoing desorption. One extension of this method over others presented in the literature is that it accounts for nonlinear Langmuir sorption isotherms. P. 359