Viscosity values of crude oils and crude oils containing dissolved natural gas are required in various petroleum engineering calculations. In evaluation of fluid flow in a reservoir, the viscosity of the liquid is required at various values of reservoir pressure and at reservoir temperature. This information can be obtained from a standard laboratory PVT analysis that is run at reservoir temperature. There are cases, however, when the viscosity is needed at other temperatures. The most common situation requiring viscosities at various pressures and temperatures occurs in the calculation of two-phase, gas-liquid flowing pressure traverses. These pressure traverses are required in tubing-string design, gas-lift design, and pipeline design. Calculation of these pressure traverses involves dividing the flow string into a number of length increments and calculating the pressure gradient at average conditions of pressure and temperature in the increment. Calculation of pressure and temperature in the increment. Calculation of pressure gradients requires knowledge of oil viscosity. In pressure gradients requires knowledge of oil viscosity. In many cases, the only information available on the fluid properties are the separator gas gravity and stock-tank oil properties are the separator gas gravity and stock-tank oil gravity; therefore, correlations requiring a knowledge of crude oil composition are not applicable.The most popular methods presently used for predicting oil viscosity are those of Beal for dead oil and Chew and Connally for live or saturated oil. Beal correlated dead oil viscosity as a function of API gravity and temperature. Chew and Connally presented a correlation for the effect of dissolved gas on the oil viscosity. The dead oil viscosity and the amount of dissolved gas at the temperature and pressure of interest must be known. pressure of interest must be known. When these correlations were applied to data collected for a study of dissolved gas and formation volume factor, considerable errors and scatter were observed. These data, therefore, were used to develop new empirical correlations for dead or gas-free crude oil as a function of API gravity and temperature, and for live oil viscosity as a function of dissolved gas and dead oil viscosity. A description of the data used, which were obtained from Core Laboratories, Inc., is given in Table 1.The correlation for dead oil viscosity was developed by plotting log 10 (T) vs log 10 log 10 (mu OD + 1) on cartesian plotting log 10 (T) vs log 10 log 10 (mu OD + 1) on cartesian coordinates. The plots revealed a series of straight lines of constant slope. It was found that each line represented oils of a particular API gravity. The equation developed is =, ........................(1) where X = y = Z = The correction of the dead oil viscosity for dissolved gas was developed by taking advantage of the fact that a linear relationship exists between log 10 mu OD and log 10 mu for a particular value of dissolved gas, Rs. Live oil viscosity may be calculated from = ...........................(2) TABLE 1 - DESCRIPTION OF DATA USED Variable Range Solution GOR, scf/STB 20 to 2,070 Oil gravity, API 16 to 58 Pressure, psig 0 to 5,250 Pressure, psig 0 to 5,250 Temperature, F 70 to 295 Number of oil systems - 600 Number of dead oil observations - 460 Number of live oil observations 2,073 P. 1140

This paper discusses the analyses of transient pressure data that has been measured during single well test and multi-well interference tests performed in wells producing gas and water from coal seams of the Fruitland Formation of the San Juan Basin of Colorado. The test procedures included open hole drill stem tests, cased hole water injection tests, open hole production tests, multi-well interference tests, and post-cavitation production and shut-in tests. Proper evaluation of the pressure behavior measured during each type of test resulted in similar estimates of the absolute permeability of the coal gas reservoir natural fracture system.Evaluation of post-cavitation well test data has not been presented in the literature prior to this paper. The analysis results are shown to be accurate by agreement with reservoir simulation and multi-phase interference test analysis results. Analysis of Coal Gas Reservoir Interference and Cavity Well Tests SPE 25860prior to cavitation. A pre-cavitation interference test was performed by producing the I #2 well and measuring the pressure response at the GRI #1 and GRI #2 locations. The interference test was repeated after cavitation to evaluate changes that may have occurred due to the completion process and additional production.

The U.S. Steel Research Laboratory employs a system of logging and describing coal drill-core samples which provides a permanent record of the lithologic variations in a coal bed. This paper outlines the procedure used for the megascopic description of coal drill-core sample.

Acidization of sandstones to improve permeability is a complex process. Linear coreflood acidization in a laboratory environment is useful in developing an experimental understanding of the process. Numerical simulation which incorporates the basic scientific principles of fluid mechanics in porous media and the principles of fluid mechanics in porous media and the reaction rate kinetics of sandstone acidization can provide a valuable interpretive aid for understanding provide a valuable interpretive aid for understanding the total process. Adjustment of model parameters so that laboratory experiments may be emulated is analogous to pressure history matching models to time-dependent field pressure response. once model parameters are correctly adjusted, the model provides a parameters are correctly adjusted, the model provides a predictive tool for estimating acidization results at predictive tool for estimating acidization results at other flooding rates and acid strengths. The purpose of this discussion is threefold:to describe the development of a numerical model containing variable porosity (with time and distance),to describe constraints other than the acid response coefficient (ARC) curve for insuring concert between the model and experimental results, andto describe laboratory measurements of the emerging core effluent and the corresponding pressure drop across the core with injection time. In conjunction with these three objectives, we will present some experimental results of our own. present some experimental results of our own Introduction A popular method for estimating the effect of acid stimulation of a permeable sandstone matrix is to subject a linear core to a floodwater containing mud acid (hydrochloric-hydrofluoric acid mixture) and record the resulting diminution of pressure drop across the core as a function of time. This particular type of core-flood is performed at a constant injection rate so that after the flood is completed one can convert the pressure drop to permeability by calculation using Darcy's pressure drop to permeability by calculation using Darcy's Law. Dividing the calculated permeability at various points in time by the initial permeability provides a points in time by the initial permeability provides a measure of the acid's effectiveness. This effectiveness is commonly referred to as the acid response coefficient (ARC). The ARC curve is the gross response of the porous reservoir rock to the flowing acid. The scientific basis for this response is a complex combination of chemical reactions and their equilibria superimposed on fluid flow through porous media. In addition to the simple mechanics of developing an ARC curve, there are other items of general importance which have a bearing on the reliability of this measurement. To initiate the flood, several pore volumes of hydrochloric acid are usually injected as a "spearhead." The hydrochloric acid dissolves all exposed carbonate and dolomite intergranular cements and prevents later formation of calcium fluoride. Calcium prevents later formation of calcium fluoride. Calcium fluoride is an insoluble precipitate which can plug the core. The hydrochloric acid forms an in situ environment high in hydrogen ions which is advantageous to the reaction kinetics of hydrofluoric acid with clays and feldspars. A third advantage of the hydrochloric acid "spearhead" and continued simultaneous injection with the hydrofluoric acid is that the solubility of sodium and potassium fluorosilicates is increased. These chemical species are reaction products which may also cause core plugging. products which may also cause core plugging. Within the last several years, acidizing technology has become more sophisticated. The scientific bases of chemistry and fluid mechanics have been combined to provide an analytic model. Much of this work was performed at Chevron Oilfield Research in collaboration with engineers from the University of Michigan. It is this fundamental work which provides the basis for the numerical simulation model described here. Lund and Fogler provide an analytical solution to a coupled set of partial differential equations, assuming a constant porosity for the porous matrix during the acidization process. The numerical model developed here allows extension of the analytic model so that a time and distance variant porosity may be included. Once the basis for the model is derives, the development of concert between the model and the measurements will be discussed. Finally, the important features of coreflood effluent measurements will be discussed along with experimental measurements performed on a sandstone reservoir core. performed on a sandstone reservoir core.

The reliability and relative merits have been estimated for three recently published multiphase-flow pressure-drop prediction correlations applicable to vertical tubing. Data from 726 tests, embracing broad ranges of flow rate, pipe size, API gravity, gas/liquid ratio, and water/oil ratio were used in the evaluation. It was found that no single correlation consistently performed best in every range. Introduction Six of the several correlations available for predicting pressure losses during simultaneous, predicting pressure losses during simultaneous, continuous, steady-state flow of oil, water, and gas in vertical pipes were evaluated statistically by Lawson and Brill. Three more promising correlations have recently been published - those of Beggs and Brill Aziz et al. and Chierici et al. The purpose of this paper is to extend the work of Lawson and Brill to cover the new correlations.Details of the three new methods can be found in the original sources listed in the references. The same flowing pressure surveys and related data for 726 field and experimental wells were used as were reported by Lawson and Brill. Fluid physical properties were estimated using the same correlations as employed by Lawson and Brill.Although every attempt was made by Lawson and Brill to screen data in the data bank, no doubt some questionable data have been included. In a study such as this, the quality of the data is critical. It has been found, for example, that small errors in measured gas volumes and oil formation volume factors can significantly affect the calculated results. A valid criticism of the bank is that inadequate use was made of what limited measured PVT data were available. Another possible criticism is that many of the data used were gas-water data with low gas/water ratios, a situation seldom found in practice. No claim was made that the gas-water data were meant to represent gas well production. Rather, these data are extremely valuable because of the absence of mass transfer between phases and the resulting improved accuracy of, for phases and the resulting improved accuracy of, for example, predicted in-situ phase velocities.All three of the correlations were developed from two-phase flow data, one of the phases being gas. A third phase (water) can be included if we assume that its presence does not change the physical phenomena of two-phase flow. Possible changes that could invalidate results are slippage between oil and water, formation of emulsions, and the influence of water on gas bubble coalescence and the formation of gas slugs. The degree to which such changes are present in the three-phase data is unknown.We applied the three correlations to all data, knowing full well that many of the data were beyond the range of variables used to develop the correlations. However, correlations are frequently used indiscriminately beyond their stated ranges of validity. Therefore a test of their performance over a broad range of data is of value. Validation of Programming Pressure losses calculated by a computer program of Pressure losses calculated by a computer program of each method were compared with the corresponding pressure losses reported by each author for identical pressure losses reported by each author for identical well cases. This comparision indicated the degree of agreement between the results of the two programs. JPT P. 829