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Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 305–312. Abstract The purpose of this research is to determinethe efficiency of small banks of enriched gas driven by methane in displacing oil from a porous medium and the effects of variation in bank size and composition of that efficiency. Most of the experiments were conducted in a sand-packed tube 20-ft long and 1/2-in. in diameter. The hydrocarbon system generally used was methane, butane and decane at 2,500 psia and 160°F. The results of these experiments indicate that, in the regions contacted by the gas, a small bank of an oil-miscible gas driven by methane can displace all of the oil in a piston-like manner. If the enriched gas is of such composition as to remain immiscible with the oil, displacement of oil is less efficient than for the miscible case, and the gas hank travels through the sand with a velocity less than that of the driving gas. These data along with theories discussed imply that smaller banks and less total gas are required when the enriched gas and oil are miscible. Introduction Widespread application of enriched-gas drive to the recovery of oil rests upon a key factor the use of limited quantities, or "banks", of enriched gas. At the present time, the value of liquefied petroleum gas or other enriching agents discourages their use in a continuous injection technique, or even in a large bank, except in a few isolated reservoirs. If small banks of enriched gas driven by methane were as effective in displacing oil as is continuous injection, the enriched-gas drive process might be applied to a larger number of reservoirs. Previous research on the mechanics of the enriched-gas drive process reported by Stone and Crump and by Kehn, Pyndus and Gaskel has utilized continuous injection of enriched gas. This work has shown that two types of displacements occur. With gases containing sufficient intermediates, the oil is displaced miscibly and complete recovery is obtained from the regions swept. When gases are used which contain insufficient intermediate hydrocarbon for miscible displacement, oil is displaced immiscibly. In the latter type, selective solution of the intermediate hydrocarbons causes a swelling and reduction in viscosity of the oil and leads to an increased recovery over that obtained by dry-gas (methane) drive.
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.69)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.68)
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 313–319. Abstract A new method for obtaining equilibrium vaporization ratios (K-values) for reservoir fluids has been developed and tested. By application of the method, complex experimental measurements of liquid and vapor phase compositions are eliminated. This simplified technique reduces the cost of experimental equilibrium ratio data for reservoir studies of condensates and volatile crude-oil systems. The method is designed for systems of constant composition and, therefore, is best suited for depletion studies where compositional changes at high pressures are minor. The basic data required, in addition to the composition of the initial reservoir fluid, are the relative vapor-liquid volumes and densities at reservoir temperature and various reservoir pressures. Tests demonstrated that the method predicts equilibrium ratios accurately for condensates. A single test on a crude oil was not conclusive; further testing will be necessary before the accuracy of the method can be determined for crude-oil systems. In addition to determining equilibrium ratios, the calculation method provides information on the physical properties of the "plus" component in the vapor and liquid phases. The "plus" component is that mixture of components heavier than the least volatile fraction analyzed. This information is useful in studies of both natural depletion and cycling operations for condensate reservoirs where the heptanes-plus component in the gas phase is produced from the reservoir. Introduction As more volatile oil and condensate reservoirs are found, the use of phase behavior techniques to predict their performance is increasing in importance. These techniques have long been used for condensate fields and have more recently been applied to crude-oil fields containing oils of medium-to-high volatility. In these phase behavior methods, equilibrium ratios (K-values) are used to predict compositional changes in the reservoir fluids-thereby accounting for the recoverable oil that exists in the gas phase. The reliability of the predictions depends to a large extent on the equilibrium ratios used. These values must be obtained for each component for the entire pressure range being investigated.
Published in Petroleum Transactions, AIME, Vol. 219, 1960, pages 223–228. Abstract An experimental investigation has been made of gas-driven slug displacements in a system of high gas saturation to evaluate the process for use in a California reservoir. Fluid compositions, temperature, pressure and core permeability duplicated reservoir conditions as closely as possible. The temperature was above the critical of the slug materials. The slug composition required for 100 per cent oil recovery in the linear flow systems was found to agree with that determined from equilibrium phase studies. A qualitative theory for the slug displacement of two-phase systems is proposed and found to be in general agreement with the observed flow behavior. The theory predicts that the length of the reservoir fluid slug transition zone will increase with increased initial gas saturation and decrease with increased oil swelling accompanying the composition change from reservoir oil to the critical composition. The precipitation of small amounts of an asphaltic phase during the formation of the transition zone had no adverse effects on the Yow behavior of otherwise miscible systems. Introduction Despite the large number of recent publications relating to oil recovery by miscible displacement, little information is available concerning the behavior of crude oil-natural gas systems at conditions likely to be encountered in field application. The laboratory data reported here were obtained during an investigation of the possibility of using a gas-driven LPG slug in a partially depleted California reservoir. Seven gas-driven slug displacements employing slugs of different compositions and sizes were made in 26- to 27-ft long sandstone cores. The equilibrium phase behavior of the systems was also determined.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 288–292. Abstract One of the major difficulties in predicting the performance of oil reservoirs from their early pressure history lies in the uncertainty of estimating the volume of the liquid hydrocarbons contained in them. As a first step in filling this need, an equation was developed to determine the molal liquid volume of pure hydrocarbons over a wide range of temperature and pressure. The second step consisted of adapting the equation to apply to mixtures, with the heavy hydrocarbons expressed as C7+. The equations are similar in form to van der Waals' equation, but the constants a and b are considered as functions of temperature. In addition to the gas constant R, there are four constants characteristic of each hydrocarbon. When compared with experimental values found in the literature, the average absolute deviation in the calculated molal volumes is found to be a maximum of 0.33 per cent for any of the pure liquid hydrocarbons studied. This maximum deviation was that found when comparing the calculated and observed values over a temperature range of 86° to 482°F and a pressure range from the bubble-point to 10,000 psia. The equations expressing the correlation for mixtures were developed from 647 experimental measurements of volume on 47 bottom-hole samples covering a temperature range of 72° to 250°F and a pressure range from bubble-point to 5,000 psig. The average absolute deviation was found to be 1.6 per cent with the maximum for any measurement of 4.9 per cent. Introduction Accurate information of the pressure-volume-temperature behavior of hydrocarbon liquids is of considerable importance in the field of both applied and theoretical science and, especially, in the solution of petroleum reservoir engineering problems. These PVT relationships can be expressed graphically, in tabular form or as equations of state.
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 38–45. Abstract A miscible displacement pilot using a slug of LPG driven by separator gas was conducted in the Cardium reservoir of the Pembina field. The injection pattern was a 10-acre, inverted, isolated five-spot. Upon completion of the LPG-gas phase, an experiment was conducted using a slug of water followed by gas. Calculated performance of the pilot is compared with actual performance. Equations are developed to calculate the distribution of LPG into zones of varying permeability, to estimate the progress of the flood at different times in the various zones and to estimate gas rates after breakthrough. The analysis indicates that permeability stratification was a dominant factor in controlling oil recovery and that oil was completely displaced from the swept pore volume. The results of the pilot indicated that miscible flooding is a practical means of pressure maintenance in this reservoir. The total recovery from the pilot area was good in spite of the early breakthrough of LPG. The effects of stratification were reduced by injecting a slug of water into the partially swept reservoir. Introduction The Pembina field, located in Alberta, is the largest oil field in Canada and one of the largest in the North American continent. The reservoir is a stratigraphic trap producing from the Cardium sand. Neither bottom water nor free gas has been found. The recovery of oil by the natural depletion mechanism has been estimated at 12.5 per cent. Pressure maintenance studies of various areas have indicated that the recovery can be increased 2 1/2 times by water flooding, and a large area of the field is presently under water flood. However, reservoir studies of the North Pembina area indicated that miscible flooding might be competitive with water flooding. A pilot test was conducted to evaluate the performance of a miscible flood.
- North America > Canada > Alberta > Yellowhead County (0.44)
- North America > Canada > Alberta > Wetaskiwin County No. 10 (0.44)
- North America > Canada > Alberta > Ponoka County (0.44)
- (3 more...)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Pembina Field > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Pembina Field > Cardium Formation (0.99)
Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 85–91. Abstract An apparatus and a procedure for determining the viscosity behavior of hydrocarbons at pressures up to 10,000 psia and temperatures between 77 and 400°F are described. The equipment is suitable for measuring viscosity of either the liquid or vapor phases or the fluid above the two-phase envelope for systems exhibiting retrograde phenomena, according to the phase state of the system within these ranges of temperature and pressure. Equations are developed for calculation of viscosity from the experimental measurements, and new data for the viscosities of ethane and propane at 77°F are reported. Introduction With the advent of higher pressures and temperatures in industrial processes and deep petroleum and natural gas reservoirs, demand has increased for accurate values of physical properties of hydrocarbons under these conditions. Proportionately, more frequent occurrence of natural gas and condensate-type fluids is encountered as fluid hydrocarbons are discovered at greater depths. This increases the importance, to the reservoir engineer, of being able to predict accurately the physical properties of light hydrocarbon systems in the dense-gas and light-liquid phase states. Reliable gas viscosity data are limited primarily to measurements made on pure components near ambient temperature and at low pressures. Few investigations have been reported for high pressures, and except for methane, data on light hydrocarbons are subject to question. This is demonstrated by the large discrepancy between sets of data on the same component reported by different investigators. For mixtures in the dense gas and light liquid regions and for fluids exhibiting retrograde behavior there are very few published experimental data. Viscosity data for methane have been reported by Bicher and Katz, Sage and Lacey, Comings, et al, Golubev, and Carr, with good agreement among the last three sets of data. Comings, Golubev and Carr utilized capillary tube instruments for which the theory of fluid flow is well established. The theory permits calculation of the viscosity directly from the experimental data and dimensions of the instrument alone.
- North America > United States > Texas > Permian Basin > Central Basin > Brown Field (0.89)
- North America > Canada > Alberta > Smith Field > Am Eagle Et Al Smith 15-7-71-24 Well (0.89)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.66)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.47)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.41)
Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 55–64. Introduction Results of experimental work on the in situ combustion process were first published in this country in 1953 when Kuhn and Koch described results of a three-well test in Jefferson County, Okla. Shortly thereafter Grant and Szasz described field studies in Nowata County, Okla., in which several modifications of the basic combustion process were investigated by injection of various oxidizing gas mixtures other than air. In the past five years speculation concerning this method of oil recovery has continued, with a number of interesting papers on various aspects of in situ combustion appearing in the literature. However, only one of these provided actual engineering information on pattern-type field experiments. The primary objectives of the Oklahoma three-well test were to check operation of specially designed electrical ignition equipment and evaluate problems associated with initiation of combustion in a natural oil sand reservoir. Immediately following successful completion of this test in the Pontotoc sand, plans were activated for a second field experiment to be conducted in the same sand a short distance away. The objective of this second field test was to establish a relationship between field observations and information derived from laboratory experimentation and computations. Secondary objectives of the test were to develop operating techniques and define operating problems, and to obtain information that would assist in the economic and engineering appraisals of the process. Careful planning was required since this test was designed with the hope of providing basic information on the characteristics and operation of a combustion drive. It was necessary to include test facilities which would not only permit precise control and measurement of the process variables but would also provide sufficient flexibility of control to insure the course of the test under a wide range of conditions. In order to accomplish these objectives elaborate instrumentation and several control wells were included in the design of the test installation. This type installation was felt to be well suited for an experimental study, but was in no respect intended as a counterpart of a commercial-scale operation.
- North America > United States > Texas > Dawson County (0.40)
- North America > United States > Oklahoma > Jefferson County (0.24)
- Geology > Petroleum Play Type (0.35)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.34)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.94)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (0.91)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.87)
Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 23–25. Abstract A correlation is presented for predicting the viscosity of gas-saturated crude oils under reservoir conditions. It is based on the dead oil viscosity and the solution GOR. The correlation was developed from a study which showed that at a fixed solution GOR, the relation between the gas-saturated oil viscosities and the corresponding dead oil viscosities is a straight line on logarithmic coordinates. Data from 457 crude oil samples from the major producing areas of the U.S., Canada and South America were used. The best straight lines through the data were fitted by the method of least squares with a digital computer. The correlation is presented in the form of an equation and also in a convenient graphical form. Introduction The viscosity of gas-saturated crude oils under reservoir conditions is an important physical property used in reservoir engineering calculations. Many difficulties are inherent in the sampling of gas-saturated oils and in the laboratory measurement of their viscosities. Therefore, it is frequently neither possible nor convenient to obtain measured values, so the viscosity must be estimated from other, more readily available data. This paper presents a correlation for predicting the viscosity of gas-saturated crude oils. The correlation is based on the amount of gas in solution and the viscosity of the dead oil at the temperature of interest. A previous correlation of these variables was presented by Bear. In comparison, the correlation presented here extends to a higher GOR and to a lower dead oil viscosity. Over the range of variables covered by both, this correlation is based on approximately 11 times as many oil samples. Development of Correlation A study was made of the variables or parameters which could be used to relate the viscosity of a gas-saturated oil to its dead oil viscosity. Preference was given to those variables which are easily and commonly measured in the field or in the laboratory. It was found that either the differential liquid formation volume factor or the solution GOR of the gas-saturated oil could be used as a correlating parameter. The solution GOR was selected for the correlation because of its simplicity and availability.
- North America > United States > Texas (0.29)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 310–315. Introduction Many differences can be imagined between gas-oil flow in which the gas is supplied at the face of the core and gas-oil flow in which the flowing gas was originally dissolved in the oil. If capillary pressure characteristics and flow requirements control gas saturation distribution, the gas would be expected to be located at preferred sites within the porous medium as determined by pore sizes. On the other hand, during solution gas drive the gas first appears as bubbles through a nucleation process. Nothing in self-nucleation theory specifies at which sites the first bubbles should be formed. In all probability they will be randomly distributed throughout the porous medium. Furthermore, it is not at all certain that even at low rates of production the gas will redistribute itself after nucleation to the channels normally occupied by gas in simple gas flow. Stewart, et al, have shown that at least for some limestone samples, oil recoveries could not be predicted for all rates of production using anyone set of relative gas and oil permeabilities. An important factor in controlling recoveries during solution gas drive was the rate of bubble formation, higher rates giving higher recoveries. Stewart, et al, attributed the increase in recovery to a better distribution of the gas phase in heterogeneous limestone samples than is obtained by simple external gas drive. Differences in recovery from these causes were not reported for sandstone cores. In the experiments to be reported here, oil recovery, pressure and producing GOR history were measured during solution gas drive for a 5-ft sandstone core. The results were compared with predictions from the Muskat method for computing solution gas-drive behavior using external gas-drive relative permeability. The effects of changing the rate of production and oil viscosity were studied. At high laboratory rates of average pressure decline, two observations were made which would not have been predicted by Muskat's depletion theory:oil recovery increased with increasing rate of production for a given viscosity oil, and oil recovery increased with increasing oil viscosity for a given high rate of production. Both of these observations are explained as consequences of diffusion control of gas saturations superimposed on the normal gas-oil flow requirements.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.45)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.45)
- North America > United States > Wyoming > Hunt Field (0.93)
- North America > United States > Illinois > Berry Field (0.93)
Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 292–303. Abstract For many years the author has been cognizant of the difficulty encountered by some in treating with the water influx formulas for unsteady-state fluid flow as pertain to the material balance equation. This has particularly applied in establishing reservoir performance and identifying reservoir pressure, which to the practicing engineer has entailed a trial-and-error procedure, and for others has necessitated resorting to computing devices and reiteration processes. In retrospect this difficulty stems from the fact that reservoir pressure in the material balance formulas, as well as associated with the water influx equations, is an inexplicit term, and the work reported in the past is irrefutable. However, what will be presented in this paper is another approach to the problem, whereby the entire material balance equation will be treated by the Laplace transformation, and reservoir pressure which hereto has been inexplicit, can now be isolated by mathematical procedure to relate that parameter with all the factors contributing to its change. This is the simplification entailed, that treats first with an undersaturated oil reservoir as an integrated effect from the inception of production. The second phase pertains to saturated oil reservoirs that encompass a survey traverse. Although both methods of approach are necessarily different in aspect, the most interesting fact is that the mathematics so deduced are identical. Both the linear and radial water-drive systems are incorporated, for which an illustrated factual example is offered for the latter, treating with a saturated oil reservoir. Introduction What is performed in this work is the simplification of an involved computation by advanced analysis. Although such may be construed as a contradiction when one treats with higher mathematics; nevertheless, when direction is given to such an undertaking the results can be most revealing. Likewise, it is to be mentioned that the bases for these mathematics have been developed on the expediency of the occasion. This is not to be inferred as a qualification of this work, but rather the demands frequently placed upon the author in his private practice in meeting a time limit. A situation, instead of being fraught with hazards, often has given emphasis to creative thought.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)