Drive Gas Reservoirs Research Articles

Water Drive Gas Reservoirs: Uncertainty in Reserves Evaluation From Past History

Abstract The use of the material balance equation to estimate the volume of hydrocarbons originally present in a reservoir, whose producing mechanism is partly due to water drive, has been discussed in the literature by several authors. There is no general agreement upon the possibility of obtaining reliable results by this method. Gas reservoirs in contact with an active aquifer are considered in this paper. Theoretical considerations based on the cybernetic principle of uncertainty (which states that the internal structure of a system cannot be uniquely determined from its observed external behavior) lead to the conclusion that the volume of gas originally present in a reservoir of this type cannot be uniquely determined from its past history. The range of values which encompasses the actual value of the reserves varies from case to case and must be determined by either numerical or analogical methods. Results obtained for six gas fields are reported. All these fields were produced with small fluctuations in their production rates, as is common practice for gas reservoirs; no gas storage fields were considered. Results obtained show that reserves values in a range of 1 to 2, associated with appropriate aquifers, allow the matching of the reservoir past history with mean-square deviations less than the experimental errors involved in pressure and production measurements. Similar results have been found in several other partial water drive gas reservoirs. From these results it is concluded that gas reserves cannot be uniquely determined from the past performance of partial water drive reservoirs, at least in cases where the reservoir has been submitted to small fluctuations in the production rates, and pressure data of normal accuracy are available. Introduction A number of authors have analyzed the problem of estimating the reserves originally present in a partial water drive reservoir from its past pressure-production performance. Literature which deals with this subject can be grouped, according to their conclusions, as follows. A reliable value for the reserves can be obtained even if reservoir data (pressure and cumulative production) are affected by errors within the normal range. A reliable value for the reserves can be obtained only if reservoir data are very accurate or if past production performance has been subjected to abrupt variations in the production rate. No unique value for the reserves can be obtained from reservoir past production performance. This conclusion has been based upon theoretical considerations and verified in several field cases. The purpose of this paper, which deals only with partial water drive gas reservoirs, is to test the above conclusions against actual field cases. Some theoretical considerations on this problem are also presented. THEORETICAL CONSIDERATIONS As the behavior of a gas reservoir communicating with an aquifer depends on both the aquifer and the reservoir characteristics, the physical system to be studied is the combined gas reservoir plus aquifer. The information which is available for studying the performance of such a system is the well production rates and bottom-hole pressures, all given as functions of time. The external behavior of the reservoir-aquifer system is therefore described by 2n input variables (Gpj, Wpj) and n output variables (pj), n being the number of wells in the reservoir. In reservoir engineering it is common practice to consider the reservoir as a whole, disregarding the internal distribution of pressures and of producing wells. This practice is equivalent to substituting the above multivariable system with a single-variable system, where the average reservoir pressure is the only output variable and the cumulative production Gp(t) and Wp(t) are the input variables. The internal structure of such a system, defined by initial gas reserves G, aquifer shape and dimensions, boundary conditions and petrophysical parameters distribution throughout the aquifer, is unknown. Therefore, from a cybernetic point of view the system is a "blackbox". It has been demonstrated that for a black box the indetermination principle holds. Accordingly, the number of different internal structures (or set of parameters) which can account for the observed external behavior is infinite. As a consequence, the initial reserves cannot be uniquely determined from the reservoir past performance. JPT P. 237ˆ

An Analysis of Large-Scale Flooding in the Fractured Spraberry Trend Area Reservoir

Introduction The Spraberry Trend oil reservoirs, producing from a very tight fractured sand, have been characterized by a rapid decline in reservoir pressure and oil producing rate and by production of only a small fraction of estimated original oil in place. Almost all original areas of development are now in the stripper stage or have been abandoned. Although it was considered unlikely that this solution gas-drive reservoir would lend itself readily to conventional methods of secondary recovery, a great deal of effort has been devoted to developing techniques which would utilize the unusual characteristics of the reservoir rock and its fracture system to increase ultimate oil recovery. A single five-spot pilot water flood was initiated in the west central portion of the Spraberry Trend Area reservoir during March, 1955. A combination analytical and numerical method employing high-speed computing equipment was utilized to analyze results of this pilot flood. With field behavior as the criterion for the analysis, orientation of the major fracture system, ratio of the permeability parallel and perpendicular to this trend, and relationship of the observed recovery from the center producing well of the pilot flood to that which might be achieved under large-scale flooding operations were determined. Information developed during analysis of the pilot water flood was then used to develop a flooding program for a 40-section area in the western portion of the field. From this work, it was concluded that the analysis procedure has considerable utility in analyzing flooding operations in a fractured reservoir and a relatively high pattern efficiency can be achieved in the area studied if the proper flooding pattern is chosen. Attempts to Develop Recovery Techniques The first attempt to develop a new recovery technique was a process designed by The Atlantic Refining Co. to utilize the principle of water imbibition. Laboratory work and the subsequent field trial demonstrated that water injected into the fractures could be imbibed spontaneously into the matrix rock by capillary action with the concurrent expulsion of oil into these same channels from which it could be produced by the surrounding wells. The second example of the research effort to increase oil recovery was work performed by Humble Oil and Refining Co. It was determined that with an intensive and inter-connected system of fractures, water injected into the formation could flood simultaneously a large number of matrix blocks. Water invading the matrix with the concurrent discharge of oil into the fractures would rapidly increase oil content and reduce water content of the effluent in the fractures moving toward the producing wells. To evaluate the potentialities of this type flood, a single five-spot pilot water flood was put into operation March 8, 1955.

Estimation of Ultimate Recovery from Solution Gas-Drive Reservoirs

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 132–138. Introduction In the past few years several articles and papers presenting results of solution gas-drive depletion calculations have appeared in the literature. Such calculations are of interest to the oil industry, for investment decisions must often be made before much is known about a reservoir. At other times, an estimate of the possible benefits to be realized from alternate production methods is desirable, and theoretical depletion calculations can serve as a floor or reference level from which to work. In any case, an estimate of ultimate oil recovery based upon engineering data is commonly required. An engineer confronted with the problem of obtaining, for a specific reservoir system, an estimate of ultimate oil recovery by solution gas-drive depletion usually will be forced to perform the calculations himself. This is despite the quantity of data in the literature. Rarely will either experience or the literature provide results from a reservoir system similar in all important respects to the one under consideration, and calculated results are not so plentiful that satisfactory interpolation procedures can be devised. Performing the calculations, however, is a tedious, time-consuming task unless an electronic computer is available, and, in practice, time and manpower are not always available for this purpose. A quick, simple, consistent method was needed for reducing the uncertainty in estimated oil recovery from solution gas-drive reservoirs when only minimum information about the reservoir system is available. Procedure Method of Calculation The usual requisite assumptions were made so that the material balance equation could be used to calculate data for the charts. The following assumptions were made:the reservoir is homogeneous and isotropic;oil recovery is due entirely to solution gas drive and neither a gas cap nor a water drive nor gravity drainage is present;the initial reservoir pressure is the bubble-point pressure of the reservoir fluid;initial total liquid saturation is 100 per cent of pore space;interstitial water saturation remains at the initial value as the reservoir pressure declines from the bubble-point pressure to atmospheric pressure;equilibrium gas saturation is 5 per cent of pore space; andoil and gas saturations are uniformly distributed throughout the reservoir at all times. There are no saturation gradients due to a wellbore, nor is the geometry of the reservoir system considered.

Flooding of Semi-Depleted Solution Gas Reservoir in Fullerton Field

Abstract Little flooding experience or technology exist which are applicable to solution gas-drive reservoirs which have been depleted considerably below the bubble point. The Fullerton field pilot is an example of flooding under these conditions where an intermediate stage or depletion exists and the water flooding will be neither a pressure maintenance project nor a depletion flood. In the case of Fullerton field where the gas saturation is approximately 18.0 per cent of total pore volume, "fill-up" will not be reached for a number of years after flooding operations begin. During this period compressibility of fluids and relative permeability factors determine performance of producing wells. The non-steady-state performance which will be in effect for a considerable time cannot be directly predicted by any presently accepted theoretical means. The pilot flood has yielded considerable information which can be used in predicting performance during this important stage of flooding. The pilot has shown that favorable reactions on producing wells adjacent to injection wells are in effect long before a theoretical fill-up is obtained. This does not indicate poor performance, but merely that the reservoir fluids are compressed to the point where a significant oil bank is formed. This isolated pilot pattern flood, where all offset wells are producing, gives some indication of what might be expected under both pattern and line-drive flooding. The pilot has progressed to a point where sufficient stock-tank oil has been recovered, in the area under pattern flooding, to justify full scale flooding. In the area surrounding the pattern flood no means exist for confining fluid movement, and performance is a function of the interdependent combination of relative permeability, fluid saturation and fluid compressibility. This pilot flood has shown the degree to which outside offset producing wells respond prior to reaching gas-space fill-up and the degree to which productivity is affected by changes in saturation accompanied by only relatively slight pressure increase. Producing wells inside the pattern flood have shown the degree to which productivity can be affected by saturation change and a considerable increase in bottom-hole pressure.

Measurements of Bubble Frequency in Cores

Published in Petroleum Transactions, AIME, Volume 210, 1957, pages 122–125. Abstract The frequency of bubble formation is measured for oils from the East Texas field and the Slaughter field in cores from these fields. East Texas oil was also tested in a Slaughter core. The data checked previous results in that a definite supersaturation may exist without the formation of bubbles in periods of observation totaling 158 hours. Measured frequencies varied from zero at supersaturations below 14 psi to 3.1 bubbles/sec/cu ft of rock at 40 psi supersaturation. Introduction The formation of bubbles is essential in a solution gas-drive reservoir in the displacement of oil. In formations where the basic pore structure consists of fine pores or fractures connected to larger pores or crevices, bubble formation in the fine pores may be the most effective means by which the oil may be displaced, even if secondary methods are applied. The most efficient oil displacement would occur where at least one bubble would form in every pore. As the pressure decreased, the bubbles would expand, due to the gas diffusing into the bubbles, and displace the oil toward the lower pressure area around the wellbore. Kennedy and Olson have shown that the total number of bubbles formed in a reservoir is primarily dependent upon the rate of pressure drop, the rate of diffusion of gas through oil, and surface area of the rock. The surface tension of the liquid and other characteristics of the rock may also exert an important effect, which would give a different frequency to different rocks and oils and various combinations of different rocks and oils. The purpose of this paper is to present frequency measurements on two rocks and two oils. A hydrocarbon liquid is at equilibrium with gas when it contains the maximum volume of gas in solution that it can have at the prevailing temperature and pressure. If the temperature is maintained constant and the pressure is reduced below the equilibrium pressure, the liquid is supersaturated to the extent of the difference in the two pressures until the gas comes out of solution as a free phase.

Effect of Gas on Production Histories of Gas-drive Reservoirs

Effect of Gas on Production Histories of Gas-drive Reservoirs

Calculated Effect of Pressure Maintenance on Oil Recovery

Abstract The application of Muskat's differential equations for predicting theperformance of a solution gas-drive reservoir to the Fullerton field indicatesthat a recovery may be expected of 14,030 bbl per acre under primary depletion, and 15,910 and 17,190 bbl per acre, respectively, under the twopressure-maintenance programs analyzed. In this analysis it is assumed that fluid properties are the same throughoutthe reservoir, that the core data used are typical of the Clear Fork limestonein the locality, and that injected gas is completely diffused through the payzones. The economic study of the three recovery programs considered indicates that theone in which 60 pct of the produced gas is returned to 'the formation is themost profitable. Introduction The purpose of this paper is to consider effect of pressure maintenance by gasinjection on the ultimate recovery of oil from a solution gas-drive reservoir.This prediction of reservoir behavior is the result calculations based on theequations presented by M. Muskat in the Journal of Applied Physics, March1945. Reservoir The reservoir analyzed is the Fullerton field in Andrews County, West Texas. Itsituated on a broad anticlinal structure with approximately 330'Ft of closure, and ends approximately eight miles north and south and five miles east andwest. The areal extent is taken as 16,642 acres. The producing horizon is the Lower Clear Fork limestone of Permian age, occurring at depths from 6650 to 7350'Ft. It is divided into four zones. Forthe purposes of this study, the fluid characteristics in all zones are assumedto be the same. Therefore an equivalent zone is assumed of thickness equal tothe sum of the thicknesses of the four zones, or an average of 216 ft. The reservoir contains 3,586,991 acre feet of producing limestone, with aninitial volume of stock tank oil in place of 918,403,100 bbl. The average connate water saturation is 24.0 pct. The permeability ranges from6.7 md. to 12.6 md., and the porosity ranges from 7.7 pct to 11.4 pct, exceptfor occasional cavernous streaks. Based on these values, the limestone may beconsidered intergranular. Production histories and material-balance studies have indicated that thedriving mechanism is solution gas. Water levels have been established. Theory It is possible to express mathematically the change in residual oil saturationwith pressure decline in a solution gas-drive reservoir as being equal to thechange in the physical properties of the fluids present in the reservoir asthis pressure decline occurs. T.P. 2231

A New Method for Measurement of Oil Saturation in Cores

Abstract This paper describes a new method for measuring the oil saturation of coresduring the course of fluid-flow experimentation. The method depends upon theaddition to the oil of a soluble tracer material that is the primary absorberof the X-rays incident upon the core. The paper includes a description of theX-ray equipment and intensity-measuring apparatus, calibration data for twocores, and results obtained with additional cores for various conditions of oiland water-flooding. The data and results are presented to show thepotentialities of the X-ray method at this stage of development rather than toestablish particular concepts pertaining to fluid-displacement mechanisms ofpermeable media. Further development of this method will include adequatepressure and flow-rate control in the liquid and gas-flow systems,.as well asadditional stabilization of the X-ray power supply. Introduction In the last several years a type of application of the' fundamentalpermeability saturation relationships has been developed which others greatpromise in the interpretation of general reservoir performance. In thesedevelopments no attempt is made to solve the detailed flow dynamics in actualoil and gas-producing systems. That problem still remains unsolved. But thepermeability-saturation phenomena are incorporated in the analysis of oilproducing reservoirs in a manner such as to reflect the true role they play incontrolling the gross reservoir behavior. In particular, they are introduced insuch a manner as to determine the gas-oil ratio of the production at any stageof depletion and, when combined explicitly with the so-called material-balanceprinciples in differential form, one can obtain a differential equationdescribing completely the average pressure and gas-oil-ratio history ofoil-producing reservoirs. While thus far they have been applied directly onlyto gas-drive reservoirs, they are susceptible of extension to partialwater-drive systems, and qualitatively the same principles are of value in thestudy of complete water-drive reservoirs. Moreover, in addition to giving ameans for computing the variation of the reservoir pressure and gas-oil ratiosvs. the cumulative production, they automatically lead to predictions of thegross ultimate recovery under natural depletion-and when properly extended theyprovide means for predicting the ultimate recovery under gas or waterinjection. The data required for such applications are the initial fluid distribution inthe producing section, the pressure-volumetemperature data on the gas andliquid phases, and the permeability-saturation relationship for theoil-saturated zone. The former can be obtained with reasonable accuracy bymethods that are well established and available throughout the industry. Thepermeability-saturation data, however, involve techniques that are not at allstandardized. T.P. 2124

Effect of Reservoir Fluid and Rock Characteristics on Production Histories of Gas-drive Reservoirs

Abstract Theoretical calculations have been made on the performance to be expected of gas-drive reservoirs for various characteristics of the oil and gas and the producing rock. Such performance has been expressed graphically as curves for the reservoir pressure and gas-oil ratios of the production as functions of the cumulative oil recovery. The latter has been expressed in terms of percentage of pore space of the reservoir rock. Such curves automatically give values for the ultimate physical recovery, if the latter is interpreted as the recovery obtained when the reservoir pressure has declined to atmospheric, or to any other pressure chosen as defining the state of practical complete depletion. Calculations of these pressure and gas-oil ratio histories have been made for conditions in which the oil viscosity, the gas solubility and shrinkage, the size of an overlying gas cap, if present, the permeability-saturation characteristics of the rock, and the amount of connate water, have been individually varied. The results serve to show the extent to which the ultimate recoveries are sensitive to the important physical parameters characterizing the oil reservoir. As is to be expected, the ultimate recoveries are found to decrease with increasing oil viscosity. Because of the predominant effect of the oil shrinkage associated with the liberation of the gas in solution, the ultimate recovery will decrease with increasing gas solubility. Increasing gas-cap volumes lead to higher recoveries, although the contribution made by the gas-cap gas is small as compared with the oil expulsion by the equivalent amount of solution gas. As a whole, the oil recovery when expressed in percentage of the pore space is not very sensitive to the details of the permeability saturation relationship. However, if the rocks possess an equilibrium free-gas saturation, the rise in gas-oil ratio will be retarded, and the ultimate recovery somewhat increased. The oil shrinkage associated with the liberation of the dissolved gas also leads to the result that as long as the connate water is immobile and the permeability ratio curve for the rock is a function only of the total liquid saturation, the stock-tank oil recovery will be less for a sand containing no connate water than for one with an original water content as high as 30 per cent. The space voidage in the former case will be somewhat greater, but the effect of oil shrinkage will lead to smaller values for the equivalent stock-tank recovery. These calculations also give data showing how the productivity indexes for the producing wells will vary during the reservoir history. Because of decreasing permeability to the oil and increasing oil viscosity, the productivity index will fall continuously as production proceeds, and may finally reach values as low as 10 per cent of the initial productivity index. Introduction In a previous paper was developed the basic theory for the prediction of the production histories of gas-drive reservoirs. T.P. 1917