Gas Segregation Research Articles

Analysis of Gravity Segregation Performance During Natural Depletion

Abstract This work presents the development and application of equations of the form developed by Martin to describe gravity segregation performance during natural depletion. One-dimensional depletion analyses are applied to several hypothetical reservoirs. Considerable attention is given to the changes in saturation distribution in the dip direction resulting from depletion at various rates. Vertical gas saturation distribution within a sand having vertical permeability is studied to illustrate conditions which provide for low gas-oil ratio production from wells selectively completed away from sand tops, as observed from well performance. Results of performance calculations are shown graphically and illustrate the rate sensitivity of the gravity segregation mechanism and the influence of reservoir geometry and withdrawal distribution. It is shown that for sufficiently high depletion rates gas saturation distribution in the dip direction is characterized by the formation of two discontinuities, or saturation "fronts"; the updip front being the gas-oil contact of the secondary gas cap and the downdip front occurring at a position dependent upon the reservoir depletion rate, withdrawal distribution and reservoir geometry. The gas saturation in the region between fronts is shown to continually increase with time, while that downdip from the lower front remains very low and relatively stable. The effect of increased depletion rate is to reduce the region of stable gas saturation and thus enlarge the portion of the reservoir producing with continually increasing gas saturation. Special attention is given to the performance of reservoirs having sufficient vertical permeability to permit liberated gas to segregate vertically within the sand section before proceeding in the updip direction. It is shown that reservoirs of this type are far less sensitive to depletion rate due to the mechanical control of producing gas-oil ratios afforded by selective well completions away from sand tops. It is shown that gravity segregation performance is adversely affected by decreasing reservoir cross-section area in the updip direction. It is also shown that downdip withdrawal concentrations can restrict gas segregation rates in the dip direction. Introduction The natural depletion performance of several large producing reservoirs in Western Venezuela has unmistakably shown the significant role that gravity forces play in governing the gas-oil ratio behavior of individual wells and the over - all pressure production performance of the reservoirs. Analysis and prediction of the natural depletion performance of these reservoirs is of great importance in determining the economics of pressure maintenance operations. In 1957, a method for the analysis of pressure maintenance performance was presented by Martin which, in the original and more general form of the equations involved, provides a physically sound basis for the analysis of one-dimensional gravity segregation performance during natural depletion. The work reported herein is an application and extension of Martin's outstanding developments to a series of hypothetical reservoirs in an attempt to explain the general behavior of the gravity segregation mechanism and the influence of such parameters as depletion rate, reservoir geometry and withdrawal distribution. The study considers two types of flow: "distributed flow", where vertical permeability in the reservoir is zero and fluids flow only in the dip direction while uniformly distributed over the sand thickness; and "segregated flow", where vertical permeability is sufficient to permit gas to segregate against the sand top before proceeding updip. This latter type of flow has been recognized as an important mechanism active in the massive sand reservoirs of Western Venezuela. SPEJ P. 261^

Scab Cementing-An Economical Workover Technique For Effective Production Control

Abstract The Main Gatchell zone of the Coalinga Nose field, Fresno County, Calif., is one of the major oil pools in the state. One very significant phase of over-all operations in this field is scab cementing. Scab cementing used in the Coalinga Nose field as a method of well workover, establishes cement bonds between the perforated liner and the formation, separating a single long productive interval into several short intervals. Cup-type tubing packers and choke nipples are set opposite these cement bonds to allow selective production of oil, gas and water using the control obtained from bottom-hole chokes. The cemented perforated sections are called "scabs".Detailed descriptions of the various phases of scab cementing are given, as well as an analysis of the costs involved. Nearly all of the wells recompleted by scab cementing in the Coalinga Nose field are still flowing. Some or all of the techniques used in scab cementing for production control have been applied to other workover operations where a cement bond is needed between perforated or blank pipe and the formation. Successful application of scab cementing in other areas would depend on a careful examination of reservoir conditions, producing mechanisms and methods of lift. Where conditions are favorable for its use, scab cementing is an economical and effective workover technique that allows selective production control through designed tubing strings. Introduction The Main Gatchell zone of the Coalinga Nose field, Fresno County, Calif., is one of the major oil pools in the state. Discovered in 1938, it has produced over 300-million bbl of 31 degrees API oil primarily by a gravity-drainage mechanism. More than 94 per cent of the productive acreage was included when the Coalinga Nose Unit was formed on March 1, 1950.The Main Gatchell zone is a stratigraphic trap situated on a plunging anticline. The reservoir is a thick, massive quartzose sand of Eocene age. The air permeability averages about 750 md in the up-structure portion of the reservoir which is very nearly isotropic. Dips range from 100 to 300 at the sand and underlying shale contact, depending upon regional location on the structure. Drill depth to the top of the Main Gatchell zone averages about 7,500 ft. There was no primary gas cap in the Main Gatchell zone. Early in the productive life as the reservoir pressure decreased, gas accumulated at the top of the structure and expanded into the up-structure producing wells as a well-defined secondary gas cap, indicating that an effective gravity segregation of oil and gas was taking place. The attendant increases in gas-oil ratios of up-structure wells were controlled in many instances by decreasing the oil rates. When this was no longer effective (or when the ratios became excessive) the wells were shut in or, if feasible, deepened. Fig. 1 shows the area affected by the growth of the secondary gas cap over the years. History of Cementing Workovers It was recognized early that remedial operations would be necessary to control gas production from the encroaching secondary gas cap. The current scab-cementing method of production control, with minor variations, was initiated in 1950 and is the only method described in detail in this paper. Scab cementing is used in the Coalinga Nose field as a method of well workover, or repair. This establishes cement bonds between the perforated liner and the formation, separating a single long productive interval into several short intervals. Cup-type tubing packers and choke nipples are set opposite these cement bonds to allow selective production of oil, gas and water using the control obtained from bottom-hole chokes. The cemented perforated sections are called "scabs". JPT P. 349^

A Study of Anomalous Pressure Build-Up Behavior

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 44–50. Abstract In one field in South Texas, approximately 75 per cent of the pressure build-up results show a characteristic "hump" (i.e., the pressure builds up and then falls off) which makes interpretation by standard methods impossible. Correlation of size and time of hump with formation permeability, well productivity index, and method of completion led to the tentative conclusion that the humps were caused by segregation of gas and oil in the wellbore after closing-in. This conclusion was confirmed by performance of simple laboratory bubble-rise experiments, by theoretical bubble-rise time calculations, and by a detailed calculation of PVT behavior in the wellbore of a particular well on which accurate surface and bottom-hole pressure measurements were made. The hump behavior has since been found to occur in many other fields. The cause, however, is not the same in all cases. In some of these the hump is traceable to leaks in the tubing which allow influx of gas from the annulus after closing-in. In other cases the hump is traceable to leaks in the device separating pay horizons in dually completed wells. It is concluded that the recording of both surface and bottom-hole pressures is desirable in wells which show an anomalous build-up behavior. A number of field examples is discussed where use of both sets of measurements enables the cause for anomalous behavior to be found, and a reasonable interpretation of bottomhole pressure to be made. Introduction Theoretically the pressure build-up in an infinite reservoir should be a linear function of ln [(t + ?t) /?t] where t is the production time and ?t is the closed-in time. Some of the variations from this behavior are well known, such as the curved portion immediately after shut-in which results from after-production and skin effect, and the flattened end portion which results from boundary effects in a limited reservoir. The effect of stratified producing zones and irregular geometrical drainage patterns may also contribute unusual characteristics to build-ups.

Gas Injection Performance Review of the LL-370 Reservoir in the Bolivar Coastal Field, Venezuela

Abstract The Conservation Plant Tia Juana No.1 began pressure maintenance operations of the LL–370 area of the Bolivar Coastal field in Oct., 1954. Gas is being returned to the B–6 Eocene sandstone via seven injection wells. During the first two years of operations, the average injection rate has been 133.9 MMcf/D. This represents a small excess of gas injected over hydrocarbon volume withdrawals. In the third quarter of 1956, average production was 77,583 BOPD, with a producing gas-oil ratio of 876 cu ft/bbl. Fifty-nine wells were classified as producers. Production characteristics of the LL–370 area under pressure maintenance have been very satisfactory and superior to predicted behavior. There has been no evidence of excessive gas channelling. The vertical segregation of oil and gas in the reservoir continues to play an important part in the production mechanism. As a result, required high-gas shutoffs in up dip areas continue to be successful with the isolation of upper high-gas saturated zones by squeeze cementing and the return of the lower portion of the sandstone to low gas-oil ratio production. The average reservoir production decline is nil, with the production decline of individual wells balanced by production increases in others. Not only will this project result in a much greater recovery of oil from the reservoir, but also a huge quantity of gas is being conserved for the future. Geology and General Reservoir Characteristics The LL–370 area is located in Lake Maracaibo 7 miles from the community of Tia Juana which is on the northeast shoreline of the lake. The oil-bearing formation consists of a truncated monocline of Eocene sandstone called the B–6. The total surface area covers 11,048 acres and is subdivided into four reservoirs by faults, which are only partial pressure barriers. The area is bounded by major faulting to the northeast and southwest, the Miocene-Eocene unconformity to the west at the top of the formation, and a water leg to the southeast. Additional Eocene productive units overlie and underlie the B–6, but these are isolated by extensive shale barriers and only local communication probably exists.

Some Theoretical Considerations of Tilted Water Tables

Abstract An analysis has been made of the factors responsible for tilted fluidcontacts in petroleum reservoirs. The factors are static and dynamic with theformer being controlled by those variables responsible for the capillary riseof fluids, and the latter include rate of formation tilt and hydrauliccirculation. The explanation that rate of formation tilt may be responsible fortilted contacts appears untenable. The role of some of these factors in themigration, fractionation, accumulation, and possibly the prospecting for oil isindicated. Introduction While it is generally considered that the segregation of gas, oil, and waterin a petroleum reservoir results in approximately horizontal planes separatingthese phases, there are factors which modify this simplified picture to a verygreat extent. Some of these factors are static, and the departure of the fluidinterfaces from horizontal may represent a static equilibrium. Some of thesefactors may be dynamic and the interface positions may be non-equilibrium andrepresent a steady state condition. Of course combinations of these twosituations may also exist. The reasons most commonly given for this behaviorare hydraulic circulation of fluids, change in character of the formation, anda rate of tilt of the formations more rapid than the rate at which the fluidsmay re-establish an equilibrium. Russell's Principles of Petroleum Geologycontains an extensive discussion of tilted fluid interfaces and theirimportance in the migration and accumulation of petroleum. Russell citesexamples of tilted water tables at Lance Creek, Wyo.; Rock River, Wyo.; CutBank, Mont.; Cushing, Okla.; and Graham, Okla. Also given was the Wasson Fieldof West Texas which has saucer shaped oil-water and gas-oil interfaces with thesaucer being deeper in the case of the oil-water contact. The Bradford Field inPennsylvania has a tilted water table. San Ardo, Coalinga Nose and some otherCalifornia fields have tilted contacts. A recent paper by King Hubbertdiscusses the effect of hydraulic circulation of the water underlying the oilin a given stratum and its implications in the accumulation of and drilling forthe oil. The foregoing would indicate that tilted fluid interfaces are not uncommonand that it would be of importance to understand the forces which areresponsible. Further, it would be of interest to examine certain idealizedmodels of situations which may cause tilting with the thought in mind ofderiving relationships between the important variables. These relationships mayonly hold exactly for the models assumed but the results may applysemi-quantitatively to actual formations and at least indicate trends. Thediscussion will be divided into the effect of static factors and the effect ofdynamic factors. T.P. 3564

鑄鐵のガス分析に就て

A tentative model of gas-analysis equipment by vacuum-fusion method was developed with a view to investigate effects of the gas contained in the molten cast iron on the structure and character of cast iron product. Recurrence of analysis values was examined as to rimmed steel and cast iron. The following conclusions were obtained.1) Recurrence of O2 and N2 analysis value for cast iron was somewhat lower than that for rimmed steel, the principal cause of difference being considered to be segregation of gas in analysisspecimens.2) O2 and N2 contents of cast iron were both in the order of 0.00 x wt%; thus variations depending upon melting conditions could be detected by the proposed analysis method.3) To secure higher reliability of gas analysis of cast iron, further studies should be carried out about the following points:a) To raise gas-extracting temperature.b) To improve the evacuating rate.c) To develop a sampling method with less segregation, etc.

The Production Histories of Oil Producing Gas-Drive Reservoirs

A theory has been developed for predicting the behavior of solution gas-drive oil producing reservoirs, on the basis of previously established empirical laws on the flow of heterogeneous fluids through porous media. Treatments are given both for the simple pressure depletion history without gas injection, and those for systems in which gas is injected during the course of oil production. The specific results provided by the theoretical analysis include the ultimate oil recovery, and the pressure decline, gas-oil ratio, and productivity factor histories. Two types of gas injection have been considered, namely: (1) that in which the returned gas is supposed to diffuse through and be produced continuously with the oil zone; and (2) that in which the injected gas remains locked in the gas cap, which merely expands as oil production and gas injection proceed. In the latter case the rate of growth of the gas cap is also obtained as a function of the cumulative oil recovery. The theory is illustrated by numerical application to a hypothetical virgin oil reservoir with an original pressure of 2500 p.s.i. producing by gas-drive, and with no initial gas cap. It is so found that if no gas is injected into the system the physical ultimate oil recovery will be 14.5 percent of the pore space, or 27.1 percent of the original stock tank oil content, assuming that the formation initially has a connate water saturation of 30 percent. The gas-oil ratio first declines as production is started, then rises sharply to a maximum of 4400 cu. ft./bbl., and finally falls steeply as the pressure is depleted to atmospheric. If there is no gas segregation and 60 percent of the produced gas is returned to the formation, the ultimate oil recovery will be increased by 27.6 percent. The gas-oil ratio history will be similar to that with no gas injection, but will rise to a maximum of 10,300 cu. ft./bbl. If 80 percent of the gas is returned, the recovery increase will be 48.8 percent, the maximum in the gas-oil ratio history reaching a value of 19,450 cu. ft./bbl. If all the gas is returned, the gas-oil ratio rise will be so rapid that by the time 20,000 cu. ft./bbl. is reached only 23.5 percent additional oil will be recovered. During these operations the productive capacities of the wells will fall by factors of the order of 10, because of the increasing viscosities of the oil and decreasing permeabilities to the oil, as the pressure declines and the oil saturation decreases. For the case where the gas remains trapped in the gas cap, the ultimate oil recovery will be 163 percent greater than by direct pressure depletion, if the residual oil after gravity drainage is 15 percent of the pore space. This recovery will be essentially independent of the amount of gas return, although the final reservoir pressure at the time of complete gas cap expansion will be greater as more gas is returned. The increased oil viscosity and decreased permeability to the oil will here reduce the specific production capacities of the wells to ¼ or ⅓ of their initial values.

The Flow of Heterogeneous Fluids Through Porous Media

The empirical results established by R. D. Wyckoff and H. G. Botset on the flow of gas-liquid mixtures through unconsolidated sands have been formulated into basic differential equations governing the motion of general heterogeneous fluids through porous media under both steady state and transient conditions. This formulation is based upon a representation of the porous medium as having a macroscopically local structure defined by the liquid saturation, or volume composition of the gas-liquid mixture, this saturation in turn determining the separate permeabilities of the medium to the liquid and gas phases. The steady state solutions of these equations are derived for the cases of linear, radial, and spherical flow, and the distributions of the pressure, permeability, and saturation are given graphically. It is found that the properties of these flow systems change but little from the corresponding ones for homogeneous fluids as long as the pressure exceeds about half the saturation pressure of the gas, except for the fact that the liquid saturation is very approximately equal to the equilibrium value and the liquid permeability has a value very near to its equilibrium value. The drop in liquid permeability and saturation is highly localized about the outflow surfaces and in those regions where the pressure is very much less than the saturation pressure, the increase in the pressure gradients above their normal homogeneous fluid values being also largely confined to these regions. For the study of the early stages of transient types of flow an analytical theory is derived, in the case of the linear system, based upon a representation of the transient as a continuous succession of steady states. For the investigation of the complete history of the linear transient system a numerical method is presented in which is developed a stepwise integration of the simultaneous partial differential equations for the pressure and liquid saturation, after the replacement of the various derivatives by their appropriate differences. The specific problem is treated in which a linear column of sand of unit length filled with liquid saturated with an ideal gas to a pressure of 10 units is suddenly exposed at one terminal to a pressure of 1 unit, which is thereafter permanently maintained at that value while the other end is permanently kept closed. The results of the calculations for this problem are given graphically in the form of sets of curves showing the history of the saturation and pressure distributions within the flow channel, the time variation of the flux from the system, and the time variation of the gas-liquid ratio associated with the liquid efflux. It is found that the liquid saturation at the time of physical depletion of the system, corresponding to an equalization of the pressures to that maintained at the outflow terminal, is quite uniform, being only 5 percent less at the outflow terminal than at the closed terminal of the linear column. The gas-liquid ratio is found to increase monotonically with the time. The bearing of these results on such problems as well spacing and gas recycling in the production of oil from underground reservoirs, and the manner of treatment of other typical heterogeneous fluid systems so as to include both the deviations from the ideal behavior of the free gas phase and the effect of gas segregation are discussed in detail.

Factors Involved in Segregation of Oil and Gas from Subterranean Water

The process of oil and gas accumulation is mainly a segregation of these substances from the water circulating in the earth's crust. The segregation is caused by intermolecular forces and differences of pore size. The hypothesis that synclinal oil has accumulated in dry or unsaturated strata is rejected. Tardiness of edge-water encroachment and irregularities in the shape of oil and gas accumulations deserve attention.

Factors Governing Accumulation of Oil and Gas in Mirando and Pettus Districts, Gulf Coastal Texas, and Their Application to Other Areas

The conditions causing the commercial occurrence of oil and gas in the recently discovered fields of the Pettus district, Bee County, Texas, show a striking similarity to those surrounding the older and better known fields of the Mirando district, 100 miles farther southwest. The productive sands in both districts are confined to a stratigraphic section, limited by basal Frio sediments above and by middle Yegua sediments below, which is mainly of Fayette age. In the Mirando district, accumulation has occurred in narrow strike lenses, formed under conditions of shore-line deposition, in which gradations in porosity have formed traps. Source material, from which the oil and gas were derived, was deposited within, or adjacent to, the present producing horizons. True deformation is ordinarily absent, although folding or fracturing may, in some places, have exerted a minor influence. Present knowledge of conditions at Pettus indicates that the same factors were primarily the cause of the oil and gas segregation in this area. In the Pettus field proper, accumulation occurs within a lensing sand which follows a definite strike trend. There is no evidence of positive structural influence. The conclusion is reached that, within the upper Eocene section throughout the inner margin of the Gulf Coastal Plain, strata of basal Frio, Fayette, and upper Yegua age contain differences in porosity sufficient to trap oil and gas, in the absence of structural influence. The following of established strike trends will prove the most effective means of locating such pools.