Separator Conditions Research Articles

Adjustment of Differential Liberation Data to Separator Conditions

Summary Solution gas/oil ratio (GOR) and oil formation volume factor (FVF) are normally obtained from differential or flash liberation tests. However, neither the differential liberation process nor the flash liberation process can represent the fluid flow in petroleum reservoirs. Therefore, data obtained from any of the two test procedures must be adjusted to approximate the fluid behavior in the reservoir. At low pressures, the conventional method of adjustment yields negative values of solution GOR and values of oil FVF of less than 1. This, of course, is not physically correct. This paper presents a new method for adjusting the differential liberation data to separator conditions. The new method overcomes the limitations of the conventional adjustment method and makes the low-pressure extension of the curves of solution GOR and oil FVF more accurate. The method is based on the fact that data obtained from both the differential and flash liberation tests should yield the same value of oil relative density at reservoir conditions. The new method is tested using 425 PVT files, yielding results that are consistent with the physical behavior of solution GOR and oil FVF.

Heavy Components Control Reservoir Fluid Behavior

The five reservoir fluids (black oils, volatile oils, retrograde gas-condensates, wet gases, and dry gases) are defined because production of each fluid requires different engineering techniques. The fluid type must be determined very early in the life of a reservoir (often before sampling or initial production) because fluid type is the critical factor in many of the decisions that must be made about producing the fluid from the reservoir. This paper summarizes the guidelines for determining fluid type from field data. If any of these three properties fails to meet the criteria described, the test fails and a representative sample of the reservoir fluid must be examined in a laboratory to establish fluid type. It also shows the expected results of laboratory analysis of the fluids. The paper also summarizes schematically the trends of producing GOR and stock-tank liquid gravity. These fluid types are defined for engineering purposes. They should not be confused with reservoir fluid descriptions defined by legal agencies that regulate the petroleum industry. Regulatory definitions of oil, crude oil, condensate, gas, natural gas, casing-head gas, etc., are not related to these engineering definitions and, in fact, often contradict them.

Derivation of PVT Correlations for the Gulf of Suez Crude Oils.

Proper evaluation of physical properties of hydrocarbon mixtures is a prerequisite for the design of various stages of oil field operations. In many cases these properties are required at a time when the only information available consists of oil and gas gravities and reservoir pressure and temperature.The purpose of this study is to utilize a sufficient base of laboratory-measured PVT data to derive specific empirical correlations for the prediction of the saturation pressure Pb, gas in solution Rs and formation volume factor βo of Gulf of Suez crude oil systems, oAPI of which ranges from 25 up to 40. Our tool in this work is some of regression analyses techniques.The correlations are based on 90 experimentally measured data which represent about 30 independent reservoirs. These data are expressed in terms of the usually measured field parameters-flash separation gas-oil ratio, tank oil gravity, surface gas gravity (at separator conditions) and reservoir temperature.Derived correlations are valid within the ranges used for the above mentioned variables (GOR, T, γg). The gases are relatively free from non-hydrocarbons. Statistical accuracy tests show that the application of derived correlations for Egyptian reservoirs gives more accuracy than the known correlations (Standing and Glaso). The use of the derived relationships requires no graphs nor charts, and their applicability is convenient to use with the computer or calculator.

Judy Creek Miscible Flood Introduced Fluids Monitoring

Abstract A produced fluid monitoring program for the Judy Creek BHL ‘A’ Pool hydrocarbon miscible flood was implemented as a basis for quantifying solvent production and for monitoring miscibility. The program involved:the collection and analysis of gas and liquid samples from wells exhibiting solvent production;the application of a tuned Peng-Robinson equation-of-state (EOS) to match gas and liquid compositions and gas/oil ratio (GOR); andin those cases where EOS matches were successful, solvent production was quantified and the miscibility state was identified. Because a wide range of LPG sources, and hence compositions, have been used in flood, the blending of LPG and dry gas into solvent was performed through a microprocessor controlled application of the miscible equivalence (ME) technique(1). Therefore, by providing evidence of first-contact miscibility, the monitoring program also provided a rest of the automated ME technique. The produced fluid monitoring program, over the course of three years, has revealed that the ME technique has been successful, and that gas analysis data provide the best basis for the determination of solvent production volumes and flood miscibility. Introduction In May of 1985, a hydrocarbon miscible flood was initiated in the Judy Creek BHL ‘A’ Pool. This flood was designed to be first contact miscible (FCM), and to ensure this condition, a variety of safeguards was employed. One of them, a produced fluid monitoring program, was implemented in November 1985. The basic premise of this program is that the composition of a produced hydrocarbonfluid can be used to determine the nature of the miscible process. Furthermore, the program was also intended to provide a quantitative ssessment of the volume of produced solvent. The monitoring program consisted of first, produced fluid sampling and compositional analysis, and second, compositional modelling to match the analysis results. The produced fluid sampling portion of the program originally consisted of obtaining one separator oil sample from a well in each of the miscible flood patterns every three months. After one round of sampling and modelling it became apparent that oil samples alone did not provide sufficiently accurate information for modelling purposes. Hence, in the second and subsequent rounds, both gas and oil samples were obtained. This was found to be considerably superior to obtaining only oil samples, and with time, it was recognized that gas-only sampling was sufficient and preferable. Also with time, it became dear that the data obtained from this monitoring program could be used to fully quantify the volume of solvent in the produced hydrocarbon stream. Monitoring Program Theory To illustrate the concept behind the fluid monitoring program, Judy Creek BHL ‘A’ Pool reservoir fluid and solvent compositions are used. These are shown in Table 1. Because the injected solvent has had, over time, a wide range of ethane and propane concentrations and given our previous success in lumping intermediates(2) these components are, for most practical purposes, lumped together as a single component. Figure 1 shows a pseudoternary diagram based on blending various amounts of Judy Creek BHL ‘A’ Pool reservoir oil and solvent at separator conditions of 45 ºC and 2100 kPa.

Ekofisk Waterflood Pilot

This paper describes the evaluation of a waterflood pilot in the highly fractured Maastrichtian reservoir of the Ekofisk field in the Norwegian sector of the North Sea. A four-well pilot consisting of one water injector and three producers was initiated in Spring 1981 and was concluded in mid-1984. A total of 21 x 10/sup 6/ bbl(3.3 x 10/sup 6/ m/sup 3/) of water was injected, and water breakthrough occurred in two of the production wells. Simulation of waterflood performance in the pilot was conducted with a three-dimensional (3D), three-phase dual-porosity model. Initial and boundary conditions were taken from a full 3D single-porosity model of the reservoir. The pilot was conducted to determine the following information for the Maastrichtian: water-cut performance vs. time, water imbibition characteristics, and anisotropy. Results from this work have been incorporated into a full-field waterflood study. Reservoir description included the determination of fractured areas, matrix block sizes, water/oil capillary imbibition, matrix permeability and porosity, and effective permeability. These data were derived from fracture core analysis, pressure transient tests, laboratory water/oil imbibition studies, repeat formation pressure test results, and open- and cased-hole logs. An excellent match of waterflood performance was obtained with the dual-porosity model. Of particular interestmore » are the imbibition characteristics of the Maastrichtian in the Ekofisk field and the character of the water-cut performance of the producing wells following injector shutdowns and startups.« less

Engineering Applications of Phase Behavior of Crude Oil and Condensate Systems (includes associated papers 16046, 16177, 16390, 16440, 19214 and 19893 )

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Summary Fluid samples must be taken early in the life of a reservoir toobtain samples truly representative of the reservoir fluid. They should betaken only after a carefully planned well conditioning and testing program. When the PVT data obtained from these samples are used, care should be taken toadjust FVF's and gas/oil ratios (GOR's) for surface separator conditions. Introduction The proper development, engineering, and production of an oil or gasreservoir requires a considerable amount of planning. At the same time thatplans are formulated to develop the field, plans should also be made for adata-gathering program to facilitate reservoir engineering months and evenyears into the future. This data-gathering plan should include a sufficientnumber and variety of electric logs and cores on key wells to describe thereservoir adequately. Electric logs and core analyses evaluate the reservoirrock. If reservoir engineering calculations are to be made to optimizeproduction from a reservoir, including EOR, then the properties of thereservoir fluids must also be known. The properties of the reservoir water fallwithin narrow ranges and are seldom studied at reservoir pressures andtemperatures. The properties of the reservoir water determined are normallyconfined to chemical analysis and possibly compatibility tests in cases ofinjection projects. This paper is concerned primarily with the study of thehydrocarbon fluids contained in a reservoir. Coring and logging programs shouldcontinue throughout the development of a reservoir. The data obtained from thelast well drilled are as valuable as the data obtained from the first well. This is usually not the case for reservoir fluids. Samples representative ofthe original reservoir can be obtained only when the reservoir pressure isequal to or higher than the original bubblepoint or dewpoint. Methods areavailable for extrapolating fluid data obtained after some pressure decline. Remember, however, that extrapolation is an educated man's word for guessing. Plans for obtaining reservoir fluid samples and analyses should be made earlyin the life of a reservoir. Reservoir fluid samples should be taken beforesignificant reservoir pressure decline has been experienced. Oil Reservoirs Oil reservoirs can be divided into two categories: ordinary oil reservoirsand near-critical reservoirs. The ordinary oil reservoirs are sometimes calledblack-oil reservoirs. This misnomer does not reflect the color of the reservoirfluids. It is meant only to distinguish them from near-critical oil reservoirfluids. The near-critical fluids will be discussed in subsequent paragraphs. Ordinary oils are characterized by GOR's up to approximately 2,000 ft3/bbl [360m3/m3], oil gravities up to 45 degrees API [0.8 g/cm3], and FVF's of less than2 bbl/bbl [2 m3/m3]. Remember that there is no sharp dividing line between anordinary and a near-critical oil. Such factors as composition and reservoirtemperature greatly influence the behavior of the reservoir fluid. It is oftenimpossible to determine whether a fluid should be studied as a near-criticaloil or as an ordinary oil until it is actually in the laboratory beingobserved. JPT P. 715^

Thermodynamics of petroleum mixtures containing heavy hydrocarbons. 2. Flash and PVT calculations with the SRK equation of state

The oil and gas mixtures described in part 1 of this series are subjected to three PVT experiments commonly performed on oil and gas mixtures: constant mass expansion, differential liberation, and constant volume depletion. In addition, P,T flashes at separator conditions are determined experimentally. These experimental results are simulated with the SRK equation of state plus various correlations for the liquid-phase molar volumes. It is found that the hydrocarbon characterization methods presented in part 1 give satisfactory simulations of the P,T flash and PVT data. The most suitable liquid-phase molar volume correlations are the Standing-Katz and Alani-Kennedy correlations.

Natural gas treatment and pipeline transportation at well site.

This paper presents the numerical models for the estimation of temperature drop in a low temperature separator and pressure drop in a horizontal pipeline. As a basis for both models, the nume-rical models for flash calculations are fully taken into consideration. These models were applied to some field cases. The calculation results were compared with measured results, and reasonable agreement was observed. These models can be utilized for the selection of separator conditions to prevent the generation of hydrate and for the decision of an inside diameter of a horizontal pipeline in designing surface production facilities of natural gas.

Carbon Dioxide Flooding-fundamentals

Introduction This is the first of two papers dealing with the fundamentals and application of carbon dioxide flooding. First, the basic mechanism involved is discussed. Then a laboratory experimental program as well as predictive techniques to determine the minimum miscibility pressure, swelling of oil, viscosity reduc tion, PVT properties, solution gas drive effect and increased injectivity are presented. Finally, laboratory tests directed toward the determination of residual oil saturation and the anticipated incremental oil recovery are discussed. Introduction Since 1950, the petroleum industry has been carrying out considerable research into the use of Carbon dioxide to increase the recovery of oil from underground hydrocarbon reservoirs(22). In the last few years, about a dozen new field applications have been initiated and more could come if economically priced CO2 supplies are found. Most petroleum research centers have projects relating to CO2 flooding, indicating the current interest in CO2 flooding and promising further innovations in the process. This paper deals with the fundamentals and the research aspects of carbon dioxide flooding. The basic mechanisms which may lead to an increased oil recovery, the data required to evaluate a potential application in the field, certain basic properties of CO2 and carbonated fluids, and the all-important considerations of residual oil and incremental oil recovery are described and discussed. A second paper covers the reservoir engineering aspects of field applications, such as selecting a reservoir suitable for CO2 flooding, determining the CO2 requirements, injection/production strategies and certain recommendations regarding pilot testing the process in the field. Basic Mechanisms Carbon dioxide flooding may be applied in the field as a secondary or tertiary process and would normally involve the injection of CO2 and some other fluids, either sequentially or in an alternating fashion. Generally, in reservoirs in which the displacement is horizontal or nearly so, the CO2 flooding process would involve alternating injection of CO2 and water to attempt to control the mobility of the fluids, whereas in vertical floods the various fluids would be injected sequentially. For example, in vertical downward displacement, the CO2 may be followed by a lighter gas to maximize the advantage of gravity segregation and minimize -viscous and gravity" fingering; in vertical upward displacement, CO2 would be followed by water, again taking advantage of the gravity segregation. Regardless of how CO2 flooding is applied in the field, the following factors may contribute to increasing the oil recovery:reduction of crude oil viscosity;swelling of crude oil;miscibility effects;increase of injectivity;internal solution gas drive. The effects of the foregoing on oil recovery have been discussed in the literature(12,22). Therefore, only the new and hitherto unrecognized aspects will be discussed here. With regard to swelling of crude oil, the additional oil recovery has generally been considered to be due to an increase in the oil formation volume factor so that the residual oil is smaller in volume at surface separator conditions.

Analysis of Unusual Performance Indicates High Solution-Gas-Drive Recovery Stateline Ellenburger Field

The primary depletion performance of the Stateline Ellenburger field did not follow the predicted usual performance for a solution-gas-drive reservoir. performance for a solution-gas-drive reservoir. Observed performance and interpretation of reservoir behavior indicate that there is a high equilibrium gas saturation for this dolomite reservoir, and that primary recovery by solution-gas drive may exceed 50 primary recovery by solution-gas drive may exceed 50 percent of the oil in place. percent of the oil in place. The Stateline field is located in Lea County, N.M., and Andrews County, Tex., and produces from the Ellenburger formation at an average depth of about 12,200 ft. The formation is a light tan dolomite with numerous pinpoint vugs and considerable fracturing. Permeabilities determined from core analysis ranged Permeabilities determined from core analysis ranged from less than 0.1 md to more than 1,000 md. Weighted average values for porosity and permeability calculated from the thickness of the net pay core samples were 3.1 percent and 90 md, respectively. The value for average permeability from core analysis is in good agreement with the effective permeabilities of 45 md to 100 md calculated from pressure buildup measurements. The porosities indicated by Sonic logs generally agreed with the core analysis values. Fluid analysis of a subsurface sample indicated a saturation pressure of 1,555 psig. The original reservoir pressure pressure of 1,555 psig. The original reservoir pressure was approximately 4,970 psig. Separation tests of the reservoir fluid sample indicated a separator GOR of 437 cu ft/bbl, with a crude oil gravity of 43.3 API. The initial producing GOR's from the wells under similar separator conditions ranged from 418 to 577 cu ft/bbl. The formation volume factors at the original pressure and at bubble-point pressure were 1.270 and 1.316, respectively. Viscosity of the fluid was 0.53 cp at the saturation pressure and 1.49 at atmospheric pressure. Three field-wide bottom-hole pressure surveys were conducted during the first 9 months of production. Because of reservoir pressure differences noted in the surveys and because of an indicated shear fault, the field was divided into a north area and a south area for purposes of calculating oil in place and estimating purposes of calculating oil in place and estimating performance. The reservoir pressure in the north area performance. The reservoir pressure in the north area had declined from the original pressure of 4,970 to 1,881 psig, only slightly above the bubble-point pressure of 1,555 psig, with the production of only pressure of 1,555 psig, with the production of only 305,000 bbl of oil. The straight-line method for the material balance solution was used to calculate the oil in place from the reservoir pressure and production data in each area. The material-balance calculations were solved on the basis of the laboratory-measured fluid properties and of a rock compressibility value indicated by Hall's correlations between compressibility and porosity. These calculations indicated that the original oil in place was 3,846,000 STB in the north area and 2,180,000 place was 3,846,000 STB in the north area and 2,180,000 STB in the south area. Four pieces of core sample were used by Continental Oil Co. for rock compressibility measurements. The data obtained in the laboratory indicated a value for rock compressibility approximately half that indicated by Hall's correlations. P. 1507

Performance of Seeligson Zone 20B-07 Enriched-Gas-Drive Project

Abstract In 1957 Humble Oil and Refining Co. initiated a program in the Seeligson (Zone 20B-07) field, Kleberg County, Tex., that involved displacement of oil by enriched gas. Early evaluation showed that nearly 100 percent oil recovery was being obtained in the volume of reservoir swept by enriched gas. Subsequently, it was observed that the enriched gas way breaking through at producing wells earlier than expected, and that volumetric sweep efficiency was lower than anticipated. Simultaneous injection of water and enriched gas was begun in 1963 in an attempt to improve sweep efficiency. In 1965 it was determined that sufficient enriched gas had been injected into the reservoir, and the injection substance was converted to water and dry gas. The experiment program in Zone 20B-07 is largely complete. Cumulative production froth the reservoir has been 3.7 million bbl of oil, and oil recovery froth the Zone 20B-07 enriched-gas project has been 50 percent of the original ail in place. Production to date has greatly exceeded the native dissolved-gas-drive recovery that was predicted to be 22.3 percent of in-place oil. As another comparison, current recovery also exceeds expected waterflood recoveries in the range of 42 to 48 percent- estimates based on experiences in similar reservoirs in this area. This paper covers field results, particularly those regarding displacement and sweep efficiency and the effects of changes in injected fluids. Reasons for observed performance are discussed with regard to future application of miscible displacement. Introduction The Seeligson Zone 20B-07 enriched-gas-drive project is completed. The theory of miscible displacement, reasons for experimenting in the zone, and early performance data are well documented by earlier reports. This paper presents final results of the project and discusses factors that will assist future evaluations of enriched-gas-drive applications. Reservoir Description The Seeligson field area is one of several multipay anticlinal structures trending from southwest to northeast along the Vicksburg flexure in Southwest Texas. Seeligson Zone 20B-07 is encountered at approximately 6,000 ft on the eastern flank of the Seeligson structure in Kleberg County, Tex. The reservoir is bounded on the northeast and south by strandlines and to the west by faulting (Fig. 1). Drilling Once 1962 has expanded the reservoir limits and established an oil-water contact to the east. The average reservoir dip, west to east, is approximately 4 deg. Zone 20B-07 contains approximately 877 oil-productive acres and currently is developed with 16 wells. Fig. 2 is a net-sand isopachous map of the reservoir. Average sand thickness is about 12 ft, with the maximum sand development being 42 ft in the center of the reservoir. Reservoir oil was saturated at the original reservoir pressure of 3,010 psi and was associated with a small gas cap. The original dissolved GOR was 600 scf/STB at separator conditions of 300 psi and 75F. Gravity of the produced crude was 40 deg. API. Average sand characteristics include 100-md permeability, 19 percent porosity and 31 percent connate water saturation. Porosity was lowered from that previously reported, based on sonic logs of the recently drilled wells. The lower porosity values resulted in essentially the same original oil in place as previously reported (7.4 million STB) although the reservoir was increased in areal extend. JPT P. 369ˆ

A New Depletion-Performance Correlation for Gas-Condensate Reservoir Fluids

Abstract This paper presents the depletion-performance correlations developed using data from PVT studies and well-completion tests of 27 rich gas-condensate and volatile-oil reservoir fluids. The PVT behavior for each fluid was determined experimentally in the laboratory, and the depletion performance of each fluid was then calculated. Well-completion test data consisting of reservoir pressure and temperature, initial total gas-oil ratio, and stock-tank oil gravity were used with the depletion-performance data to develop general performance correlations. Three correlations are presented. The first equation shows the empirical relation of gas in place per barrel of hydrocarbon pore space with reservoir pressure and temperature, and initial total gas-oil ratio. The second equation is the correlation of stock-tank oil in place per barrel of hydrocarbon pore space. The third equation relates stock-tank oil production (to 500-psia depletion pressure) with pressure, temperature and oil gravity. All three correlations are also presented in convenient graphical form. Gas production to 500-psia depletion pressure is approximately 92.6 per cent of the gas in place for each fluid, so no correlation was developed for gas production. Introduction The rate of discovery of shallow, low-pressure and low-temperature oil reservoirs in the United States has been declining in recent years. For this reason, the search for oil gas gone to greater depths where high pressures and temperatures are encountered. A high-pressure and high-temperature reservoir is the environment in which many rich gas condensates and highly volatile oils are found. Because of this trend, the performance prediction of such reservoirs has become an important task of the reservoir engineer. The need and usefulness of a performance correlation based on field data that are available from the usual well-completion tests have previously been established.6 These earlier attempts have shown that the phase behavior of rich gas-condensate systems and volatile-oil and temperature.1 However, very little information on gas-condensate depletion performance5 was available at the time of these earlier attempts. The available of more recent data has made possible the development of an improved correlation. The data, as listed in Tables 1 and 2, are for 25 gas-condensate and two volatile-oil systems that were studied. The problem was to correlate the data for in-place fluids and the production data with the initial total gas-oil ratio, initial reservoir pressure and temperature, and stock-tank oil gravity. These correlations were obtained by multiple regression analysis, whereby the data were fitted to an equation by the method of least squared error.4 Basis of the Correlations The data used in the development of these correlations were obtained from depletion-performance calculations6 and well-test or production measurements. All of the independent variables used in the correlations are available from the usual well-test completion data. The reservoir volume considered is 1 bbl of hydrocarbon pore space (HCPS). The gas-oil ratio used is the total standard cubic feet of gas (at 14.7 psia, 60F) coming off the entire separator train per barrel of stock-tank oil. This minimizes the effect of separator conditions which might vary from system to system.

The Predicted Performance of a Gas-Condensate System Washington Field, Louisiana

Published in Petroleum Transactions, AIME, Volume 210, 1957, pages 102–107. Abstract A method is presented for calculating the pressure depletion performance of a gas-condensate reservoir from the original reservoir fluid composition using the laboratory determined pressure-production history and retrograde liquid accumulation as guides. Equilibrium vaporization ratios for this calculation were modified from published data until the calculated dew point pressure and retrograde liquid accumulation agreed with the values observed in the laboratory. The calculated results are compared with the produced gas composition determined by low temperature analysis during constant volume laboratory experiments of pressure depletion behavior. This comparison shows that the calculation procedure is adequate for determination of gas phase composition. Data from field separation tests in low temperature separators are presented which verify the applicability of published equilibrium vaporization ratios for a wide range of separator conditions. Introduction A reliable prediction of the pressure depletion performance of a gas-condensate reservoir is necessary in determining reserves and evaluating field separation methods. The predicted performance is also used in planning future operations and studying the economics of projects for increasing liquid recovery. Because the flow of fluid in a volumetric gas-condensate reservoir is usually single phase flow, the pressure-depletion performance is primarily a function of the phase behavior of the reservoir fluid. The properties of a gas-condensate system of major importance are:compressibility factor at reservoir temperature and pressure;dew point pressure;composition changes of the vapor phase with pressure depletion;recovery of original in-place hydrocarbons at any pressure; andretrograde condensate accumulation. These properties are most generally determined by a pressure depletion-type experiment on recombined separator gas and liquid samples in the laboratory. Ideally the pressure-depletion performance can be calculated from the composition of the original reservoir fluid if the reservoir temperature and initial pressure are known.

A Method for Predicting Depletion Performance of a Reservoir Producing Volatile Crude Oil

Published in Petroleum Transactions, AIME, Vol. 210, 1957, pages 27–33. Paper presented at Petroleum Branch Fall Meeting in Los Angeles, Oct. 14–17, 1956. Abstract Future depletion performance and ultimate oil recovery from reservoirs producing under volumetric control are often predicted with the aid of a material balance equation. when the reservoir fluid is very volatile, however, certain assumptions implicit in the use of the conventional methods are no longer valid. This is because laboratory differential vaporization test procedures do not adequately represent the reservoir depletion process and the performance of surface separation facilities. In such cases recovery of stock tank oil per unit of pressure decline can be predicted only from a detailed knowledge of the separator conditions and the over-all composition of the fluid entering the wellbore at each stage of depletion. Surface recovery is not simply related to the total quantity of liquid flowing into the well under reservoir conditions. In order to improve predictions for reservoirs which produce volatile oils, a stepwise method of calculation has been developed. This method uses relative permeability data and multi-component flash calculations to predict oil and gas production as a function of reservoir pressure. Calculations are presented for a reservoircontaining a volatile crude oil, and predicted tank oil recovery by primary depletion is more than twice that predicted by conventional methods which are known to be adequate for ordinary black crude oils. Calculated maximum produced gas-oil ratio is less than one-fourth of the conventional prediction. Wellstream compositions have also been used to determine variation in stock tank oil composition and liquid content of the separator gas. This information is of particular importance for crude stabilization calculations and for design of gasoline plant facilities to recovery LAG and natural gasoline.

An Electrical Computer for Solving Phase Equilibrium Problems

Introduction In both production and refining operations of the oil industry manyprocesses are controlled by the gas-liquid phase relationships of thehydrocarbon mixtures of interest. The quantitative behavior of fractionating ordistillation columns and stills depends on the changes in the equilibriumdistributions of the hydrocarbon components between the gas and liquid phasesas the pressure or temperature conditions may vary along the length of thecolumn or as the gross operating parameters and compositions are varied. In oilproducing operations the nature and amount of gas phase developed within anunderground reservoir as it is being depleted and its pressure declines alsoinvolve the basic equilibrium gas-liquid phase interactions. The influence ofsurface conditions of temperature and pressure and various separationprocedures on the nature and amount of stock tank oil and natural gas recoveredfrom a given well stream is likewise determined by the same basic phaseequilibrium characteristics of the hydrocarbon systems. Such equilibriumseparation of the gas and liquid phases in a well stream is of importance bothin establishing optimum separator conditions for obtaining maximum stock tankoil yields and in the general problem of crude stabilization. The phenomena involved in these problems and their quantitative aspects can, of course, be established in each individual instance by appropriate laboratoryexperimentation. It has been found, however, that by associating with theindividual hydrocarbon components functional characteristics describing theirindividual gas-liquid phase equilibrium behavior, the phase properties of thecomposite mixtures can be predicted by mathematical computation. T.P. 2733