Hydrocarbon Pore Volume Research Articles

Performance of TheTaber South Polymer Flood

Abstract A polymer flood was initiated in the Taber South Mannville B Pool in February, 1967. The reservoir, which contains a viscous, highly undersaturated crude oil with no bottom water, was depleted to the bubble-point pressure of 400 psig prior to polymer flooding. A 20 per cent hydrocarbon pore volume slug of polyacrylamide (Pusher* 700) was injected at the center of this long, narrow Lower Cretaceous' sandstone reservoir. In early 1972, injection was converted to plain water by gradually reducing polymer concentration. The reservoir was studied with reservoir simulation models in an attempt to identify incremental polymer flood oil recovery (relative to waterflood). It was found, because of unknown polymer quality in the reservoir and uncertainties in transmissibilities, that incremental polymer flood oil recovery could not be quantified. Results of a wettability study using restored cores under reservoir conditions are presented. The potential effects of wettability on polymer flood performance are discussed. It is not possible, using existing techniques, to quantify quality of produced polymer solution from the field. Some indirect observations on polymer quality are presented to help shed some light on the performance of this major polymer flood. Introduction THE TABER SOUTH Mannville B Pool, located in southern Alberta, was discovered in 1963, The pool consisted of 23 completed producers drilled on 40-acre spacing when polymer flooding was implemented in early 1967, Polymer was added to the injected water until the middle of 1972, at which time a 20.% HOPV slug of polymer had been injected into the reservoir. The polymer slug is currently being displaced through the reservoir with plain water, which consists of produced water plus sufficient fresh water to replace reservoir voidage. Oil recovery to December 1974 was approximately 18 per cent of the original oil in place. Our objective in this study was to evaluate polymer effectiveness by comparing polymer and waterflood performance using numerical simulation" models. Intercomp's three-phase, compressible polymer model was used to study the Taber South Mannville B Pool performance. The results are presented below. Geology The Taber South Mannville B Pool is an offshore barrier bar sandstone reservoir of Lower Cretaceous age. The reservoir rock, a fine-grained sand containing significant amounts of glauconite and- pyrite, is vertically homogeneous, with only a few minor shale stringers. The areal permeability variation is low, with tighter areas near the edges of the sand body. The pool is approximately 5 miles long and 1/2 mile wide. No initial gas cap or water zone is associated with the reservoir. A maximum net pay of 73 ft occurs in two wells, 3A-16 and 11–16, as shown in Figure 1. The sand reaches a structural high of 97 ft subsea in section 16; the base dips northwest at about 30 feet per mile. The average reservoir depth is 3250 ft. Basic Reservoir Data Six of the 31 completed wells in the pool have been cored. The core analysis indicates a low permeability variation, with the highest measured permeability and porosity being 6656 millidarcics and 33.9 per cent, respectively.

Determining Well Drainage Pore Volume and Porosity From Pressure Buildup Tests

Abstract Well drainage pore volume and effective porosity can be determined using the results of a pressure buildup test. The procedure uses theoretical, dimensionless Horner type curves to analyze the buildup test data. Limitations and applications of the procedure are discussed, and an example is given. Introduction Knowledge of the well drainage pore volume and effective porosity of a reservoir is of vital importance to the petroleum engineer. These values, when combined with the associated hydrocarbon saturation, are necessary for estimating the reserves of a particular reservoir. Furthermore, these reserves are particular reservoir. Furthermore, these reserves are used to plan additional wells, to establish operating procedures, and to study the feasibility of various procedures, and to study the feasibility of various enhanced recovery processes. The need for an accurate value of the hydrocarbon pore volume is obvious. The use of geologic and well logging data to estimate both effective porosity and well drainage pore volume is well established. Unfortunately, pore volume is well established. Unfortunately, these methods are limited to a determination of rock properties at or near the wellbore. Accordingly, many important decisions affecting reservoir performance are based on information that performance are based on information that represents, at best, a minute fraction of the total reservoir system. A method of analysis that encompasses a larger portion of the reservoir is clearly needed. It has long been recognized that the pressure response of a well following a disturbance in flow rate is indicative of the reservoir properties within the drainage volume of the test well. This idea has led to the development of several types of transient pressure tests that can be used to determine, among pressure tests that can be used to determine, among other things, the average permeability and volumetric average pressure associated with the well. Unfortunately, the effect of porosity on pressure response is not as explicit as the effect of permeability. Consequently, only moderate success has been achieved in calculating porosity from the results of a pressure test. The pressure drawdown test is currently the only transient pressure test commonly used for obtaining well drainage pore volume. Although the pressure drawdown test offers the advantage of surveying a large fraction of the well drainage volume, its application is severely restricted by a number of factors. First, this test must be conducted for a longer time than that necessary to achieve pseudosteady state within the drainage volume of the well. The producing time required to meet this condition, particularly in low-permeability reservoirs, often makes the test impractical. Second, the test requires that a constant flow rate be maintained. From an operational standpoint, this can be very difficult for the long test times required. Third, for large drainage volumes the rate of pressure change may be too small to measure during the pseudosteady-state flow period. This is a major limitation since the pore volume is inversely proportional to the rate of pressure decline. Finally, if the reservoir is in communication with an aquifer, the test will give optimistic and misleading results. Therefore, this method has very limited application in the determination of reservoir pore volume. The design and analysis, as well as the limitations of the pressure drawdown test have been detailed in the pressure drawdown test have been detailed in the literature. A more versatile and commonly used transient pressure test for evaluating reservoir properties is pressure test for evaluating reservoir properties is the pressure buildup test. The two methods most commonly used to evaluate pressure buildup tests were published by Horner and Miller et al. Horner showed that plotting buildup pressure vs the logarithm of the time ratio, (t + delta t)/delta t, yields a straight line with slope inversely proportional to the average formation permeability. Horner assumed an infinite reservoir to develop his method of analysis. SPEJ P. 209

Use of Uncertainty Analysis in Evaluating Hydrocarbon Pore Volume in the Rainbow-Zama Area

A technique, including Monte Carlo simulation and history matching, for evaluating hydrocarbon pore volume in an environment of uncertainty is demonstrated through a case history study of a specific Rainbow-Zama pool in Alberta. Introduction Oil was discovered in the Rainbow Lake area of northern Alberta in 1965 and the play extended north to the Zama Lake area in 1966. By the end of 1968 some 150 separate pools had been discovered, with total oil in place approximating 2.1 billion bbl, of which 800 million bbl is estimated as recoverable under the producing mechanisms now in effect. The play is by no means exhausted and could extend both to the northwest and to the southeast. It is conceivable that the Rainbow-Zama area of northern Alberta will ultimately be found to hold 5 billion bbl of oil, 3 billion of which will be recovered through various recovery schemes. The features exist as pinnacle reefs that grew on a common platform.5 There is an extreme range in the size of the reefs: the hydrocarbon pore volume varies from 500,000 to 500,000,000 STB. In general, the larger features have been found in the Rainbow area. The seismograph has proven to be particularly successful in the Rainbow-Zama area. Modem techniques, including common-depth-point stacking, have located the crestal portion of the pinnacles with almost 100 percent success. The areal extent of the reefs and the size-shape relationship are not so easily defined by seismic methods. A few wells, drilled on development locations in the flank positions, either did not encounter the reef or encountered it below the oil-water contact. This presents a paradoxical situation in which the risk associated with an exploratory well is essentially nil and the risk associated with a development well is high. As a result, development wells have been drilled only where the seismic data show the feature to be large. There are few off-reef wells, and many of the features are one-well pools, penetrated only by a crestal well. In Alberta, producing capability exceeds market demand. For this reason, a production allowable is established for each well in the Province by the Alberta Oil and Gas Conservation Board. This allowable is prorated on the basis of the recoverable reserves. Initially, the Conservation Board assigned Rainbow-Zama allowables by assuming that the wellbore parameters were representative of the 160-acre drilling spacing unit. Seismic data indicated the features to be essentially circular, although seismic estimates of the exact reef flank position and side-slope angles proved to be unreliable. Fig. 1 is a schematic of the four gross models that could be deduced from the seismic data and initial wellbore evidence. The range of uncertainty is extreme. For example, the feature could conceivably vary between a cone and a cylinder, with the conical volume being one-third the cylindrical volume. The most likely geometric configuration is that of the frustum of a cone with side slopes of 30° to 45°. Most of the available acreage in the Rainbow-Zama area was competed for under bonus bid strategy. Bids were generated on the postulated reserves of an individual feature, along with the best estimate of the allowables to result from such reserves, overlaid on a most reasonable decline in production capability.

Case History of Radioactive Tracers and Techniques in Fairway Field

Radioactive isotopes have been useful in tracing the configuration of the gas displacement fronts in the Fairway alternate gas-water miscible recovery project. Variations in sweep patterns with changing reservoir pressure gradients, source of gas breakthrough, and indications of pressure gradients, source of gas breakthrough, and indications of miscibility can be inferred from tracer responses in this field. Reservoir Description The Fairway (James Lime) oil reservoir, containing approximately 421 million STB of oil initially in place at original reservoir pressure of 5,226 psia, was discovered in July, 1960, at a depth of about 10,000 ft. Productive limits of the field, enclosing approximately Productive limits of the field, enclosing approximately 23,000 acres with an average pay thickness of about 70 ft, were established in 1963. The field, now fully developed on 160-acre spacing with 152 wells, is currently producing 36,000 BOPD under pressure maintenance by alternate gas-water injection. The Fairway (James Lime) reservoir is a reef deposition with three major porous intervals - Upper A zone, Lower A zone and C zone - which are lithologically related to various stages of reef development. The three major zones are connected vertically in several areas of the reservoir, although the zones are distinctly separated by dense lime over most of the field. Average permeabilities of the three zones vary widely - 42.5 md in the Upper A, 22.6 md in the Lower A and 3.2 md in the C zone - even though average porosities of all three zones range from 12 to 13 percent. The James Lime oil in the main field area is an undersaturated 48 degrees API gravity crude with a solution GOR of 1,350 to 1,600 cu ft/bbl. Saturation pressure varies with depth, and ranges from about 3,950 psia at the average oil-water contact of 9,550 ft to 4,350 psia at the structural high of 9,280 ft. Laboratory psia at the structural high of 9,280 ft. Laboratory tests show that the James Lime oil is miscible with dry gas at about 4,800 psi. The irreducible water saturation varies from about 10 percent to about 30 percent, depending on rock type. There is evidence that the Lower A zone may be oil wet as a result of the presence of residual bitumen in the pore spaces. The western gas cap area of the James Lime reservoir, which exhibits different fluid characteristics and behaves as a separate reservoir, is beyond the scope of this paper. Alternate Gas-Water Injection Plan Initial economic studies indicated that pressure maintenance by alternate gas-water injection at the miscibility pressure of 4,800 psia would be the optimum recovery program. The miscible recovery program was expected to increase recovery efficiency to 50 percent, which is 13 percent more than the expected percent, which is 13 percent more than the expected waterflood recovery factor of 37 percent. The initial injection plan was based on alternating gas and water injection into several parallel lines of injection wells running generally northwest-southeast, parallel to the reef core trends. The A zone and C parallel to the reef core trends. The A zone and C zone were to be operated as separate reservoirs insofar as possible. Plans were to begin the program by injecting into the A zone an initial gas slug equal to 3 to 5 percent of the hydrocarbon pore volume in the area of injection in the first line of injection wells on the east side of the reservoir. Initial gas slugs in the first line of injectors were to be followed by initial water slugs equal to approximately 50 percent of the preceding gas slugs. After placement of the initial preceding gas slugs. After placement of the initial slugs, subsequent smaller gas and water slugs were to be injected alternately at an approximate 1:1 gas-water injection ratio. The initial gas slugs were larger than subsequent slugs of water and gas, on the theory that a miscible bank of gas could be maintained in contact with the oil. Gas injection into the first line of injection wells was begun in March, 1966, shortly after the entire field was unitized in Oct., 1965. P. 1217

A Current Appraisal of Field Miscible Slug Projects

In addition to experimental and mathematical studies of miscible slug flooding, more than seventy field tests have been initiated. Of those tests carried out where conditions are favorable to miscible flooding, more than forty percent have shown good or encouraging oil recovery efficiencies. Introduction Over the past 20 years, research efforts have been directed toward improving conventional gas injection by increasing the oil displacement efficiency. This research has resulted in a family of so-called "improved gas drives". The common characteristic of these improved gas drives is that a solvent bank is developed or created within the reservoir. This solvent bank is miscible at its leading edge with the reservoir oil and miscible at its trailing edge with gas. This bank can be driven through the reservoir, displacing oil ahead of it, resulting in higher oil recoveries than those normally obtainable by conventional gas drive. This miscible bank can be created either from hydrocarbon components already present in the reservoir or from components contained in the injected fluid. The former is termed high-pressure or vaporizing gas drive and the latter is termed miscible slug flooding. The mechanism of high-pressure (miscible) gas drives has been described in the literature, and the steps involved in miscible slug flooding have been taught by Morse and Crump. In miscible slug flooding the constituents in the solvent bank are injected as a fluid - either as liquid at reservoir conditions (LPG slug flooding) or as liquefiable components contained in rich gas (condensing gas drive or enriched gas drive). In miscible slug flooding, mixing bones form between the reservoir oil and the solvent bank and between the solvent bank and the scavenging gas. Early research studies were devoted to a quantitative description of the factors affecting mixing-zone growth. Other studies have focused upon determining what composition of injected rich gas would develop within the reservoir a solvent bank that is miscible with the reservoir oil. The areal and vertical sweep efficiencies expected during miscible slug flooding have also received research attention. Engineering efforts have also been concerned with methods of predicting the oil recovery possible by miscible predicting the oil recovery possible by miscible slug flooding. Based upon these laboratory studies, the preferred reservoir and operating conditions for proper application of miscible slug flooding have been defined as follows: Reservoir oil viscosity of 5 cp or less. Formation with less than about 25 ft ofcontinuous vertical section. Permeability less than about 100 md. No continuous high permeability streaks. Reservoir pressure sufficient for miscibility, atboth the leading and trailing edges of the solventbank. An injected solvent slug volume of from 2 to 10 percent of the hydrocarbon pore volume involved. Dimensionally, scaled model test results have shown that, because of gravity segregation of the oil, solvent, and scavenging gas, the tendency for channeling and bypassing of oil is reduced in permeable, steeply dipping reservoirs. JPT P. 529

Rock Compressibility and Failure as Reservoir Mechanisms in Geopressured Gas Reservoirs

A study of the North Ossun field, Louisiana, reveals that as reservoir pressure is depleted the increase in net overburden pressure initially pressure is depleted the increase in net overburden pressure initially causes rock failure and as the failure continues with decreasing pore pressure, rock compressibility decreases until eventually it reaches a pressure, rock compressibility decreases until eventually it reaches a normal value. Introduction Rock compressibility has long been recognized as an important factor in material balance calculations of oil in place for closed reservoirs producing above bubble-point pressure. For example, if the pore volume compressibility of the reservoir rock is half of the compressibility of the undersaturated oil, neglect of the rock compressibility term results in about a 50 percent overestimation of oil in place. In general, it percent overestimation of oil in place. In general, it may be stated that in material balance calculations on closed reservoirs, consideration of rock compressibility becomes increasingly important as the fluid compressibility decreases. For this reason the effect of rock compressibility is commonly neglected in studies on gas reservoirs where gas compressibility is usually great. Because gas compressibilities decrease with increasing pressures, the consideration of rock compressibility becomes increasingly important for deeper, high pressure gas reservoirs. For example, the compressibility of the gas in the reservoir to be discussed is 30 microsip** at an initial reservoir pressure of 8,921 psia. For a nominal pore volume rock compressibility of 6 microsip, neglect of rock compressibility in material balance calculations on a closed reservoir will result in a 20 percent overestimation of initial gas in place. If the rock compressibility is larger than 6 microsip, then a still larger over-estimation of gas in place results. In this study we propose that because of low net overburden pressures, rock compressibilities in geopressured reservoirs are considerably greater than for similar rocks in normally pressured reservoirs. We further suggest that as pressured reservoirs. We further suggest that as reservoir pressure is depleted, the increase in net overburden pressure initially causes inelastic rock compaction or rock failure. As failure continues with decreasing pore pressure, rock compressibility decreases and eventually reaches normal values in the range of 6 microsip. North Ossun Field, Louisiana The mechanisms proposed in the previous paragraph are believed to be illustrated by the performance of the NS2B reservoir of the North Ossun field, Lafayette Parish, La. This is a geopressured gas reservoir with an initial pore pressure of 8,921 psia at 12,500 ft subsea depth, or a gradient of 0.725 psi/ft. Table 1 gives pertinent data on this reservoir. Good geologic control is indicated by the structure map, Fig. 1. Although a gas-water contact exists, it is doubtful that the associated aquifer is very large because the reservoir appears to shale out on the west. In addition, considerable complex faulting in the area almost certainly closes the reservoir with a small associated aquifer. Good core and log data have been used to calculate an initial hydrocarbon pore volume of 583 million cu ft, and, with PVT data, to calculate an initial gas in place of 114 Bscf. JPT P. 1528

A New Method for Determining a Well's In-Place Hydrocarbons From a Pressure Buildup Test

Abstract A method for estimating in-place hydrocarbons from pressure buildup tests has been derived and applied to actual well test data. Four examples utilizing this new method are presented and compared with in-place hydrocarbon estimates determined by other methods. In addition, a derivative application of the method is described for calculating stabilization tune of gas wells which have well-defined production-pressure decline curves from which reliable estimates of gas in place can be made. The method presented in this article is not based on new theory; the calculations can easily be done on a slide rule or a desk calculator, and most of the various reservoir parameters which are commonly determined from well logs or core analysis are not required. Introduction Most routine approaches for gas-in-place determinations require that years of pressure-production data be available before original pore volume estimates, based on log interpretation, can be verified. The original volumetric reserves estimates can often vary by a factor of two or more from results obtained by actual production data. Unfortunately, most significant economic decisions must be made early in the life of a well, often before reliable reserves information is available. In the case of oil wells. the original oil-in-place volume may never be verified from production decline curves unless these are supplemented with period: c bottom-hole pressure tests and material balance determinations are made. Hydrocarbon pore volume estimates require values for porosity, water saturation, drainage area and reservoir thickness. Porosity, water saturation and reservoir thickness can be obtained from well logs; however, they are normally applicable to only the vicinity adjacent to the wellbore. Generally, gas-bearing reservoirs are heterogeneous and erroneous reserve estimates may be caused by assuming various parameters constant throughout the reservoir. Gas reservoirs are normally drilled on much wider spacing than oil reservoirs and, as a result, core and well log data are assumed representative of a relatively larger area in a gas reservoir. Hydrocarbon pore volume estimates for each new well usually assume the drainage area to be equal to the well's unit acreage even if the well is far removed from the center of the unit. Pressure transients which result from drawdown, buildup, fall-off or interference tests contain much quantitative information about the well and the reservoir. Proper analysis of these tests permits the engineer to determine wellbore damage, effective capacity (kh), static reservoir pressure, distance to boundaries or flow restrictions, reservoir size and stabilization characteristics. Carefully followed well test procedures and methods of analysis can also result in reliable pore volume estimates. A method was derived by Park Jones' for determining the reservoir limits from a buildup test. By combining the reservoir limits radius with well log parameters, it is possible to determine oil or gas reserves. The new method developed in this article, and illustrated by examples from field tests, does not require various well log parameters. The gas in place determined from buildup tests agrees remarkably well with volumetric calculations based on well log and geological interpretations. The method has also been adapted for use in determining oil in place from buildup tests on oil wells. One example of this application is presented which also agrees closely with the amount of oil in place determined volumetrically by the operator of the well. The calculations can easily be made on a desk calculator and none of the various well log parameters are required. Development of Equations The most commonly used equations in unsteady-state analysis are those developed by Muskat, van Everdingen and Hurst and Horner. Many authors have investigated and accepted these equations as valid. JPT P. 859ˆ

Predicting Waterflood Performance by the Graphical Representation of Porosity and Permeability Distribution

Abstract A simple tool for predicting the waterflood performance of stratified reservoirs has been developed using a variation of the familiar layer concept. The variation suggested allows consideration of non-uniform porosity, development and mobility ratio. The procedure involves predicting both cumulative water injected and cumulative oil production in terms of percent water cut using a permeability-porosity classification system. The simplicity of the graphical approach to the cumulative oil recovery vs water cut prediction provides a convenient means of evaluating the areal as well as the vertical aspects of flood performance. Introduction A prediction technique, to be applicable to a heterogeneous reservoir should provide a means for considering variation in volume as well as permeability. The presence of multiple rock types with different porosity-permeability relationships cause the common assumption of a uniform porosity to be impractical. Further, the number of projects being evaluated in the prospect of a unitized operation make it desirable that a convenient means be provided to evaluate the lateral as well as the vertical aspects of porosity and permeability development. A variation in the application of some familiar devices can provide the solution to both of these problems. Premises The premises necessary to the use of the procedure to be described are common to other methods with the following exceptions:1. It is not necessary to assume a uniform porosity distribution or uniform water saturation.2. It is assumed that in layers of equal permeability capacity, the advance of the flood front is inversely proportional to the mobile hydrocarbon volume of the layer.3. A changing mobility ratio during the fill-up period is assumed. Procedure Rock Classification To evaluate the effect of stratification on vertical sweep efficiency, reservoir permeability data from core analysis are classified according to a system similar to that proposed by Law and demonstrated in Table 1. In addition to classifying the permeability data, the porosity of each sample is recorded. By listing both the porosity and permeability for each sample, it is possible to relate the porosity capacity and permeability capacity without the necessity of assuming that a uniform porosity exists or assuming a porosity-permeability relationship. If sufficient data are available to estimate the water saturation for each permeability range, it is possible to compute the hydrocarbon pore volume which can be substituted for the porosity capacity value, establishing a direct relationship between permeability and hydrocarbon volume. The data are summarized at the bottom of each column, with the cumulative permeability capacity and corresponding reservoir volume shown as a per cent of the total as indicated in Table 1. For convenience, values are added from the highest toward the lowest permeability range. The example in Table 1 includes water saturation data and the cumulative hydrocarbon pore volume. A plot of the cumulative permeability capacity vs the logarithm of the corresponding cumulative porosity capacity for four wells is shown in Fig. 1. Data from several wells in a single project were plotted on this graph to illustrate that more than one system is implied in each instance by the changing slopes and that there is some disparity between the plots representing different wells. Variations in rock type are responsible for the multiple systems, a common occurrence in carbonate reservoirs. Areal variation in porosity and permeability development account for the disparity between the curves. It is often possible to combine the data from several wells as shown in Table 2 to provide a composite representation of the reservoir permeability distribution. It is important that the selection of data for a composite curve describes the vertical classification of the rock. JPT P. 1285ˆ

Gas-Oil Relative Permeability Ratio Correlation From Laboratory Data

Abstract Gas-oil relative permeability ratio is an important relationship in oil reservoir predictive calculations. A correlation has been developed from 107 gas-flood krg/kro tests on Venezuelan core samples. The correlating parameter is based on restored-state water saturation tests and is applicable to both consolidated and poorly consolidated sandstone reservoirs. Data of the correlation show that there are no distinguishable differences between the mass-data groupings for the two classifications. A procedure is recommended for running sufficient relative permeability analyses to compute a geometric mean of the sample group. The geometric mean is more representative of the total core, and probably the entire reservoir. For example, while only one in four of the krg/Kro test curves agreed closely with the resultant correlation of this report, the geometric mean curves of the 16 suites (three samples or more) showed good agreement in three cases out of four. Introduction The gas-oil relative permeability, ratio is an important, fundamental relationship in most oil reservoir predictive calculations. Predictive calculations are made to estimate future reservoir production characteristics and ultimate oil recovery. The Krg/Kro relationship is specifically needed to relate the surface gas-oil ratio to the reservoir oil and gas saturation, and to calculate the relative movement of these phases within the reservoir whenever some of the more complex driving mechanisms are present. Laboratory Krg/Kro tests are not generally run as a routine analysis. Consequently, Krg/Kro data often are not available when needed because the cost of laboratory work could not be justified or the need for such data had not been properly anticipated. When laboratory Krg/Kro data are available, they are often very difficult to interpret. For example, wide divergence is sometimes shown in a family of Krg/Kro tests representative of the producing horizon in a single well. With these considerations in mind, a study was made to determine if a relationship might exist between the Krg/Kro curve and some other simple laboratory test criteria. The most probable Krg/Kro curve correlation for Venezuela described in this paper is the result of the investigation. The presented correlation defines the most probable gas-flood Krg/Kro curve through the medium of air-water capillary displacement and centrifuge water saturation tests. The laboratory procedures of these tests are relatively simple and inexpensive: test data should be widely available from routine analysis. DATA AVAILABLE, LABORATORY METHODS The report correlation utilized 107 gas-flood Krg/Kro tests run on sandstone cores of Venezuelan reservoirs. Table 1 is a general tabulation of data pertinent to the tests, while Table 2 summarizes the data. The tests include 96 from Western Venezuela and 11 from Eastern Venezuela. Eighty-two of the 107 test samples were sandstones that varied from poorly consolidated to unconsolidated; 25 were consolidated. The average sample porosity was 26.7 per cent and the average permeability was 1,121 md; these values typify the better sandstone reservoirs of Venezuela. The Welge gas-flood technique. based on fundamental Buckley-Leverett frontal displacement theory, was introducted in about 1952 and is widely accepted in the industry. The laboratory procedure is relatively simple, rapid, and can be performed on small core samples. While there have been some minor variations in sample preparation and laboratory procedure in the tests used for the correlation, these tests can be generally summarized as follows. The core sample was first solvent-extracted and dried. Connate-water saturation was restored by the oil-flushing or evaporation-blowdown methods. At the beginning of flood the hydrocarbon pore volume was completely saturated with the test oil phase. Unsteady-state gas-ail displacement then began with the injection of nitrogen or helium, while the displaced oil and gas phases were incrementally metered at the out-flow face. From the test data. the Krg/Kro curve was calculated by the Welge method. The individual oil and gas relative permeabilities were also calculated. CORRELATING PROCEDURES In attempting to establish a basis of correlation, we found that broad mid-range sections of 105 of the 107 Krg/Kro test curves could be closely duplicated by a straight line. Only two curves did not show a degree of linearity in this region. Correlation-curve definition parameters were subsequently developed from this observation of consistent mid-range linearity. Possible correlating variables were limited to the physical properties measured on core samples that were widely available as common test data and could be easily and cheaply obtained through future laboratory work. JPT P. 1111ˆ

Prediction of Waterflood Behavior in a Stratified System

Abstract A general model which approximates the effect of cross-flow has been developed to give a practical method for predicting the water flood behavior of a stratified reservoir. The model is based on a modification of Dietz's theory and allows for variations in both the permeability and hydrocarbon pore volume.in the particular cases considered, it is assumed that the permeability can be characterized by a log- normal distribution and the hydrocarbon pore volume by a normal distribution. A simple graphical method which enables the practicing engineer to predict the behavior of a stratified system is presented The results obtained by the proposed method are compared with those obtained by the Dykstra-Parsons method As a result of this study the following conclusions have been drawn: - The effect of cross-flow in a stratified system can be appreciable, particularly at very favorable or very unfavorable mobility ratios; - Under normal conditions, the effect of variations in the hydrocarbon pore volume can be neglected; and - The failure to use all of the available permeability data can lead to large errors in the prediction of the behavior of a stratified reservoir. Introduction Various methods have been proposed to characterize and to predict the waterflood behavior of a stratified reservoir. Most of the methods assume that the reservoir is composed of discrete homogeneous continuous layers. With this model, the degree of stratification can be measured by several parameters based on core-analysis data. Among these are the Lorenz coefficient and the variation of a log-normal permeability distribution. The behavior of stratified systems is usually predicted by the Stiles, Dykstra-Parsons method or some modification of these. In both of these methods the reservoir is divided into discrete homogeneous layers with no cross-flow between layers. In the Stiles method the mobility ratio is assumed to be equal to unity while in the Dykstra-Parsons method it is allowed to take on any value. Other predictive methods have been proposed; Hiatt's method allows for cross-flow between the beds and a method by Schmalz and Rahme correlates the recovery directly with the Lorenz coefficient. In this new approach, which is essentially a continuous analog of Hiatt's method, the effects of both mobility ratio and cross-flow between the beds have been included. It is assumed that the permeability can be represented by a log-normal distribution and the hydrocarbon pore volume or porosity by a normal distribution. These types of distributions have been observed by several authors, and most field data seem to confirm their observations; e.g., if these distributions are assumed and there is a 1:1 correspondence between porosity and permeability samples, the commonly encountered linear relationship between porosity and the log of permeability is obtained.

Bisti-Solvent Production During Three Years of Unit Operations

Introduction The Central Bisti unit was formed July 1, 1959, and was the first LPG miscible-phase flood project in the state of New Mexico; also it is one of the few large-scale LPG floods to date. The project consists of 10 LPG injection wells located along the major axis of the reservoir, with producing wells forming five-spot and nine-spot 160- acre patterns. A slug of nearly 1 million bbl (5.4 per cent of hydrocarbon pore volume) of LPG was injected into the reservoir and driven away from the injection wells by dry gas. The volume of produced solvent was calculated, using the equations of Dean and Brinkley. As a result of these calculations, a total of 278,269 bbl of propane and 71,682 bbl of butanes had been produced to the end of Aug., 1962, representing the first 38 months of unit operations. Reservoir Characteristics The Bisti field is in the San Juan basin near the northwest corner of New Mexico. The field is approximately 32 miles long and varies from 0.5 to 3 miles in width, with the Central Bisti unit comprising some 5,000 acres in the west central portion. Production is encountered at a depth of about 4,900 ft from bar sands of the Lower Gallup sandstone of Upper Cretaceous age. The productive interval averages 130 ft in gross thickness and consists of alternating layers of sandstone, sandy shale, and shale with only about 20 per cent of the total section having permeability of more than I md. The most permeable section, identified as the First bench, is located at the top of the Lower Gallup section. This is the principal oil producing interval and is light- gray, medium-grained, clean, well-sorted sandstone with variable permeability. The lower sands, immediately below the First bench and referred to as Second and Third benches, are inferior in porosity, permeability and productivity. The lower sands are silty and fine-grained with irregular, dark-grey, micaceous shale inclusions and partings. The best development of porosity, permeability and thickness parallels the major axis of the long, narrow sand bar, with sand pinchout along the edges. This development forms a stratigraphic trap. Analysis of cores from 35 wells in the western portion of the field revealed an average hydrocarbon porosity (excluding water saturation) of 12.16 per cent for the First bench and 7.83 per cent for the Second bench. These values represent averages for wells located near the productive boundary as well as wells located within the fairway area. Hydrocarbon porosity of the fairway portion of the First bench averaged 14.7 per cent. Reservoir Fluid Two bottom-hole samples of reservoir oil were obtained during the early development of Bisti. These samples represent reservoir oil at British American Marye No. 1, NE NE Sec. 1–25N-13W, and Sunray DX Federal C-21 (Central Bisti unit No. 17) NE NE Sec. 8–25N-12W. The samples reflect similar physical properties. Bubble-point pressures of the Marye No. I and Federal C-21 samples were 1,155 and 1,260 psia at 145F respectively. Original reservoir pressure was estimated to be 1,612 psig at + 1,300 ft datum, the latter approximating the mid-point in the reservoir oil column. Structurally, the reservoir oil samples represent the mid-oil column at a position in the field located between the gas-cap area in Range 11-West and the structurally low pinchout areas. JPT P. 515^

Performance of a Miscible Flood with Alternate Gas-Water Displacement

Abstract A miscible displacement project was begun in 1960 in the Midland Farms (Wolfcamp) field. Initially, enriched gas was injected which was equivalent to 2 per cent of the project-area hydrocarbon pore volume. This solvent volume, which is small compared to volumes proposed in some of the literature, was followed by a residue gas buffer and is being displaced by alternate gas and water slugs. Favorable response, such as increased reservoir pressure, increased producing capacity and apparent miscible-bank movement indicates predicted recoveries may be achieved. Additional performance may prove many field applications now considered impractical can be economically justified. Introduction A full-scale miscible-drive project has been in operation in the Midland Farms (Wolfcamp) field since May, 1960. The project utilized a propane volume equivalent to 1 per cent of the hydrocarbon pore volume in the project area. It began with the injection of 13.9 million gal of residue gas which, with the propane, formed the enriched gas phase of about 2 per cent hydrocarbon pore volume. The enriched gas was followed with a dry-gas buffer, and now alternate slugs of water and residue gas are being utilized as the displacing media. Geological and Reservoir Data The Midland Farms (Wolfcamp) field, one the many fields in the huge Midland Farms complex, is located approximately 14 miles southeast of Andrews, Tex. The location of the field with relation to other major fields in the general area is shown in Fig. 1. The field lies on the western edge of the Midland basin in a transition zone between the Central Basin Platform and the Midland basin. Fig. 2 illustrates the Wolfcamp structure contoured on the top of the limestone section which is considered the top of the reef build-up in the area. The pay section, ranging in depth from 8,350 ft to 8,500 ft, is composed of fine- to medium-crystalline organic limestone. Some oolitic deposits are present which are associated with the better-quality pay. In some wells, Wolfcamp reefing is absent. The degree of reef build-up at the various wells determines the structure. Fig. 3 is an illustration of the typical pay characteristics of the field. Table 1 lists the reservoir rock and fluid properties. Primary Performance and Secondary Recovery Planning Until secondary recovery was started, the reservoir had operated since discovery in 1953 under a solution gas- drive mechanism. Through May, 1960, the cumulative production for the field amounted to 1.97 million STB. During the primary production phase the average reservoir pressure had declined to approximately 1,600 psi. As a result, the producing wells in many cases had also reached a stage requiring artificial lift equipment. Fig. 4 graphically illustrates the field performance since discovery. The field was unitized for the purpose of conducting secondary recovery operations. Although initial plans were to water flood the reservoir, laboratory experiments were conducted which indicated that a miscible drive could be established with moderate propane requirements. Subsequently, the enriched gas-drive project was selected, based on favorable incremental economics over conventional water flooding. JPT P. 372^

Small Propane Slug Proving Success in Slaughter Field Lease

Abstract A propane-gas-water miscible-phase displacement process has been in operation on the H. T. Boyd lease, Slaughter field, since May, 1958. The total requirement of 255,416 bbl of liquid propane and 2,625 MMcf of residue gas has been injected. These materials were injected to obtain the high unit displacement efficiency of a miscible process in a portion of the reservoir. This lease is not bounded and the pressure differential created by high injection rates places a limit on the area to be miscibly swept. Water injection is being used to improve the miscible sweep, to displace the oil bank, and to flood portions of the reservoir not miscibly contacted. A total of 4.2-million bbl of water has been injected. The lease performance history indicates the small propane slugs have created a substantial oil bank in the major portion of the reservoir. Considerable test data have been obtained and interpreted to determine the type of displacement in each injection area. These data show that a portion of each injection area has been miscibly swept. There is a wide variation in performance between the areas, and this difference is attributed to permeability stratification. Field data have been used to make required changes in the original plan of operation, and miscible displacement is continuing. The small propane slugs (about 3 per cent of the volume to be miscibly contacted) are expected to sweep at least 18 per cent of the hydrocarbon pore volume. The predicted recovery for this project is 58 per cent of the oil in place. This recovery is about 1.5-million bbl of oil over the predicted waterflood recovery, and it is almost three times the predicted primary recovery. Introduction A combination secondary recovery process has been in operation on the H. T. Boyd lease, Slaughter (San Andres) field, Tex., since May 9, 1958. A propane-gas-water miscible-phase displacement process to be followed by water flooding is being used to increase the ultimate recovery from this lease. The project was designed to take advantage of the desirable features of both processes. The past performance of this project has answered some of the questions concerning the application of the gas-miscible slug process. Considerable test data have been obtained and interpreted to learn bow effective the small propane slugs injected here have been in displacing oil miscibly and to aid in developing plans for the future operation of the lease. Plan of Operation The original plan of operation can be described in terms of the type of fluid injected and the type of displacement planned. Step 1-Inject a volume of propane into each injection area to miscibly sweep a portion of the hydrocarbon pore volume. The liquid propane is miscible with the reservoir fluid and efficiently displaces it from the rock. Step 2-Inject a volume of lean hydrocarbon gas, equal to the volume left as residual gas to water flooding in the volume to be swept miscibly. A gas slug is injected to maintain a buffer zone between the propane and the water zone. The gas must be injected at a rate high enough to maintain the miscible-displacement pressure at the gas-propane front. The miscible-displacement pressure for this project is about 1,300 psia. The gas will then miscibly displace the propane slug. Step 3-Inject water at a high pressure to maintain the pressure of the gas-propane boundary at, or above, the miscible-displacement pressure until the planned sweep by miscible displacement is achieved. The water immiscibly displaces the gas slug and increases the sweep efficiency of the miscible phase. Step 4-Continue to inject water to abandonment, but at a lower pressure. This lease is surrounded by other producing wells and the pressure of the gas-propane front must be maintained above 1,300 psia. This is several hundred pounds greater than the offset lease pressures. This limits the area to be swept miscibly by propane-gas-water injection to the central portion of the lease. After the miscible sweep has been completed, water flooding will be used to increase the recovery from the portion of the lease not contacted by the miscible sweep. The area to be swept by water will depend upon the extent of the offset lease cooperation. Geology and Reservoir Data The Slaughter field is one of several large San Andres reservoirs in the Permian Basin. JPT P. 31^

A Method for Computing Pressure Behavior and Volume of Gas-Storage Reservoirs

Abstract The volume of gas in storage reservoirs may be computed from estimates of hydrocarbon pore volume and gas density. However, both are difficult to estimate accurately. Further, no adequate method has been presented for estimating reservoir performance during operation for volumetric gas-storage reservoirs. Normally, gas-storage reservoirs exhibit small pressure gradients in the area containing the storage wells, even under conditions of maximum injection or withdrawal. A zone of low permeability usually surrounds, and is in communication with, the permeable zone which causes the storage reservoir to exhibit a definite pressure lag, as evidenced by lack of pressure stabilization after extended periods of shut-in. An analysis is presented for determining pore volume and gas in place, and for predicting future reservoir behavior of such reservoirs. The mathematical development is presented and a solution is shown for an operating storage reservoir. Introduction Depleted gas reservoirs are often used for gas storage. The reservoir usually contains a permeable area in which numerous storage wells are located. The permeable zone permits high deliverability and injectivity with relatively small pressure loss. However, pressure equilibrium may not be attained even after long periods of shut-in because of the fact that the permeable zone is in communication with an adjacent tight section. Most of these gas-storage reservoirs are sand lenses, such as ancient beaches or offshore bars. The areal geometry of these reservoirs is normally such that flow in the tight zone will be approximately linear, and the solutions presented here should apply. Discussion For purposes of this paper, a gas-storage reservoir is considered to consist of a volume of permeable rock in communication with tight rock, all of which is surrounded by an impermeable barrier. Pressure gradients across the permeable zone are small due to low flow resistance and well density. Hence, the permeable zone is considered to be at a uniform pressure which is only a function of time as gas is injected or withdrawn. The tight zone is considered to be linear with uniform permeability and porosity, and the pressure in the tight zone is a function of both position and time. Two solutions for flow in this system are used to define the reservoir and determine its properties. The first solution is for an infinite linear tight zone in communication with the permeable zone. The expression for constant gas-withdrawal rate is ............................(1) where c is the constant. The expression is derived in the Appendix. The second solution is for a finite tight zone in communication with the permeable zone. An adequate solution may be adapted from Carslaw and Jaeger, as shown in the Appendix. ............................(2) L where b = and the 's are the roots of the DL expression L cot (L) + = 0.D Eqs. 1 and 2 are superposed to account for varying rates of production or injection and are used to fit gas-storage field reservoir history. The solution for the infinite case, Eq. 1, is first applied to field data for early times following a shut-in period. Constants BD and c are obtained by a least-squares fit of pressure and rate data. After the pressure wave from gas injection or withdrawal reaches the external boundary of the tight zone, the infinite solution will no longer apply and pressure behavior should be more nearly represented by Eq. 2 for a gas reservoir in communication with a finite linear tight zone. JPT P. 544^

Performance Prediction of a Miscible-Slug Process in a Highly Stratified Reservoir

Abstract This paper utilizes the layered-system approach, modified to include areal sweep efficiency, to determine the miscible-slug size required and to predict the performance of a miscible-slug process in a highly stratified reservoir having a permeability variation of 0.76. The slug size in each layer was determined from theoretical calculations and laboratory data which showed that, to maintain miscibility in the reservoir, the slug size had to be 8.2 per cent of the floodable hydrocarbon pore volume. Economic considerations, however, such as the value of the miscible product injected, the cost of injection and the cost of reprocessing the miscible product, limited the amount of miscible product which could be injected into the lower-permeability layers. This resulted in subjecting only 60 per cent of the reservoir to a slug size sufficient to maintain miscibility. Utilizing the relationship of producing gas-oil ratio and areal sweep efficiency as a function of pore volume injected (as obtained from data published by Dyes, Caudle and Erickson, the theoretical performance was determined. This prediction is compared with actual performance to date. Actual performance reflects an increasing percentage of miscible product in the produced fluid to a particular level, which remains static for a short period and then increases again to a higher level. This performance suggests that the reservoir has performed as a layered system. It is concluded that the layered-system approach can be used to predict performance in a highly stratified reservoir and that economic consideration is a limiting factor in determining the amount of the reservoir which can be miscibly swept. Introduction The Paloma zone in the Paloma oil field, Kern County, Calif., is comprised of several sand members separated by siltstone, shale and/or cherty sections. Rapid facies changes within the zone indicate that the sediments were deposited in a "near shore" environment. As a result, the Paloma sands have a high permeability variation, and the Paloma zone is comprised of several sand reservoirs. Since one of the sand reservoirs containing crude oil was not receiving the benefits of gas injection, consideration was given to recompleting certain wells to isolate the sand in order to perform a miscible-phase injection project and, thereby, to increase its ultimate oil recovery. Before proceeding with the project, a review of the literature was made to determine the miscible-slug size that would be required to maintain miscibility throughout the displacement process. Although the review showed that considerable information was available for homogeneous systems, insufficient information was available to determine slug-size requirements and to predict performances for a highly stratified reservoir. This paper has been prepared to describe the method used to determine the miscible-slug-size requirement and to predict the performance of the miscible-phase injection project initiated in the Paloma oil field. Although the Paloma project has only been in operation since Aug., 1958, sufficient production history has been obtained so that a comparison can be made with the predicted performance. DESCRIPTION OF RESERVOIR The reservoir in which the miscible-phase project was initiated in the Paloma field is shown on Figs. 1 and 2. Reservoir properties are as follows: average sand thickness, 43 ft; porosity, 19.1 per cent; water saturation, 47.2 per cent; oil viscosity, 0.328 cp; reservoir temperature, 250F; reservoir pressure, 3,500 psi; gas saturation, 21.2 per cent at time of miscible product injection; and total net hydrocarbon pore volume, 19,993,000 reservoir bbl. LIMITATIONS The method described herein utilizes a layer-system approach, where injection into and production from each layer is assumed to be proportional to the layer's fractional capacity. The effects of increased fluid mobility on injection and production rates, in layers which have had breakthrough, are not reflected in this method. There has been considerable controversy over the slug size necessary to maintain miscibility throughout the displacement process. JPT P. 81^

Miscible Displacement - A Multilayer Technique for Predicting Reservoir Performance

Abstract A three-dimensional, multilayer, mathematical model has been developed for predicting performance by miscible displacement. Areal and vertical coverage, total gas-oil ratio, propane-oil ratio and oil-recovery factor for the multilayer system are computed as functions of hydrocarbon pore volumes of solvent injected. The technique has been programed for use on the IBM–7090 digital computer and was used in calculating performance for continuous miscible displacement of a five-spot, 50-layer system. Results reported are based on the use of published laboratory data for a single, uniform five-spot layer. However, the technique is sufficiently generalized to calculate performance of any system of layers of any pattern configuration and mobility ratio, provided data are available to describe performance of a single layer. The technique has also been adapted for predicting oil recovery resulting from various gas-driven slug sizes. The results presented for both continuous and slug-type injection show that permeability variation has a significant effect on oil recovery but that solvent composition, within the range studied, has a lesser effect on oil recovery. Introduction Experience from many of the miscible-phase displacement projects currently in operation indicates that the injected solvent flows preferentially through the more permeable zones in the reservoir. This preferential solvent flow in the high-permeability streaks results in a reduction of vertical coverage (Cv) and an attendant decrease in oil recovery. The multilayer technique presented in this paper uses areal coverage (C A) data for a single layer from the literature and from laboratory measurements of displacement efficiency (herein referred to as microscopic coverage, C M) to calculate areal coverage (C A) and vertical coverage (C V) for the multilayer system. Oil recovery for the multilayer system is obtained as the product of (C A) (C M) (C V). It is assumed that C V in a single layer is 100 per cent; therefore, (C A) (C M) is a measure of oil recovery from that layer. Data presented in the literature for a single layer generally deal only with areal coverage and/or microscopic coverage - but seldom specifically with oil recovery. Nevertheless, this technique is flexible in that either C A and C M of an individual layer or a direct measurement of oil recovery for the layer may be used. In developing this technique, the problem arose concerning a method of determining the relative amounts of solvent that will enter each layer during any increment of solvent injected. To solve the problem, a dimensionless equation was derived for expressing solvent injected into each layer as a fraction of total injection. A finite-difference method was applied in integrating the equation to determine oil recovery for the system of layers as a function of pore volumes injected. The technique subsequently was programed for solution on a digital computer. The method was applied to predict performance of a deep California reservoir under continuous miscible displacement and has been extended for calculating oil recovery as a function of slug size for gas-driven slug injection. The technique may be applied to any petroleum reservoir that can be adequately represented as a layered system, by considering permeability variation, permeability range and average permeability. Each layer is then assigned its appropriate permeability, porosity and hydrocarbon saturation. RESERVOIR VOLUME CONTACTED BY SOLVENT It has been recognized for some time that high microscopic coverage (C M) can be obtained by injecting a miscible agent, such as propane, into an oil reservoir. These high values of C M have been demonstrated in the laboratory and are normally between 80 and 100 per cent, depending on solvent and reservoir oil composition as well as on reservoir temperature and pressure. In miscible-phase displacement, because there is no interface between solvent and oil, effective permeability to solvent is the same as that to oil. (This assumes that oil saturation has not changed and that water is immobile.) Consequently, mobility ratio (M) simply reduces to that of viscosity ratio (o/ s). JPT P. 73^

A comparison of propane and carbon dioxide solvent flooding processes

AbstractA laboratory investigation was conducted on oil displacement from porous media by the use of either a slug of propane followed by gas or a slug of carbon dioxide followed by water. A comparison was made of the efficiencies of these two solvent flooding processes for petroleum reservoirs. The results of flooding experiments on cores and on scaled pattern models showed the effect, on oil recovery, of type of porous medium, pore geometry, length to width ratio of the flood pattern, fluid viscosities, and miscibility. Oil recoveries of from 60 to 80% of the original oil in place were obtained by these solvent flooding processes as compared with conventional waterflood recoveries of between 35 to 50% on the same cores and linear models. Furthermore these recoveries were obtained with solvent slug sizes of 10 to 30% of a hydrocarbon pore volume, with less solvent being required as the length of the flood path increased. Data showing the relations between mobility ratio and volumetric sweep efficiency for the propane‐gas and carbon dioxide water flooding processes for two widely different types of porous medium are included in this paper.It was concluded that in reservoirs where pressure, oil viscosity and composition, and flooding pattern are favorable, either of these solvent flooding processes would give oil recoveries considerably higher than conventional waterflood or gas drive. It was further concluded that this improved recovery would be realized earlier in the life of a flood with carbon dioxide‐carbonated water than with propane followed by gas.

Stability Theory and Its Use to Optimize Solvent Recovery of Oil

Abstract This paper shows how stability theory can be used to optimize solvent recovery of oil. Application of the theory leads to definition of the limiting conditions required for stable displacement to occur. One of these conditions is that the size of a solvent "slug" must at least equal a prescribed minimum. The criteria to be satisfied are miscibility and stability. Stability implies that no viscous fingering will occur and that mixing will be caused only by a dispersion process. Miscibility implies that complete recovery will be obtained from the swept regions. Thus, for any specified set of reservoir conditions, an optimum use of solvent is defined. Introduction The early outlook for solvent flooding as a means to increase oil recovery was very favorable. Some laboratory results indicated that a "slug" containing perhaps 2 to 3 per cent of a hydrocarbon pore volume could be successful. However, other data suggested as much as 30 per cent would be required. The difference is of considerable economic importance. A theoretical explanation for these divergent results has been advanced by the author. Stability theory defines conditions for two distinct flow regimes. In stable displacement, solvent and oil become mixed by a dispersion process, and the solvent requirement is small. On the other hand, unstable displacement can degenerate into viscous fingering. The practical result is a considerable increase in the extent of mixing and, thus, in the solvent required. The present paper shows how to use stability theory to optimize solvent recovery of oil. Oil is usually considered to be displaced by a small amount, or a slug, of solvent. Gas in turn follows solvent. Any fingering will permit contact of nearly solvent-free gas and oil, leading to immiscibility and reduced recovery. Thus, our optimum is defined by two restrictions - stable flow and miscibility.

The Development of Stability Theory for Miscible Liquid-Liquid Displacement

Abstract A stability theory is developed for miscible liquid-liquid displacement within a porous medium. In the usual case considered, a high-density high-viscosity "oil" is displaced downdip by a low-density low-viscosity "solvent". Perturbation methods are used to find the conditions under which the spreading mechanism changes from the stable dispersion process to unstable viscous fingering. We find that instability is conditional, that there is a dependence on the shape of a disturbance leading to a "diameter" effect and that very difficult experimental scaling problems may result. A useful consequence is the definition of a minimum "slug size" for stable miscible displacement. This should make possible optimum use of the solvent process for oil recovery. The results may apply to many situations in which one fluid displaces another of somewhat different fluid properties within a porous medium. Introduction The process of miscible liquid-liquid displacement looked very favorable when it first received serious consideration as a means to increase petroleum recovery. Some early laboratory results were interpreted to mean that only a small "slug" of solvent was needed, perhaps 2 to 3 per cent of a hydrocarbon pore volume. This "slug" could recover the oil in an entire reservoir provided the fluids remained miscible. Only a slow growth of the "mixing zone", or gradual transition from oil to solvent, should occur. This would follow naturally from mixing by a dispersion mechanism such as that described by Scheidegger. And, indeed, laboratory cores have shown this kind of behavior provided solvent viscosity was at least as great as that of the oil. The same kind of behavior has also been observed with solvent viscosity lower than that of the oil after the distance traversed became large. Not all laboratory results have been this favorable, however. Mixing zone growth may become proportional to the distance traveled rather than the square root of this quantity. Such behavior accompanies high rates in short systems of large diameter, provided the viscosity ratio is adverse. If this more rapid spreading were to persist in a reservoir, the solvent requirement for miscible "slug" displacement could exceed 30 per cent of a pore volume. There is considerable economic importance in the difference between 3 and 30 per cent solvent.

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

Abstract An enriched gas-drive project was initiated in Zone 20-B, Seeligson field, Jim Wells and Kleberg counties, Tex., on March 19, 1957. To date nearly 2.5 billion cu ft of an enriched gas mixture composed of about 50 per cent methane and 50 per cent propane has been injected through two injection wells. There are 11 producing wells in this project. Cumulative production since injection began is approximately 750,000 bbl of stock-tank oil, and the current oil-producing rate for the reservoir is 1,000 bbl per calendar day. Enriched gas in appreciable quantities has reached the first row of producing wells down-structure of the two injection wells. As predicted from laboratory work, displacement of reservoir oil by the enriched gas mixture has proved to be highly efficient. Project results to date are encouraging, and additional information should be gained from a conformance evaluation workover to be performed in the near future. The project is still at an early stage of operation because the enriched gas volume injected to date is only 16 per cent of the hydrocarbon pore volume. Introduction The enriched gas-drive process entails the injection of a gas which has been enriched through the addition of such intermediate hydrocarbon components as ethane and propane to the extent that it is completely soluble in the oil to be displaced. Enriching components in the gas are absorbed into the oil, forming a bank of swelled oil that is miscible with the oil ahead and the gas behind. There is no sharp interface between the displaced and displacing fluids; rather, there is a zone of short duration between the injected and resident fluids in which the fluid properties grade from those of the displaced to the displacing medium. Under these conditions, capillary and interfacial tension forces are not believed to be present. High recovery is made possible by removing or reducing the interfacial tension between the injected material and the reservoir oil to the extent that essentially no oil is left as residual droplets.