Water Injection Project Research Articles

ブンドク油田の水攻法プロジェクト

ブンドク油田の水攻法プロジェクト

A Prediction Technique for Immiscible Processes Using Field Performance Data (includes associated papers 13392, 13793, 15146 and 19506 )

Summary A prediction method based on the use of performance history of a waterflood proposed in 1978 by Ershaghi and Omoregie is scrutinized here. Using a reservoir simulation approach, performance data for some hypothetical waterfloods are generated to test the application of the proposed technique to various floodpatterns, reservoir properties, and field operating conditions. Recently published results on the behavior of relative permeability curves for immiscible processes areused to substantiate the assumptions inherent in the proposed technique. The limitations of the technique are discussed and applications to some actual case studies are presented. Introduction Conventional waterfloods and modified waterfloodsusing various additives still constitute the bulk of the fluid injection projects active in the U.S. and elsewhere. During the history of a water injection project, reservoir engineers are expected to predict performance using the past response data. A literature review shows that over the last 40 years, there have been many techniques proposed for such prediction purposes. These techniques range from empirical correlations to various analytical models. In addition to these techniques, the advent of reservoir simulation has resulted in the availability of a very powerful tool for performance prediction. Many operators are still reluctant to use reservoir simulators because of inadequate reservoir data or insufficiently trained personnel to conduct simulation studies. Simple models often fail because of the inherentassumption as to the nature of the displacement mechanism or the misrepresentation of the real reservoir conditions. Many years of field and laboratory research by the petroleum industry and the academia has resulted in abetter understanding of the multitude of parameters influencing the efficiency of fluid injection projects. It is well established that for immiscible displacements, reservoir heterogeneity, relative permeability characteristics, fluid viscosities, and flood pattern are the most important factors. No prediction method can be used successfully in afield where the real reservoir is represented by laboratory-derived data and inadequately defined reservoir heterogeneity. A successful prediction technique requires input from the real reservoir performance. Alumped-parameter model that would embody all properties of the reservoir and the operating conditions can lead us to a realistic prediction of performance. In 1978, Ershaghi and Omoregie presented a technique for extrapolation of water-cut vs. recovery curvesin waterflood operations. The technique allows one togenerate a field composite relative permeability ratiocurve that includes reservoir properties as well as operational problems. The main assumptions were (1) the plot of log (krw/kro) vs. Sw is a straight line and (2) the leaky-piston displacement concept of Buckley and Leverett is applicable. Since Ref. 1 was published, many operators have contacted the authors with questions and comments about applying the technique to their specific cases-ranging from natural bottomwater drive to modified waterflood. Two additional papers about the technique haveappeared in the literature by others. This paper is aimed at clarifying ambiguities about the technique and providing guidelines for its application. Review of the Technique Assuming that log (krw/kro) vs. Sw is a straight line, the concepts of fractional flow and the frontal advance theory proposed by Buckley and Leverett may be used toderive the following relationship between the recovery and the fractional water cut: ER = (m . X) + n, where ER = recovery, X = ln[(1/fw) - 1] - (1/fw)fw = fractional water cut, m = 1/[b(1 - Swi)], n = -1/(1 - Swi)[Swi + 1/b ln(A)], A = a(mu w/mu o), and a and b from kro/krw = a ebSw. JPT P. 664^

Meren Field-The Geology and Reservoir Characteristics of a Nigerian Offshore Field

Summary The Meren field is located offshore Nigeria. The field contains 1.3 billion bbl original oil in place (OOIP) and may be classed as a major oil accumulation. The more landward-lying fault blocks within the field contain an increasingly greater preponderance of oil reserves to gas reserves. All field pays display evidence of the depositional process occurring contemporaneously with fault movement. Sand sections have a tendency to become magnified in the downthrown portion of a fault block. The reservoirs are composed of sandstone with minor accumulations of authigenic kaolinite. The amount of kaolinite within a particular sand is a major factor in determining the porosity and permeability. The high porosities and permeabilities and the ability of the reservoir rock to remain unaltered by the introduction of seawater should minimize many of the operational problems ordinarily coincident with the installation of a water-injection project in the Meren field. This study indicates the possibility of using a combination of well-log interpretation with laboratory analyses of sidewall cores to help determine the areal variation of porosity and permeability within a particular reservoir. Introduction The Meren field is jointly owned by Nigerian Natl. Petroleum Co. (NNPC) (60%) and Gulf Oil Co. (40%); however, the field is operated be Gulf Oil Co. (Nigeria) Ltd. (GOCON). Fig. 1 shows the location of the field, offshore Bendel State and approximately 25 miles northwest of the GOCON/NNPC Escravos River Tank Farm and Export Terminal. The water depth in the field varies from 48 to 60 ft. Fifty-seven wells have been drilled in the Meren field, three of which are dry holes. The field was discovered in 1965. Production began in Sept. 1968. As of July 1, 1980. the Meren field has produced 347,194,961 STB oil, 321,545,190 Mcf gas, and 10,123,132 bbl water. Cumulative recovery is 26% OOIP. Performance analysis has shown that the majority of the reservoirs producing from the Meren field are being affected by minimal water influx. The reservoirs appear to be producing by a depletion-drive/gas-cap expansion mechanism. In 1978 GOCON and NNPC authorized a full-fledged feasibility study to determine the true worth of enhancing oil recovery from the Meren field. The first portion of the study ascertained reservoir configurations and their reservoir rock and fluid characteristics. The following segments were contained in this preliminary field definition study. Geological Study The Meren field was subjected to a complete geological study. All geological data were analyzed, and proper corrections were made to the original interpretations. Core Analysis The Meren 57 well was drilled and cored in late 1978 to confirm the results of the coring of the Meren 5 well in 1968. JPT P. 2095^

Status of the 10-Pattern Steamflood, Kern River Field, California

Summary The 10-pattern steamflood was converted to water injection in Sept. 1975 after 7 years of operation. Recovery is now 59 % of the presteam oil in place (OIP), with 22 % of this oil produced during the waterflood. Poststeam water injection apparently works best in reservoirs with large hot and unaffected zones remaining at the end of steam injection. Introduction Finding a way to end a steamflood project has been a problem for many operators. Usually this is done by stopping steam injection at the economic limit on the steam/oil ratio (SOR) and producing the reservoir to its new economic limit without steam assistance. Simulation studies conducted by Chevron U.S.A. Inc. have shown that higher ultimate recovery was possible by injecting water after a steamflood. This subsequent recovery results from heat scavenging (areally and vertically) and pressure maintenance effects. Maintaining reservoir pressure aided well productivity, prevented lateral resaturation of the depleted zone by oil from outside steamdrive areas, and prevented possible subsidence. Project economics also are improved because fuel is not needed to generate steam for the recovery of this additional oil. A successful poststeam water-injection project was reported previously. This project followed an unsuccessful steam injection program. A similar poststeam project, using a mixture of air and water, also has been reported. To our knowledge, no other poststeam waterinjection projects currently exist. Our first application of poststeam water injection was in the 10-pattern steamflood, Section 3 of the Kern River field. Steam injection began in Sept. 1968. The project was converted to cold-water injection in Sept. 1975. A previous papers described this project and its performance through Sept. 1973. Our paper updates the project's performance and status as of Jan. 1, 1981. Project Description The changes in well completions, operating practices, surface facilities and reservoir data since the first report are discussed in the following Fig. 1 shows the location and status of all wells in the project. Well Completions No temperature observation wells have been added or reworked since the beginning of the steamflood. Two of the 14 observation wells, T5-1 and T5-6, are no longer used because of apparent cement breakdowns. The 10 injection wells were 5 1/2-in. jet-perforated completions without packers. All injectors were completed in the middle of the drive zone, although originally this was not recognized. None of the injection wells have required work since completion. Wellhead injection pressures during the final steamflood period ranged from 150 to 200 psi. All injection wells have been on vacuum since water injection began. Even a change in April 1979 to unfiltered produced water apparently has not hurt injectivity. Thirty-three producers now are included in the project. Well 12-4 was drilled in Jan. 1977 to replace Well 163, which was in poor mechanical condition. Well 12-4 was completed with a 6 5/8-in. liner with 40-mesh slots. Producer 7-7 was redrilled in May 1977 to sidetrack a collapsed liner. It was completed the same way as the previous wells but with 50-mesh slots. All producers in the project have slotted liners opened to other producing intervals. Slot plugging and lack of control of placement during steam stimulations are the major drawbacks to liner completions. JPT P. 2251^

GUPCO'S Experience in Treating Gulf of Suez Seawater for Waterflooding the El Morgan Oil Field

Summary Pressure maintenance by waterflooding in some reservoirs may be considered essential for satisfactory oil recovery. The main objective of waterflooding is to place water into a rock formation at both the desired rate and pressure with minimal expense and trouble. This objective, however, cannot be achieved unless this water has certain characteristics. The water, therefore, should be treated and conditioned before injection. This treatment should solve problems associated with the individual injection waters, including suspended matter. corrosivity of water scale deposition, and microbiological fouling and corrosion. Gulf of Suez Petroleum Co. (GUPCO) is waterflooding two fields, El Morgan and July, with Gulf of Suez (GOS) water. The paper addresses the treatment phases adopted to improve seawater quality before injection, and to control problems associated with untreated seawater. Also discussed are GUPCO'S experience in seawaterfloods, problems encountered, and corrective actions taken to overcome these problems. The chemical treatment programs adopted are presented along with final conclusions and recommendations that can be applied to similar floods in Egypt with GOS. Introduction Any treatment should be designed to solve the problems associated with individual injection waters. These problems involve suspended matters in the water, corrosivity. scale deposition, and microbiological fouling and corrosion. Additional problems that may result from water injection are injection well plugging and scale deposition both downhole in the oil producers and at surface in production equipment because of incompatible water mixing. Historically, in injection projects subsurface and/or makeup waters, river waters, and lake waters have been used. Seawater also has been used in many waterfloods. Pacific Ocean water, North Sea water, and Gulf of Mexico water have been used in similar waterflooding projects. ADMA has one seawater injection project in Abu Dhabi making use of Arabian Gulf water, which also is used in a large ARAMCO water injection project in Saudi Arabia and in Dubai as well. GUPCO has two injection projects for the El Morgan and July fields involving use of Gulf of Suez water. There is no published information on the characteristics of GOS water the treatment requirement for injection, or GUPCO'S operational experience with these projects. The main purpose of this paper is to introduce some information relative to GUPCO'S seawater injection system for the El Morgan field. Water Injection and Formation Plugging The quality of an injection water depends on its properties-e.g., suspended matter (turbidity caused by organisms and particulates), corrosivity in the system handling this water, and the tendency of the water to deposit scale. Hence the net water quality is dependent on all these properties simultaneously and is primarily connected with its capability to plug the formation rocks. Jones discussed rock plugging by solids. Generally, the tendency of an injection well to become plugged is dependent on the characteristics of both the formation and the injection water. The matrix of any rock is a fine filter for solids in the injection water (free or suspended). This is generally true in spite of differences in pore sizes that formation porous rocks may have. Consequently, the formation face of the water injection well is a good filter for the suspended solids present in the injection water and can become clogged. JPT P. 1449.

Reservoir Simulation of Variable Bubble-Point Problems

Abstract This paper presents the development of a general beta reservoir simulator that will model conventional (fixed bubble-point) problems as well as problems involving a variable bubble point, such as gas injection projects above the original bubble point and water injection projects resulting in a collapsing gas saturation, Provisions are included for allowing the pressure to cross the bubble point with the same relative ease as in a conventional simulator. Example problems are presented to demonstrate the utility of the model for gas and water injection problems. problems Introduction Many reservoir simulation problems involve treating a variable bubble point throughout the reservoir. For example, when gas is injected into an undersaturated reservoir, gas will go into solution, increasing the bubble point of the oil. As this oil moves away from the injector, the bubble point of surrounding areas also may increase point of surrounding areas also may increase because of mixing. During waterfloods of saturated reservoirs, the gas saturations in regions near the injectors frequently reduce to zero at pressures below the original bubble point. Thus, the bubble point will vary areally throughout the field. point will vary areally throughout the field.Recent publications have discussed certain aspects of the variable bubble-point problem. Most of these papers contain only a brief discussion of this problem. Ridings discusses the need for allowing saturation pressure to vary continuously throughout the reservoir as long as there is free gas associated with the oil. In the model presented by Cook et al., free gas saturation is monitored for saturated systems and the bubble point is set equal to the prevailing reservoir pressure when the gas saturation in a cell disappears. Bubble points for undersaturated cells are allowed to change because of the entrance of free gas and mixing. Spilletta et al. assume that a cell that is saturated or undersaturated at the beginning of a time step will remain so throughout the time step. They then solve their saturation equations for water and gas saturations. The bubble point of any undersaturated cell is adjusted to account for nonzero gas saturation, and the water saturation is modified to conserve oil. Steffensen and Sheffield devote their paper to the reservoir simulation of a collapsing gas saturation during waterflooding. In their model, blocks that have a free gas saturation at the beginning of a time step and have zero or negative gas saturations at the end of a time step are detected, and the bubble points for these cells are set equal to the estimated pressure where Sg reduced to zero. Gas saturation for these blocks is set equal to zero and S is set to 1 - S . The oil saturation in adjacent saturated grid blocks is then adjusted so that oil material balance is maintained. Mixing caused by flow between undersaturated blocks is neglected. This paper presents a comprehensive analysis of modeling variable bubble-point problems.* It treats the specific problems of simulating gas injection above the bubble point as well as waterflooding depleted reservoirs. It differs from previously reported work by accounting for the effect of bubble-point change on computed pressure change during a time step. Also, provisions are included that allow the pressure to cross the bubble point with the same relative ease as in a conventions! simulator In regard to waterflooding, mis paper differs from the work of Steffensen and Sheffield in mat it allows for bubble-point changes caused by mixing. DEVELOPMENT OF FLOW EQUATIONS To simulate the variable bubble-point problem, the expansion of the flow equations above the bubble point must include the effects of pressure and bubble point on fluid properties. Also, special consideration must be given to cells passing through the bubble point if both pressure and material-balance errors are to be eliminated. SPEJ P. 10

Waterflood Performance of a Shaly Sand Reservoir, Smiley-Dewar Field, Saskatchewan

The recovery from a waterflood in the Viking sand could be predicted within reasonable limits because fairly complete reservoir descriptions were available. Lack of data on residual oil saturations for the full range of sand conditions, however, made it necessary to apply a reduction factor to the floodable pore volume to make the results of theoretical waterflood calculations acceptable. Introduction The producing interval in the Smiley-Dewar field in western Saskatchewan is the Viking sand. It is of Cretaceous age and lies at a depth of about 2,400 ft. The oil pool includes an area of about 6,000 acres developed on 40-acre spacing, and the pay interval with an average thickness of about 13 ft is characterized by shale content of varying degrees, low permeability, and high water saturation. A 2,000-acre extension to the south, proved by step-out drilling after 1970, is not included in these discussions. The field began producing in the latter part of 1953. Individual wells declined steadily in rate, mainly as a result of increasing GOR's which reached an average of about 3,200 cu ft/bbl before the beginning of water injection in Feb. 1964. Cumulative oil production from the Viking sand, excluding the Viking chert zone in the lower part of the formation, was about 7.2 million bbl when injection began. Recovery by natural depletion of the solution-gas-drive reservoir was estimated at 10 million bbl of 33 degrees API crude. Detailed reservoir description indicated this recovery to be only 16 percent of the stock-tank oil originally in place. It became obvious in the early life of the field that some enhanced recovery method would be required to complete the development program. In early reviews of performance, it was established that initial costs would have to be kept at a minimum and that if the sand was floodable a conventional water injection project on an inverted nine-spot pattern would best serve the needs of the field. The initial investigations of waterflooding feasibility included waterflooding tests on sand samples, an evaluation of water supply, injectivity tests on wells, and a waterflood pilot test. Although theoretical waterflood calculations were based on a detailed reservoir description, the recovery predictions were too optimistic and were considered unacceptable as a prudent or realistic basis for analyzing the economic feasibility of the project. To our knowledge, case histories of waterfloods in similar sands were not available. But by analysis of available data, the ultimate recovery of the waterflood project was estimated to be 23 million bbl of stock-tank oil, or approximately 36 percent of oil originally in place if produced to a water cut of 95 percent. It was agreed among the four operators that the waterflood development and operation would be carried out under a cooperative plan. Field-wide water injection was begun in Feb. 1964 when the average producing rate was about 1,600 BOPD at an average GOR of 3,200 cu ft/bbl before oil wells were converted to injectors. Cumulative oil production at that time was 7.2 million bbl. Peak production at that time was 7.2 million bbl. Peak rate reached 2,970 BOPD in 1967. Cumulative oil production as of Dec. 31, 1972, was 14.3 million bbl production as of Dec. 31, 1972, was 14.3 million bbl when the rate was 1,861 BOPD with 2,366 BWPD. Projection of the existing producing trend suggests Projection of the existing producing trend suggests that the above calculated oil recovery can be attained only if waterflood operations continue for another 40 years. JPT P. 1375

Stream Channel Concept Applied to Waterflood Performance Calculations For Multiwell, Multizone, Three-Component Cases

The system of programs outlined here should enable the engineer to conduct economic feasibility studies for water injection projects containing irregularly located wells. The flexibility of this technique will permit the selection of the optimum pattern and well density for multiple-zone reservoirs and should be particularly, useful for small and medium-sized projects. projects. Introduction In practice, potential water injection projects frequently contain wells on asymmetrical spacing and hence do not lend themselves to a satisfactory analysis by many performance estimate methods. Also, fields that have been developed on an even spacing often contain irregular edge locations or geologic features that complicate application of standard waterflood prediction methods. When such problems are prediction methods. When such problems are encountered, the technique generally employed is to approximate field conditions by one or more simplified geometric forms representing average conditions. This approach is often time-consuming and may produce unreliable results, depending on the degree of approximation. Numeric simulators provide a more sophisticated analysis; however, the engineering and computer time required to model the reservoir and to match past performance generally restricts their use to larger projects. As a means of computing shape factors for any well spacing and flood pattern, Higgins et al. described a technique whereby a potentiometric model was used to define the streamline system. The volumes of channels and the shape factors were determined from potentiometric model streamline data. potentiometric model streamline data. The technique we propose here utilizes information on streamline positions similar to that obtained from the more time-consuming potentiometric model studies. Expansion of the Higgins-Leighton waterflood performance program to asymmetrical conditions performance program to asymmetrical conditions required the addition of a program to generate a streamline network and another to produce shape factors from the streamline-defined channels. The combined programs provide a rapid means of estimating programs provide a rapid means of estimating performance of small- to intermediate-sized waterfloods performance of small- to intermediate-sized waterfloods or pressure maintenance projects. Discussion of Technique The expanded waterflood performance program consists of adding programs for streamlines, related shape factors, and well-zone-field combinations to the original Higgins-Leighton method. First, a streamline network is developed that provides both the sides and axes of channels connecting injectors to producers. The areas of the channels are integrated and divided into 40 equal parts for computation of the shape factors. Since ideal conditions are assumed, the shape factors may be used for overlying or underlying zones, provided the ratios of flow capacities are the same provided the ratios of flow capacities are the same between wells. Gas and oil are then displaced from channels of the model, thus providing an estimate of water injection and oil, water, and gas production. In the final operation, the injector-producer channel performance is combined for a well-zone-field estimate performance is combined for a well-zone-field estimate of water injection and produced fluids. The application may be visualized from the injector-producer pair illustrated on Fig. 1. P. 373

Over-all Heat Transfer Coefficients in Steam And Hot Water Injection Wells

Abstract Casing temperatures and wellbore heat losses are critical variables in steam and hot water injection wells. Several papers have been written presenting methods of estimating these parameters if the over-all heat transfer coefficient is known. The over-all heat transfer coefficient for a wellbore is developed from its component terms to promote a better understanding of the concept. Specific methods have been selected from the heat transfer literature for estimating the size of each heat transfer component. Simplified calculation procedures are suggested for determining the over-all heat transfer coefficient. Comparison of calculated and measured casing temperatures during steam injection confirms the basic formulation and applicability of the suggested procedure for engineering calculations. Introduction The design of steam and hot water injection projects requires estimation of casing temperatures and wellbore heat loses. Several authors have shown that wellbore heat losses and casing temperatures can be calculated if the over-all heat transfer coefficient is known. This article discusses methods of determining the over-all heat transfer coefficient from the process variables. Development The steady-state rate of heat flow through a wellbore Q Btu/hour is proportional to the temperature difference between the fluid and the formation, and the cross-sectional area perpendicular to the direction of heat flow. The proportionally factor, called the over-all heat transfer coefficient, represents the net resistance of the flowing fluid, tubing, casing annulus, casing wall and cement sheath to the flow of heat. Thus, we can write Q = Uj Aj Tj............................ (1) Eq. 1 defines Uj, the over-all heat transfer coefficient based on the characteristic area A, and a characteristic temperature difference T,. Subscript j in Eq. 1 identifies the surface upon which these quantities are based. In theory, any radial surface could be used to determine the characteristic area. Some choices are more convenient to work with than others. For example, if hot fluid is injected down tubing it is preferred to let A, be the outside surface area of an incremental length of injection tubing, 2 to L, and let T, be the difference between the temperature of the flowing fluid Tj and the temperature at the cement-formation interface (the drill hole) Th. Then Uj = Uo, referring to the outside tubing surface area, and Eq. 1 would be Q = 2 to Uto (Tj- Th) L................ (2) If the fluid is injected down the casing or casing annulus. the characteristic area could be the inside surface area of the casing, and Eq. 1 would be written as Q = 2 ci Uci (Tj - Th) L..................(3) Subscript ci refers to the inside casing surface. An expression for the over-all heat transfer coefficient for any well completion can be found by considering the heat transfer mechanisms between the flowing fluid and the cement-formation inter-face. A brief derivation of the over-all heat transfer coefficient is presented in the following paragraphs for the case of a hot fluid flowing through tubing insulated with a dry air annulus. Other cases can be derived easily once the basic concepts are understood. Fig. 1 shows the wellbore model which will be used to derive Uto. Heat Transfer Mechanisms The rate of heat transfer between the flowing fluid and inside tubing wall is given by Eq. 4. Q = 2 ti hj (Tj - Tti) L...................(4) hf, is defined by Eq. 4 and is the film coefficient for heat transfer based on the inside surface area of the tubing (subscript ti) and the temperature difference between the flowing fluid and the inside tubing wall Tj-Tti. Heat flow through the tubing wall, casing wall and the cement sheath occurs by conduction. Fourier discovered that the rate of heat flow through a body is directly proportional to the temperature gradient in the medium. JPT P. 607ˆ

Locating a Burning Front by Pressure Transient Measurements

Abstract A pressure fall-off test on the injection well of a forward combustion project may permit us to calculate the distance to the burning front. In the mathematical description and analysis of test data, we have considered the effect of temperature on the thermodynamic properties of reservoir fluids. The temperature distribution predicted by Chu for a combustion wave has been used in analyzing a field test. Numerical solutions were obtained by simultaneous solution of the flow equation, the continuity equation and the equation of state. Although this analysis concentrated on isotropic systems, the results can be extended to systems having directional permeability. Introduction Conventional pressure fall-off tests have been used extensively to determine reservoir characteristics in gas- or water-injection projects. Such tests consist of injecting fluid into the formation at a constant rate until steady state is nearly achieved, then discontinuing injection and measuring the bottom-hole pressure as a function of time. A plot of pressure vs the logarithm of time (measured from the instant of shut-in) yields a smooth curve characterized by three distinct regions (Fig. 1): Region 1 reflects the permeability alterations in the vicinity of the wellbore; Region II reflects the reservoir characteristics further away from the wellbore; and Region III, the characteristics in the displaced fluid bank. The curves in Regions II and III are straight lines, the slopes of which are proportional to the reciprocal of the flow capacity of the formation behind and ahead of the interface as shown by Eq. 1, respectively: .....................(1) If the two-phase interface is a circular cylinder, and if the portion of the formation occupied by the injected fluid is homogeneous, the distance to the interface may he calculated by Eq. 2: .................(2) Several analysts use an assumed value for .Eq. 3 may also be used to calculate the distance to the interface: ....................(3) The coefficient of the logarithmic expression on the righthand side is the transmissibility ratio between the regions behind and ahead of the front, and is equal to the ratio of the inverse slopes of the straight lines in the plot. A pressure fall-off test can also be applied in a forward combustion project to locate the position of the burning front. The shape of the pressure fall-off curve is different from that in a conventional test. This is because the fluid properties are functions of position caused by variations in temperature in the tested zone. Also, irregular geometry in both the reservoir and the combustion front (tonguing of the combustion front) can produce similar effects. Van Poollen reported the first fall-off test on a thermal project, but he did not consider the effect of temperature variations. In this work a new method is presented which includes the effect of temperature in the analysis, and a technique is proposed for locating the burning front. THEORY ASSUMPTIONSThere are several assumptions implicit in this development:the formation is horizontal, of uniform thickness and homogeneous;before breakthrough, the burned-out zone is circular in an isotropic system, and vertical conformance is 100 per cent (although the analysis is concerned primarily with isotropic systems, it is shown that the results can be extended to systems having directional permeability);the burning front has infinitesimal thickness in the radial direction;the region behind the burning front contains only air, while in the region ahead of the front there are flue gases, hydrocarbon and water vapors and liquid hydrocarbons and water (Fig. 2); JPT P. 227ˆ

Laboratory Models of Oil Reservoirs Produced By Natural Water Drive

Abstract Reservoir depletion by natural water drive is typified by the movement of water from an aquifer into the adjacent oil-bearing formation. Prior studies of this type of water movement have generally neglected the resistance to flow in the aquifer and its effect on the movement of water into the oil bearing zone. A method for designing and operating scaled models of such reservoir systems is presented, Experimental data on a model of an edge-water-drive reservoir are shown and discussed. Introduction Most petroleum reservoirs derive at least a part of their productive capacity from water influx. This water may be injected from the surface or it may come from an aquifer adjacent to the oil zone. In either case, the reservoir engineer must be able to estimate the advance of the water as a function of either the elapsed time or the fluid produced. This paper describes a type of fluid flow model which includes the effect of viscous and gravitational forces in the reservoir and the surrounding aquifer. Natural water influx can be divided into three general (but widely overlapping) categories according to the direction of flow in the aquifer. These are shown schematically in Fig. 1. Fig. 1 (a) illustrates an edge-water-drive mechanism. In this case, water advances updip along the stratum but the movement of water is essentially horizontal and very little of the oil is actually underlain by water. The bottom-water drive (Fig. l (b)) is characterized by a thick aquifer underlying the oil zone. The water movement is generally vertical in the aquifer. The third category is illustrated in 1 (c). Referred to as the "thin oil column", this type of oil accumulation consists of oil over water in a relatively thin stratum. Fluid movement is horizontal in both the oil and water zones, except close to the producing well. One characteristic which all three of these types have in common is that part of the water flow takes place in the water invaded region of the oil reservoir while the remainder of the water flow occurs in the aquifer. The resistance to the flow of water usually will not be the same in these two regions. This occurs because the porous rock normally contains only water in the aquifer, while the water-invaded region always contains microscopic globules of bypassed oil (residual oil) which interfere with the flow of water through the rock. The production history of any type of a water-drive system is a function of two phenomena where the water goes, and how it displaces the oil in the area invaded by the water. It is usually impractical to study these two phenomena at the same time. In most cases one type of analysis is used to predict the gross movement of water in the reservoir, while a different type of analysis is employed to determine the amount of oil to be recovered from the gross volume contacted by the water. The portion of the oil reservoir which is invaded by water is mainly a function of the resistances to fluid flow in the several parts of the flow system. This gross water influx in the three types of natural water drive typically results in water cusping to the production wells either from the side or from below (water coning).In 1947, Muskat described a greatly simplified mathematical model for predicting the area invaded by water in a bottom-water-drive reservoir. This model used the Laplace equation and suitable boundary conditions to describe the isopotentials and streamlines in the flow system. The use of this model assumes that the reservoir rock is homogeneous in nature, the oil and water mobilities are equal, there is no oil flowing in the water invaded region, and external forces - such as gravity - do not affect the flow. This method has been used for both natural water drives and water injection projects. In this, as in most models, the method of images is used to reduce the size of the model necessary to describe the reservoir. SPEJ P. 25ˆ

Early Performance Review of a Successful Pressure Maintenance Project in a Deep Louisiana Reservoir

Abstract The Broussard oil sand unit, operated by Tidewater Oil Co, is located in the Erath field, Vermilion Parish, La. The unit was formed as a reservoir-wide pressure maintenance project utilizing salt water injection below 12,500 ft. Formation of a reservoir-wide unit was accomplished and pressure maintenance operations were initiated in April, 1961. Actual performance of the project during the more than three years of operation has been very close to predicted performance. Reservoir productive capacity is in excess of the unit allowable of 1,764 BOPD. Performance of the project to date indicates that ultimate recovery from the reservoir will reach or exceed the predicted value of 7.4 million STB oil. Introduction The Broussard oil sand unit is located in the Erath field of Vermilion Parish, La. (Fig. 1). The Broussard sand was proven productive with the completion of the Tidewater Oil Co. H. H. Broussard Well No. 1 (B-4) in Jan., 1957. Development of the reservoir was completed in 1959, with 13 oil completions producing 1,538 B/D from an average depth of 12,440 ft sub-sea. In addition to the 13 producing wells, four dry holes were drilled before the reservoir limits were completely defined. Pressure-production performance of the reservoir indicated the reservoir energy mechanism is solution-gas drive with a weak water drive. Reservoir engineering studies indicated that the natural reservoir energy would recover only 31 per cent of the estimated 12.8 million STB oil initially in place. Secondary recovery feasibility studies indicated that pressure maintenance by water injection could greatly increase the ultimate recovery from the reservoir. The reservoir was unitized on a 100 per cent acre-foot basis, effective April 1, 1961. On that date, Tidewater Oil Co. became operator of the first reservoir-wide unit to be formed under Louisiana Department of Conservation Act 441, Act 441 provides for forced pooling of a reservoir to prevent mineral waste if 75 per cent of both the royalty interest owners and the working interest owners approve the unitization. Sixteen days after unitization was effective, pressure maintenance operations were initiated by down-dip water injection in one well. Additional development has expanded the injection pattern to five wells, all of which are injecting water below a depth of 12,500 ft sub-sea. The pressure maintenance project has been in operation for over three years. During this time over 1.9 million bbl of oil have been produced and 3.1 million bbl of water have been injected. This paper is a review of the operation of the project during the three years since unitization with a comparison of predicted pressure maintenance performance vs the actual performance. Geological and Reservoir Data The Broussard oil sand unit is one of Louisiana's and the petroleum industry's deepest water injection projects in an oil reservoir. The reservoir is located on a monocline from a depth range of 12,200 to 12,600 ft sub-sea (Fig. 2). JPT P. 1357^

Horseshoe-Gallup Water Injection Project-An Engineering Challenge

Abstract The Horseshoe-Gallup unit, which comprises about 75 per cent of the Horseshoe-Gallup field, is located near the northwest corner of New Mexico. A pressure maintenance project utilizing water injection is now in operation in the unit. The reservoir is similar to the many other Gallup sand developments in the area, most of which are thin, elongated stratigraphic traps which produce by solution gas expansion. Several of the Gallup reservoirs are being flooded at this time, however little is known by The industry of the problems involved in these floods. The paper discusses the reservoir properties, history and problems encountered in the operation of the Horseshoe- Gallup unit pressure maintenance project. The difficulties encountered in this project are probably typical of what can be expected in most Gallup reservoirs. Although these problems could result in reduced recoveries and increased investments in comparison to conventional water injection programs, a prior understanding of the reservoir will minimize the effects and permit reasonable estimates of performance. Introduction The Gallup sand is the most prevalent oil producing horizon in the Four Corners area of New Mexico. There are 20 fields in this area which produce from the Gallup sand. These fields contain about 1,300 active wells and have produced a cumulative 67 million bbl of oil. The Gallup reservoirs are solution gas driven with rather modest primary recoveries in the order of 10 to 15 per cent. A rapid decline in producing rate, coupled with the low primary recovery, makes these reservoirs excellent candidates for pressure maintenance by water injection. At this time, there are 12 water injection programs underway in the Gallup reservoirs. Very little information has been published on these projects or the problems that arise during water injection. Presented in this case history are the problems that were found in one of these projects, the Horseshoe-Gallup unit. This unit covers most of the Horseshoe-Gallup field and is the largest Gallup flood operated as a single project in Northwest New Mexico. It is also the largest water injection project operated by The Atlantic Refining Co. The information gained in Horseshoe-Gallup should be helpful to the operators of other water injection programs in the Gallup sand. Geology and Reservoir Characteristics The Horseshoe-Gallup field is located in San Juan County, N. M., near the northwest corner of the state. Geologically, the field is on the northwest rim of the San Juan basin. Most of the field is actually situated on the Four Corners Platform with only about a fourth of the field located on the steep hogback monocline dipping into the San Juan basin (Fig. 1).Oil production is from a large stratigraphic trap of Cretaceous age about 14 miles long and 3 miles wide which trends in a northwest-southeast direction. The Gallup sand in the Horseshoe field varies in depth from 800 ft in the northwest to 3,400 ft at the southeast end of the field where it dips into the San Juan basin. However, within the Horseshoe-Gallup unit area, the sand is encountered from 800 to 1,600 ft deep. JPT P. 1101ˆ

Water Flooding a High Water-Cut Strawn Sand Reservoir

Abstract The Baylor County Water flood Unit No. 1 is located in the East Seymour Strawn field, approximately 11 miles east of the city of Seymour, Tex. Production is from a stratigraphic-trap Strawn sand reservoir at an average depth of approximately 4,675 ft, with the reservoir almost completely underlain by water. After seven years of primary production with a partial water-drive mechanism, and with producing water-cut at an average of 75 per cent, the field was unitized and a downdip peripheral water-injection project was installed. This paper discusses the geology, rock and fluid properties, and field producing characteristics. The producing history, before and after the beginning of injection, is presented as are the detailed projections of both primary and water-injection performances and the various factors considered in the design of this successful water-injection program. Introduction The Baylor County Waterflood Unit No. 1, operated by Sheets and Walton Drilling CO. of Breckenridge, Tex., is located in the East Seymour Strawn field, Baylor County, Tex. (Fig. 1). This field is approximately 11 miles east of the city of Seymour in Sections 196, 197, 206 and 207 of the T. and N. O. R. R. Survey. The producing reservoir is a stratigraphic-trap Strawn sandstone of Pennsylvanian age with an active, but limited, aquifer. By July, 1960, when water-injection operations were initiated, oil producing rates had declined to less than 8 B/D/well, and the producing water-cut had increased to an average of 75 per cent. In spite of the adverse geological conditions present with respect to water content and position in the reservoir, unitized water- injection operations have been both economically and technically successful. This paper presents the geological and engineering data and interpretations which led to the application of water- injection operations, and describes the production performance under injection operations. History and Development Production in the vicinity of the Baylor County Waterflood Unit No. 1 was discovered in June, 1950, with the completion of the J.J. Lynn, First National Bank of Fort Worth No. 1 well as a Caddo lime producer (Fig. 2). In Sept., 1951, the J.J. Lynn, First National Bank of Bowie No. 1 well was completed as a Strawn sand producer in what was designated as the Seymour Strawn field with a total of 11 producing oil wells. The East Seymour Strawn field was discovered in Sept., 1952, with the completion of the J.J. Lynn, Claude Cowan "H" No. 1 well. By Dec., 1955, a total of 24 Strawn sand oil wells had been completed, 23 of which were in what is now designated as the Baylor County Waterflood Unit No. 1 (i.e., the Cowan "B", "J" and "H" leases, Sections 206 and 207, T. and N. O. R. R. Co. Survey, Baylor County, Tex.). JPT P. 845ˆ

Time-Lapse Logging, A Valuable Reservoir Evaluation Technique

Abstract A logging procedure is described which utilizes a comparison of two logs of the same type to define a reservoir property or condition of interest. Interpretation is based on a natural or induced change in reservoir conditions during the lapse occurring between the time the two logs are run.In a gas injection project in a wet gas reservoir, a comparison of neutron logs run before and after three months of dry gas injection accurately defined the zones of gas entry in an injection well. Electric and neutron logs run before and after gas injection in a water-bearing formation were used to define the zone of injection and the magnitude of gas saturation developed. Finally, in a pressure depleted reservoir, electric and neutron logs run before and after water injection were used to compute the oil, water and gas saturations of the formations prior to water injection. A list of other possible applications of this logging procedure is presented. Introduction Well logging devices are available which can provide both qualitative and quantitative information on the chemical and physical properties of underground formations and their contained fluids. The primary use of these devices to date has been to identify and characterize potential oil or gas productive horizons in exploratory (and developmental) drilling operations. However, with the ever increasing change in emphasis from exploration to secondary and tertiary recovery operations for increasing reserves, the utility of logs must be extended to provide information about the reservoir throughout its entire productive life. It has long been recognized that the response of some downhole logging devices is influenced by changes in the formation liquid saturations. In fact, this sensitivity demands that some logs be run soon after cessation of drilling operations if true formation properties are to be determined. Similarly, however, this sensitivity has made it possible to locate zones containing mobile hydrocarbons. It is also this sensitivity of log response to changes in formation saturation conditions that can be used to advantage to provide data necessary for application to or interpretation of secondary recovery operations. As an example, prior to the initiation of a water or solvent injection project in a reservoir, a knowledge of the vertical and lateral oil saturation distribution in the reservoir is needed. Logs might not normally be considered as a means for obtaining this information because their interpretation is difficult, or even impossible, when three immiscible phases are present in the reservoir. However, interpretation may be possible if the change in reservoir saturations with time, injection, or production can be coupled with known initial or final saturation conditions. The change in saturation may be determined by a direct comparison of the same log run before and after the change. The result of this comparison may thus provide information about the reservoir that may otherwise be unattainable. Since there is a lapse in time between the logging runs, this logging procedure has been called "time-lapse logging". To demonstrate the utility of this logging procedure, detailed discussions of three field applications are presented in the following section.

Effect of Overburden Pressure on Flow Capacity in A Deep Oil Reservoir

Abstract Brine flow capacity of a 9,000-ft deep, loosely consolidated sandstone reservoir was only about one-seventh as high as that predicted fro in routine relative-permeability data. It was found that the discrepancy between predicted and actual flow capacities was due to compression of the reservoir rock by the overburden. A close agreement was obtained when calculating reservoir brine flow capacity by five methods:laboratory relative-permeability tests conducted at high confining pressure,actual injectivity data,combination of routine relative permeabilities with productivity-increase data,pressure fall-off analysis andwater-influx data. The findings of this study should be applicable to other similar reservoirs. The third method listed should be particularly useful to the engineer for predicting injection rates in general. Overburden pressure affects reservoir oil and gas flow capacity in much the same way as it does brine flow capacity. Introduction While trying to supplement the aquifer water drive in the Third Grubb reservoir of the San Miguelito field, Ventura County, Calif., it was noted that injection rates were only about one-seventh as high as the ones predicted from routine relative permeabilities. This discrepancy prompted the present study. It was found that the water treatment was adequate and that the wellbores of the injection wells were undamaged, thus leaving the effect of net confining pressure as a possible explanation. The net confining pressure is defined as the difference between the external and internal pressure acting on the formation. The external pressure is caused by the weight of the overburden, while the internal pressure is the counteracting force exerted by the fluids contained in the pore spaces. Although effect of confining pressure on permeability has been previously reported, this is the first known application of such data to a water-injection project. Reservoir Characteristics The Third Grubb zone is located in the San Miguelito field, which is a faulted anticline located along the Ventura field trend some four-miles northwest of Ventura, Calif. Production is from sandstone layers of the Repetto formation which are interbedded with shales and siltstones typical of the Pliocene in the area. Most of the sandstone is loosely consolidated and occurs in layers 1/2- to 3-ft thick. The reservoir is bounded on the north and east by faulting and to the south and west by the water-oil contact. As seen in the structure map (Fig. 1), structural relief is high with an average dip of 45 degrees. Rock and fluid characteristics are summarized in Table 1, and reservoir permeability distribution is shown in Fig. 2.The zone was discovered in 1950, and development was completed by the end of 1953. Reservoir performance is illustrated in Fig. 3. The predicted (dashed) curves were constructed by the Schilthius material-balance method using laboratory kg/ko data. The actual (solid) curves are typical for a field having a strong aquifer water drive. A pilot water flood was initiated in 1955, and since that time many treatments have been attempted to increase the low injection rates. JPT P. 962^

Combination Gas and Water Injection Project - Leduc D-3 Pool

Abstract The oil zone in the Leduc D-3 Pool is sandwiched between an extensiveoverlying gas cap and a large underlying aquifer. It is therefore free to moveto higher or lower elevations within the reef, in response to any imbalancebetween gas cap expansion and water influx. Recent studies have shown that itwill be necessary to control the movement of both the gas-oil and oil-watercontacts relative to well completion intervals for optimum recovery andperformance. The field has been unitized and both gas and water are beinginjected to achieve this objective. The results of a detailed engineering studyare being used to control injection ratios and pool performance. Introduction The discovery, geology, development and performance of the Leduc D-3 Poolhave been discussed in the past. Only a brief chronological summary of poolhistory will be given here to provide a basis for this review of reservoirengineering studies. The reservoir was discovered in 1947 about 12 milessouthwest of Edmonton. Early development was spread over a period of severalyears with a total of 535 wells being drilled to 5300 feet on 40-acre spacing.At least four separate pools have been defined as shown in Figure1. Thesubject of this paper is the "Main Reservoir", which covers almost 90 per centof the developed acreage. Its properties are summarized in Table 1. It was in 1948 that Atlantic No. 3, drilling on the eastern edge of thepool, blew wild for six months. The uncontrolled production of oil and gas-capgas during this period resulted in a sharp decline of 50 psi in reservoirpressure. An estimated 28 billion cubic feet of gas was produced withapproximately a million barrels of oil, most of which was salvaged in earthenpits.

Review of California Waterflooding Operations

Abstract This paper presents a statistical review of California waterflooding operations. Water flooding was first started in California in 1944; and, as of June 1, 1960, there were 55 active secondary recovery water-injection projects. In addition, there are 14 projects in which pressure is being maintained by water injection and 18 waste-water-disposal projects. The number of floods has increased markedly since 1951 when the crude-oil demand began exceeding the supply. However, for varying reasons, 24 water-injection programs have been discontinued. The majority of floods were started following careful preliminary engineering analyses. No serious difficulties appear to have been encountered as a result of either the relatively high oil viscosity or the rather large average zonal thickness. No data are available to evaluate increased oil recoveries which may result from the water injection, but response has been described as "good" in 20 of the 55 secondary water floods. Scope of Investigation The present investigation is concerned primarily with secondary recovery operations, or those water-injection projects which were instigated at a time when reservoir pressures had declined to values substantially less than the original. Other water-injection projects, those undertaken with the intent of maintaining reservoir pressure relatively near to the original or those primarily instigated for the purpose of waste-water disposal, have not been considered in detail. Projects in these latter classifications are listed in Tables 1 and 2. Current California Secondary Recovery Projects As of June 1, 1960, there were 55 active secondary recovery projects in California. At that time, the secondary recovery projects encompassed a total of 322 injection wells, into which water currently is being injected at a rate of 497,895 B/D. Fig. 1 shows the number of active secondary recovery projects in the state by years since the inception of flooding in 1944. This same graph also shows California's total annual crude-oil production and the annual refinery utilization of crude oil. It is interesting to note the accelerated rate at which new projects were started after the crude-oil demand began to exceed the supply. Tables 4a and 4b summarize all available data pertaining to current, active, secondary recovery projects in California.

Peripheral and Line-Drive Water-Injection Projects

Introduction The question of the pattern to be employed is one of the most important considerations necessary to the proper planning of a water-injection project. Before the decision can be made as to what type pattern should be employed, a thorough study of the reservoir parameters must be made. In some reservoirs, it is impractical to employ the five-spot pattern; in others, peripheral or line-drive patterns cannot be used. Table 1 lists the reservoir data on four waterflooding projects employed in peripheral and the line-drive waterflooding patterns. The results obtained from these projects to date indicate that high sweep efficiencies in water-injection projects can be obtained with a minimum of hazard. The Sojourner Peripheral Flood The Sojourner sand unit in Haskell County, Tex., is a waterflooding project which employs the complete peripheral waterflooding pattern (Fig. 1). This waterflooding unit has 57 wells drilled on irregular 40-acre spacing and is completed in the Strawn sand penetrated at approximately 5,100 ft. The average porosity and permeability for this sand are 14 per cent and 12 md, respectively, as determined from 35 complete core analyses. The peripheral pattern was recommended for this project primarily because of the irregular drilling pattern employed. Because of the depth and the waterflood reserves anticipated, it was impractical to employ in-fill drilling to design a workable five-spot or conventional water-injection pattern. Because of the low natural permeability, however, it was questionable if sufficient water could be injected into the sand to obtain the desired injection rate for an economical floodout time of the reservoir. From calculations using air permeability as a criterion, it originally was estimated that the maximum injection rate per well would be approximately 300 B/D at 1,800-lb surface injection pressure. A pilot water-injection program was initiated in Feb., 1956, into three water-input wells. Results of this pilot indicated that 600 to 900 B/D injection rates were permissable with 600-lb surface injection pressure.

Field Histories Show Benefits of Gas and Water-Injection Projects in Eastern Venezuela

Introduction Pressure maintenance depletion of appropriate reservoirs by fluid injection has been practiced in Eastern Venezuela since 1948. This program has resulted in benefits such as increased ultimate recovery, lowered artificial-lift costs and, in the case of gas injection, lowered treating costs and the conservation of natural gas which otherwise would be flared. The L1 sand, OG–56 reservoir, has been under a gas-injection pressure maintenance program since 1948. The oil recovery from this reservoir as of Aug. 31, 1959 had been increased 4.75 per cent over that predicted by natural depletion. This is approximately 6.3 million bbl of additional recovery, with all present outlets still on natural-flow production. The ultimate recovery by this means of depletion is 42 per cent of the original stock-tank oil in place, or 55.9 million STB. The G sand, 00–271 reservoir, was subjected to a pressure maintenance, water-injection program in May, 1954. As of Aug. 30, 1959, 34.5 per cent of original reserves (or 9.29 million STB of oil) had been produced. This represents an increase of 5.8 per cent, or 1.56 million bbl, over the predicted pressure-depletion recovery. Gas Injection in L1 Sand, OG–56 Reservoir, Central Oficina Field Reservoir Characteristics The L1 sand, OG–56 reservoir, is a north-south trending, fork-shaped channel deposit. The south boundary is defined by the Caris fault, the flanks by sand thinning and the downdip boundary by the water-oil contact at approximately 4,480 ft subsea. The reservoir consists of two segments separated by a shale break which varies from 1 ft to several feet in thickness. The segments are in pressure communication and are considered a single reservoir. Four of the 82 wells drilled in this sand cored the L1. Some 22 ft of L1 core was recovered and analyzed. The sand ranges from a coarse-grained, well sorted, clean sandstone with high permeabilities and porosities to medium-grained, poorly sorted, silty sandstone with clayey laminations at the top and bottom of the sand. (See Table 1.) The permeability ranges from 300 md in the dirtier sand to 8 darcies in the center portion of the cores. The weighted porosity was found to be 24 per cent.