STB Of Oil Research Articles

Preliminaries Study of Pilot Project Carbon Capture Utilization and Storage in An East Java Oil and Gas Field

A preliminary study for Carbon Capture Utilization and Storage (CCUS) pilot project in an East Java oil and gas field Indonesia has been conducted. CCUS projects have dual purposes: providing a means for increasing production in declined oil fields and reducing greenhouse gas emissions from oil and gas sector by injecting the separated CO2 into the declined oil and gas reservoir. CCUS will be attractive in Indonesia since it could offer additional income for the country from the incremental oil and gas productions and the implementation could use the existing regulations that valid for oil and gas sector. The study of a CCUS pilot project plan has been conducted in order to make sure that the reservoir is suitable for CO2 EOR storage. The CCUS pilot project plan is situated in an oil onshore field in East Java province, Indonesia, which was discovered in 2001. It is situated in the Tuban block, and has nearly 308 million STB of oil in place and more than 100 million barrels of oil in cumulative production. The chosen oil field for has been in production decline for several years and yet the efforts to increase recovery, such as water injection, have been ongoing. Suitability for a CO2-EOR operation is dependent on the petrophysical properties of the reservoir, such as porosity, permeability, and fluid saturation, as well as in-situ reservoir fluid properties such as oil density and viscosity. Reservoir depth is also a key parameter in making a decision as it will impact the miscibility and interaction between CO2 and oil phases. This CO2 EOR pilot project consists of a total of five wells – four production wells at the four corners of a square with an injection well in the middle. The preliminary design for a pilot scale is based on the available CO2 from the field itself, which currently produces 4.4 million SCF (240 tones) of CO2 per day. This pilot-scale test is aimed at examining the performance and viability of a gravity stable CO2 flood. The proposed CO2 injection volumes at the pilot scale are 5 million SCFD respectively, which are estimated to correspond to a production increase of 400 BOPD. For a gravity (gas cap) drive EOR system, the gas (in this case CO2) will be injected into the gas cap above the producing zone. This will help in driving the oil down to the production zones and into the production wells. When injecting into the gas cap, the wellbore integrity in the gas zone and just above the gas zone in the sealing layer must be evaluated. This is to ensure that the CO2 does not escape up the wellbore outside the casing and enter a higher layer. It is essential to include well integrity in the baseline monitoring program to evaluate periodic changes in the well integrity with injection. Monitoring is crucial for the success of a subsurface CO2 injection operation. CO2 injection monitoring is used to verify and compare the injection behaviour with reservoir simulation predictions as well as monitor for potential CO2 leakage through faults or wellbore and avoid any CO2 migration to and accumulation at the surface.

Foam-EOR Pilot: Mature Volatile-Oil Reservoir Under Miscible-Gas Injection

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 16984, ’Successful Foam-EOR Pilot in a Mature Volatile-Oil Reservoir Under Miscible-Gas Injection,’ by A. Ocampo, A. Restrepo, SPE, H. Cifuentes, SPE, J. Hester, N. Orozco, C. Gil, and E. Castro, Equion Energia, and S. Lopera and C. Gonzalez, Universidad Nacional de Colombia, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. A successful field trial in which foam was used as a gas- injection conformance enhancer was implemented in the Cusiana field in Colombia. An extensive front-end loading (FEL), including chemical-product screening, studying foam stability at reservoir conditions, coreflood experiments, reservoir modeling, and careful selection of well candidates, was executed for this pilot. The treatment was performed in a gas-injection well in the northern part of the field that had already attained a high recovery factor (RF) with high levels of gas recycling. The operation was performed by use of a surfactant-alternating-gas (SAG) method. Introduction The Cusiana field is in the foothills of the Eastern Mountain chain in Colombia, and initial production was in 1994. The field comprises three stacked reservoirs (Mirador, Barco, and Guadalupe) and two fluid systems (both volatile oils) with a rich-gas cap at near-critical conditions (pressures and temperatures greater than 5,000 psia and 250°F, respectively). The initial in-place volumes were 1.5 billion STB of oil and more than 3 Tcf of gas, with the Mirador formation containing approximately 60% of the total fluid. Development strategies have included natural depletion, gas recycling, water injection, and gas-injection redistribution. Gas recycling and redistribution provided the best recoveries. The Mirador reservoir is a low- porosity quartzarenite with significant heterogeneities in permeability, both vertically and areally. The reservoir was developed with extensive gas reinjection, beginning in the early days of production with the gas-injection wells updip on the structure. This strategy proved beneficial from the very early stages of gas injection with regard to efficient first-contact miscibility and the favorable location of the injectors. The result has been RFs greater than 50% for most of the Mirador units. After approximately 10 years of gas reinjection, high levels of recycling were observed as a result of reservoir heterogeneities and a less-efficient gas-enrichment process because of the decrease in reservoir pressure below the minimum miscibility pressure. Those conditions led to unrecovered oil in areas that are difficult to access, such as the oil rim between the producers and the aquifer, poor-quality rock layers, and bypassed areas between the producers and injectors.

Investigation of hydrocarbon and non-hydrocarbon (CO2, N2) gas injection on enhanced oil recovery in one of the Iranian oil fields

Masjed-I-Suleyman (MIS) field is the first field in the Middle East that has produced oil and has such a long production history (100 years). This field’s production started in 1911. Most of the oil production in the Middle East come from carbonate reservoirs, the majority of which are fractures. These reservoirs tend to produce at high rates in their early production period followed by low rates later on, leading to low overall recovery. The early production rate of this field was 120,000 stb/day, now reaching about 2,000 stb/day. MIS field has produced 1.39 billion stb of oil as of 1 January 2010, which makes it a giant field by world standards. 267 million of this produced oil was re-injected into the reservoir and if the recycled oil re-injected into the reservoir is included, the net total oil produced as of 1 January 2010 would be 1.123 billion stb. Based on original oil-in-place of 6 billion stb, the recovery factor equates to 23.2 % (based on the gross oil production) or 18.7 % (based on the net oil production). So this reservoir is a candidate for an EOR process. It seems the gas injection into oil reservoirs is one of the most effective methods in EOR approaches (Ganji and Haghighi 2006). In this study, the injection technique that was used includes gas injection with different fluids that causes an immiscible process. A compositional reservoir simulator has been used to determine the effect of the gas injection process on reservoir production to optimize the oil recovery for the MIS field. Simulation results show that gas injection is not useful for this field.

Clair Field: Development of a Waterflooded Fractured Reservoir

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 96316, "Clair Field - Managing Uncertainty in the Development of a Waterflooded Fractured Reservoir," by P.J. Clifford, SPE, A.R. O'Donovan, SPE, K.E. Savory, SPE, G. Smith, and D. Barr, BP plc, prepared for the 2005 Offshore Europe, Aberdeen, 6–9 September. Clair is the largest naturally fractured reservoir developed in the U.K. Recovery is by waterflood. Its 28-year appraisal period reflects the high reservoir complexity, relatively poor-quality conventional-seismic image, and uncertain effect of the conductive fractures. Clair is not predrilled, and the preferred well locations and design will change. Introduction Clair is a naturally fractured Devonian sandstone reservoir with a 1,970-ft reservoir interval containing 23°API oil 47 miles west of Shetland in 500 ft of water. Clair was discovered in 1977 and appraised by a series of vertical wells with disappointing rates. Field potential finally was demonstrated by the drilling of high-angle appraisal wells 206/8-9z and 206/8-10z, culminating in an extended well test (EWT) of 206/8–10z in 1996, which produced 500,000 STB of oil and demonstrated communication with a minimum of 500 million STB. The EWT led to sanction of the Clair Phase 1 development in 2001 and first oil in February 2005. The Clair Phase 1 development comprises the core, graben, and horst fault blocks (Fig. 1) believed to contain approximately 1.5 million STB of oil. Appraisal of the remaining areas of the field is continuing and may lead to sub-sequent development phases. Phase 1 is a single fixed-platform development. The field will be developed by drilling 22 additional wells over a 3-year period. The principal recovery mechanism is waterflood, with a planned ratio of approximately 2 producers per injector. Matrix permeability averages approximately 30 md, and oil viscosity is 3.5 cp at reservoir conditions. Recovery strategy begins with development of the more productive relatively high-permeability fluvial sands of Unit V in the large core segment and proceeds with development of the interbedded lake-margin fluvial sands of Unit VI on the basis of learning from Unit V wells. Drilling in the smaller and less appraised graben and horst blocks proceeds in parallel with the later core development. Natural-Fracture Description. The controlling feature of reservoir development in Clair is the system of natural fractures. Core and image logs demonstrate widespread granulation seams, conductive fractures, and cemented fractures. Use of seismic techniques to distinguish conductive from nonconductive faults and fractures is a key methodology in Clair reservoir description. To describe the possible fracture distributions, and to allow their incorporation into reservoir models, a number of scenarios have been generated. In these scenarios, stochastic distributions of conductive faults or joints have been generated with use of conditioning to seismic data, and these have been upscaled into fracture permeability arrays for incorporation into dynamic reservoir models.

An Evaluation of Prudhoe Bay Horizontal and High-Angle Wells After 5 Years of Production

Summary Based on 5 years of production history on 14 horizontal and high-angle wells, this paper reviews the performance of these wells compared with conventional offsets, discusses how shales influence GOR's, describes production log and well test interpretation, gives evidence that only parts of the horizontal section actually produce, and describes the success of coiled-tubing workovers. Introduction The Prudhoe Bay field is the largest Alaskan oil field. BP Exploration operates the western half, which is the subject of this paper. Production is from the Ivishak sand stone, a layered reservoir of variable properties, including high-permeability fluvial conglomerates and lower-permeability sand stones. The average sand/shale ratio is 0.9, and the shales are a major factor controlling well performance. The first horizontal well in the western area of the Prudhoe Bay field was drilled in Nov. 1985. Since then, BP has drilled a number of horizontal and high-angle wells. This paper discusses the first 14 of these wells. They have been on production for an average of about 5 years. These wells, with deviations greater than 82, are called non conventional wells (NCW's) and are listed in Table 1. The wells can be split into two groups: 10 wells located below the original gas cap in the gravity-drainage area, where high GOR's cause problems, and 4 wells in the peripheral and west end areas (see Fig. 1), where water cuts can be significant. By 1992, a large amount of information had been accumulated. This paper is the result of a review of that information-production histories, production logs, pressure-buildup tests and coiled-tubing workovers. Drilling and reservoir simulation are not covered. Cumulative Oil Produced by NCW's Compared With Offsets. To establish the benefits of NCW's, the cumulative oil produced by NCW's was compared with that produced by offset conventional wells (0 to 60). Offset wells chosen as analogs were completed in the same zone at a similar time and had no known mechanical problems (e.g., cement channels). Table 2 gives the results. These comparisons show that overall the NCW program has been a considerable success, recovering an extra 21 million STB of oil. Although some of this oil may have been produced at the expense of offset wells, it is still a large incremental volume. How ever, 5 of the 14 wells do not currently show any benefit in terms of additional oil produced compared with analogous conventional wells. Efforts were made to establish why some wells were more successful than others.

Impact of Grid Selection on Reservoir Simulation

Summary This paper presents a field case study of a faulted, multilayer carbonate reservoir to quantify the impact of grid selection on the reservoir history match. Comparison of the history match using both orthogonal and nonorthogonal grids revealed that the simple five-point scheme can lead to significant error in the history match and in the different representations of the reservoir. Introduction A simulation study of the Thamama reservoir, a faulted carbonate reservoir in Abu Dhabi, investigated flow communication across faults and evaluated development options for the field. The field is an elongated anticline that covers 62 sq miles. Geophysical and geological data and early reservoir performance indicated that the field was separated into several fault blocks by partially sealing and nonsealing faults. Two full-field simulation models were constructed that used two different approaches to represent faults:an orthogonal (regular) grid model with faults defined at block boundaries anda nonorthogonal (irregular) grid model with block boundaries defined at fault traces. The first approach results in a greater number of cells and presents difficulties in representing the fault geometry properly. However, finite-difference techniques can be used for numerical calculations. The second approach uses fewer gridblocks and provides an accurate description of the fault pattern, but transmissibility calculations could lead to significant errors because the grid is locally distorted. To quantify the impact of grid selection on the reservoir history match, both models were used and the results compared in the simulation study. History matching was performed first with the orthogonal grid model. Then, a history match using the same matching parameters was conducted on the nonorthogonal grid model. Background The Thamama reservoir comprises three zones, Zones A, B, and C. Characterized by high faulting and low permeability, this carbonate reservoir contains about 3.6 billion STB of oil in place (OIP). Zones B and C, which contain about 80% of the total OIP, have been the focus of major development since the field discovery in 1967. Fig. 1 shows the general structural configuration of the reservoir, which consists of a large dome with faults oriented north-west/southeast. Faulting in the field, which partitions the reservoir into numerous small fault blocks, has caused some concern about implementation of the full-field development plan. Although lateral and vertical communication between upthrown and downthrown faulted blocks along major faults was suspected, it was never fully identified. Throughout the field's producing life, the extent of lateral and vertical communication within the reservoir, particularly between the oil zone and the underlying aquifer, has been questioned. This question became acritical operating consideration when a peripheral water injection plan was proposed in the late 1970's. Although an extensive reservoir study was undertaken to predict the field'sfuture producing performance under different waterflood operations, no waterinjection program was implemented. We decided that further detailed reservoir studies should be conducted to understand the communication and crossflow between fault blocks fully before a full-scale injection program could be designed. A preliminary 3D, coarse, full-field simulation study of the Thamama reservoir with an in-house simulator having a rectangular (orthogonal) grid system showed the significant effect of faulting on reservoir performance. Unfortunately, the crossflow and communication levels between the fault blocks could not be determined accurately because the model could not represent the faults properly owing to simulator limitations. Therefore, we decided to use a simulator capable of handling distorted (nonorthogonal) grids, or corner-point geometry, to fit the faults and reservoir boundaries better. Two approaches were considered for constructing the model grid. The first approach uses a rectangular (orthogonal) gridding system that represents faults at block boundaries. As a result, reservoir geology and geometry cannot be represented properly. However, finite-difference techniques can be used in a straight forward manner with good accuracy. The second approach uses a nonrectangular (nonorthogonal) gridding system that accommodates accurate description of the fault pattern by placing block boundaries along fault traces. However, the nonrectangular gridding systems could lead to serious calculation errors.1 We conducted full-field simulation studies using both orthogonal and nonorthogonal grid models. The results of the history match of both models with the same input data were compared to determine the magnitude of the calculation error and differences in model performance.

Long-Term Production Results of Polymer Treatments on Producing Wells in Western Kansas

Summary This paper describes the analysis of the long-term oil production performance of 37 near-well polymer treatments on 26 producing wells in western Kansas to determine incremental oil recovery resulting from the treatments. Estimated incremental oil recovery from the 37 treatments was 76,500 STB of oil from 39,600 Ibm of polymer injected, or 1.93 STB/lbm of polymer injected. The polymer treatment types giving the best oil recovery performance were solutions of anionic polyacrylamide (ungelled) and cationic polyacrylamide gelled in situ with the chromium reduction/oxidation process. Both gave incremental oil recoveries of 2.6 STB oil/Ibm of polymer injected and had average treatment lifetimes exceeding 1 year. Introduction Polymer treatments of injection and production wells have been used extensively for fluid diversion and to increase oil recovery. Injection of high-molecular-weight polymers increases the viscosity of the injected water and reduces the permeability of the porous medium to water. In producing-well treatments, the injected aqueous polymer solution preferentially flows into zones that exhibit high permeability to water and subsequently restricts the flow of water when the well is put back on production. Polymer injection has two effects: the water production rate decreases substantially and the pressure drawdown into the wellbore often increases greatly, resulting in an increased oil production rate. During the 1970's, Phillips Petroleum Co. conducted 37 polymer treatments on 26 producing wells in western Kansas. All but one of the treatments were on wells completed in the Arbuckle dolomite formation. The formation has been characterized as a highly fractured, vuggy dolomite with varying amounts of chert and with reservoir characteristics varying from field to field throughout the Central Kansas Uplift. Permeability ranges from 50 to 5,000 md; porosity ranges from 1% to 20%, with an average of 15%. The oil zone is estimated to be 5 to 50 ft thick; the total Arbuckle zone is up to 300 ft. Oil viscosity ranges from 3 to 13 cp. The reservoir drive mechanism is primarily bottomwater drive, and the wells are completed at the top of the formation to delay the onset of water production. Water production comes primarily from coning. Because of the natural fracture network, vertical permeability is high and there are few vertical barriers to restrict water coning.

Modeling Reservoir Heterogeneity to Determine Current Oil Saturation Distribution in a Mature Field: ABSTRACT

The Rangely field is a 900-well giant oil field located in northwest Colorado. The field is at the facies transition between the clean, eolian Weber Sandstone derived from the north and the tight arkosic sandstones and shales of the Marcon Formation derived from the south. The Weber Sandstone produces from six discrete stratigraphic horizons. The character of these depositional packages varies, both vertically and laterally, across the field. This Heterogeneity significantly affects field performance. The Rangely Weber Sand Unit has produced 700 million STB of oil by primary and secondary recovery from an OOIP of over 1,500 million STB of oil. A tertiary recovery project was initiated in 1986 using carbon dioxide as a solvent. Currently, over one-third of the 30,000 STB/day oil rate is attributed to solvent injection. A team of development geologists and reservoir engineers has been working to ensure the continued success of the CO{sub 2} project by refining the geologic model. The porosity, permeability, and original oil saturation distributions have been redefined using modem data and also to account for reservoir heterogeneity. From this data, the current distribution of recoverable oil was determined through the use of a hybrid simulation technique that combines geostatistical interpolation withmore » finite difference and stream-tube displacement simulators. Knowing the distribution of secondary and tertiary recoverable oil will allow aggressive reservoir management to improve recovery efficiency and project profitability through infill drilling, pattern realignment and prioritized allocation of CO{sub 2} resources.« less

A Method for Determining Reservoir Fluid Saturations Using Field Production Data (includes associated paper 6408 )

Abstract Reliable reservoir fluid saturation data areimportant to the over-all planning for prospectivesupplemental recovery projects. A trial-and-error graphical procedure, based on the fractional flowequation and using field production data, has beendeveloped to determine these values with reasonable accuracy. Introduction The preliminary analysis of a reservoir todetermine the feasibility of supplemental recoveryoperations requires a reliable estimate of reservoir fluid saturations, and a judgment must be made asto the degree of accuracy desired. An increase inthe complexity, data requirements, andsophistication of the various available solution methods doesnot necessarily imply that the results will be moreprecise. The decision as to which solution method should be used is sometimes difficult to make.This decision should consider, among other things, engineering manpower requirements for the various alternatives, the quality of existing data, and thesensitivity of the project economics to a reasonablevariation in fluid saturation levels.Average oil, water, and gas saturations for areservoir as a whole are usually determined by apressureTroducdonhistorymatchusingconventionalmaterial-balance methods. More sophisticatednumerical simulation techniques are generally used to determine reservoir saturation distributions.Simulation work can be time consuming andexpensive when efforts are made to determineaccurately the saturation distribution by attemptingto match the individual performances of a largenumber of wells.A trial-error graphical procedure has been developed as an alternative to the moresophisticated methods. Because of its easy use, the procedure may be considered as an efficientand economical application of engineering effort forplanning purposes. An application of this techniqueis illustrated for the Ten Section field, KernCounty, Calif. RESERVOIR DESCRIPTION The Ten Section field, located near Bakersfield, Calif., was discovered in 1936; developmentprogressed continuously until 1942, at which time 126 wells had been completed within the originallyproductive area of about 2,200 acres (Fig. 1). TheTen Section structure is a gently dipping (3 deg. to 7 deg.)doubly plunging anticline. The producing measuresare the upper Miocene Stevens turbidite sands, which have been subclassified as Zones 1, 2, and 3.The Zone 2 reservoir includes the intermediateseries of these sands that are bounded above by athin continuous shale varying in thickness from 5to 10 ft and are separated from the deeper measuresby an extensive thin shale. The sand intervals ofthe upper Stevens turbidite sequence are composedof individually graded and rythmically beddeddeposits. Core observations indicate that the cyclesaverage 2 to 3 ft in thickness and that the sandscomposing each cycle display the usual turbiditevariation in grain size (grading from coarse at thebase to fine at the top). Both sands and shaleswithin Zone 2 are discontinuous and few units arecorrelative across the field.Original oil in place within the Zone 2 volume of170,000 net acre-ft is estimated to have been 91million STB. About 35 million STB of oil (38.5percent) have been produced to date. An activepartial water drive is currently maintaining reservoirpressure in most portions of the field and anultimate primary recovery efficiency of 41.5 percentof the stock tank oil originally in place should berealized. Table I lists the pertinent reservoirproperties.About 58,000 acre-ft of the crestal portion of thereservoir are currently productive (Fig. 2). Part ofthis volume has been swept by natural water influx, as evidenced by the high producing water cuts inmany of me wells. Reservoir heterogeneitiesaccount for the lack of an easily discernible commonwater level in Zone 2. SPEJ P. 477^

The Use of Numerical Simulation To Design a Carbon Dioxide Miscible Displacement Project

The prediction of a single-layered, two-dimensional areal model was compared with results from cross-sectional, two-dimensional vertical models. Effects of gravity segregation and existing reservoir heterogeneity were not significant enough to justify use of a three-dimensional model for predicting field behavior of the North Cross (Devonian) Unit CO2 miscible displacement project in West Texas. project in West Texas. Summary A numerical simulation method was used to design a carbon dioxide (CO2) miscible displacement project in a low-permeability carbonate reservoir. A field history match was obtained as a check on the model's validity. Two-dimensional, vertical (cross-section) models were used to determine the potential effects of a high gas saturation at the top of the formation on CO2 injection profiles and to evaluate the effect of reservoir heterogeneity on sweep efficiency. A twodimensional areal model was used to describe the field's response to CO2 injection. Using an areal model, various CO2 injection patterns were simulated and compared, and an inverted patterns were simulated and compared, and an inverted nine-spot was found to be the optimum pattern for this field. Further simulation predictions were conducted to evaluate various schemes of handling produced CO2-contaminated gas after CO2 breakthrough. produced CO2-contaminated gas after CO2 breakthrough. It was found that direct reinjection of the contaminated gas was preferable to separating the CO2 from the gas or venting the contaminated gas. The project - the North Cross (Devonian) Unit in West Texas - is unlike the classical miscible project in that continuous injection of CO2 and residue project in that continuous injection of CO2 and residue gas is planned rather than injection of miscible slugs followed by or alternating with water or dry gas. Injection of CO2 commenced in April 1972. Actual project performance to date has been encouraging. project performance to date has been encouraging. Reservoir Description The Crossett field is located at the southern edge of the central basin platform of West Texas. The reservoir is a chalky, siliceous carbonate having 21 percent porosity and 3 md permeability. Fig. 1 shows percent porosity and 3 md permeability. Fig. 1 shows the gross Devonian reservoir thickness above the water-oil contact. There is no significant water drive present, so the primary recovery mechanism is solution gas drive. The reservoir is limited on the west by truncation caused by the post-Devonian unconformity. The eastern limit of the reservoir is provided by a water-oil contact, and the north and provided by a water-oil contact, and the north and south boundaries are defined by permeability and porosity deterioration. The reservoir is unusually uniform for a carbonate. Fig. 2 shows a plot of core permeability and porosity vs well depth. Properties of the reservoir fluid are listed in Table 1. The field contained 53 million STB of oil in place when discovered in 1944. The Crossett field was unitized in 1964 and renamed the North Cross (Devonian) Unit. The purpose of unitization was to implement a gas-injection purpose of unitization was to implement a gas-injection pressure maintenance project. All residue casinghead pressure maintenance project. All residue casinghead gas was injected into the three updip gas injection wells shown on Fig. 1. Fig. 3 shows the Unit's production history since unitization. production history since unitization. Residue gas injection would only increase the field's recovery to 19 percent from the expected primary efficiency of 13 percent. With so much oil being left in the reservoir, further supplemental recovery schemes were considered. P. 1327

Advanced Technology Improves Recovery at Fairway

The most important decision made in the early stages of this miscible recovery project was to hang loose. The original plan of operation allowed for injecting all gas, all water, or any combination, depending upon what new information was gained as the project went along. Radioactive tracers, new logging techniques, numeric modeling, and sophisticated down-hole equipment provided that information. Introduction The Fairway (James Lime) field is about 30 miles south of Tyler, Tex. The discovery well was drilled in July, 1960. near the eastern edge of the field, which eventually proved up over 400 million bbl of oil in place under about 23,000 acres. The 10,000-ft James Lime reservoir is a reef development at Fairway, quite different from the regional character of the formation. Three major zones exist in the reservoir as a result of differing conditions of reef growth environment. From the start, this complex, highly stratified, variable-permeability, reservoir offered quite a challenge to the operators. The James Lime oil is an undersaturated 48 degrees API-gravity crude containing from 1,350 to 1,600 cu ft of solution gas per barrel. Saturation pressure varied with depth and ranged from 3,950 to 4,350 psia. The reservoir fluid was determined to be miscible, with lean hydrocarbon gas or flue gas at about 4,800 psia - about 400 psi below the initial reservoir pressure. Connate water saturation ranged from 10 to 30 percent, and the porosity averaged about 12.5 percent. Unitization studies showed that incremental economics favored an alternate gas-water high-pressure miscible recovery project over waterflooding or immiscible gas injection. The operators recognized that many miscible projects had experienced poor recovery and even lost projects had experienced poor recovery and even lost money. Alternating gas and water injection represented the "outer limits" of miscible recovery technology available at the time and involved a high degree of risk. The decision was made to go ahead with the alternating approach, but with a program designed to have a large degree of operational flexibility. In this manner, necessary changes and adjustments could be made along the way. Additional recovery from the alternating gas-water high-pressure miscible recovery technique in use at Fairway is significant. Production exceeded the estimated primary reserves of 65 million STB of oil in June, 1971 (see Fig. 1). Currently the Unit is producing the top allowable of 40,500 BOPD. producing the top allowable of 40,500 BOPD. Injection capacity determines the maximum production rate at Fairway. The average reservoir production rate at Fairway. The average reservoir pressure has been maintained essentially constant at pressure has been maintained essentially constant at 4,500 psi since early 1970. An expansion program to increase gas injection capacity from 70 to 100 MMcf/D and water injection from 60,000 to 90,000 BWPD is currently in progress. With the increased injection capabilities and 13 new wells, now drilling. the Unit will be capable of producing at 100-percent market demand factor, about 53,000 BOPD for about 2 years before it declines as a result of an increasing voidage of injected fluids. Mobility Control The use of water injection to restrict the mobility of the injected gas is the key factor in the improved recovery of the Fairway project. A reduction of viscous fingering of the gas and improved sweep efficiency through water injection is very important in the over-all control of the Fairway project. Many of the early indications of fingering were in the north end of the field (Fig. 2) where gas injection was concentrated initially. Fig. 3 illustrates the typical relationship between producing trends and injection cycles. producing trends and injection cycles. JPT P. 354

A Field Test of Soluble-Oil Flooding At Higgs Unit

This pilot field test in West Texas demonstrated that tertiary oil can be mobilized and recovered by the soluble-oil flooding process. Such a tertiary application can be economic, provided the residual oil saturation after waterflooding is high enough, but application at the beginning of waterflooding has a greater economic potential. Introduction Laboratory studies have indicated that the use of soluble oil could recover substantial quantities of oil not recoverable by waterflooding. Field testing of these materials in oil recovery processes has been previously reported. Considering the potential of previously reported. Considering the potential of the process and the developing need for tertiary oil, plans were made to field test the Uniflood* process plans were made to field test the Uniflood* process at Higgs Unit, near Abilene, Tex. The Higgs Unit (Fig. 1) encompasses 350 acres in Jones County, Tex. The productive zone is the Bluff Creek sand of Permian age, at an approximate depth of 1,870 ft. The primary life of the field extended from discovery (Well 6) in March, 1951, until water injection was started in Wells 1, 3, and 7 in Oct., 1964. Waterflood History In the original developmental drilling of the field, no cores were taken. Because none of the wells penetrated the entire production interval (it was suspected that there was a water-oil contact on the western flank of the sand body), no accurate determination of reservoir size was available. It was estimated that the reservoir consisted of 1,200 acre-ft, containing an average of 908 STB of oil per acre-ft (about 1,090,000 bbl total). Primary oil production was about 334,000 bbl and secondary recovery to Jan. 1, 1969, totaled about 244,000 bbl. The waterflood was developed as a peripheral flood, with injection into Wells 1, 2, 3, 7, and 11. Wells 4, 5, and 6, the first-line producers, showed poor response and watered out early in the flood. poor response and watered out early in the flood. (Well 4 had been used for salt-water disposal before the waterflood program was begun.) Wells 4 and 6 were inactivated when they watered out, and Well 5 was plugged and abandoned because of collapsed casing. The second-line producers, Wells 8, 9, and 10, responded to the waterflood, as did the two remaining producers, Wells 12 and 13. The unit production history from 1962 through 1971 is production history from 1962 through 1971 is presented in Fig. 2. presented in Fig. 2. Pattern Selection Pattern Selection To make the best use of the existing waterflood pattern and to insure the confinement of injected pattern and to insure the confinement of injected chemicals, it was decided to redrill Well 5 and use it as the pilot-area injector. The continued water injection on the west and south sides of the field would help to move mobilized oil toward Wells 8 and 9 and possibly toward Well 4. In addition, drilling a new well would provide an opportunity to core and log the hole and to measure reservoir thickness, porosity, oil saturation, and permeability - factors porosity, oil saturation, and permeability - factors that had only been estimated previously. JPT P. 9

Ante Creek - A Miscible Flood Using Separator Gas and Water Injection

The Ante Creek Beaverhill Lake pool in Alberta is a deep, high-pressure reservoir containing a light crude. A miscible flood, started in 1968, was designed on the basis of laboratory tests and utilizes the gas from the separator, alternating with water injection. The calculated recovery efficiency is 61 percent. Reservoir Description and Development The Ante Creek Beaverhill Lake oil pool located northwest of Edmonton was discovered in Nov., 1962, with the Atlantic Ante Creek 4–7 well. The producing horizon is the Swan Hills member of the Beaverhill Lake (BHL) formation at 11,000 ft depth. This formation is the same reef that is productive in the prolific Swan Hills oil fields and Kaybob South wet prolific Swan Hills oil fields and Kaybob South wet gas field (see Fig. 1). Ante Creek is the deepest of the Beaverhill Lake reservoirs discovered to date. The oil accumulation is found in the updip termination of a porous reefal development. There is a water line to the west side of the field. Cross-sections of the reservoir show that the porosity is scattered through the section but correlatable from well to well. There are presently 19 oil wells completed in the reservoir on 320-acre spacing. The interpreted isopachous map and material balance calculations indicate 37.5 million STB of oil in place. Table 1 lists the reservoir and fluid properties. Most notable of these properties are the low oil viscosity of 0.13 cp and the high initial pressure of 5,173 psia. Fig. 2 is a porosity-foot map of the pool, showing the unit outline. porosity-foot map of the pool, showing the unit outline. Secondary Recovery Considerations It was recognized early in the development of the reservoir that a pressure maintenance project would be advantageous. The reservoir pressure declined to 4,290 psia by Dec., 1966, approaching the bubble-point pressure of 4,140 psia. The primary recovery for the volatile oil was calculated to be 16.2 percent. Also a consideration for secondary recovery was the incentive offered by the Alberta proration system, whereby the well allowable is proportional to the recoverable reserves. With the level of primary reserves calculated for the pool the per-well allowable would drop to a minimum of 32 BOPD in 1969. In 1967 a depletion study was started, as was negotiation towards unitization. Since several other Beaverhill Lake fields in the province are under waterflood, with recoveries expected to be from 40 to 50 percent of the oil in place, waterflooding was considered here, also. However, several factors pointed toward miscible flooding: the high gravity of the oil, the high reservoir pressure, and the available casing-head gas. The gas from the field was being flared at rates of 2 to 3 million ft a day with no immediate prospects for sales. Following a review of the information available on miscible flooding and of the factors involved in operating a flood in Ante Creek, a method was developed to permit efficient oil recovery with the materials available. The method can be described as continuous alternate solvent water injection. P. 1232

A Case History of the Pegasus Ellenburger Reservoir

The performance of the 13,000-ft-deep Pegasus Ellenburger in West Texas has shown that, even in an extremely heterogeneous reservoir, gravity segregation drive can be an efficient producing mechanism. Introduction The Pegasus field is a large multizone field in Midland and Upton Counties, Tex. Oil productive intervals have been found in the San Andres, Spraberry, Pennsylvanian, Devonian, Fusselman and Ellenburger zones. The Pegasus Ellenburger is the deepest reservoir at an average depth of 13,000 ft and is also the most prolific oil producer. Since discovery in 1949, over 60 million STB of oil have been produced from this reservoir. The 4.5 million STB produced in 1967 was the highest annual oil production during the life of the reservoir. As production during the life of the reservoir. As of April, 1968, the reservoir pressure was more than 1,100 psi below the bubble point and the producing GOR had not significantly increased. producing GOR had not significantly increased. Development and Unitization Magnolia Petroleum Co. (now Mobil Oil Corp.) drilled and completed TXL "A" Well No. 1 as the discovery well in the Pegasus Ellenburger field. This well, which is now the Pegasus Ellenburger Unit Well No. 15-1, was drilled in March, 1949, to a total depth of 13,295 ft, with a potential of 1,167 BOPD flowing with over 1,000 psig tubing pressure. From 1950 to mid-1954 the field was pressure. From 1950 to mid-1954 the field was developed at an average rate of 24 wells/year. In all, 119 wells have been drilled. The Pegasus Ellenburger unit became effective June 1, 1954. Fig. 1 shows the location of wells and the unit boundary. Production and Injection History Production and Injection History Fig. 2 shows the oil and water production history, water and gas injection history, and GOR performance. The sharp decrease in oil production in 1951 resulted when the allowable was reduced from 395 to 200 B/D/well to allow time to initiate pressure maintenance operations before the bubble-point pressure was reached. Pilot water injection was begun in 1955 and expanded in 1959 to a full-scale peripheral injection program. In 1960 the allowable was increased to 435 B/D/well (the 1947 yardstick value for 80-acre spacing). Water injection performance did not prove efficient and, in performance did not prove efficient and, in 1963, injection rates were curtained so that the effects of continued pressure decline could be observed. Gas injection was begun in 1967 and expanded to a full-scale crestal gas injection program in early 1968. Geology Structurally, the Pegasus Ellenburger reservoir is a three-domed anticline with a general northeast-south-west axial trend. (See Fig. 3.) The production area encloses almost 10,000 acres. There are major faults along the east and west sides of the field, and it is believed that numerous other faults (having smaller displacements) also exist throughout the field. JPT P. 1330

Gravity Segregation in a Propane Slug-Miscible Displacement Project-Baskinton Field, Louisiana

Abstract A propane slug-miscible displacement project was instigated in Baskinton field, Franklin Parish, La., in April, 1962. Laboratory tests and potentiometric studies were performed to insure applicability of the miscible displacement mechanism to this reservoir. As the principal part of the evaluation of this project, an observation well was drilled in the reservoir near the injection well. From this well, a three-string triple completion equipped with separate surface gas and oil measuring facilities, token withdrawals were produced in an attempt to examine and define frontal profiles. Introduction Many miscible displacement projects of the LPG-slug type have been undertaken and various degrees of success reported in the literature. "Premature" or early breakthrough seemed a common difficulty in these projects. Sun felt that the reservoir rock properties of the Holt "D" sand would permit a true test of gravity segregation in a lowdip reservoir as the homogeneity minimized the effects of permeability distribution. Equally as important was the thought that an examination of frontal profiles would permit an evaluation of mixing-zone performance. The following pages discuss the design and subsequent performance of an observation well drilled expressly to collect data on the propane slug-miscible displacement project. This paper is an interim report on this project. Comments on preliminary results regarding mixing zone description and displacement efficiency are included, but no definite conclusion in these areas can be drawn at this early stage of the project. Geology and Reservoir Characteristics Baskinton field, La., is located several miles south of Delhi, La, (and the Delhi field) in the northeastern corner of the state. The Holt "D' sand, the horizon of interest in this project, is a stratigraphic trap encountered at 3300 n. As depicted on Fig. 1, the trap strikes generally East-West and is bounded on all sides by a pinchout, except on the south side where a water-oil contact establishes the reservoir limits. The sand is very low relief, dipping generally to the South at about 2 degrees. It is a well developed homogeneous Lower Tuscaloosa sand of Cretaceous age. The reservoir originally contained approximately 5 million STB of oil. Table 1 shows the rock and fluid characteristics of the reservoir. Primary Performance and Pressure Maintenance Investigations From discovery in mid-1956 to Jan. 1, 1962, the field produced 525,000 STB of oil, 275,000 Mcf of gas and 6,000 bbl] of water. A pressure decline of 150 psi from the original of 1,802 psig accompanied this production. A material-balance calculation, supported by field performance, indicated the presence of a partial water drive aiding the dissolved gas drive mechanism in this reservoir and impeding the formation of an adverse gas saturation. Pressure maintenance possibilities involving water injection and propane slug-miscible displacement were subjected to detailed engineering analyses. Sweep patterns for each, subject to conventional potentiometric analyzer limitations, were determined. In the propane-slug potentiometric study, injection in a Single up-dip well near the pinchout yielded an essentally radial pattern. This will become quite significant later in the discussion. The propane-slug program appeared economically more attractive than the water-injection program and was selected as the pressure maintenance mechanism. JPT P. 661ˆ

An Engineering Challenge Development of South Louisiana's Giant Timbalier Bay Field

LIPARI, C.A., JUNIOR MEMBER AIME, GULF OIL CORP., MORGAN CITY, LA. Abstract The Timbalier Bay field, covering 9,500 productive acres of inshore and offshore area, containing 81 productive horizons and some 434 reservoirs ranging in depth from 2,000 to 17,500 ft, presents a challenge to engineers. Reservoir mechanisms of many combinations make it necessary that water flooding, gas injection, attic oil recovery and other recovery methods be examined for possible application in this filed. This paper presents the history and characteristics of the field and the approaches taken by Gulf Oil Corp. in arriving at a system of operation in the coastal waters of South Louisiana. Introduction The operation of an oil field in the coastal area of Louisiana is similar in many ways to operations elsewhere, but there is one significant difference. The operation takes place over a body of water. The logistics of an operation of this type require that all functions be coordinated carefully if the project is to be successful. Throughout 24 years of operating the Timbalier Bay field, Gulf Oil Corp. has employed more efficient equipment as it became available, and the most efficient operating practices known at the time. The purpose of this paper is to convey to the industry the history and the practices followed by Gulf Oil in developing this field in the coastal waters of South Louisiana. Location and General Description The Timbalier Bay oil and gas field is located in, and offshore from, Lafourche Parish, La. (Fig. 1). It is situated approximately 20 miles south of the town of Golden Meadow, 70 miles southeast of Morgan City (the area operational office) and 60 miles southwest of the city of New Orleans. The crest of the structure lies almost directly underneath East Timbalier Island. This low-lying island, averaging about 350-yd wide, is the site of the central Timbalier Bay field camp (Fig. 2) and separates the open waters of the Gulf of Mexico from the shallow Timbalier Bay waters. Access to the field is from the Leeville shore base, through Bayou Lafourche, into Timbalier Bay and the Gulf of Mexico, Presently, there are 410 completion intervals in 277 wells. Daily production is 33,826 STB of oil and 52 MMcf of gas. The productive portion of the field covers approximately 9,500 acres, The present lease arrangement (Fig. 3), within the present productive area of the field, consists of Gulf Oil Corp. as sole owner and operator of Louisiana State Lease "PP" 192, 1772 and 1773, and operator for the joint interest of the Louisiana State Leases 1423, 1483 and the Outer Continental Shelf Lease 0263, Block 21. Union Oil of California operates Louisiana State Leases 3088 and 3324, and Tenneco operates Louisiana State Lease 1369.Surrounding fields are (Fig. 1) Bay Marchand to the cast, Caillou Island to the west, Lake Raccourci to the north and South Timbalier Area Block 54 to the south. JPT P. 127^

Fluid Distribution and Reservoir Characteristics of the Big Piney Mesaverde Reservoir, Wyo.

Abstract The text presents an approach used to evaluate a productive reservoir whose hydrocarbon accumulation is under hydrodynamic control. The fluid, rock and structural factors that control the distribution of the fluids and their flow characteristics have been studied. Potentiometric and structural information have been utilized to determine the limits of the hydrocarbon accumulation and its qualitative relationship with structure. A comparison is made of predicted and actual gas-oil and oil-water contacts. The oil column was divided into two producing intervals, and capillary-pressure and relative-permeability data were utilized to evaluate their fluid distribution and transmissibility. Introduction One of the main problems to be solved in evaluating a hydrocarbon reservoir is determining the fluid interfaces and their relationship with structure. This is especially vital in reservoirs where the hydrocarbon accumulation is under hydrodynamic control. The purpose of this paper is to report an approach used to determine the distribution and structural relationship of the gas, oil and water phases in the Big Piney Mesaverde reservoir, Sublette County, Wyo. In conjunction with this study, potentiometric data have been utilized to evaluate entrapment, and a study has been made of the rock and fluid properties of the reservoir which are related to saturation distributions and flow mechanics. The Big Piney Mesaverde reservoir lies approximately 100-miles northwest of Rock Springs, Wyo. The field was discovered in Aug., 1957, by the Gulf No. 1 Tresner State well located in the SW-NW Section 36–29N–113W (see Fig. 1) which produced gas and oil during drill-stem testing. Selective tests during completion in the gas and oil columns resulted in indicated capacities of 9.5 MMcf/D and 118 BOPD, respectively. The discovery was confirmed by Belco Petroleum Corp.'s completion in Jan., 1958, of Well B–34. Initial development in the field showed that the oil column possessed a low productive capacity; this subsequently was attributed to a combination of circumstances, including a low reservoir temperature, a relatively high pour-point oil and low matrix permeability. No particular difficulty was observed in producing free gas. Due to this situation, only 17 wells were completed within two years after discovery. In June, 1959, development was stimulated when Gulf Oil Corp. introduced notch-fracing, and 40 wells had penetrated the reservoir by the end of 1960. To date, production has been curtailed by market restrictions and the need of conserving gas-cap energy; however, as of Jan., 1961, the field had produced approximately 740,000 STB of oil, 1,760 MMcf of separator gas and negligible volumes of water. Fig. 1 is a plat of the producing area showing the limits of development drilling to Jan. 1, 1961, and the areal distribution of the hydrocarbons. Geology The Big Piney Mesaverde reservoir lies on the LaBarge Platform, a major structural feature on the west edge of the Green River basin. JPT P. 608^

Adverse Effects of Water Injection Into Thick Sand Reservoirs Containing Thin, Highly Permeable Lenses

Abstract Engineering studies for pressure maintenance by water injection were completed in 1956on four reservoirs located in the Ovejafield of Eastern Venezuela. Injection into the reservoirs began in Nov., 1957. Severechanneling of injected water occurred in the reservoirs, causing the suspension of water injection. Channeling is attributedto selective encroachment of the injectedwater through thin, highly-permeable sandsections. The J3 sand, OM–100 reservoir, is presented as a case history of the existing problem. Preliminary reservoir data indicatedgood sweep efficiencies and high recoveryby water injection. Flood studies on coresamples yielded recoveries in the 45 to60 per cent range. Predicted recoveries by pressure depletion and pressure maintenancewere 10.5 and 18.1 per cent, respectively. Water injection into the J3 sand wasdiscontinued in Nov., 1960, when it becameapparent that continued injection would be detrimental to ultimate recovery. The volumetric size of the water-encroachedpattern was 30 per cent of total reservoir volume. Channeled water extended into updipwells, and continued injection would extend these channels in an updip direction. The remedial approach to depletionis planned for two phases:wet wells will be produced at increased rates to prevent extension of water encroachment; andgas will be injected into the secondarygas cap for pressure maintenance. Preliminary studies indicate an ultimate recovery of 26 million bbl by gas injection, which represents 14 percent of the oil originally in place. Introduction The Oveja field is located in the southernportion of the Greater Oficina area of Eastern Venezuela. The field was discovered in 1952 with the drilling of a wildcat well, Mundo–1, which has been renamed OM–100. Subsequently, field development included88 wells for drainage of the I J3, L1L andL4 sands. Water encroachment through thin sections of highly permeable sand contained in thicksand deposits has yielded adverse effectsto pressure maintenance by water injectionin all of the afore-mentioned sands. Injection of water into the J3, L1L (southern reservoir)and L4 sands has been discontinued. A fourthinjection project, L1L sand (northern reservoir), is currently being studied for possible discontinuation. Water injection into theI2L–3 sand was never initiated because ofobserved adverse effects in the other reservoirs. The problem of water encroachment, as displayed in the J3 sand, will be considered in this paper. The J3 sand is selected for presentation because the encroachment pattern is more severe than in the other sands. Geological and Reservoir Data Structure The Oveja sand deposits are channel deposits with closure to the south formed by the main Oveja fault. The structureand isopach maps presented in Figs. 1 and2 disclose a 20 dip to the northeast andsand pinch-outs occurring to the east and west. Reservoir boundaries are completedto the north by a southwest-to-northeastmajor fault and the water-oil contact at3,438-ft subsea. Size Surface area overlying the J3 sandcovers 2,216 acres and the average net sandthickness is 44 ft, giving a total reservoir volume of 97,500 acre-ft. Volumetric calculations indicate that the pool originally contained185 million STB of oil, a volume which hasbeen confirmed within a small percentage by material-balance calculations. JPT P. 253^

Material-Balance Analysis of a Water-Drive Reservoir with An Unusual Development History

Abstract Frequently, the analysis of an undersaturated waterdrive reservoir by a material balance is unsatisfactory because reservoir conditions do not reasonably satisfy the assumptions of the material-balance equation. This occurred in the case of a Devonian reservoir in West Texas which proved difficult to analyze because of a rather unusual development history. The standard material-balance analysis technique had to be modified before a satisfactory oil-in-place value could be determined. The modified technique consisted of a material-balance formulation which permitted the analysis of pressure-production data from separate portions of the reservoir with one equation; it also permitted a judicious application of the "least-squares method" to reduce the effect of inherent inaccuracies in the early data. The analysis was accomplished with the aid of an IBM 704 computer and represents a good example of the flexibility in material-balance calculations that may be obtained by computer usage. Introduction The determination of oil in place and water-influx performance of undersaturated water-drive reservoirs, using the material-balance principle, is a well established practice. Frequently, however, the material-balance results are questionable, and the practicing engineer begins to regard such calculations as either totally unreliable or applicable only to a strange breed of reservoirs which apparently are owned only by competitors. Inconclusive or questionable results will occur when reservoir conditions do not reasonably satisfy the assumptions of the material-balance equation and when the true average reservoir pressure is not accurately represented by an average of individual well pressures. These difficulties often can be overcome by modifying the material-balance equation to introduce additional independent parameters which may be assigned various values during the calculations to determine the effects, within certain limits, of possible inaccuracies in basic assumptions. This is exemplified by the reservoir study which is the subject of this paper. The subject reservoir is a structural trap in the Devonian dolomite-limestone formation of West Texas. The initial reservoir pressure of 3,231 psi declined to about 2,250 psi during 12 years of production, but it has remained above the saturation pressure of 1,775 psi. Material-balance calculations, made early in the life of the field, indicated a much larger reservoir than had apparently been defined by the drilling of 10 producing wells and three dry holes. Although a material balance during the early life of an expansion-drive reservoir is notably unreliable, the effort proved rewarding in this case. The consistency of the calculated value of oil in place after nearly eight years of production prompted additional drilling which eventually extended the field to include a volume approximately three times that of the initial discovery and resulted in an additional 28 producing wells. Even with the additional drilling, the amount of reservoir pore volume was still questionable. Volumetric calculations indicated 40 million STB of oil in place, but very few wells had penetrated the full Devonian section; since the top of the Devonian is eroded over most of the structure, the estimated pay thickness may be considerably in error. Material-balance calculations, although not so consistent as the earlier ones, gave an oil-in-place value of about 140 million STB and no definite indication of water influx. Furthermore, data from drill-stem tests of the Devonian formation taken in dry holes in the vicinity of the reservoir indicated the possibility of a very limited aquifer. The pressure-decline curves indicated a recovery above saturation pressure much greater than normal for an expansion drive--if the amount of actual oil in place was reasonably close to the volumetric estimate. JPT P. 37^

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.