Water Injection Operations Research Articles

Nanofiltration for oil-fields water injection operations: analysis of osmotic pressure and scale tendency

Consumption of specific energy (total energy consumed to produce a unit volume of permeate) and scale inhibitors are key factors for efficient or inefficient operation of nanofiltration (NF) (or reverse osmosis, RO) systems. To minimize energy consumption, a suitable energy recovery device must be installed to recover waste energy. Even with optimum recovery of waste energy, still energy consumption exceeds 50% of the total operating costs. The best way to minimize the cost of scale inhibitors is to prevent scale (particularly sulfate) from forming. Scale cleanup (shut-down time and cost of inhibitors and dissolvers) and membranes replacement occupy the rest of the operating costs. As such, designers of NF systems must be aware of the hydraulic and scale envelops, that are the extreme boundaries of operational parameters over the lifetime of the systems. Such boundaries are determined by two factors. The first factor is the throughput ratio, which in turn, is governed by salinity, scale tendency, and temperature. The second factor is the overall system hydraulic, which in turn, is controlled by throttling losses, array losses, and pressure drops within membranes modules. However, the focus of this analysis is the first factor. This third article, in a four-part series, provides a modeling tool to predict: (1) the actual osmotic pressure difference between the membrane surface (Π m ) rather than the bulk of the feed stream (Π F ), and the permeate stream (Π P ) taking into account the actual rejection (R a ) factor; and (2) the saturation degree of calcium sulfate dihydrate (gypsum) and strontium sulfate (celestite) at the membrane surface, and on the concentrate side of the membrane.

Modeling of Subsidence and Reservoir Compaction under Waterflood Operations

A full-field, three-dimensional (3D) computer model has been developed to numerically simulate reservoir compaction and surface subsidence for a weak, water-sensitive, hydrocarbon reservoir during field-wide water-injection operations. The developed model was used for modeling the compaction and subsidence processes under waterflood operations at the Ekofisk Field in the North Sea. The model was thoroughly validated through the comparison of model results to extensive field measurements with good agreement being achieved. The validated model has been successfully employed as a tool to forecast subsidence and to assist in the development of a subsidence risk assessment. For practical field applications, important quantitative information, that includes reservoir compaction, seafloor subsidence, and seafloor horizontal movement, may be generated from the full-field, 3D model and is presented in this paper.

The Water Injection Process: A Technical and Economic Integrated Approach

Water injection is an essential part of many modern oilfield development plans. High-cost offshore developments require that the waterflood process equipment is designed and installed prior to acquiring any injection experience on that particular field. The chosen design must not only maximize the oil production revenue, but also carry an acceptable level of risk in terms of the project costs and technical uncertainties. This paper describes a holistic approach for an economic evaluation of the water injection process, integrating the key technical and economical elements. Well injectivity which describes the well-to-reservoir connection, is a central factor in any water injection operation. The formation characteristics, water properties, well configuration and the injection water pressure determine this. Injection well behaviour is dominated by fracture geometry if the well is operated at sufficiently high pressure. By contrast, the injectivity of a well operated under matrix conditions (below fracture pressure) is dominated by formation damage caused by impurities in the injection water. This paper highlights the role of well injectivity provides a quantitative framework and a worked example of how decisions concerning design and operation of the waterflood plant, process and wells can be made.

Evaluation of Injection-Well Risk Management in the Williston Basin

Summary A study of subsurface water-injection operations in the Willisten geologicbasin demonstrated the practicality of incorporating risk management proceduresinto the regulation of underground injection control (UIC) programs. Arealistic model of a computerized data base was developed to assess the maximumquantifiable risk that water from injection wells would reach an undergroundsource of drinking water (USDW). In the Williston basin, the upper-boundprobability of injection water escaping the wellbore and reaching a USDW isseven chances in 1 million well-years where surface casings cover thedrinking-water aquifers. Where surface casings do not cover the USDW'S, theprobability is six chances in 1,000 well-years. probability is six chances in1,000 well-years. Introduction In the continental U.S., the oil and gas industry operates 170,000saltwater-disposal and EOR injection wells that inject 60 million BWPD intosubsurface formations. By assessing the potential risk of USDW con tamination, operators and regulators can identify those areas where additionalcorrosion-protection measures and increased surveillance of injectionoperations can be most effective in reducing the likelihood of injection waterreaching a USDW. An API study of oil- and gas-industry subsurface waterinjection in the U.S. developed a methodology to quantify an upper limit forthe risk of water from waterinjection wells reaching a USDW. The methoddetermined the probability of simultaneous failures of an injection well'stubing, production casing, and surface casing going undetected, permittinginjection water to escape into the borehole and possible to reach a USDW. The API study also showed that the individual well and field data needed to assessrisk are available, but that the information often is kept by a number ofdifferent operators, regulatory agencies, and commercial computer data bases. The study recommended that a model of a UTC data base be implemented in ageologic basin to evaluate the practicality of collecting and usingrisk-assessment guidelines in managing underground injection programs. As aresult, a study was conducted to test the feasibility of constructing a modeldata base for the Williston basin and to use the risk approach to rank areasbased on their risk of contaminating a USDW. Recommendations on databasecontent solicited from selected regulatory agencies and operators were used todefine the basic engineering, geologic, and injection data, along with thedatabase queries and reports necessary to administer UIC programs andoperations effectively. As a result of this effort, a realistic model wasdeveloped of a data base containing the necessary elements for evaluating therisk of USDW contamination in underground injection operations in the Willistonbasin. Overview of Risk Approach The risk approach to managing underground injection operations in apractical method of prioritizing and/or redirecting personnel and prioritizingand/or redirecting personnel and funds toward activities that are most likelyto contaminate a USDW. Risk-assessment guidelines do not give scientificcertainty, but they can be useful in setting priorities, in designing corrosionprotection systems, and in formulating protection systems, and in formulatingregulations. Risk assessments can help distinguish realistic potential USDWcontamination threats from trivial ones. They also can give regulators theinformation they need to decide what degree of monitoring and testing is neededfor a given area. To be effective, the data elements used in defining risk mustbe an integral part of a basic UIC data base. Such a data base conwellidentifiers, well-completion data, mechanical-integrity test results, injectionvolumes and pressures, and the base and top of the deepest USDW. The dataelements needed to maximize the risk-based decision process include tubing andcasing failure process include tubing and casing failure history, well-workoverresults, and reservoir definition (including identification of corrosive zonesand saltwater aquifers). UIC Regulations A major driving force leading to increased emphasis on the protection of USDW's has been the regulations promulgated by the U.S. Environmental Protection Agency (EPA) under the Safe Drinking Water Act of 1974. That actgave the EPA or an EPA approved state agency the authority to regulatesubsurface fluid injection to protect USDW's. The EPA's UIC program addressesfive classes of injection wells. Class II wells, which the oil industry isprimarily concerned with, include those used for disposal of fluids brought tothe surface and in connection with oil and natural gas production, injection offluids for EOR, and storage of liquid hydrocarbons. JPT P. 737

Injection-Water Quality

"The objective of any water-injection operation is to inject water into the reservoir rock without plugging or permeability reduction from particulates, dispersed oil, scale formation, bacterial growth, or clay swelling." Introduction Ideally, injection water should enter the reservoir free of suspended solids or oil. It should also be compatible with the reservoir rock and fluids and would be sterile and non-scaling. The objective of any water-injection operation is to inject water into the reservoir rock without plugging or permeability reduction from particulates, dispersed oil, scale formation, bacterial growth, or clay swelling. In addition, souring of sweet reservoirs by sulfate-reducing bacteria should be prevented if possible. How Good Must Water Quality Be? Actually, the question posed by most producers is, how bad can water quality be without causing any significant problems? The methods by which people arrive at an answer to this question are both curious and diverse. In many injection projects, experience is the sole guide, and little, if any, technical investigation precedes design of the injection system. Those who wish to apply the best available technology should precede system design with a careful study of the water to be injected and the characteristics of the formation rock and fluids. Characterization of the Water and the Formation Injection Water. The water must be carefully sampled and characterized to assess the likely problem areas. The following measurements are considered essential. Chemical Composition. Knowledge of the chemical composition of the water is required to calculate scaling tendencies and to determine the likelihood of clay swelling. Certain parameters, such as pH, must be measured on site immediately after sampling. Dissolved Gases. The amounts of dissolved oxygen, carbon dioxide, and hydrogen sulfide should be known to anticipate the types of corrosion. Corrosivity. On-site corrosion-rate measurements are necessary to quantity the water corrosivity. Bacteria. Any bacteria in the water should be identified and their population estimated. Sulfate-reducing bacteria are of particular interest. Suspended Solids. The amount and composition of the suspended solids are primary indicators of water quality. The particle-size distribution can also be determined for surface waters and waters from water-supply wells. Particle-size measurements in produced waters have little meaning because particle-size-measurement instruments cannot distinguish between solid particles and oil droplets. Oil Content. Dispersed oil can decrease injectivity, especially when combined with suspended solids, such as iron sulfide. Also, emulsion blocks can form in injection wells. Injection Formation. The injection formation is often characterized simply by its permeability. Pore-size distributions, however, may also be useful in the determination of injection-water standards. Knowledge of the composition and distribution of clays in sandstone reservoirs is desirable to assess potential clay swelling and migration problems. Water-Treatment Objectives Once the water and the rock have been characterized, the difficult task of deciding how much water processing is required to create a nonplugging water begins. Suspended Solids and Oil. Methods to estimate the quantity and size distribution of suspended solids that can be tolerated in an oil-free water abound. Most methods attempt to correlate the suspended-solids concentration, particle-size distribution, or water-quality measurements with the formation permeability or pore-size distribution. Unfortunately, there is no consensus as to which method provides the most dependable estimate, and petroleum engineers are left with a bewildering array of choices. When produced water is injected, the water contains both solids and oil. Attempts to estimate acceptable levels of suspended solids and oil with theoretical models have not been successful to date. Empirical correlations currently offer the best hope.

Water Injection Operations and Studies in the Geysers Geothermal Field: ABSTRACT

Water Injection Operations and Studies in the Geysers Geothermal Field: ABSTRACT

Analysis of Horizontal Strain Measurements, 1971-1980, Wilmington Oil Field

A system of long distance, horizontal strain lines has been established in Wilmington Oil Field, Long Beach, California. The length of these lines, which ranges from about 2,600 to 18,000 feet (729 to 5,486 m), is established twice yearly using electro-optical, line-of-sight ranging devices. These lines are used to measure changes in compression and tension over the Wilmington Oil Field subsidence bowl. The ground surface is unstable owing to water injection operations which slowly raise and lower the ground surface. Most of the strain lines that are shorter than about 5,000 feet (1,524 m) lengthen as the surface is raised and shorten as it is lowered. The amount of length change roughly duplicates elevation change. Average strains over the total line lengths are in the order of 10 −4 to 10 −5 , which as a general rule do not harm surface structures.

AN ANALYSIS OF THE PRODUCTION PERFORMANCE OF THE WINDALIA SAND RESERVOIR OF THE BARROW ISLAND OIL FIELD

The Windalia Sand is a high porosity, low permeability oil reservoir. Currently 454 wells penetrate the unit for production or water injection operations, and are drilled on a north-south, east-west 16 ha (40 ac.) spacing. Early production performance data indicated a trend of water break-through into wells located east and west of water injection wells in an inverted nine-spot pattern. This early trend has continued and the east- west break-through has become more widespread with time. It was recognised that it could be possible to improve the performance of the waterflood if the factors causing the phenomenon were able to be identified. A detailed geological review of well data was initiated to investigate causes and possible controls of the phenomenon and to determine if oil recovery could be improved. This work was augmented by an engineering study of production data. Subsequently, a computer model was developed to investigate the simulated effects of changes to well patterns on the field's production performance.The geological review determined that the reservoir contains significant local and transitional irregularities (or inhomogeneities). The mapping of a number of reservoir parameters has shown there are genetic patterns or trends and these are postulated as being at least partial controls of preferential direction of fluid movement.Previously the reservoir had been regarded as being a more uniform "layer-cake" sand. Well completion practices and timing together with production and injection methods are thought to have accentuated the latent genetic controls. Imposed pressure parting has been postulated, on engineering premises, as a control of fluid movement. The modelling study used the notion of anisotropic permeability in attempting to history-match production performances.Because of the reservoir size and anisotropy it was impractical to model the entire field. Selected type areas within the reservoir were studied. Good history-matching of various well types (based on location within a pattern) was possible. Predictions of production performance can be made for various simulated pattern changes allowing feasibility studies to be made of possible conversion programs.East-west producing wells are being converted to injectors as they water out. This program has converted part of the reservoir to a line-drive injection configuration and improved performance in these areas is evident.

Miscible Flood Performance of the Intisar "D" Field, Libyan Arab Republic

Introduction Pressure maintenance by both crestal-gas and bottom-water injection was Pressure maintenance by both crestal-gas and bottom-water injection was initiated early in the life of the Intisar "D" reservoir to maximize oil recovery and to conserve produced gas. As of June 1974, cumulative oil recovery amounted to 496 million bbl and no significant breakthrough of injected gas was observed. A reservoir simulator confirms uniform downward miscible displacement of oil and predicts that continued high-pressure gas injection, combined with recompletion of wells, will yield a recovery efficiency of 80 percent. Introduction This paper reviews the performance of a combination miscible gas and bottom-water displacement program begun almost coincidentally with first production from the Intisar "D" field. This project is one of the largest miscible gas displacement projects implemented in any reservoir to date, with 300 to 400 MMcf of gas being reinjected daily. Water injection operations were begun in Nov. 1968, 1 month after production started, and crestal-gas injection was initiated in Dec. 1969, when the first of three 40,000-hp gas compressors was commissioned. This early supplemental recovery effort was necessary because recovery of the highly undersaturated oil in this reservoir by primary means alone would have been low. A compositional reservoir simulator was used to match the 5 years of available performance history. This match was accomplished easily and indicates that a high-pressure, vaporizing gas-drive process, which generates miscibility through interphase mass transfer, is performing very efficiently. This is the result of effective gravity drainage in the permeable and vertically homogeneous carbonate reef and of attainment of a pressure level high enough to assure miscibility. The history match provides the basis for model prediction runs that indicate that continued injection of gas at miscible conditions will result in an ultimate oil-recovery efficiency of about 80 percent of the stock tank oil originally in place in the percent of the stock tank oil originally in place in the reservoir. This is comparable with the high recovery efficiencies being achieved in some Canadian reef reservoirs where crestal miscible gas displacements have been conducted previously. Discovery and Development The Intisar "D" field was discovered in Oct. 1967 by the fourth well drilled on Occidental of Libya's 465,000-acre Concession 103. It is located in the Libyan Arab Republic's prolific Sirte Basin, 220 miles south of Benghazi and 525 miles east-southeast of Tripoli (see fig. 1). The field discovery well, Well D1-103, penetrated Paleocene carbonate reservoir rock at a depth of 8,946 ft Paleocene carbonate reservoir rock at a depth of 8,946 ft and found the oil-water contact 888 ft lower, at 9,834 ft. Production tests of this well yielded oil rates of up to Production tests of this well yielded oil rates of up to 75,000 B/D, and its productivity index was calculated to be 423 B/D/psi. Development of the field was begun in June 1968 and completed in May 1970 with the drilling of 13 producing wells, 16 water injection wells, and seven gas injection wells (see Fig. 2). In addition, 24 shallow-water source wells also were completed. The field went on stream in Oct. 1968, when production-handling facilities were completed. Geology The reservoir is almost circular in shape, with a diameter of about 3 miles, as shown in Fig. 2. JPT P. 935

A Modeling Approach for Optimizing Waterflood Performance, Slaughter Field Chickenwire Pattern

A two-dimensional areal simulation indicated significant trapping of oilbetween center and off-center producers in this unique waterflooding pattern. For typical conditions, the predicted ultimate recovery of 41 pattern. Fortypical conditions, the predicted ultimate recovery of 41 percent of originaloil in place was increased to 44.6 percent by drilling percent of original oilin place was increased to 44.6 percent by drilling additional producers betweencenter and off-center producing wells. Introduction The 3,200-well Slaughter field is one of Texas' major fields. It is on theNorth Basin Platform in West Texas, approximately 35 miles west-southwest ofLubbock. The field was discovered in April, 1937, and most drilling took placein the late 1940's. It produces 32 degrees API sour crude from the San Andresproduces 32 degrees API sour crude from the San Andres dolomite formation ofPermian age at an average depth of 5,000 ft. The formation is relativelyheterogeneous; it structure is a monocline, dipping at less than 1 degrees tothe south-southeast. The field covers an area of approximately 100,000 acresand currently has 2,311 producing wells and an estimated 903 water injectionwells. The producing rate of 113,000 BOPD (July, 1972) ranks fourth in Texas. Cumulative production to Jan. 1, 1972, was 464 million bbl. production to Jan.1, 1972, was 464 million bbl. Field discovery and bubble-point pressure was1,710 psia at 1,250 ft (subsea). Except for several minor gas injectionprojects, the field produced by a solution gas drive until waterfloodingoperations commenced during the mid 1960's on many leases. The field is notbeing produced as one fieldwide secondary recovery unit but consists of a groupof smaller units and cooperating lease floods. Water injection operations arecurrently being conducted on practically every major lease or unit. A uniquespacing exists in much of the field since that part of West Texas wasoriginally surveyed in the Spanish land measurements of hectares, labors, andleagues. A large portion of the field was developed with a density of fivewells per labor (35.4 acres per well). Four wells usually were drilled atlocations 440 to 500 ft from the respective labor lines and a fifth well wasdrilled in the center of the labor. Many of the early Slaughter Fieldwaterflood projects started as cooperative lease-line injection projects orperipheral waterfloods. These were later converted to a unique pattern when itwas determined that an increased pattern when it was determined that anincreased injection-to-producing-well ratio was necessary for more effectiveflooding in this low-permeability reservoir. Fig. 1 shows the two-injector, three-producer pattern that Slaughter Field operators call the pattern thatSlaughter Field operators call the "chicken-wire" pattern. The patternresults in six injectors enclosing three producing wells. A repeating developedchickenwire pattern results in a net injector: producer ratio of 2:3 duringsecondary operations as producer ratio of 2:3 during secondary operations asopposed to a ratio of 1:1 for the conventional five-spot pattern. Thechickenwire pattern resulted in an intensification of flooding. However, it wasnot obvious whether or not this was the optimum pattern or to what degreewaterflood recovery might be influenced by previous unbalanced injection. Evenwith this intensified injection pattern, most flood rates would be relativelylow and the projects long-lived. Thus, it was decided several years ago to do amodel study of a typical area of the field. This study would investigate theeffects of imbalance and additional drilling or well conversions on rates andultimate recovery. JPT P. 757

West Burkburnett Waterflood-A Successful Shallow Project In North Texas

Abstract The West Burkburnett field is located about two miles west of burkburnett in Wichita County, Tex. Waterflooding of the field began nearly 22 years ago. The project has been so successful that expansion has ultimately covered the entire reservoir, although initial plans were to flood only about half of the area. Recoveries are given showing that 50.5 per cent of the original stock tank oil in place will ultimately be recovered and that secondary recovery of 35.3 per cent of the original stock tank oil in place will be 2.3 times greater than total primary. Mobil Oil Corp. is the major operator in the field and has gained much valuable experience in waterflooding through operation of the project. Pertinent data concerning the development, operation, characteristics and success of the project are given, and general conclusions are drawn concerning certain engineering techniques used in waterflood operations. Introduction Waterflooding has long been recognized as an important method of increasing oil recovery from shallow reservoirs in North Texas, The West Burkburnett project, a water injection operation in the 1,750-ft Gunsight sand, was one of the first major secondary recovery projects to be developed in the area. Information gained in the operation of the project has been profitably applied in the project itself and in other reservoirs. In most shallow Cisco Sand waterfloods in North Texas, secondary oil recovery has been less than primary oil recovery except where primary recovery was less than 15 per cent of the original stock tank oil in place. Primary recovery from the West Burkburnett project was 15.2 per cent. Secondary ultimate will be more than twice the total primary. The J. G. Goins lease, which served as a pilot for the project, had a primary recovery of 24.3 per cent, Secondary ultimate recovery for the pilot area was about 1.6 times the total primary. This project has been far more successful than the average North Texas project. Ultimate total recovery from Mobil leases, which comprise about 85 per cent of the field. will be more than 20 million bbl. The West Burkburnett field is situated between the old Burkburnett Townsite and Clara fields, about two miles west of Burkburnett, Wichita County, Tex. Geology and Reservoir Properties The Gunsight sand of the Cisco series and Pennsylvanian age is found in the West Burkburnett field from a depth of 1,550 ft at the south edge of the field to 1,850 ft at the north edge. Sand thickness averaged 10.6 ft for the primary area and 11.6 ft for the secondary area. The structure is monoclinal, dipping about 120 ft/mile from south to north. The reservoir is formed as the sand grades into shale on all sides. Shale is also interspersed in the sand body throughout the reservoir, but is not found in any continuous beds. The sand is also associated with a limestone which lies immediately above it and is almost always known to be present. Thin lime streaks are also commonly present, but are not believed to be continuous. The sand is fairly uniform in porosity and permeability distribution, and in sand thickness. The primary recovery mechanism was solution gas expansion. Primary productive limits on Mobil leases contained more than 3,100 acres, about 2,600 of which have been included in the waterflood project. Approximately 700 core samples were taken from new development wells on Mobil leases. Analyses of these core samples and supplemental data from electrical logs were considered in determining reservoir properties. Comparison of properties from individual leases showed that the sand was of such uniformity that, after the initial development, averages were compiled for the total reservoir (Table 1). History of Development The field was discovered in June, 1912, when Corsicana Petroleum Co., a predecessor of Mobil, completed its Chris Schmoker No. 1 for 85 BOPD. Corsicana owned several other leases in the field amounting to about 85 per cent of the primary productive area. Development of the field continued between 1912 and 1926, and virtually all the locations were drilled on regular 10-acre spacing. Several inside locations on Mobil's leases were not drilled. Initial potentials varied between 5 and 125 BOPD (pumping) with the average being approximately 30 BOPD and no water. A vacuum of 18 in. of mercury was pulled on the casing-tubing annulus of most wells early in their lives. Gas was transported to the Burkburnett gasoline plant, which was constructed in 1918. JPT P. 919ˆ

El Capitan Source Water System

Abstract The talent of pipeline and production engineers can be coordinated to create opportunities for diversified investments. This has been demonstrated by the efforts of Shell Oil Co. and Shell Pipe Line through the construction of El Capitan source water system, which serves many Permian Basin secondary recovery injection programs. The project was conceived during 1960 after the need for a large water supply was recognized. A study of local water-bearing formations suggested that these sources might be inadequate to serve projected secondary recovery programs and still provide sufficient water for residential, farming and industrial requirements. The Capitan reef complex was selected for the supply because the extensive aquifer yields brackish sulfide water suitable for injection. The initial project when completed will require a capital expenditure of an estimated $10 million. It will be capable of delivering some 2.8 billion bbl of water at a rate of 600,000 B/D from 18 wells approximately 5,000 ft deep. The water will be pumped through some 135 miles of line ranging in size downward from 36 in. at the 5,000-hp pump station. Additional capacity up to 1,000,000 B/D can be obtained with only additional source wells and pumps being required. The water will be supplied through a closed system free of air to 28 terminals, each with meters for custody transfer. The wells and pump station are equipped with gas engines and the necessary auxiliary equipment to permit automated operation. While nearly four years have been required from inception to delivery, less than a year was required for design, development and construction. The greatest time and effort were required for contract negotiations for water rights, for right of way, and with the water purchasers. Introduction The advent of expanding secondary recovery operations, together with the growing demand for water utilized in the industrial expansion and agriculture in Ector County, led to Shell's investigation of additional water sources as an allied investment opportunity. Allied opportunities might be differentiated from diversification in that it is management's desire to find additional investment programs through further utilization of available talent and experience. A review of local water sources for Shell's Ector County water injection operations during 1960 indicated that the available sources might prove inadequate in many areas if they were developed on a unilateral lease basis. It appeared that fresh water sources would have to be exploited beyond the limits of some of the oil fields to assure an adequate water supply. Since other operators undoubtedly experienced similar problems, it presented an excellent opportunity for a water supply service. Two alternate water sources given consideration were the Capitan reef complex in Winkler County, a prolific aquifer which had yielded several billion barrels of brackish sulfide water with little or no drawdown, and the Ogalalla formation in Gaines County, a shallow. fresh aquifer. Further investigations revealed that one major oil producer had already laid a water system from the Capitan reef to supply its Ector and Crane counties field injection requirements, that another operator had purchased water rights with plans to bring Capitan reef water to its projects in Ector County, and that operators of other Ector County projects had purchased the Odessa city excess water capacity and the Odessa butadiene plant waste water. Several oil producers had substantial operations in Ector County, while Shell's interests were dispersed with its major operations in the TXL field area, where water requirements were neither immediate nor relatively large. It appeared certain that Shell operations would be served either incidental to the above systems or through local water development. Consequently, a water source service was not actively pursued. Through contact in engineering committee work in late 1961, Shell was advised that at least one of the other operators with water rights could not construct a pipeline to deliver water from the Winkler County reef into Ector County. The reason given was that a group of ranchers controlled sufficient lands between the water source and the Ector County projects and that they had made exhorbitant demands for water transmission rights across those lands. JPT P. 1351ˆ

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

The Future Outlook for Tertiary Recovery

Introduction What is the future outlook for tertiary recovery in the United States? Undoubtedly, 25 years ago this same question was asked with regard to the outlook for secondary recovery. At that time, economic conditions were such that oil operators and petroleum engineers were searching for means of increasing oil reserves -- not only through the use of more advanced exploration and drilling technology, but also through prolonged and more efficient production from producing wells and through additional recovery from depleted reservoirs. This search led to the development and widespread application of fluid-injection operations for the purposes of pressure maintenance and secondary recovery. That this search was successful is evidenced by the fact that unitized fluid-injection projects alone produced a total of 357 million bbl of oil and condensate during 1958, representing 15 per cent of all the oil produced in the U. S. during that year. In a report recently presented to the Interstate Oil Compact Commission by its Secondary Recovery and Pressure Maintenance Committee, it was indicated that an additional 14.8 billion bbl of oil will be recovered in the future by conventional gas- and water-injection operations. On the other hand, it has been estimated that less than one-third of the total original oil in place will be recovered from currently developed reservoirs by primary production and conventional gas- and water-injection operations. Even with the widespread application of the recently developed miscible-displacement and in situ-combustion techniques, less than one-half of the original oil in place in these reservoirs will be recovered. Once again conditions are such that oil operators and petroleum engineers are searching for methods of obtaining greater percentages of the oil from currently producing fields and from reservoirs which have previously been subjected to primary and secondary operations -- hence, tertiary recovery. Definitions To avoid confusion due to somewhat vague terminology, it would be well to define the various types of recovery operations. For the purpose of this paper, the following definitions are stipulated. Primary recovery is the production of oil reservoir by depletion of the natural reservoir energy. Pressure maintenance is the production of an oil reservoir by means of artificial stimulation and/or by augmentation of the natural producing mechanism(s) by fluid injection prior to depletion of the natural reservoir energy. Secondary recovery is the production of an oil reservoir by some means of artificial stimulation (fluid injection) after the natural reservoir energy has been essentially depleted by primary recovery operations. Tertiary recovery is the production of an oil reservoir by some means of artificial stimulation after secondary recovery or pressure maintenance operations. Since tertiary recovery, by definition, would consist of additional recovery of oil from reservoirs which have previously been flooded to economic abandonment, it would seem reasonable to assume that such additional recovery would be expensive and more difficult to obtain than the oil recovered under secondary operations. Therefore, it seems appropriate to examine some of the more important factors which are contributing to the desirability of and/or the necessity for tertiary recovery operations. Exploration-Drilling Costs Up, Crude Prices Stable The average cost per barrel for all newly-drilled liquid-hydrocarbon reserves in the U. S. increased from approximately $0.71 in 1950 to a maximum of $1.33 in 1957. This cost declined to $1.17 in 1958 and to $1.06 in 1959. The average cost of finding a barrel of crude oil in new fields in 1959 averaged about $2.77. Over this same period, the average price per barrel of crude oil increased from $2.51 in 1950 to a maximum of $3.09 in 1957. It decreased to an average of $2.92 in 1959. Industry-wide statistics indicate that the average domestic operator lost $0.27/bbl of oil produced in 1959, because for each net barrel of crude-oil production at an average wellhead price of $2.92/bbl, a total expense of $3.19 was incurred. This expense included $1.07 for exploration, $1.21 for development, and $0.91 for lifting costs and overhead. JPT P. 416^

Oil Recovery Performance Of Pattern Gas Or Water Injection Operations From Model Tests

Published in Petroleum Transactions, AIME, Vol. 204, 1955, pages 7–15. Paper presented at Petroleum Branch Fall Meeting in San Antonio, Oct. 17–20, 1954. Abstract A series of both water and gas pattern floods was made in the laboratory to study the oil recovery performances of such operations. These tests were conducted on consolidated sandstone models, using oil, water, and gas. The model floods were scaled to reproduce field performance under gas and water five-spot injection, X-ray shadowgraphs permitted observation of the gross fluid movement within the models. A method was developed for applying the mobility ratio concept to water flooding and dispersed gas drives in a five-spot well pattern. The areal sweep efficiency at breakthrough for dispersed gas drives is much higher than previously expected, lying in the range of 50 to 100 per cent. A method is presented for predicting the water-oil ratio performance of five-spot pattern water floods in uniform sands. This method is verified experimentally for the condition of no free gas initially present and for values of gas saturation normally encountered in fields following depletion operations. Production performance for pattern gas injection is also predictable by this method.