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Radioactive tracers, such as tritiated water, iodides, cobaltic compounds, etc., are frequently used in subterranean reservoir studies. Their great advantages over non-radioactive (chemical) tracers are often outweighed by their large losses within the reservoir matrix due to undesired adsorption. The chemical tracers can also be adsorbed at a high rate. However, their high adsorption losses do not necessarily lead to large variations of the tracer retention times in the reservoir (chromatography effects) because of their larger number of molecules or ions in the liquid (mobile) phase if the (a) adsorption is governed by Langmuir type isotherms, and (b) the concentration in the liquid phase is within the flat portion of the isotherm (asymptote).
The adsorption effects experienced with both types of tracers make very precise interpretations of tracer data obtained in field studies almost impossible. For example, material balances have shown a larger acceptable degree of tracer recovery only if very severe and extreme reservoir heterogeneities are encountered. In real matrix flow, i.e., uniform or homogenous zones, the adsorption contributes significantly to the total dispersion of the tracer, thus creating a high degree of uncertainty in the data about various reservoir characteristics obtained from the tracer test in larger reservoirs. It becomes impossible to distinguish between the three main fractions contributing to the total mass dispersion: (a) fluid-dynamics, (b) diffusion, and (c) adsorption/desorption.
A new method is suggested whereby not a single tracer test but a radioactive tracer cocktail is applied. Each individual tracer contains a different radioactive element incorporated into a chemical compound. These compounds have pre-determined adsorption isotherms. These isotherms plus the material balances and the variations in the retention times for the various chemical compounds (chromatography) will allow the determination of reservoir parameters not possible by any other reservoir tracer study.
Basically, this new tracer method employs the same ideas and techniques as those used in the generally accepted analytical laboratory method of high pressure adsorption liquid chromatography (HPLC). Only the objectives are different. In HPLC, a known volume of a mixture of unknown chemical compounds flows through a known, "calibrated" porous media. Determining the "pulses" of the separated chemicals as a function of time, pulse height and pulse shape allows the analytical chemist to determine the previously unknown mixture of chemicals.
In the described reservoir tracer method, a known volume of a mixture containing known chemicals at known concentrations flows through an unknown porous media. But now, the "pulses" of the separated chemicals (function of time, pulse height and pulse shape) will allow the precise description of the porous media itself. The basic principles of both methods, HPLC and "Tracer Adsorption Chromatography Method", are the same, although the methodology (applications) and the final evaluation methods are quite different.
The described new tracer method allows the precise determination of various reservoir heterogeneities and matrix properties. In addition, it allows an experimentally determined properties. In addition, it allows an experimentally determined differentiation between the three main factors contributing to the total fluid mass dispersion (fluid-dynamics, diffusion and adsorption/desorption). This tracer chromatography method, applied in a large reservoir, cannot be duplicated with non-radioactive tracers.
Tracer tests to evaluate the flow patterns between injection and producing wells are common practice in oil and gas field operations. Gulati described the use of tritiated water in a geothermal steam reservoir. In some recent papers we described some general aspects of the use of single tracers for reservoir verification and monitoring in geothermal steam and liquid dominated fields.
Tracers are used in well to well tests to gather data about the movement and saturation of fluids and hydrocarbons in the subsurface. Chemical tracers can be used to gather data about water or gas. This article discusses some of the commonly used chemical water tracers for well to well tests. Chemical tracers can also be used in a single well configuration to estimate residual oil saturation or connate water saturation. Application of several nonradioactive chemical tracers has been reported in the literature.
This paper documents the design, operation, analysis and use of two different radioactive tracers, tritium and iodide-125, which were injected in the Ekofisk Formation Pilot Waterflood Project. This paper also describes how Pilot Waterflood Project. This paper also describes how chemical analysis of water produced in the offset producers during the pilot project was successfully analyzed, interpreted, and used as a second tracer method.
Both tracer methods were used to evaluate waterflood mechanisms and were invaluable to the overall interpretation of the Ekofisk Formation Pilot. A comparison of both methods is made to demonstrate their repeatability for possible future use. possible future use. During the pilot water injection program, clear responses from the injected radioactive tracers were identified from the three production wells within the pilot. Analysis of the produced water from these wells was carried out in the laboratories of IFE ("Institutt for Energiteknikk") in Oslo with an accuracy within 1-2 percent.
Chemical composition of the produced water was monitored during the same tracer injection period which showed a direct correlation. The large differences in sulfate concentration between Ekofisk formation water and the injected seawater makes this ion a good alternative to the more ideal radioactive tritium tracer.
Careful analysis of the various tracers in the Ekofisk Formation Pilot confirmed that both waterflood recovery mechanisms capillary imbibition and viscous displacement were contributing to the overall waterflood recovery. This was a key element in the interpretation and simulation of the pilot.
The Ekofisk Field is located in the Norwegian Sector of the North Sea and is composed of two naturally fractured chalk formations, the Ekofisk and the Tor. This essentially volumetric, solution gas drive reservoir was initially under-saturated, with an initial pressure of 7120 psi and a bubble point pressure of 5545 psi at 268 degrees Fahrenheit. Initial solution GOR at producing separator conditions was 1530 SCF/STB and initial oil gravity was 33 degrees API.
Production from Ekofisk was commenced in 1971 through four Production from Ekofisk was commenced in 1971 through four subsea producers and switched to three permanent production platforms in 1975. Production peaked in 1976 at over platforms in 1975. Production peaked in 1976 at over 300,000 BOPD and declined to below 75,000 BOPD by mid 1986. Through waterflooding, the oil production has increased to the current level of 130,000 BOPD. Reservoir pressure declined through the bubble point pressure of 5545 psi in 1978 after which producing GOR from the field increased and peaked at 9000 SCF/STB in 1986. Through 1989, Ekofisk had peaked at 9000 SCF/STB in 1986. Through 1989, Ekofisk had produced 1,362 million barrels of oil equivalents. produced 1,362 million barrels of oil equivalents. Waterflooding was first initiated in Ekofisk Field in November 1987 and was restricted to the Tor formation in the northern two thirds of the field. This was preceded by extensive study of laboratory imbibition experiments and a pilot waterflood project to confirm laboratory results and to gain experience from water injection into the highly fractured chalks.
Initial laboratory data had indicated water injection into the Ekofisk formation was of lower potential. in June 1986 a Lower Ekofisk Formation Pilot was initiated to determine waterflooding potential of that formation. The pilot was configured similar to the Tor Pilot 1 with injection through Well B-16 situated in the middle of a triangle formed by the three producers Well B-19, Well B-22 and Well B-24 (Figure 1).
Radioactive isotopes have been useful in tracing the configuration of the gas displacement fronts in the Fairway alternate gas-water miscible recovery project. Variations in sweep patterns with changing reservoir pressure gradients, source of gas breakthrough, and indications of pressure gradients, source of gas breakthrough, and indications of miscibility can be inferred from tracer responses in this field.
The Fairway (James Lime) oil reservoir, containing approximately 421 million STB of oil initially in place at original reservoir pressure of 5,226 psia, was discovered in July, 1960, at a depth of about 10,000 ft. Productive limits of the field, enclosing approximately Productive limits of the field, enclosing approximately 23,000 acres with an average pay thickness of about 70 ft, were established in 1963. The field, now fully developed on 160-acre spacing with 152 wells, is currently producing 36,000 BOPD under pressure maintenance by alternate gas-water injection. The Fairway (James Lime) reservoir is a reef deposition with three major porous intervals - Upper A zone, Lower A zone and C zone - which are lithologically related to various stages of reef development. The three major zones are connected vertically in several areas of the reservoir, although the zones are distinctly separated by dense lime over most of the field. Average permeabilities of the three zones vary widely - 42.5 md in the Upper A, 22.6 md in the Lower A and 3.2 md in the C zone - even though average porosities of all three zones range from 12 to 13 percent. The James Lime oil in the main field area is an undersaturated 48 degrees API gravity crude with a solution GOR of 1,350 to 1,600 cu ft/bbl. Saturation pressure varies with depth, and ranges from about 3,950 psia at the average oil-water contact of9,550 ft to 4,350 psia at the structural high of9,280 ft. Laboratory psia at the structural high of9,280 ft. Laboratory tests show that the James Lime oil is miscible with dry gas at about 4,800 psi. The irreducible water saturation varies from about 10 percent to about 30 percent, depending on rock type. There is evidence that the Lower A zone may be oil wet as a result of the presence of residual bitumen in the pore spaces. The western gas cap area of the James Lime reservoir, which exhibits different fluid characteristics and behaves as a separate reservoir, is beyond the scope of this paper.
Alternate Gas-Water Injection Plan
Initial economic studies indicated that pressure maintenance by alternate gas-water injection at the miscibility pressure of 4,800 psia would be the optimum recovery program. The miscible recovery program was expected to increase recovery efficiency to 50 percent, which is 13 percent more than the expected percent, which is 13 percent more than the expected waterflood recovery factor of 37 percent. The initial injection plan was based on alternating gas and water injection into several parallel lines of injection wells running generally northwest-southeast, parallel to the reef core trends. The A zone and C parallel to the reef core trends. The A zone and C zone were to be operated as separate reservoirs insofar as possible. Plans were to begin the program by injecting into the A zone an initial gas slug equal to 3 to 5 percent of the hydrocarbon pore volume in the area of injection in the first line of injection wells on the east side of the reservoir. Initial gas slugs in the first line of injectors were to be followed by initial water slugs equal to approximately 50 percent of the preceding gas slugs. After placement of the initial preceding gas slugs. After placement of the initial slugs, subsequent smaller gas and water slugs were to be injected alternately at an approximate 1:1 gas-water injection ratio. The initial gas slugs were larger than subsequent slugs of water and gas, on the theory that a miscible bank of gas could be maintained in contact with the oil. Gas injection into the first line of injection wells was begun in March, 1966, shortly after the entire field was unitized in Oct., 1965.
It is common practice to employ radioactive tracers for studying fluid movement in oil reservoirs. In many instances, excessive tracer adsorption and anomalous tracer flow behaviour have been reported. The present investigation was concerned with the phenomena associated with the flow of fluids containing radioactive tracers (tritium and Carbon-14). Miscible displacements were conducted in order to evaluate tracer retention and/or adsorption effects. A suitable counting and efficiency determination technique was developed in order to evaluate the radioactivities of fluid systems containing two radioisotopes. The use of two radioactive tracers to trace the simultaneous flow of two fluids was found to be a very effective tool.
The adsorption of tritium during miscible displacements conducted in Berea sandstone cores averaged 1.5 per cent. A systematic investigation showed that this adsorption could be explained on the basis of the exchange of tritium atoms with the hydrogen atoms of the water of hydration found in naturally-occurring clays in porous media.
It was found that the adsorption of tritium increased with a decrease in the displacement rate.
No adsorption of Carbon-14 was observed in miscible displacements in sandstone cores. An average of 0.47 per cent tracer retention was observed during desorption displacements involving Carbon-14, but such retention is attributed to mass transfer effects, and is not considered a true adsorption phenomenon.
A technique for determining the counting efficiency of multiply-tagged fluids was developed. The quenching and scintillating effects of a salt, a hydrocarbon and an alcohol were investigated. It was found that liquid scintillation instrument counting efficiency corrections only partially compensate for extraneous quenching or scintillation effects.