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Collaborating Authors
Eastland County
Summary Brigham's model has been used extensively in the petroleum industry for the design and interpretation of interwell tracer tests. The model is based on correlation and has included physical dispersion as an input parameter. In spite of its limitations, the model is useful in estimating layer heterogeneity, layer distribution, permeability contrast, and dispersion in the reservoir. However, the model can only handle nonpartitioning tracers that have no solubility in oil. With the advancement in partitioning tracer technology and interpretation technique, interwell partitioning tracer testing has gained its popularity, especially in China,1 for determining residual oil saturation, Sorw, between wells. Partitioning tracer testing also find sits application in environmental protection, where tests are routinely run to determine the amount of nonaqueous liquid phase nonaqueous phase liquid (NAPL)trapped underground due to spill or seepage. While sophisticated streamline or finite difference simulators have been increasingly used to determine Sorw distribution from the tracer production data, the simple semiquantitative model still has its merits in providing a direct, unambiguous estimate of average Sorw along the tracer flow path. This paper broadens the scope of the original Brigham's model by incorporating partitioning tracers into the model using a chromatographic transformation technique. By matching the partitioning and nonpartitioning tracer curves, Sorw can be determined by layers. The extended Brigham model was applied to the Ranger oilfield multiple tracer test, and the residual oil saturation determined compared favorably with those obtained by chromatographic transformation method and numerical simulation. Introduction Interwell tracer testing has been recognized as a reliable method for determining residual oil saturation between wells. The method 2--5 involves the injection of a slug of partitioning and nonpartitioning tracers at an injector and production of the tracers from nearby producers. Partitioning between phases slows down the partitioning tracers by a delay factor of 1+ GREEK beta in a phenomenon known as chromatographic retardation, from which the residual oil saturation can be determined. Oil distribution between wells is derived by matching the tracer production profiles using a 3D finite difference simulator such as UTCHEM 6,7 or by a streamline model. 8,9 To circumvent the technical problems encountered in simulation, an analytical chromatographic transformation method was proposed by Tang 2--4 and Wood et al. 5 and a moment-analysis method 10--13 to calculate S or. directly by comparing the relative separation of tracers. Chromatographic transformation was employed by Tang 2--4 and Wood et al. 5 to determine S orw for the Golden Spike, Judy Creek, and Leduc interwell partitioning tracer tests. The moment analysis method was applied mainly to laboratory tests or small-scale NAPL tests where the complete profiles could be generated within days. In a reservoir-scale tracer test, the tracer monitoring program is usually stopped for cost-saving purposes once the peak is observed; therefore, complete production is seldomattained. Extrapolation of tracer production curve to completion will introduce a large uncertainty in moment calculation, 14 and therefore in S orw determination. The semiempirical Brigham's homogeneous five-spot model, 15--17which is a common tool in the industry for tracer design 18,19 and data interpretation for its simplicity, lies between these two extremes. However, it should be noted that in spite of its frequent use, the applicability of the model to patterns with significant deviation from the aforementioned assumptions has not been rigorously proved. The original Brigham model can only handle nonpartitioning tracer, and its functionality is expanded in this paper to include partitioning tracer for S orw determination. The extended Brigham model was used to interpret the Ranger field tracer test data, and the results were compared with those obtained by chromatographic transformation and other numerical means.
- South America > Guyana > North Atlantic Ocean (0.55)
- North America > United States > Texas > Eastland County (0.55)
Abstract Brigham's model has been used extensively in the petroleum industry for the design and interpretation of interwell tracer tests. The model is based on correlation and has included physical dispersion as an input parameter. In spite of its limitations, the model is useful in estimating layer heterogeneity, layer distribution, permeability contrast and dispersion in the reservoir. However, the model can only handle non-partitioning tracers that have no solubility in oil. With the advancement in partitioning tracer technology and interpretation technique, interwell partitioning tracer test has gained its popularity, especially in China, for determining residual oil saturation Sorw between wells. Partitioning tracer test also finds its application in environmental protection, where the test is routinely run to determine the amount of non-aqueous liquid phase NAPL trapped underground due to spill or seepage. While sophisticated streamline or finite difference simulators have been increasingly used to determine Sorw distribution from the tracer production data, simple semi-quantitative model still has its merits in providing a direct, unambiguous estimate of average Sorw along the tracer flow path. This paper broadens the scope of the original Brigham's model by incorporating partitioning tracers into the model using a chromatographic transformation technique. By matching the partitioning and non-partitioning tracer curves, Sorw can be determined by layers. The extended Brigham model was applied to the Ranger oil field multiple tracer test and the residual oil saturation determined compared favorably with those obtained by chromatographic transformation method and numerical simulation. Introduction Interwell tracer test has been recognized as a reliable method for determining residual oil saturation between wells. The method involves the injection of a slug of partitioning and non-partitioning tracers into an injector and production of the tracers from nearby producers. Partitioning between phases slows down the partitioning tracers by a delay factor 1+ß in a phenomenon known as chromatographic retardation, from which the residual oil saturation can be determined. Oil distribution between wells is derived by matching the tracer production profiles using a 3D finite difference simulator such as UTCHEM or by a streamline model. To circumvent the technical problems encountered in simulation, an analytical chromatographic transformation method was proposed by Tang and a moment analysis method by Pope et al. to calculate Sorw directly by comparing the relative separation of tracers. Chromatographic transformation was employed by Tang to determine Sorw for the Golden Spike, Judy Creek and Leduc interwell partitioning tracer tests. The moment analysis method was applied mainly to laboratory tests or small-scale NAPL (Non-Aqueous Phase Liquid) tests where the complete profiles could be generated within days. In a reservoir-scale tracer test, the tracer monitoring program is usually stopped for cost saving purposes once the peak has been observed, therefore complete production is seldom attained. Extrapolation of tracer production curve to completion will introduce a large uncertainty in moment calculation, hence Sorw determination. The semi-empirical Brigham's homogeneous 5-spot model, which is a common tool in the industry for tracer design and data interpretation for its simplicity, lies between these two extremes. The original Brigham model can only handle non-partitioning tracer and its functionality is expanded in this paper to include partitioning tracer for Sorw determination. The extended Brigham model was used to interpret the Ranger field tracer test data and the results were compared with those obtained by chromatographic transformation and other numerical means. Bingham Model for Non-partitioning Tracers Brigham and Smith were able to come up with a semi-quantitative model to predict tracer breakthrough curve for unit mobility ratio displacement in a homogeneous, repetitive, balanced five-spot pattern. In Brigham's approach, an empirical correlation (Eq.1) was developed to describe the fractional flow or normalized tracer concentration C/Co for continuous tracer injection.
- South America > Guyana > North Atlantic Ocean (0.55)
- North America > United States > Texas > Eastland County (0.55)
Summary This paper discusses the application of an efficient streamline based inversion method to a large multiwell multitracer Partitioning Interwell Tracer Test (PITT) in the McClesky sandstone, the Ranger field, Texas, to characterize both permeability and oil saturation distribution. During a typical PITT, a conservative and a partitioning tracer are injected into the reservoir. The partitioning tracer gets partially absorbed into the oil phase, leading to a separation in the tracer responses that can be used to infer oil saturation distribution in the tracer-swept area. Our approach is extremely efficient because it relies on analytic computation of the sensitivity of the tracer response to reservoir parameters such as permeability and saturation using a single streamline simulation. We follow a two-step procedure whereby we first match the conservative tracer response to determine the permeability distribution, and then match the partitioning tracer response to obtain oil saturation distribution in the reservoir. The entire history matching took less than 6 hours on a PC as opposed to several months typically required for a manual history matching. We compared our results to a manual history match obtained using a finite-difference simulator. Both the manual history matching and the streamline-based inversion identified similar largescale trends in permeability and saturation distribution. However, well-specific matches were significantly improved over those obtained through the manual history matching. Our approach is much more efficient in terms of computation time and effort, and the results are less sensitive to personal bias compared to manual history matching. Finally, we discuss a procedure to assess the results in terms of resolution of the estimates of permeability and saturation distribution. Introduction Success of secondary and tertiary oil recovery projects targeting the remaining oil in mature or partially depleted reservoirs strongly depends on adequate description of reservoir heterogeneity and remaining oil distribution. Many field studies have reported successful application of conservative tracers to characterize interwell communication, presence of flow barriers, and preferential flow paths to improve understanding of fluid movement in the reservoir. Also, single-well partitioning tracer tests have been widely used in the industry to estimate oil saturation in the vicinity of wells. Analysis of tracer tests typically requires the solution of an inverse problem. To date, most of the work on inverse modeling associated with tracer data have been limited to estimating permeability distribution or transport parameters such as dispersivities or molecular diffusion. Inverse problems dealing with the estimation of spatial distribution of oil saturation have remained relatively unexplored. During partitioning interwell tracer tests, a suite of tracers with a range of oil-water partitioning coefficients are injected into the subsurface and are sampled at the producing wells. A conservative or nonpartitioning tracer is also injected during the test. Because of the presence of oil, partitioning tracers are retarded compared to the nonpartitioning tracer. The chromatographic separation between these tracers is utilized to estimate oil saturation in the reservoir. An excellent summary of the analytic methods for analysis of the PITT data in oil reservoirs is given by Tang. These analytic methods are simple and easy to apply; however, they only provide an estimate of average oil saturation. Potentially, every observed data point of a PITT may carry important information about reservoir properties. Thus, a direct match of the tracer history is desirable but is difficult because it involves the solution of a computationally intensive inverse problem. Manual history matching is a common practice wherein one attempts to find a combination of permeability, porosity, and oil saturation that would lead to an adequate match of both conservative and partitioning tracer data. Such manual history matching is a time-consuming process that relies heavily on personal judgments and trial and error. Past attempts to solve the inverse problem by automated history matching using finite-difference simulators have shown that despite ever-increasing computational speed, finite-difference simulators often require prohibitively large computation time. Recently, streamline simulation has received wide-spread attention because of its high-speed performance. Use of streamline simulation in analyzing field tracer data can be beneficial in several ways. Apart from significantly faster forward simulations, another major advantage is that parameter sensitivities can be computed analytically in a single forward simulation. Such sensitivities quantify the relationship between small perturbations in reservoir properties, such as permeability or saturation, and changes in observed tracer response. Vasco et al. presented a streamline-based production data integration approach that exploits an analogy between streamlines and seismic ray tracing. Yoon et al. demonstrated the utility of the streamline-based inversion method for estimating nonaqueous phase liquid (NAPL) saturation in an aquifer from PITT data and applied the method to a set of tracer tests carried out in a test cell at the Hill Air Force Base. In this paper, we show how a field-scale PITT data can be analyzed using the streamline-based inverse method. Our approach is fast, eliminates much of the trial-anderror associated with manual history matching, and provides an estimate of the spatial distribution of oil saturation in the reservoir. We also discuss and illustrate a procedure to assess the solution to the inverse problem using a resolution analysis. To our knowledge, this is the first time inverse modeling has been applied for fieldscale estimation of saturation distribution.
- North America > United States > Texas > Fort Worth Basin > Ranger Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- (10 more...)
Abstract This paper discusses the application of an efficient streamline-based inversion method to a large multi-well multi-tracer Partitioning Interwell Tracer Test (PITT) in the McClesky sandstone, Ranger Field, Texas, to characterize both permeability and oil saturation distribution. During a typical PITT, a conservative and a partitioning tracer are injected into the reservoir. The partitioning tracer gets partially absorbed into the oil phase, leading to a separation in the tracer responses that can be used to infer oil saturation distribution in the tracer-swept area. Our approach is extremely efficient because it relies on analytic computation of the sensitivity of the tracer response to reservoir parameters such as permeability and saturation using a single streamline simulation. We follow a two step procedure whereby we first match the conservative tracer response to determine the permeability distribution and then match the partitioning tracer response to obtain oil saturation distribution in the reservoir. The entire history matching took less than 6 hours in a PC as opposed to several months typically required for a manual history matching. We compared our results to a manual history match obtained using a finite-difference simulator. Both the manual history matching and the streamline-based inversion identified similar large-scale trends in permeability and saturation distribution. However, well-specific matches were significantly improved over those obtained through the manual history matching. Our approach is much more efficient in terms of computation time and effort and the results are less sensitive to personal bias compared to manual history matching. Finally, we discuss a procedure to assess the results in terms of resolution of the estimates of permeability and saturation distribution. Introduction Success of secondary and tertiary oil recovery projects targeting the remaining oil in mature or partially depleted reservoirs strongly depends on adequate description of reservoir heterogeneity and remaining oil distribution. Many field studies have reported successful application of conservative tracers to characterize inter-well communication, presence of flow barriers, and preferential flow paths to improve understanding of fluid movement in the reservoir. Also, single-well partitioning tracer tests have been widely used in the industry to estimate oil saturation in the vicinity of wells. Analysis of tracer tests typically requires the solution of an inverse problem. Todate, most of the work on inverse modeling associated with tracer data have been limited to estimating permeability distribution or transport parameters such as dispersivities or molecular diffusion. Inverse problems dealing with the estimation of spatial distribution of oil saturation has remained relatively unexplored. During partitioning interwell tracer tests a suite of tracers with a range of oil-water partitioning coefficients are injected into the subsurface and are sampled at the producing wells. A conservative or non-partitioning tracer is also injected during the test. Because of the presence of oil, partitioning tracers are retarded compared to the non-partitioning tracer. The chromatographic separation between these tracers is utilized to estimate oil saturation in the reservoir. An excellent summary of the analytic methods for analysis of the PITT data in oil reservoirs is given by Tang. These analytic methods are simple and easy to apply; however, they only provide an estimate of average oil saturation. Potentially, every observed data point of a PITT may carry important information about reservoir properties. Thus, a direct match of the tracer history is desirable but is difficult because it involves the solution of a computationally intensive inverse problem.
- North America > United States > Texas > Fort Worth Basin > Ranger Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > West Central Graben > PL2244 > Block 21/27a > Pilot Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > West Central Graben > P2244 > Block 21/27a > Pilot Field (0.99)
- (12 more...)
Summary Oryx Energy Co. evaluated the design and operation of a low -tensionsurfactant/polymer pilot in the McCleskey sandstone of the Ranger field in Eastland County, TX. The test was performed in a watered-out area developed on40-acre spacing that was chosen because good reservoir permeability, theavailability of fresh water, and high residual oil saturations (ROS's) made itsuitable for a surfactant/polymer process. Major disadvantages of the are awere a potential lack of pattern confinement and a salinity contrast causedpotential lack of pattern confinement and a salinity contrast caused by theinjection of fresh water. The purpose of the test was to determine theapplicability of the technology and its implementation. The pilot wassuccessful on the basis of both monitored results and produced oil but did notachieve its design objectives because of reservoir heterogeneity and reducedsweep efficiency. The successful propagation of chemical fronts and oilrecovery within the pilot area demonstrated that in this and similarreservoirs, pilot area demonstrated that in this and similar reservoirs, surfactant flooding can recover tertiary oil in significant quantities on largeareal spacing. This paper discusses the design, operation, and evaluation ofthe field project and includes considerations for the successful implementationof the technology. Introduction In 1986, a surfactant flood pilot test was initiated to develop andunderstand the requirements for the implementation of surfactant floodingtechnology. The pilot test, conducted in the McCleskey sandstone formation ofthe Ranger field, Eastland County, TX (Fig. 1) in the North Central Ranger Unit(NCRU), consisted of one injection well, Well 3-41, surrounded by six producingwells drilled on 40-acre spacing. The pattern was considered closed to the westby a stratigraphic trap and bounded to the north, east, and south by waterinjection, as indicated by the dashed lines in Fig. 2. The test area in the McCleskey sandstone formation was selected because ofthe high ROS's remaining in the swept areas and the availability of freshwater. The formation also had good reservoir permeability with good injectivityand a low clay content, The permeability with good injectivity and a low claycontent, The waterflood had been under way long enough to establish a stabledecline, so oil response to surfactant flooding could be clearlydelineated. Geology. The moderately oil-wet McCleskey formation is a marine sandstonedeposited under a deltaic environment. The formation in the NCRU area is partof one of the distributary channels that fed sediments to the delta. In thepilot area, the channel is bounded by other distributary channels to the eastand west, but it is only toward the west that the sandstones lose lateralcontinuity. A shale barrier caused by a pinchout in the sand is in the westernpart of the surfactant pilot area. The pilot net pay varies from 8 to 28 ft ata depth of 3,400 ft. The McCleskey formation is a quartzose sand of varying grain size with goodpermeability ranging from 200 to 500 md with an average porosity of 15 %. The Dykstra Parsons coefficient of permeability variation from core data rangedfrom 0.71 to 0.83 as a permeability variation from core data ranged from 0.71to 0.83 as a result of poor sorting of the sand grains. The 40 deg. API gravityoil has a viscosity of 2 cp at the reservoir temperature of 125 deg. F andpressure of 450 psia. pressure of 450 psia. History. The Ranger field wasdiscovered in 1917 and was quickly developed, with production peaking in 1919at 80,000 BOPD, but then declined rapidly. Stripper operations continued, andgas-injection and waterflooding projects were undertaken with various degreesof success over the years. Detailed records of the field's actual production donot exist, and estimates of oil recovery range from 15 % to 21 % of theoriginal oil in place. Oryx acquired the property in 1980, and a waterflood of the NCRU wasevaluated and initiated in 1981. The waterflood used water from Possum Kingdom Lake. The total dissolved solids (TDS) of the lake water varied seasonally, butaveraged 0. 14% TDS with 0.02% being multivalent ions such as Ca+2 and Mg+2. Core studies indicated that the Possum Kingdom water-was compatible with the McCleskey sandstone with no sign of clay swelling. Core analysis showed thetotal average clay content of the McCleskey to be less than 1 % with very lowcationic exchange capacity and little or no kaolinite and other swellingclays. An interwell tracer program was undertaken in 1982 in the water-flood pilotarea, which was just east of the surfactant pilot area. Simulation of the firsttracer study results led to the conclusion that there was appreciable fluiddrift toward the south and that certain parts of the pilot were poorly swept. The study determined that sweep conformance within the pilot ranged from 79 %to 87 % and that the average oil saturations in the watered out zones were 40%to 50%, according to analysis of partitioning tracer tests. A subsequent black-oil model study in 1983 concluded that water-floodrecovery would be 58% to 66% of the mobile oil in place and the averageremaining oil saturation to waterflooding would be 46 %. This was consistentwith core studies that had determined the average S., (irreducible oilsaturation to water) to be 37.8%. Because of the large unrecoverable oil reserves remaining afterwaterflooding, a study was undertaken to evaluate Ranger for enhanced recoveryprocesses. A polymer-augmented waterflood was ruled out because the incrementalreserves obtained with a polymer flood alone would not justify the costs. Surfactant systems, polymer flood alone would not justify the costs. Surfactantsystems, on the other hand, generate low interfacial tensions, which raise thereservoir capillary number and reduce ROS's to increase oil recovery. For thisreason, a surfactant process was developed for application at Ranger. Project Design Project Design The project objective was to field test aproprietary surfactant/polymer process on 40-acre field Spacing to evaluatethe applicability polymer process on 40-acre field Spacing to evaluate theapplicability and economics of the technology in the field. The importantprocess variables included slug performance m the varying-salinity processvariables included slug performance m the varying-salinity reservoir, predictability of the slug injectivity, potential chromatographic separation ofthe surfactant slug, and scale up from the laboratory to the field. The original salinity in the Ranger field was 11 % TDS with 1.1% multivalentions such as Ca+2 and Mg+2. After many years of fresh Possum Kingdom waterinjection, the produced water salinities ranged from 1.6% to 5% TDS at thestart of the project in the pilot area. As a result, a salinity contrast orgradient was known pilot area. As a result, a salinity contrast or gradient wasknown to exist in the reservoir. It is well documented that reservoir salinityhas a major effect on surfactant flooding and that surfactant recovery systemshave failed because of wide salinity variations within the reservoir. Theeffectiveness of the surfactant slug to mobilize and produce oil in the pilotarea would be used as a measure of the effectiveness of the surfactant designto address the salinity variation in the pilot area.
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
North Central Texas has recently become a center of interest for the oil menof America. The bringing in of the McClosky well at Ranger, Eastland County, and the shallow pool at Brownwood, Brown County, in 1917, has stimulatedinterest in this area to fever pitch. Oil men from all over the United Statesare now investing there. The area of present interest is shown by theaccompanying map (Fig. 1). The money spent in leases runs into millions of dollars. It is no exaggerationto say that a strip of country 200 miles (321 km.) long and 125 miles (201 km.)wide, comprising some 15,000,000 acres (6,070,310 ha.), has been leasedpractically solid at a cost for rentals and bonuses of at least $1 per acre.The test holes contracted for will certainly number 400, at a cost of at least $5,000,000. From what has been done in the past six months, $20,000,000 atleast will be spent. To pay returns on this amount of money, new production tothe extent of at least 12,000,000 bbl. must be obtained. At present, theproduction from new fields will not average over 5000 bbl. per day; three wellsat Ranger are producing 3000 bbl.; 250 wells at Brownwood produce 1000 bbl.;and the Gray well, Coleman County, is as yet an unknown factor. However, at Ranger there is every indication of developing a good pool coveringfrom 1500 to 2000 acres (607 to 809 ha.), more or less, but the wells are deep,3400 to 3800 ft. (1036 to 1158 m.), and cost $35,000 to $40,000 to drill. Largewells are necessary to pay for such expensive holes. As new wells are drilled, the gas pressure will be lowered rapidly, and large production need not beexpected. For those oil men who expect a second Cushing or an Eldorado, Rangerholds little of promise. At Brownwood, Brown County, there are some 250 shallow wells (depths from 200to 350 ft.) averaging 4 to 7 bbl. per day. There is a chance of an extensiveproducing area for these shallow sands to the southwest, and the opening ofseveral thousand acres of shallow oil territory, and also some promise ofdeeper oil horizons in the Ranger horizon, but probably all under 2500ft. At present, the lease brokers and speculators, and only a handful of oil men, have made any money. More fields must be developed, and it is more particularlywith these possibilities that this paper deals. Lack of water for drillingpurposes has undoubtedly held back development so far this year; this part ofTexas has had a drought for two years and there is an actual scarcity ofwater. AIME 061–47
- North America > United States > Texas > Coleman County (0.25)
- North America > United States > Texas > Eastland County (0.24)
- North America > United States > Oklahoma > Payne County > Cushing (0.24)
- North America > United States > Indiana > Brown County (0.24)
- Geology > Geological Subdiscipline > Stratigraphy (0.69)
- Geology > Rock Type > Sedimentary Rock (0.56)
- North America > United States > Mississippi > Magee Field (0.99)
- North America > United States > Mississippi > Magnolia Field (0.98)
- North America > Canada > Alberta > Coleman Field > Canlin Coleman 5-27-9-4 Well (0.91)
- (2 more...)