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The single-well chemical tracer (SWCT) test is an in-situ method for measuring fluid saturations in reservoirs. Most often, residual oil saturation (Sor) is measured; less frequently, connate water saturation (Swc) is the objective. Either saturation is measured where one phase effectively is stationary in the pore space (i.e., is at residual saturation) and the other phase can flow to the wellbore. Recently, the SWCT method has been extended to measure oil/water fractional flow at measured fluid saturations in situations in which both oil and water phases are mobile. The SWCT test is used primarily to quantify the target oil saturation before initiating improved oil recovery (IOR) operations, to measure the effectiveness of IOR agents in a single well pilot and to assess a field for bypassed oil targets. Secondarily, it is used to measure Swc accurately for better evaluation of original oil in place (OOIP). Fractional flow measurement provides realistic input for simulator models used to calculate expected waterflood performance. This chapter familiarizes the reader with the SWCT method, and offers guidelines for selecting suitable test wells and for planning and executing the field operations on the target well. Test interpretation is also discussed and illustrated with typical examples. The first SWCT test for Sor was run in the East Texas Field in 1968. Patent rights were issued in 1971. Since then, numerous oil companies have used the SWCT method.
Figure 1.1b – Reservoir evaluation by material balance with measured Sor. A reliable in-situ measurement of Sor simultaneously defines the target for enhanced oil recovery (EOR) and allows estimation of the potential bypassed (mobile) oil in the field. This moveable oil is the target for infill drilling and/or flood sweep efficiency improvements. Because Sor varies greatly with formation type, oil/water properties, and other variables that are not completely understood (e.g., wettability changes caused by water flood practices), Sor measurements range from 10% to 45%. There is no reliable way to predict Sor with acceptable accuracy for most reservoirs.
This paper reviews various applications of partitioning tracers in the petroleum industry. While non-partitioning tracers are routinely used for flow characterization and source identification, partitioning tracers have been under-utilized largely because of a lack of publicity and credibility. In theory, partitioning tracing is potentially applicable whenever a phase boundary, for instance, gas-oil, oil-water, and water-rock, exists. Partitioning between phases will slow down the partitioning tracers in a phenomenon known as chromatographic retardation, from which fluid saturations and surface properties can be deduced. properties can be deduced. Single-well tracer testing to determine residual oil saturation to waterflood S orw constitutes the most common application of partitioning tracers. More than 200 tests have been run since its first invention In 1971. In the meantime, to overcome model inadequacies, new features are continually incorporated into the simulators, making the simulators extremely difficult to run. To get around the simulation problems, a mass balance method was proposed for direct calculation of S orw from the hydrolysis rate. Based on the same principle, an internally calibrated method involving a new class of compounds which can undergo hydrogen exchange with water is being investigated. With recent advances in instrumentation and the introduction of the chromatographic transformation technique. several successful interwell tests, mostly by Esso Resources Canada Limited (ERCL), to determine residual oil saturations in watered-out and gas-saturated reservoirs have been reported. The technique involves direct comparison of the partitioning and non-partitioning tracer profiles with no need for simulation. Under ideal conditions, S or can be determined by layers. In a different approach, full-field simulation of a multi-well test has also been employed to estimate oil saturation distribution. These tests clearly demonstrate that the valuable information on S or justifies the incremental cost of including a partitioning tracer with the non-partitioning tracer in any routine tracing projects. projects. In-situ miscibility measurement by ERCL is another interesting application. Separation of partitioning tracers injected with solvent is a measure of deviation from the first contact miscibility condition FCM. Other unproven techniques including determining trapped gas saturation during a foam flood, relative permeability ratio measurement and direct logging of gamma emitting partitioning tracers through casing to determine S or partitioning tracers through casing to determine S or vertical distribution are also reviewed in the paper.
Inert non-partitioning tracers have been widely used in the petroleum industry to tag the injected fluid as well as to characterize the flow path. The tracer results provide a guideline to pattern balancing and reconfiguring provide a guideline to pattern balancing and reconfiguring for better sweep and more effective utilization of the injected fluid. Tracer response can also be indicative of in-fill drilling potential. In addition to their use in reservoir management, non-partitioning (in particular, radioactive) tracers are also employed routinely in drilling/completion and injection profile logging.
Teklu, Tadesse Weldu (Colorado School of Mines) | Brown, Jeffrey S. (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Graves, Ramona M. (Colorado School of Mines) | AlSumaiti, Ali M. (The Petroleum Institute)
Abstract In petroleum reservoirs only a small fraction of the original oil-in-place is economically recovered by primary, secondary, and tertiary recovery mechanisms. A considerable amount of hydrocarbon ends up unrecovered or trapped due to microscopic phase trapping in porous media which results in an oil recovery factor typically less than 50%. Waterflooding is by far the most widely used method to increase oil recovery. The oil that remains in the porous media after waterflooding is called remaining oil saturation (ROS) which is larger than the relative permeability residual oil saturation (Sorw or simply Sor). This residual oil saturation varies depending on lithology, pore size distribution, permeability, wettability, fluid characteristics, recovery method, and production scheme. Determination of the residual oil saturation of a reservoir is a key parameter for reserve assessment and recovery estimates. Further, reliable Sor data is important for investigation of possible incremental recovery under Enhanced Oil Recovery (EOR) methods. Various residual oil saturation measurment techniques are available both at laboratory and field scale. None of the techniques can be regarded as a single best method of determining Sor. Depending on the complexity of the reservoir under study, combinations of methods are always advisable for appropriate Sor determination. This study is an up-to-date review of techniques used in determining Sor in laboratory and field. The study further reports on the advantages and limitations of each method and provides recommendations for best practices.
This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., April 22–24, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A previously-described single-well tracer test for measuring residual oil saturation in watered-out formations has been modified and extended to permit measurement of connate water saturation in formations producing water-free oil. The method provides a viable alternative to oil-base coring as a means for obtaining saturations for use in making reserve estimates or in calibrating saturation logs. The measured saturation represents an average value for a much larger reservoir volume than that sampled by logs or cores. The connate water saturation test cons of three phases:injection of a bank of crude oil containing propyl formate, the primary tracer, reaction of part of the primary tracer, reaction of part of the propyl formate to form propyl alcohol, the propyl formate to form propyl alcohol, the secondary tracer, and production, sampling and analysis of the injected fluid to obtain concentration profiles for the two tracers. Because of their different affinities for water, the two tracers separate as they move through the formation to the wellbore. The degree of separation is related to the amount of immobile water present in the formation — the greater the separation, the larger the connate water saturation. The method has been field tested, and the results of the field test are in good agreement with log and core data. Introduction The use of a single-well tracer method to measure residual oil saturation in watered-out formations has been described by Tomich et al. The tracer method has now been modified and extended to permit in-situ determination of connate water saturation in a formation producing water-free oil. The same procedure can producing water-free oil. The same procedure can thus be used to measure the two saturations in a given formation that delimit the recovery attainable by waterflooding. The method also provides a viable alternative to oil-base provides a viable alternative to oil-base coring as a means for obtaining saturations for use in making reserve estimates or in calibrating saturation logs directly in the zone of interest. In-situ chemical tracer tests avoid many of the limitations of core analysis and well logging, the most commonly used methods for determining fluid saturations.