Two field tests were conducted using the single-well tracer test to measure residual oil saturation. A description of the tests is presented. A dilution effect or production from zones that did not take tracer injection occurred and had to be accounted for in the data analysis. Introduction Residual oil saturation measurements are important in the evaluation of tertiary recovery projects. Reliable values are necessary to evaluate a pilot performance and to determine the potential for commercial tertiary recovery projects. projects. The single-well tracer method to measure residual oil saturation in watered-out formations has been described by Tomich et al. This method has the attractive feature of measuring the residual oil saturation in a relatively large pore volume and involves the following steps:Injecting a bank of water containing a primary tracer, either ethyl acetate or n-propyl formate.Shutting in a well to allow time for some of the primary tracer to react, forming a secondary tracer of primary tracer to react, forming a secondary tracer of ethyl alcohol or n-propyl alcohol.Producing a well and analyzing water samples to determine concentration profiles of the primary and secondary tracers. The separation of the arrival times of the two tracers indicates the residual oil saturation. This separation is caused by different partitioning of the primary and secondary tracers between the oil and water. primary and secondary tracers between the oil and water. The greater the separation between the tracers, the higher the residual oil saturation. Continental Oil Co. has been licensed to conduct Exxon Production Research Co.'s single-well tracer method to determine residual oil saturation since 1973. Residual oil saturations were run at three locations in five different wells. A service company tested two wells at one location, while Conoco Production Research tested at the other sites. Logistic problems of scheduling the tests on short notice and economic considerations caused Conoco to conduct its own tests. Two wells were tested at the Maier lease in the Illinois Basin and one well was tested at the Big Muddy field in Wyoming. Both locations had low rates that limited test size. The Big Muddy is a fresh water reservoir, while salinity of the Maier lease is about 10,000 ppm. There was no appreciable gas production with either test. This paper coversthe details of the field tests conducted solely by Conoco,the determination of the partition coefficients, andthe fitting of the produced partition coefficients, and (3) the fitting of the produced tracer concentrations using Exxon's single-well tracer computer models. Several approaches were made to fit the data from the Big Muddy test because results were complicated by drift and the tracers were diluted by water from zones that did not accept them. Test Design The following items were considered when designing the test.A large test (up to 90 bbl of injection per foot of pay) was desirable. Injection of 50 bbl per foot of pay was pay) was desirable. Injection of 50 bbl per foot of pay was a good design size.The reservoir temperature dictated the selection of the primary tracer. Ethyl acetate was used for the higher temperatures and n-propyl formate for the cooler reservoirs. JPT P. 194
Summary. Conoco Inc, initiated a low-tension pilot test in 1973 at the Big Muddy field east of Casper, WY. The process mobilized an oil bank ahead of the slug, reached a peak oil cut of 20%, and recovered 36% of the residual oil saturation (ROS). Tracers were injected in the preflush and postflush to determine swept volumes and distributions of flow. Tracer responses showed that more than 95% of the flow to the center well of the five-spot came from the two northern injection wells. The overall performance of the pilot was analyzed with a numerical simulator. pilot was analyzed with a numerical simulator. As a result of the pilot and the supporting research, a nearby 90-acre [36.4-ha] commercial demonstration low-tension flood was initiated in 1980 and was operated as an EOR project until July 1985, although oil production still continues. Introduction The pilot test was conducted at the Big Muddy field between 1973 and 1978. Objectives of the pilot wereto determine the oil recovery for a known low-tension slug size and reservoir swept volume;to calibrate a numerical simulator for application to future projects; andto develop process design technology for projects; andto develop process design technology for field-scale projects. Oil recovery by the low-tension process was analyzed with the help of a reservoir simulator. Tracers were injected during the preflush and postflush periods to determine flow distributions and preflush and postflush periods to determine flow distributions and swept volumes. Calculation techniques and highlights of the design and operations are presented. Finally, the results of a single-well surfactant test (SWST) conducted in the Big Muddy field are compared with the pilot results. Design and Operation Highlights Reservoir Description and Operating Problems. The Big Muddy Wall Creek reservoir is an anticlinal structure with edgewater encroachment. The pilot area is located near the anticlinal crest in the center of what was the best waterflood area. Four injection wells and a center producing well were drilled inside four existing wells. The five-spot was about 1 acre [0.4 ha], and the total pilot area was 5.5 acres [2.2 ha], as shown in Fig. 1. Formation data were obtained from a comprehensive logging and coring program that included oriented cores and a sonic borehole televiewer log. These data were complemented with pressure-transient testing and a single-well tracer test (SWTT) to pressure-transient testing and a single-well tracer test (SWTT) to determine ROS. 3 These data were used to achieve a balanced, confined five-spot operation. 4 Preflush and postflush tracers were injected to help determine the distribution of flow and swept volumes. Well J30, the center well of the five-spot, produced 25 % of the total injection rate. Although the total producing rate from Well J30 remained nearly constant, injection well rates were adjusted at the end of the preflush as shown in Table 1. The adjustment was based on tracer data that were later determined to be erroneous as a result of microbial degradation of the ethanol tracer. The adjustment, rather than balancing the five-spot, actually resulted in a less-balanced pattern. Because of the likelihood of microbial degradation of the ethanol tracer in the preflush and concern that polysaccharide and dilute isobutyl alcohol (IBA) would also act as substrates, efforts for microbial control were intensified at the start of the low-tension slug injection. After supply water was chlorinated, caustic was added to increase the pH to a range of 12.5 to 13.0. For the remaining project life, microbial cultures were routinely obtained from project life, microbial cultures were routinely obtained from production and injection sites. Bacteria were not observed in any of production and injection sites. Bacteria were not observed in any of the cultures on the injection side. Ethanol and C were injected as tracers in Well 13 1. Ethanol tracer degraded during the post-flush, however, as evidenced by a smaller fraction of the ethanol post-flush, however, as evidenced by a smaller fraction of the ethanol tracer that was recovered relative to the C tracer. Average injection or producing rates were only about 100 B/D [15.9 m3 /d], or about half of the desired rate without stimulation. Therefore, the injection wells and center producing well were fractured and propped with 2,000 lbm [907 kg] of sand. The small sand volume was designed to produce propped fractures of 40 ft [12.2 m], or about 15% of the well-to-well distance. Greater fracture lengths carried the risk of unacceptable loss of oil recovery if the fracture direction and the pattern orientation were misoriented more than 15 [0.26 rad].4 An unusual feature of the Wall Creek formation is that the parting pressure determined from step-rate injectivity tests was about 75 pressure determined from step-rate injectivity tests was about 75 to 150 psi [517 to 1034 kPa] less than hydrostatic pressure. Downhole pressure sensors similar to tank-level bubblers were used to monitor and to control maximum injection pressure. The bubbler depths were set slightly below a depth corresponding to the interpreted parting pressure. For pilot interpretation, this system was limited because there were no pressure measurements when the fluid levels were below the bubblers. As previously stated, the rates of the injection wells were changed before surfactant injection was begun. While all four injection rates were initially about 200 B/D [31.8 m /d], the rates of Wells J31 and W79 were increased 50 % to 300 B/D [47.7 m3/d], and Wells J14 and S27 were decreased 50% to 100 B/D [15.9 m3/d]. At the same time, the rates of the offset producers were also increased to maintain lower reservoir pressures. During interpretation of pilot performance, it was pressures. During interpretation of pilot performance, it was concluded that two wells, Wells W79 and J31, were unintentionally pressure parted after the rate changes. Therefore, because of pressure parted after the rate changes. Therefore, because of operating conditions that likely lowered the parting pressure below the operating pressure and because of the rather drastic rate changes, the fractures in the two wells were probably extended. As discussed later with the SWST, when the rates of off-set producers were raised to increase drawdown, we observed that pressure parting could occur as low as 960 to 980 psi [6620 to 6760 kPa]. During the development of a reservoir description for simulating the pilot performance, it was independently concluded that the fractures of only performance, it was independently concluded that the fractures of only these two wells were extended. Low-Tension Process. The selection of chemicals and the chemical composition of five sequential slugs of the low-tension process were previously reported. The injection plant design provided for blending the injected slugs to specified concentrations and viscosities within tolerances of 0.1% concentration and 0.5 cp [0.5 × 10 Pa s]. Precoat filtration was used with all injected fluids to minimize formation plugging. SPEFE P. 315
Summary A method is presented for testing enhanced oil recovery (EOR) processes in a single well. The method uses a multitracer version of the single-well tracer test (SWTT) for determining residual oil saturation to measure the oil displaced by an EOR slug process. A test was conducted to demonstrate the validity of the method. This test and its results are described. Introduction Piloting an EOR process is both time-consuming and expensive. Conventional pilot tests can take 3 years or more to conduct and cost several million dollars. A single-well test for evaluating tertiary slug processes has been developed that is both faster and less expensive than conventional piloting by at least one order of magnitude. The basis for this method of evaluating tertiary slug processes is the SWTT for measuring residual oil saturation developed by Exxon Production Research Co. The large depth of investigation from the wellbore of the SWTT and the ability to control this investigation depth are unique properties that make the single-well test for evaluating EOR slug processes possible. This single-well test consists of the following steps.Conduct an SWTT to determine the residual oil saturation after waterflooding.Inject a small slug containing an oil recovery chemical to establish an oil saturation profile within the SWTT pore volume (PV) of investigation.Inject a mobility control bank if needed.Inject a brine bank to displace the mobile banked oil from the test area, and recover the inaccessible PV caused by the mobility control bank if one was used.Conduct another SWTT with several different esters, each having different partition coefficients, so that average oil saturations can be measured for different distances from the wellbore. Steps 1 and 5 can be analyzed to determine oil saturation curves as a function of contacted PV and percent oil recovery vs. chemical slug size. These data are very useful in scale-up to larger projects and are not directly available from multiwell pilot tests. Another application of this testing method could be to conduct several tests with different chemical formulations in a given area. This would aid in selecting the best system for a particular field. Conoco Inc. has conducted a 1-acre (4047-m2) pilot test of a surfactant process at the Big Muddy field in Wyoming. Success of that pilot led to expansion of the surfactant process to 90 acres (364 km 2). In April 1979, Conoco ran a single-well surfactant test in conjunction with the surfactant expansion project. This single-well test was conducted to measure residual oil saturation after waterflooding and to determine the potential for evaluating tertiary slug processes by use of the single-well method. The same surfactant formulation used in the pilot test was used in the single-well test to provide a basis for checking the single-well test. This paper discusses theory, design, operation, results, and interpretation of the single-well surfactant test conducted in the Big Muddy field. Theoretical Development The theoretical basis and the general technique for measuring residual oil saturation by the single-well tracer method are well documented in the literature. Briefly, the method relies on determination of the chromatographic retardation factor of a tracer, which partitions between the oil and water phases in the reservoir. In practice, this determination is made by injecting a slug of primary tracer, such as an organic ester (having solubility in both water and oil), followed by a relatively large volume of water. A shut-in period then follows, during which the ester partially hydrolyzes to form an alcohol (having essentially no solubility in oil); this is the secondary tracer. JPT P. 1887^
PRACTICALLYall known petroleum oils contain sulfur in amounts varying from a few hundredths of a per cent to more than 4 per cent. Free sulfur, hydrogen sulfide, alkyl sulfides, mercaptans, thiophenes, thiophanes and carbon disulfide have been reported in certain petroleum distillates and residues. When a petroleum distillate containing mercaptans is refined by either the hypochlorite or "doctor" method, the more inert alkyl disulfide is formed and remains in solution. Sulfonic acids and alkyl sulfates are sometimes present in acid-refined distillates. Sulfur, beyond certain limits, is objectionable in refined petroleum products. This is particu-
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