Miscible Project Research Articles

Advanced Technology Improves Recovery at Fairway

The most important decision made in the early stages of this miscible recovery project was to hang loose. The original plan of operation allowed for injecting all gas, all water, or any combination, depending upon what new information was gained as the project went along. Radioactive tracers, new logging techniques, numeric modeling, and sophisticated down-hole equipment provided that information. Introduction The Fairway (James Lime) field is about 30 miles south of Tyler, Tex. The discovery well was drilled in July, 1960. near the eastern edge of the field, which eventually proved up over 400 million bbl of oil in place under about 23,000 acres. The 10,000-ft James Lime reservoir is a reef development at Fairway, quite different from the regional character of the formation. Three major zones exist in the reservoir as a result of differing conditions of reef growth environment. From the start, this complex, highly stratified, variable-permeability, reservoir offered quite a challenge to the operators. The James Lime oil is an undersaturated 48 degrees API-gravity crude containing from 1,350 to 1,600 cu ft of solution gas per barrel. Saturation pressure varied with depth and ranged from 3,950 to 4,350 psia. The reservoir fluid was determined to be miscible, with lean hydrocarbon gas or flue gas at about 4,800 psia - about 400 psi below the initial reservoir pressure. Connate water saturation ranged from 10 to 30 percent, and the porosity averaged about 12.5 percent. Unitization studies showed that incremental economics favored an alternate gas-water high-pressure miscible recovery project over waterflooding or immiscible gas injection. The operators recognized that many miscible projects had experienced poor recovery and even lost projects had experienced poor recovery and even lost money. Alternating gas and water injection represented the "outer limits" of miscible recovery technology available at the time and involved a high degree of risk. The decision was made to go ahead with the alternating approach, but with a program designed to have a large degree of operational flexibility. In this manner, necessary changes and adjustments could be made along the way. Additional recovery from the alternating gas-water high-pressure miscible recovery technique in use at Fairway is significant. Production exceeded the estimated primary reserves of 65 million STB of oil in June, 1971 (see Fig. 1). Currently the Unit is producing the top allowable of 40,500 BOPD. producing the top allowable of 40,500 BOPD. Injection capacity determines the maximum production rate at Fairway. The average reservoir production rate at Fairway. The average reservoir pressure has been maintained essentially constant at pressure has been maintained essentially constant at 4,500 psi since early 1970. An expansion program to increase gas injection capacity from 70 to 100 MMcf/D and water injection from 60,000 to 90,000 BWPD is currently in progress. With the increased injection capabilities and 13 new wells, now drilling. the Unit will be capable of producing at 100-percent market demand factor, about 53,000 BOPD for about 2 years before it declines as a result of an increasing voidage of injected fluids. Mobility Control The use of water injection to restrict the mobility of the injected gas is the key factor in the improved recovery of the Fairway project. A reduction of viscous fingering of the gas and improved sweep efficiency through water injection is very important in the over-all control of the Fairway project. Many of the early indications of fingering were in the north end of the field (Fig. 2) where gas injection was concentrated initially. Fig. 3 illustrates the typical relationship between producing trends and injection cycles. producing trends and injection cycles. JPT P. 354

Finding the Most Profitable Slug Size

Several current sophisticated oil recovery projects involve injection of a slug consisting of a micellar solution, and carbon dioxide or a hydrocarbon solvent. Slug costs combined with low oil saturation may result in marginal economics; thus, the economic success or failure of a miscible project may hinge on choosing the proper slug size. A simple technique will be described here for estimating the "optimum" slug size. Required data include oil price, average oil saturation, per-barrel slug cost, and a slug-size vs oil-recovery curve. The last item is most desirable obtained from pilot floods, but can often be estimated from laboratory data, provided that these results are corrected to allow for heterogeneities of the reservoir in which the flood is to be attempted. Failure to correct for heterogeneities will result in an optimistic prediction of production performance. performance. Profit from a flood is derived from the value of the oil recovered less the cost of slug, and drive fluids, capital expenditures, and operating expenses. ............(1) Oil recovery hence profit, is a function of, among other things, slug size. Assuming that the per-barrel slug cost is independent of slug size, the maximum profit for given reservoir conditions, oil price, profit for given reservoir conditions, oil price, chemical costs, etc., can be found by setting the partial derivative of a rearrangement of Eq. 2 with respect to slug size equal to zero: ............(2) Maximum profit occurs when: ................(3) that is profit is maximum when the slope of the oil-recovery vs slug-size curve is equal to the right-hand side of Eq. 3. Fig. 1 shows four recovery curves. The uppermost curve shows laboratory data for micellar solution floods in which various slug sizes were used. Polymer solutions were used to propagate the slugs through 4-ft.-long-, 3-in.-diameter Berea sandstone cores. The three other curves were computed from these data by assuming that for each of them there were two equal-volume, equal-porosity layers, identical in all respects except for absolute permeability. Oil recovery is reduced with increasing permeability contrast, partly because slug is not equally accepted by the two layers, and partly because the tighter layer is not completely swept before the economic limit is reached. Other recovery curves could be generated, simulating more layers, pattern geometries other than linear, or other desired degrees of complication. Only simple cases are shown here, however, to illustrate the technique of determining optimum slug size. For purposes of illustration, let us assume that the cost of the injected micellar slug, is $5.00/bbl, the average preflood oil saturation is 0.35 and the price received for oil after royalties is $3.00/bbl. For this set of conditions, Cs / (SoPo) is 4.76. Lines of this slope are shifted up or down until they become tangent to the curves of Fig. 1. The point of tangency for each case represents the most profitable slug size. P. 993

Meadow Creek Unit Lakota "B" Combination Water-Miscible Flood

Abstract The Meadow Creek unit Lakota "B" reservoir was subjected to LPG cycling, repressuring and miscible slug flooding with water injection. The last two steps are reported in this paper. This field case history covers the reservoir properties, primary production history, the miscible project including history of repressuring and of LPG- water and gas-water injection. Inherent problems in the Lakota "B" reservoir were paraffin and carbonate deposition, and several were related to the miscible flooding method used. Down-hole pump freeze-ups, heavy paraffin deposits on the downstream side of the gas separators and low treating temperatures were caused by the cooling effect of LPG as it expands under reduced pressures. The success of the operation is indicated by the fact that the flood will probably recover 13 per cent more oil than would have been recovered under water flood. Introduction Improving oil recovery has been the subject for much research and field experimentation in the past several years. Incentive for this increased activity is the realization that large amounts of oil still remain unrecoverable after using present knowledge and methods. Many new techniques are being tried, but those currently most popular are the miscible displacement processes. There are basically five types of miscible displacement processes:high-pressure gas drive,enriched or condensing gas drive,LPG slug drive,LPG cycling, andalcohol slug drive. In addition the first four methods may be improved by injection of water along with or after the miscible fluids. The process being used in the Meadow Creek Lakota "B" reservoir is the LPG slug drive augmented by injection of water in alternate slugs with the miscible fluids. These LPG-water slugs were originally followed by ethane-rich gas and water in alternate slugs; however, lean residue gas and water are presently being injected. This particular project has taken place in three phases. The first was LPG cycling, the second was repressuring the reservoir, and the third is miscible-slug flooding with water injection. This paper discusses the second and third phases of this project. The first phase was discussed in an earlier paper by Harbert et al. Reservoir Properties The Meadow Creek unit Lakota "B" reservoir covers approximately 350 acres. Pressure surveys, liquid levels, production histories and detailed log studies indicated that the Lakota "B" consists of two sand sections separated by a 10-ft shale break. The lower section is generally tight and primarily water productive, thus the majority of the production has come from the upper section. For individual data on the reservoir and reservoir fluids refer to Tables 1 and 2.The structure is an anticlinal fold trending northeast- southwest. A large normal fault cuts the Lakota formation north of Well 26 with a strike bearing approximately N 67 deg. E, dip NW at 50 deg. (Figs. 1 and 2). Oil was present in wells on the west side of the other possible fault shown in Figs. 1 and 2; however, the pay section to the west was thin, tight and commercially non-productive. JPT P. 993ˆ

Ten Years of Miscible Displacement in Block 31 Field

Abstract A decade ago The Atlantic Refining Co. introduced to the oil industry a new concept of secondary recovery--miscible displacement by the high- pressure gas-injection process. The initial application of this process was made in the Block 31 Devonian field in Crane County, Tex. Since the first injection of gas, a cumulative of 127 billion cu ft has been injected. Total field production has been 55 million bbl of oil, or nearly 80 per cent of the estimated production by primary. Current producing rate for the field remains at 15,350 BOPD. Performance to date indicates that the process is operating essentially as predicted and that miscible sweep of the reservoir is being achieved. To achieve optimum sweep of the reservoir and maximum oil recovery, considerable reservoir engineering effort is directed toward maintaining pattern balance. To insure miscible sweep, annual pressure surveys are taken to ascertain that the pressure at each of the displacing gas fronts is at least 3,500 psig, the pressure needed for miscible displacement. Several problems which threatened the success of the program have arisen but are now under control. The most serious of these was a siege of injection-well plugging which occurred in 1958. Most of the wells were affected before the problem could be remedied. Breakthrough of injectedgas has been detected in six wells to date. In three of these, the cumulative oil produced at breakthrough was essentially as predicted. The other three wells have experienced breakthrough earlier than expected, but these wells are balanced by three others that should have broken through but have not. The results average out so that an ultimate recovery as predicted for miscible sweep can be expected. Introduction The first miscible project ever undertaken is that in the Devonian reservoir of Block 31 field in West Texas. Here miscible sweep is maintained by the high-pressure gas-injection process. The process entails the injection of lean gas into the reservoir at high pressure. The Block 31 Devonian crude properties and reservoir conditions are such that, by maintaining 3,500 psig at the injected gas front, miscible displacement is achieved. The entire oil-producing industry has shown a high degree of interest in this program since its initiation. A decade ago the concepts of miscible displacement were in their infancy and the program in Block 31, being the first field application of the process, was experimental in nature. A progress report was made early in its life. However, the program now has been operating long enough for significant results to be reported. Several producing wells have experienced gas breakthrough, making it possible to render at least a limited interpretation as to the success and ultimate outcome of the program. The program of high-pressure gas injection was initiated in June, 1949. Initially, the gas produced from the Devonian and Ellenburger formations was injected into the crest of the Devonian reservoir to partially maintain the reservoir pressure. At the same time, laboratory research was being conducted on the application of the high-pressure gas process to the field. The research showed that high additional recovery could be expected from its application. The plans for Block 31 field were revised accordingly, and the decision was made to fully maintain pressure in the field. On Oct. 1, 1952, the program was expanded to full pressure maintenance. This entailed the purchase and injection of gas in addition to that being produced. Currently, 57 MMcf/D of gas are being injected into 15 injection wells on a nine-spot pattern. Production from the field is 15,350 BOPD. Geology and Reservoir Properties The Block 31 field is located in the east-central part of Crane County, on the eastern side of the central basin platform. The Devonian accumulation is situated on an anticline lying in a northeast-southwest direction. The top of Devonian is encountered at about 7,900 ft and has a gross thickness of approximately 1,000 ft. As shown in Fig. 1, the Devonian has three pay horizons referred to as the Upper, Middle and Lower Devonian horizons. The main oil-producing section is the Middle Devonian horizon, which covers the interval from 450 to 800 ft below the top of the Devonian. This 350-ft interval contains about 85 per cent of the oil in place and is the only portion of the reservoir which is being miscibly swept. The middle horizon itself is further stratified with dense and permeable streaks. The permeable zones can be correlated from well to well over most of the field. Up to 185 ft of this horizon is net pay in some of the structurally higher wells. JPT P. 543^