Theoretical and experimental investigations of a constant pressure gravitydrainage system are reported. Experimental data are presented to show thatrecovery to gas breakthrough by gravity drainage is inversely proportional torate. The gravity drainage reference rate, which is numerically equal to theso-called "maximum theoretical rate of gravity drainage" is shown tohave no particular significance from a recovery standpoint. Before this ratecan be used as a basis of comparison for recoveries, it is necessary that therelative permeability and capillary pressure characteristics and displacingfluid viscosities be identical for the systems compared. A method is presented by which accurate prediction of the performance of agravity drainage system can be made. Close agreement between experimental andcalculated drainage performance shows that steady state relative permeabilityand static capillary pressure data can be used to describe fluid displacementbehavior. The very wide range of liquid recoveries before gas breakthroughwhich result from production rate variation alone demonstrates the importanceof this factor in planning depletion of a gravity drainage reservoir.Calculated results are presented which show that little additional recovery canbe expected from a high pressure gravity drainage system between the times ofgas breakthrough and attainment of such high gas/liquid ratios as to makefurther pressure maintenance impractical. Introduction It has been recognized for some time that gravity forces play an importantpart in the recovery of oil from some types of reservoirs. Field experience hasshown that under certain conditions, gravity drainage can result in very highoil recoveries. Qualitative reasoning has led most engineers to the generalconclusions that:Where gravity drainage is important, the reservoir pressure should bemaintained by gas injection at the crest of the structure to prevent shrinkageof the oil in place and to keep a low viscosity so the oil can drain at thefastest possible rate.Recovery by gravity drainage is rate sensitive. A survey of the literature indicates that while considerable work has beendone on the effects of gravity in oil production problems, no satisfactorymethod of calculating the performance of gravity drainage reservoirs has beenreported. In the absence of any proven method of calculating reservoirperformance, the level at which pressure should be maintained and the rate ofproduction for most efficient operation has been open to debate. T.P. 3199

Terwilliger, P.L., SPE-AIME, Gulf Research and Development Co., Clay, R.R., Gulf Research and Development Co., Wilson Jr., L.A., SPE-AIME, Gulf Research and Development Co., Gonzalez-Gerth, Enrique, SPE-AIME, Gulf Research and Development Co. In 1964 Mene Grande Oil Co. began a fireflood in a sand reservoir of the Miga field in Eastern Venezuela. It was expected that only 5 percent of the 13 degrees API gravity oil would be recovered by primary means; the fireflood has recovered more than twice that amount. No serious operating problems have been encountered. problems have been encountered. Introduction In 1964 Mene Grande Oil Co. started a fireflood in the P2-3 sand reservoir in the Miga field of Eastern Venezuela. The project has continued since that time. The original oil in place was estimated at 23.2 million bbl and 1.2 million bbl, or 5 percent, was expected to be produced by primary depletion. To date, an additional 2.6 million bbl, or more than twice the primary production, have been recovered by the use of the fireflood process. The air injection rate has averaged about 10 MMcf/D over the 9-year life. The average air/oil ratio (AOR) has been 11,000 cu ft/bbl. No serious operating problems have been encountered during the fireflood. The loosely consolidated sand is controlled through use of pressure-gravel-packed liners. Corrosion has not been a problem. No water injection has been used for producing well cooling, although a lighter oil is used for down-the-hole blending to increase the producing rates and facilitate the surface handling of the oil. Past performance and sweep pattern studies indicate that fireflooding could result in the production of 50 percent of the original oil in place, whereas the ultimate percent of the original oil in place, whereas the ultimate primary recovery would be only 5 percent. Experience both primary recovery would be only 5 percent. Experience both in this reservoir and other similar ones had shown that gas drive and waterflooding were completely ineffectual. Reservoir Description The project was performed in the P2-3 sand, MG-517 reservoir, of the Miga field located in Eastern Venezuela. A structure-isopach map of the project reservoir appears in Fig. 1. Fig. 2 includes a summary of the reservoir properties. This reservoir is one of several in the P2-3 properties. This reservoir is one of several in the P2-3 channel sand, which is found in scattered locations throughout both Miga and the neighboring Oleos fields. The updip seal is a combination of faulting and sand thinning. Lateral limits are considered to be the 10-ft isopach, as indicated in Fig. 1. The downdip limit is formed by a fault and the original water-oil contact. Reservoir volume is estimated at 18,600 acre-ft. Well MG-525 was high-GOR when completed, suggesting a small initial gas cap. At the time this well was selected for air injection, the south boundary of the reservoir was believed to be a fault located just south of the well. The revised interpretation of the reservoir indicates this is not the case; the reservoir actually extends much further south, as indicated in Fig. 1. Depth of the reservoir ranges from 4,000 to 4,350 ft below ground level, with dip to the north of about 2 degrees. The sand is loosely consolidated, with a porosity of 22.6 percent and an estimated average porosity of 22.6 percent and an estimated average permeability of 5 darcies. Maximum sand thickness is permeability of 5 darcies. Maximum sand thickness is about 25 ft. Connate water saturation is about 22 percent; stock-tank oil originally in place was 23.2 percent; stock-tank oil originally in place was 23.2 million bbl. P. 9

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Summary A field pilot test of forward combustion utilizing fracturing techniques was conducted in a shallow tar sand deposit in central Kentucky. The tar sand at a depth of 100 ft had an average porosity of 22%, an oil saturation of 64% (6.4% porosity of 22%, an oil saturation of 64% (6.4% tar by weight) and a permeability of about 2000 md. The tar had an API gravity of 10.6 deg. and a viscosity of 150,000 cps at a reservoir temperature of 56 deg. F. The pilot area was a small inverted five-spot which was 107 ft on a side. Horizontal fractures were created in the four producing wells by breaking down the formation producing wells by breaking down the formation with air pressure, and the fractures extended and propped to a calculated radius of 25 ft by propped to a calculated radius of 25 ft by injecting water-base, gel carrying 4–8 mesh sand. A pneumatic fracture was created in the central injection well which was held open by the continued injection of air. A down-hole burner was used to initiate the combustion zone. Oil production responded to the movement of the production responded to the movement of the combustion zone ten days after the fireflood was started. The average oil production was 24 barrels per day for the four months required to complete the test. The total oil production of 3100 barrels was 54% of 5700 barrels originally in place in the pattern area. The injected place in the pattern area. The injected air-produced oil ratio was 42,000 cu ft/bbl. The produced oil was upgraded to 14.5 API and 2000 cps at 60 deg. F compared to 10.6 deg. API and 100,000 cps for the original tar at the same temperature. The major problems encountered were the lack of complete oxygen consumption, the unsymmetrical advance of the fireflood and the tendency of the combustion zone to move toward the top of the reservoir. Introduction During 1959 and 1960, Gulf Research and Development Co. conducted a fireflood field pilot test in a shallow tar sand deposit lying about halfway between the towns of Brownsville and Leitchfield, Kentucky, which had been leased from the Kentucky Rock Asphalt Co., hence the name KYROCK. The fireflooding or forward combustion method has been adequately described elsewhere and the modification tested at the Kyrock site was the utilization of both pneumatically and mechanically propped fractures. pneumatically and mechanically propped fractures. Earlier reverse combustion experiments in the sand tar sand deposit had indicated that horizontal fractures could be extended at constant depth over considerable distances and that a forward combustion reaction zone could be maintained using these fractures for a major part of the fluid flow. part of the fluid flow.

A new well completion technique has been used to prevent the production of sand into wells producing oil from an unconsolidated sand formation. The laboratory development of this method of sand consolidation, known as "warm-air coking", is described. Warm air injected into an unconsolidated sand saturated with a heavy crude oil causes the oil to be oxidized. Continued oxidation of this very viscous oil forms an insoluble coke of resin which cements the sand grains together. Ignition of the coke-forming residue is prevented by proper control of the injection rate and of the temperature-increase rate of the injected air. Reservoir oils having cokable heavy ends provide the most satisfactory source of coke, but specially compounded oils or suitable crude oils not native to the formation could be injected to replace the reservoir oil. Usually crude oils having gravities of less than 20 deg. API contain a sufficient amount of heavy ends. Several wells producing from unconsolidated reservoirs containing heavy crudes have been satisfactorily treated with this method. These wells have produced sand-free oil over an extended period of time and have high productivity indices. Introduction The prevention of sand production concurrent with the oil from unconsolidated reservoirs has been a major problem in some areas. In many cases, the sand control problem has been solved by the use of mechanical devices such as screens, perforated liners and gravel packs, or by consolidating the sand around the wellbore with a plastic which is injected into the formation. The advantages and disadvantages of these methods and their success in combating sand production have been discussed by several authors. As pointed out by Hower and Brown, mechanical devices in the wellbore do not leave the casing clear for multiple completions, while sand consolidation with plastics has been only partially successful. In reservoirs producing low-gravity, viscous oil, the conventional methods are only moderately successful because they sometimes do not prevent sand production and frequently require remedial work during the life of the well to maintain the productivity at a satisfactory level. This is more pronounced when the formation contains a wide range of particle sizes, including clays and silts. This paper presents a new sand-control method known as the warm-air coking sand consolidation process. It was developed to prevent sand production from unconsolidated sand reservoirs producing low-gravity crude oils. Sand consolidation is accomplished by the injection of heated air into the formation around the wellbore until the crude oil becomes oxidized into an insoluble resin or coke. Details of the laboratory development and a description of the equipment are given. The results of several field tests of the method are summarized. Two obvious requirements of any sand-control technique are that sand production be prevented and that the oil productivity be maintained. Other desirable features are that the completion lasts the life of the reservoir without remedial work and that no obstruction be left in the casing. It was believed that these requirements might be satisfied if the sand surrounding the wellbore could be cemented with coke. The coked sand would need sufficient permeability to provide the required productivity and enough strength to withstand the pressure gradients created by the flowing fluids and the weight of the overburden. It is well known that crude oils, especially those having a low gravity, form coke when heated to high temperatures. When an unconsolidated sand saturated with an oil containing heavy ends is heated to the coking temperature the coke formed binds the sand grains together. Several methods of heating to form coke in sand-oil mixtures were tried in the laboratory and the most satisfactory appeared to be the injection of heated air. The use of air as opposed to an inert gas enhances the formation of an insoluble binder in two ways. JPT P. 367^

A new completion technique has been developed which allows unlimited drawdown and improves productivity in wells completed in unconsolidated formations containing shales and clays. Historically, producing oil and gas from such reservo~rs has been limited by rate-dependent sand productlon and fines migration which resulted in near wellbore formation plugging. This technique eliminates the problems of sand pr?duc~ion and fines migration ~y artificially consolldatlng a volume of reserVOlr sand near the wellbore.The consolidation is resistant to high temperature, chemical attack, and degradation resulting from high velocity fluid flow. Additi onally, paras ity and permeabil ity in the consolidated volume of reservoir sand are improved as a result of irreversible dehydration of clays.