This paper presents a simple and practical method for the estimation of effective permeability and reservoir pressures from the rise in bottom hole pressure when a well is shut in. The equations on wh~ch the method is based consider a stabilized well producing from a uniform formation when flow is shut off at the sand face followed by the uns.teady state flow of a compressible liquid from regions far from a well to points closer in during the build-up period. An approximation for extending the method for two-phase flow in the reservoir is also presented.
The study of the influence of fluid mobilities on the sweepout pattern resulting from the injection of gas or water has been extended to cover the production period which follows breakthrough of the injected material. Mobility ratios over the range common in field operations (0.1 to 17) were studied for several pattern floods (five-spot, staggered, and direct line drive). The experimental data required for these studies were obtained by the use of the x-ray shadow graph technique using miscible oil phases of different viscosities in porous plate models of a reservoir element. From the shadowgraph pictures obtained before and after breakthrough of the injected fluid, flowing ratios at the producing well and cumulative volumes injected were calculated. The method for applying such data in predicting field behavior is illustrated for a water flood of a five-spot. For this case a range of mobility ratios of 0.5 to 5.0 results in:nearly complete (95 to 100 per cent) sweepout pattern efficiencies at abandonment conditions,production after breakthrough being responsible for as much as one-third of the total recovery at the lower mobility ratios, anda twofold variation in the operating life of the reservoir.
Published in Petroleum Transactions, AIME, Vol. 213, 1958, pages 281–283.Paper presented at 32nd Annual Fall Meeting of Society of Petroleum Engineers in Dallas, Tex., Oct. 6–9, 1957. ABSTRACT Miscible displacement recovers all oil in the area contacted by the injected fluid, whereas water or immiscible gas drives usually leave substantial amounts of oil as residual. However, the poor mobility ratios associated with a gas-driven miscible displacement cause the sweep pattern efficiency to be much lower than that obtained with water flooding. One way in which the sweep efficiency in a miscible displacement process can be increased is by decreasing the mobility behind the flooding front. This can be achieved by injecting water along with the gas which drives the miscible slug. This water reduces the relative permeability to gas in this area and thus lowers the total mobility. The main operating conditions for the simultaneous injection process are that a zone of gas exists between the miscible slug and the leading edge of the water and that a sufficient amount of gas be injected with the water to form the gas volume which is being left in the water zone. Laboratory model studies have shown that the ultimate sweep pattern efficiency can be as high as 90 per cent for a five-spot flooding system. If gas alone is used as the driving medium an ultimate sweep-out efficiency of about 60 per cent would be obtained in the same system. INTRODUCTION The miscible displacement processes are a step towards total oil recovery. Conventional gas or water drives usually leave 25 to 50 per cent of the oil as residual in the swept portion of the reservoir. This residual can be eliminated if the oil is driven by a fluid with which it is miscible. At some reservoir conditions natural gas will become miscible with the oil. This is the" high pressure gas process". More often, the oil does not contain enough light hydrocarbons to cause the gas to become miscible with the oil at reasonable pressures. In these cases a small band of fluid which is miscible both with the oil and gas must be kept between them. Less than 2 per cent of the reservoir volume of the slug material is needed to keep the displacement miscible.
In the operation of a water-driven reservoir, a free gas saturation can be established by maintaining production rates fast enough to cause the reservoir pressure to decline below the bubble point. The benefit of such a procedure on the displacement efficiency of the oil by water is illustrated for two types of sandstone samples from one reservoir. Those rock samples showing the poorest recovery to water drive in the absence of a free gas saturation give the most improvement in the presence of a free gas saturation. Employing one type of reservoir fluid (low shrinkage) the benefit of evolved gas on oil displacement is calculated at several reservoir pressures below the bubble point. This demonstrates the presence of an optimum pressure for water displacement which is several hundred pounds per square inch below the bubble point. Displacement of oil at the optimum pressures results in the removal of 7 to 12 per cent more oil than would be obtained by displacement at the bubble point pressure. In some instances this magnitude of increase may be worthy of consideration in establishing the maximum efficient rate of production from many water-driven fields. Introduction For many years the belief that the use of gas could be combined with that of water to result in a better recovery operation than the use of either of these phases alone has been prevalent in the oil industry. This is evidenced by the several field trials which have employed the injection of gas and water in combination. In most cases the small amount of any additional recovery, in combination with the limited knowledge available on the older reservoirs, has left uncertain the influence of gas on recovery in these earlier attempts to combine the use of gas with water. Research studies in recent years have demonstrated through laboratory floods the magnitude of the benefit of the presence of gas on the displacement of oil from sandstones by water. In addition, studies of the distributions of the phases which are present during the displacement process have developed concepts concerning the mechanism by which this benefit is obtained. It now remains for the engineer to incorporate these findings into the general technology of reservoir operations.
The application of a method for analyzing pressure build-up curves to determine the effective permeability in the Spraberry is presented. Sixteen Upper Spraberry wells of the Driver area are analyzed and show variations in the in-place effective permeability of 2 to 183 md. Since these values are much larger than the.5 md, or less, reported for the matrix rock, a large part of the vertical fractures noted in Spraberry cores must be considered native to the formation. The effectiveness of the well fracture treatment in connecting the well bore to the native fracture system is analyzed by comparison of the effective permeability as determined from the PI test to that obtained from a pressure build-up curve. These results show that the fracture treatment is sufficiently effective in connecting the well bore to the native fracture system to yield a flow capacity within about ?50 per cent of that dictated by the native fracture system. About two-thirds of the wells show some degree of local blockage. Introduction Fractured reservoirs have been known in the past: However, during the past two years the Spraberry formation has directed the attention of the petroleum industry to a study of the performance of a fractured reservoir. The large variation in the number of fractures noted in Spraberry cores, the large variation in the producing ability of offset wells, the dramatic effect of well treatment on well productivity, the unknown quantity of oil stored in the fractures and matrix rock, and the unknown oil to be recovered were part of the initial Spraberry puzzle. In this type reservoir where the well treatment is an important factor in determining the productivity, it is particularly desirable to determine the in-place flow capacity of the drainage area at distances far removed from the well bore. This value, when compared to the flow capacity obtained from a PI measurement, will show the effectiveness of the well treatment (completion, fracture treatment, acidization, etc.) in establishing a flow capacity in the vicinity of the well bore equal to that in the more remote region. The object of this paper is to show the application of a method of pressure build-up analysis for this purpose in studying the Upper Spraberry formation in the Driver area.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.