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Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 301–304 Abstract Inclusion of anisotropic permeability in mathematical analysis of pressure transients observed during development of the huge Spraberry field indicates a major fracture trend which is in good agreement with that observed by fluid-injection tests spread over a 12- by 17-mile area. Delineation of this trend is important in selecting a pattern of injection for the pending large-scale water flooding in this field. Determination of reservoir parameters yielding best agreement between calculated pressures and observed reservoir pressures in newly completed wells was made using an IBM 650 computer. Introduction The Spraberry field covering 400,000 acres is a tight sand of less than 1-md permeability cut by an extensive system of vertical fractures. Primary recovery dominated by capillary retention of oil in the fractured sand matrix blocks is less than 10 per cent of oil in place. Strong forces of capillary imbibition of water into the sand, coupled with water flow under dynamic pressure gradient, indicate considerable increase in oil recovery can be achieved through water flooding. Best results will occur if the pattern of water injection is selected to force the water flow across the grain of the major fracture system. Existence of an oriented vertical fracture system in the Spraberry, observed first in cores, was highlighted more recently by the 144-fold contrast in permeability along and at right angles to the major fracture trend required to match relative water breakthrough times in Humble Oil and Refining Co.'s waterflood test there. Spraberry Operators since have conducted two gas-injection tracer tests for further areal confirmation of the fracture trend. Re-analysis of early reservoir pressure transients for evidence of anisotropic permeability has permitted many more local determinations of major fracture trend without resort to further field tests. This paper is limited to updating analysis of reservoir pressure transients to include anisotropic permeability as a test for orientation of the major fracture trend in the Spraberry. The reader is referred to Ref. 1 and 2 for information about general Spraberry reservoir performance and to Refs. 3 and 4 for information about significance of fracture orientation in selection of the injection well pattern for water flooding the Spraberry.
- North America > United States > Texas > Midland County (0.89)
- North America > United States > Texas > Martin County (0.89)
- North America > United States > Texas > Howard County (0.89)
- North America > United States > Texas > Dawson County (0.89)
- North America > United States > Texas > Permian Basin > Midland Basin > Spraberry Trend Field (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin > Spraberry Field > Spraberry Formation (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 305–312. Abstract The purpose of this research is to determinethe efficiency of small banks of enriched gas driven by methane in displacing oil from a porous medium and the effects of variation in bank size and composition of that efficiency. Most of the experiments were conducted in a sand-packed tube 20-ft long and 1/2-in. in diameter. The hydrocarbon system generally used was methane, butane and decane at 2,500 psia and 160°F. The results of these experiments indicate that, in the regions contacted by the gas, a small bank of an oil-miscible gas driven by methane can displace all of the oil in a piston-like manner. If the enriched gas is of such composition as to remain immiscible with the oil, displacement of oil is less efficient than for the miscible case, and the gas hank travels through the sand with a velocity less than that of the driving gas. These data along with theories discussed imply that smaller banks and less total gas are required when the enriched gas and oil are miscible. Introduction Widespread application of enriched-gas drive to the recovery of oil rests upon a key factor the use of limited quantities, or "banks", of enriched gas. At the present time, the value of liquefied petroleum gas or other enriching agents discourages their use in a continuous injection technique, or even in a large bank, except in a few isolated reservoirs. If small banks of enriched gas driven by methane were as effective in displacing oil as is continuous injection, the enriched-gas drive process might be applied to a larger number of reservoirs. Previous research on the mechanics of the enriched-gas drive process reported by Stone and Crump and by Kehn, Pyndus and Gaskel has utilized continuous injection of enriched gas. This work has shown that two types of displacements occur. With gases containing sufficient intermediates, the oil is displaced miscibly and complete recovery is obtained from the regions swept. When gases are used which contain insufficient intermediate hydrocarbon for miscible displacement, oil is displaced immiscibly. In the latter type, selective solution of the intermediate hydrocarbons causes a swelling and reduction in viscosity of the oil and leads to an increased recovery over that obtained by dry-gas (methane) drive.
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (0.69)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.68)
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 320–331. Abstract A model of heat flow in an underground combustion process is studied. This model includes convection effects and thus is more general than previous studies which considered conduction as the only mechanism for heat transfer. Both linear (tube run) and radial (field application) geometries are considered. The effects of ignition heaters, vertical losses and finite source width are considered for the linear case. The results are in the form of equations and are presented in graphical form for a number of cases. Convection effects increase frontal temperatures about 25 per cent over those computed for conductive transfer for typical field operating conditions. This increase in temperature is a result of heat being transported toward the front by the injection gas. Even greater temperature increases are realized as the per cent oxygen in the injection gas decreases. It is well known that compression costs are of considerable importance in estimating the economic feasibility of underground combustion. By assuming an ignition temperature for the combustion fuel, predictions of limiting conditions on fuel density and injection rate necessary to sustain the combustion zone are made. For typical field conditions, at least 0.75 lb/cu ft of fuel are needed with air as the injection gas. if the injection gas is 10 per cent oxygen and 90 per cent nitrogen, this figure is 0.69 lb/cu ft. Introduction The possibility of increasing oil recovery by underground combustion has been considered for many years. Recent field tests indicate that the underground combustion process is technically feasible. The economic feasibility depends to a large extent on the amount of air which must be injected to sustain combustion. Prediction of the success of employing underground combustion in a particular reservoir must be based on existing field tests, laboratory tube runs and solutions of mathematical or analog models. Vogel and Krueger devised an electrical analog of the heat transfer problem in an underground combustion process. They considered the problem of heat conduction from a cylindrical source with increasing radius assuming no vertical losses. Bailey and Larkin, and Ramey solved the corresponding problem including vertical losses by considering a mathematical model of the conduction process. Ref. 9, 10 and 11 also present information related to the subject study. The present paper generalizes these results to include both conduction and convection mechanisms for heat flow. A model of the conduction-convection process is described. The partial differential equations governing this model are written and solved for a number of cases of interest. The formulas are evaluated and the results are presented graphically.
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 88–93. Abstract The perforating of multiple tubingless completions, in which two or more strings of 2 7/8-in. OD casing are installed in the same borehole, presents two basic problems. First, good completion practices require an efficient perforator that leaves no debris to interfere with subsequent completion operations. Second, and of more complicated nature, a system is needed for controlling the direction of fire so that adjacent strings are not damaged. Development of a 2-in. OD, steel, retrievably, shaped-charge gun has solved the first problem. The second was resolved through development of three different devices to provide directional perforating for the two types of completion methods being employed today. These include a mechanical orienting device and two self-orienting radiation devices. Conceivably, the latter methods could be adapted to the directional perforating (of upper zones) of conventional dual and triple completions without removing production tubing and packers. Introduction The recent trend to multiple tubingless completions, wherein two or more strings of 2 7/8-in. OD casing are installed in the same borehole, has presented two basic perforating problems. The first problem to be overcome was the design of a gun that would result in efficient perforations without causing debris to bridge in these small-diameter casings. The second problem was, of course, to devise a system for controlling the direction of fire such that adjacent strings would not be damaged. The problem of gun debris in slim-casing completions has been well defined in the numerous 2 7/8-in. single tubingless completions which have been effected during recent years with the expendable-type perforators. Failure of expendable-gun debris to settle out properly, even with good gun break-up, has resulted in bridging inside these small-diameter casings. This, in turn, has interfered with completion and re-conditioning operations.
Published in Petroleum Transactions, AIME, 1960, Vol. 219, pages 31–37. Paper presented at 34th Annual Fall Meeting of SPE, Oct. 4–7, 1959 in Dallas. Abstract The use of a partial monolayer of propping agent to obtain a high flow capacity for a hydraulically induced fracture is discussed. From the results of laboratory work it was shown that a modified form of the Kozeny-Carman relation could be used to describe the flow in the partial monolayer propped fracture. With equations presented in the paper, the density pattern of the propping agent (number of particles per unit of fracture surface) that results in the maximum flow capacity for the fracture can be determined. The maximum flow capacity obtained with a partial monolayer is often an order of magnitude greater than the flow capacity obtained in greater width fractures containing multilayers of the propping agent. Introduction One of the predominant factors controlling the success of a hydraulic fracturing operation is the propping of the fracture. The trend in hydraulic fracturing recently has been an increase in the ratio of propping agent-to-fluid. The primary purpose of this increased ratio is to sustain a propped fracture of greater width. It was shown in a recent study that for some formations low concentrations Of propping agent would result in "closing" or "healing" of the fracture. In some cases, in an effort to insure sufficient propping agent concentration, the fracturing operation is designed to obtain a pack of the propping agent in the fracture. The placing of a pack of propping agent in the fracture provides a fracture of maximum width; however, the width alone does not control the flow capacity of the fracture. The flow capacity is dependent on the permeability of the fracture, as well as the fracture width. Thus, increasing the permeability to obtain larger flow capacities is as important as obtaining a greater width fracture.
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 238–250. Abstract Several investigations in recent years have shown that drilling rates are increased significantly with increased hydraulic horsepower. But, there has been no overall method of designing jet-bit programs that efficiently uses the surface power. A study of present practices indicates that frequently as little as 50 per cent of the possible effects at the bit are used. Some observers have indicated that the best utilization of hydraulic horsepower (maximum effect on drilling rate) occurs when the bit hydraulic horsepower is maximum; others have stated that jet impact force is more important, and others have believed that maximum jet velocity is required. Limited efforts to date have shown some optimum conditions for bit hydraulic horsepower and impact, but these conditions cannot exist during drilling of a large part of the hole and do not provide a basis for designing a complete jet-bit program. This paper shows the maximum obtainable bit horsepower, impact force and jet velocity at all depths, taking into account the limitations of the pump, piping, hole and minimum circulating rate for adequate cuttings removal. Ranges of operation are developed; and flow rates, surface pressure and bit pressures are specified for each range to provide a maximum of any one of the desired effects. It also is shown that, by proper selection of nozzle sizes and by following the rules presented, the maximum obtainable quantities can be effectively utilized from surface to total depth. Finally, a simple graphical method of selecting nozzle sizes and flow rates is presented which can be used with familiar bit-company hydraulic tables and calculators to design jet-bit programs for maximum bit hydraulic horsepower, impact or jet velocity, as desired. These programs make most effective use of the pumps. Heretofore, there was no method available for designing field tests which adequately separated the effects of bit horsepower, impact and jet velocity. The programs and procedures developed in the paper are dissimilar and, when used in future field testing, should demonstrate which program is the most important in obtaining the fastest drilling rate.
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 1–6. Abstract Water often enters an oil reservoir during completion of workover operations on a well and forms a partial "water block" to oil production. A mathematical study of radial two-phase flow, neglecting capillary effects, has been employed to study the formation of such a water block and subsequent removal by production from the well. The effects of reduced oil permeability about the well on the well productivity were studied. The fluid saturation distributions about the well during formation and removal of the water block have also been computed. Several relative permeability relations and viscosity ratios were employed. If water has invaded the formation, its influence through relative permeability effects alone can cause the following.Oil productivity will be depressed for extended periods after production is resumed and will build up only gradually as the water is removed. Oil injected for treatment of water blocking will delay rather than promote restoration of full well productivity by enlarging the region invaded by water. Thus, unless the specific action of chemicals contained in the oil is needed, oil injection appears undesirable. Introduction During oilwell workover operations, water may enter the oil-bearing formation from the wellbore. When production is resumed, oil must flow through the region invaded by this water. The presence of this region can cause both well productivity and oil production rate to be low and oil to be produced with high water-oil ratio for some time after production is initiated. This situation is sometimes described as a water block. The introduction of water into the formation may result in other actions which also lead to reduction in well productivity and which are also usually included in the connotation of the broad term, water block.
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 257–263. Abstract The flash X-ray has been used more than a decade to study the configuration of the jet from a shaped charge. The high-speed, rotating-mirror smear camera has provided time-distance graphs of detonations and shock fronts in transparent material, and the high-speed framing camera has given pictorial representations of the progress of explosive phenomena. Adequate means for measuring the paths and velocities of all parts of the shaped-charge cavity liner during the collapse phase have not existed heretofore. A technique enabling the single-lens framing camera to make stereoscopic photographs of the cavity liner while it is collapsing has been developed. Analysis of this photographic record gives the directions and velocities of various parts of the liner surface, permitting direct quantitative measurement where this has previously been impossible. Significant improvements in shaped-charge design are expected to result. Introduction The familiar oilwell jet perforating charge, generally referred to as a "shaped charge", is related to the Munroe charge first described by C. E. Munroe in 1888 and later by Neumann in 1910. It differs in construction from the Munroe charge in that its cavity is lined with some inert material (usually metal), and it differs in performance by projecting a fast jet of dense liner material against the target instead of a stream of expanding detonation products. Fig. 1 represents a typical shaped charge in axial cross section. The charge is circularly symmetrical about its longitudinal axis. The cavity at the right is lined with metal, usually copper; and, with the exception of air, the liner is otherwise completely empty. High-explosive material is intimately in contact with the convex surface of the liner and extends in the other direction to the booster. This is a pellet of high explosive having somewhat different characteristics and serves to couple the detonator to the main charge.
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 390–392. Abstract The concept of sodium single-ion equivalent activity as developed by Gondouin, Tixier and Simard, was used to determine the filtrate resistivity-activity relationships for 150 laboratory and 49 field drilling muds. With the exception of the native and phosphate high-resistivity muds and the calcium-treated muds, the filtrate resistivity-activity relationships were found to be within 20 per cent of that for pure sodium-chloride solutions. Gondouin, et al, previously suggested a method of treating the high-resistivity muds in quantitative electrical log analysis. A new treatment is presented which uses the P-alkalinity of the filtrate as a correlating parameter in handling the calcium-treated muds in quantitative electrical log analysis. Introduction Gondouin, Tixier, and Simard in 1957 introduced new interpretive procedures for analyzing the self-potential curve of electric logging. They re-emphasized the previous work of the Schlumberger brothers, Wyllie and others, and re-defined the activity concept in terms of a number which they termed the effective resistivity. Their procedures are particularly effective when the connate-water resistivities are less than 0.08 ohm-m or greater than 0.3 ohm-m. For gyp muds where the calcium content is known, a procedure was presented which allows calculation of the connate-water resistivity with improved accuracy. These procedures assume that one of the fluids in the system is a pure sodium-chloride solution, but they are not limited by the assumptions. For the fresh and saline connate waters, for instance, it is assumed that the drilling mud filtrate is a pure sodium-chloride solution. For the gyp mud interpretive procedure, it is assumed that the connate water is a pure sodium-chloride solution. Brown, on the other hand, has suggested that it would be extremely fortuitous if drilling mud filtrates could all be treated electrochemically as sodium-chloride solutions, and he cites some examples where discrepancies exist. A study has been made of the deviations of sodium single-ion equivalent activities, a Na+, of drilling mud filtrates from that of pure sodium-chloride solutions. Drilling fluids in common use on the Texas and Louisiana Gulf Coast and laboratory-controlled muds were investigated.
- North America > United States > Texas (0.35)
- North America > United States > Louisiana (0.25)
- North America > United States > Texas (0.89)
- North America > United States > Louisiana (0.89)
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 16–23. Abstract Analysis of acidizing techniques, in correlation with reservoir data and a backlog of past treatments, has resulted in the development of a valuable engineering guide for planning acidizing treatments. Such treatments fall into three categories:acid injection into the pores of the matrix; acid injection into natural formation fractures at less than parting pressure; and combination acidizing-fracturing treatments in which acid solutions (without propping agents) are injected at treating pressures sufficient to open and extend fractures through which the acid flows. Because the spending time of acid during a specific well treatment does not change appreciably, maximum penetration is attained when the first increment of injected acid is completely spent. Additional acid injection cannot be expected to further extend the benefits of the treatment. Depth of penetration will depend upon the reaction rate of the acid under treatment conditions, the injection rate of the acid into the matrix or fractures and the area-volume relationship existing in the flow channels. Based on Darcy's flow formula, extremely low injection rates must be used in order to keep bottom-hole injection pressures below formation fracturing pressure. As a result, only limited penetration of unspent acid will occur. Treatment records indicate that, in most acidizing treatments, formation parting pressures are exceeded, greatly extending acid penetration. Under these conditions, stimulation benefits are limited to the fracture area produced during the spending time of the first increment of acid injected into the formation. This area may be calculated from laboratory and well data to estimate depth of penetration. This, in turn, may be correlated with productivity data to assist in the selection of optimum treating techniques and materials.
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > P474 > Darcy Formation (0.99)
- Africa > Tanzania > Indian Ocean > K Formation (0.99)