Transactions of the AIME

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ISSN : 0081-1696
Published by: Society of Petroleum Engineers (SPE) (10.2118)
Total articles ≅ 938
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John J. Justen, P.J. Hoenmans, H. Groeneveld, C.A. Connally, W.L. Mason
Transactions of the AIME, Volume 219, pp 38-45; https://doi.org/10.2118/1308-g

Abstract:
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 38–45. Abstract A miscible displacement pilot using a slug of LPG driven by separator gas was conducted in the Cardium reservoir of the Pembina field. The injection pattern was a 10-acre, inverted, isolated five-spot. Upon completion of the LPG-gas phase, an experiment was conducted using a slug of water followed by gas. Calculated performance of the pilot is compared with actual performance. Equations are developed to calculate the distribution of LPG into zones of varying permeability, to estimate the progress of the flood at different times in the various zones and to estimate gas rates after breakthrough. The analysis indicates that permeability stratification was a dominant factor in controlling oil recovery and that oil was completely displaced from the swept pore volume. The results of the pilot indicated that miscible flooding is a practical means of pressure maintenance in this reservoir. The total recovery from the pilot area was good in spite of the early breakthrough of LPG. The effects of stratification were reduced by injecting a slug of water into the partially swept reservoir. Introduction The Pembina field, located in Alberta, is the largest oil field in Canada and one of the largest in the North American continent. The reservoir is a stratigraphic trap producing from the Cardium sand. Neither bottom water nor free gas has been found. The recovery of oil by the natural depletion mechanism has been estimated at 12.5 per cent. Pressure maintenance studies of various areas have indicated that the recovery can be increased 2 1/2 times by water flooding, and a large area of the field is presently under water flood. However, reservoir studies of the North Pembina area indicated that miscible flooding might be competitive with water flooding. A pilot test was conducted to evaluate the performance of a miscible flood.
D.B. Robinson, C.A. Macrygeorgos, G.W. Govier
Transactions of the AIME, Volume 219, pp 54-60; https://doi.org/10.2118/1359-g

Abstract:
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 54–60. Abstract Experimental data have been obtained on the volumetric behavior of ternary mixtures of methane, hydrogen sulfide and carbon dioxide at temperatures of 40°, 100° and 160°F up to pressures of 3,000 psia. The results indicate that the compressibility factors for this system do not agree with compressibility factors for sweet natural gases at the same pseudo-reduced conditions. The deviation increases as the temperature and methane content decrease. Discrepancies of up to 35 per cent were observed. A careful analysis has been made of the existing published data on compressibility factors for binary systems containing light hydrocarbons and hydrogen sulfide or carbon dioxide. It has been found that the deviation of actual from predicted compressibility factors for methane-acid gas mixtures is a function of the methane content and the pseudo-critical properties of the mixture. The ratio between actual compressibility factors for methane-acid gas mixtures and compressibility factors for sweet natural gases at the same pseudo-reduced conditions has been correlated over a range of pPr from 0 to at least 7 and a range of pTr from about 1.15 to at least 2.0 with an error not exceeding 3 per cent and over most of the range within 1 per cent. The validity of the correlation for mixtures containing appreciable heavier hydrocarbons has not been fully established, but it is shown to be preferable than the use of a correlation based only on hydrocarbons. Introduction Although a relatively accurate method for predicting compressibility factors of pure materials is provided by charts based on reduced properties and the assumption that the compressibility factor is a unique function of Tr, Pr and zc, the determination of the correct values of compressibility factors for gas mixtures is somewhat difficult. Two general methods of dealing with gaseous mixtures have been proposed. The first assumes a direct or modified additivity of certain properties of the mixture in terms of the properties of the individual components. Examples of this method are based on the familiar laws of Dalton and Amagat. The second method averages the constants of an equation of state applicable to the pure components. Both of these methods are of limited value in engineering calculations because the first usually provides reliable answers only over narrow ranges of pressure and temperature and the second is cumbersome to handle.
T.E. Morrisson, James H. Henderson
Transactions of the AIME, Volume 219, pp 7-15; https://doi.org/10.2118/1330-g

Abstract:
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 7–15. Abstract An investigation has been made of the production of oil through horizontal fractures of high capacity and large radius placed at the base of producing formations. The specific aims of the study were todetermine by model studies the reservoir performance when gravity drainage is the only producing mechanism, anddevelop a method of predicting such performance from commonly measured reservoir properties. Although the theoretical approach failed to develop a rigorous analytic solution to the transient problem, it did lead to a practical method of predicting performance. Predictions are in good agreement with rates and recoveries observed in scaled-model experiments. Capillary effects and the influence of relative permeability are taken into account. The experimental program wad mainly concerned with the influence of fracture radius, fracture capacity and capillary hold-up on the total recovery and the rate of recovery. Much of the experimental work was done on a triangular model which represented one-eighth of a square well pattern, so constructed that horizontal fractures of varying radii and flow capacity could be studied. An electrolytic model was used to relate the initial production rates to fracture radius, formation thickness and the drainage radius of the well pattern. The conclusions reached as a result of the work are as follows.The production of oil under gravity force alone into a well-propped horizontal fracture, whose radius is of the order of hundreds of feet, is a recovery method which combines high recoveries with very acceptable production rates.The mechanism is effective in "dead oil" reservoirs as well as in reservoirs which possess the energy of solution gas.A method of predicting performance has been developed which gives good agreement with experimental behavior in cases of practical interest. Even for very thick beds and large fracture radii, where actual conditions do not conform to the assumptions made, the method gives order of magnitude predictions which would not otherwise be possible.
H.R. Bailey, B.K. Larkin
Transactions of the AIME, Volume 219, pp 320-331; https://doi.org/10.2118/1482-g

Abstract:
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.
R.D. Carter, G.W. Tracy
Transactions of the AIME, Volume 219, pp 195-200; https://doi.org/10.2118/1328-g

Abstract:
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 195–200. Abstract Numerical calculations were made to determine the behavior of reservoirs with high-pressure drawdown and wide well spacing where the initial productivity is low and the wells are completed by hydraulic fracturing. The two-phase flow equations were solved for the flow into a single well. This well was assumed to be producing from a reservoir with hydraulically created horizontal fractures (four different systems with fractures were studied). For comparison purposes, additional two-phase flow calculations were made assuming a reservoir with uniform rock properties. The two-phase flow results were also compared with the conventional calculation methods, which do not include the effect of saturation gradients resulting from a simultaneous flow of oil and gas which are normal to this type reservoir. It was found that the conventional methods predicta high and too optimistic value of ultimate recovery,a high producing rate and a high reservoir pressure at a given oil recovery anda low trend of gas-oil ratio with oil recovery. Included in the two-phase flow calculations were provisions to control the oil production rate by an allowable rate and, also, by a gas-oil ratio penalty rule. For the systems with hydraulic fractures, the producing rate was controlled by the gas-oil ratio penalty rule for most of the life. This is in contrast to the system with uniform rock properties which went "on decline" almost immediately. An unexpected characteristic of the systems which included fractures was the early rise in producing gas-oil ratio from 730 cu ft/bbl to approximately 1,200 cu ft/bbl, followed by a "leveling off" before the normally expected gas-oil ratio rise began. Additional features which are a result of hydraulic fracturing aregreater ultimate recovery,higher average producing rates anda lower average reservoir pressure at a given oil recovery.
Ronald L. Reed, Denzel W. Reed, Joseph H. Tracht
Transactions of the AIME, Volume 219, pp 99-108; https://doi.org/10.2118/1313-g1

Abstract:
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 99–108. Abstract Laboratory experiments on the reverse combustion of tar sands in a linear adiabatic system have shown that a highly upgraded oil can be produced from an exceedingly viscous, immobile oil. The dependence on the air-injection rate of peak temperature, combustion-zone velocity, oil recovery, air-oil ratio, residual coke and oil, fuel burned and distribution of product gases is shown graphically. Effects of initial temperature, oxygen concentration, oil saturation and heat loss are discussed. Experiments bearing on the coking properties of heavy oils are mentioned and some results exhibited. Field application of the process hinges on the existence of adequate air permeability and the rate of reaction under reservoir conditions. Introduction It has been established that oil can be recovered from underground reservoirs by means of at least two fundamentally distinct methods involving in situ combustion of a certain fraction of the oil. Characteristic of both of these known methods is the production of oil from one or more wells by means of hot gases formed when a high-temperature reaction zone is advanced through the reservoir. In both cases, the reaction zone is created by heating certain of the wells to a sufficiently high temperature prior to the introduction of air, and the zone is maintained and advanced through the reservoir by appropriate control of the air-injection rate. In the first of these methods, which is called "forward combustion", the combustion zone advances in a direction which is generally the same as that of the air flow; whereas in the second method, "reverse combustion", the combustion zone moves in a direction generally opposite to that of the air flow. Forward combustion, on the one hand, is an ideal combustion process in the sense that a minimum of the most undesirable fraction of the oil is consumed as fuel in the form of coke, a clean sand is left behind and generated heat is used as efficiently as possible. However, the applicability of forward combustion is limited. Since the products of combustion, vaporized oil and connate water must flow into relatively cold regions of the reservoir, there is an upper limit on the viscosity of oil which can be moved by this process in a practical and economical fashion.
Carl Gatlin, R.L. Slobod
Transactions of the AIME, Volume 219, pp 46-53; https://doi.org/10.2118/1356-g

Abstract:
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 46–53. Abstract This study defines the basic mechanism of the miscible displacement of oil and water from porous media by various water-driven alcohol slugs. Three distinct alcohol slug processes were studied. Considerable data concerning the quantity of alcohol required for oil recovery were also obtained. All data were obtained in a 1-in. diameter, 100-ft long, unconsolidated core. The porosity of this system was 35 per cent, and the permeability was approximately 4 darcies. Total core pore volume was 5,716 cc. All displacements were conducted at a constant injection rate of 5 to 6 cc/min, which correspond to a frontal advance of 5 to 6 ft/hr. The first portion of this paper is concerned with the use of one alcohol-isopropyl-as the slug material. Isopropyl alcohol (IPA) is completely miscible with both oil and water; however, miscibility of the three-component systems, oil-water-IPA, requires a relatively high concentration of IPA. Hence, the displacement is not of the miscible type unless the IPA concentration is maintained above some critical value. A slug of IPA equal to only 13.5 per cent of the pore volume was found to be sufficient to obtain complete recovery of residual naphtha. In later studies two distinct process variations were developed. The first of these utilized methyl alcohol (MA) and IPA as slug materials. It was shown that methyl alcohol may be substituted for IPA at the front and rear of the slug with no loss of oil recovery. A slug of 4 per cent MA–4 per cent IPA–4 per cent MA was sufficient for complete oil recovery. Because MA is considerably cheaper than IPA, this represents an important step toward economic application. A second process variation used normal butyl alcohol (nBA) and MA as the composite slug, the nBA segment being injected first. This technique requires the smallest total slug size (approximately 10 per cent) of all processes studied. The high cost of nBA, however, precludes commercial application. It is possible that this basic process, subject to changes of alcohol type, may lead to a commercial process.
H.A. Kendall, W.C. Jr. Goins
Transactions of the AIME, Volume 219, pp 238-250; https://doi.org/10.2118/1288-g

Abstract:
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.
B.H. Caudle, I.G. Locaric
Transactions of the AIME, Volume 219, pp 132-136; https://doi.org/10.2118/1396-g

Abstract:
Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 132–136. Abstract TransPilot flooding is one method of evaluating a proposed secondary recovery project. However, the amount and rate of oil recovery from an unconfined pilot area is not usually the same as from an equal area in a large-scale flood. This is true because fluids are free to move across the boundary of a pilot area. The result is that some of the oil produced in a pilot flood may come from outside the designated area and some of the displaced oil may leave the pilot area completely. This paper presents the results of fluid-flow model studies on a five-spot pilot flood. Mobility ratios between 0.1 and 10 have been studied. The effects of changing the ratio of injection to withdrawal rates are shown. Introduction A small-scale field test, or pilot flood, is an accepted method for evaluating the applicability of a secondary recovery operation and the economic potential of that operation for a reservoir. The pilot flood is carried on in the same manner, with the same injected materials and at the same pressures as would be used were the secondary recovery program to be expanded to a larger area of the field or to the entire field. If the reservoir fluid and reservoir rock properties are the same in the pilot area as in the rest of the reservoir, the production, injection and other pertinent data associated with the pilot test will represent and measure what should be expected from a full-scale development of this secondary recovery program. There is one major exception which, unfortunately, has been overlooked by many and which has been awaiting quantitative definition. This is the sweep-out pattern the reservoir engineer must use in interpreting the pilot flood and in extrapolating it to the full-scale development. The sweep-out area in a pilot flood is not contained within the five-spot pattern. Further, there is oil flow into and/or out of the five-spot during a pilot test. Thus, production data from pilots must be interpreted with this different flow system and sweep pattern in mind.
David E. Brink, Thomas C. Poulter, Blake M. Caldwell
Transactions of the AIME, Volume 219, pp 257-263; https://doi.org/10.2118/1293-g

Abstract:
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.
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