bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comments on Finding the Most Profitable Slug Size
Authors: Holm L.W. 
Published: December 2007

In the Forum, "Finding the Most Profitable, Slug Size" (Aug, 1972 JPT, Pages 993-994), S. C. Jones found that the most profitable slug size for the micellar solutions he investigated was about 3 percent PV for a homogeneous porous system. He concludes that "even smaller slugs should be used with increasingly stratified reservoirs, quite the opposite conclusion from a classical paper on the subject." The explanation Jones gives for using reduced slug sizes in heterogeneous sands is that the oil in the tighter zones costs more to recover than it is worth. On the surface, this explanation seems reasonable. However, these tight zones may contain the major portion of the oil we seek to recover. In any event, I think the conclusion applies only to a limited number of reservoirs. Let me explain why. To begin with, Jones' conclusion that the optimum slug size becomes smaller as the degree of stratification increases is not supported by experimental data. The oil recovery curves presented by Jones for various stratified sands were calculated on the basis of the curve for the homogeneous sand. These calculated curves apply to watered-out, stratified systems in which no communication between zones exists and in which all zones are at or near residual oil saturation. Consequently, they do not include the effects of crossflow or transverse dispersion that occurs between zones of different permeabilities in many porous systems. porous systems. On Fig. 1,* I have plotted Jones' calculated curves for comparison with experimental results (Curve A) that we have obtained from soluble-oil floods conducted in a two-layer, noncommunicating stratified system at high (65 percent PV) oil saturation. The greater slope of the experimental curve indicates that the optimum slug size would not decrease as stratification increases but may remain at about the 3-percent-PV level.
P. 77
Failure of Stream Tube Methods To Predict Waterflood Performance of an Isolated Inverted Five-Spot at Favorable Mobility Ratios
Authors: Martin J.C. , Woo P.T. , Wagner R.E. 
Published: December 2007

Failure of Stream Tube Methods To Predict Waterflood Performance of an Isolated Inverted Five-Spot at Performance of an Isolated Inverted Five-Spot at Favorable Mobility Ratios

Introduction
Since their introduction by Higgins and Leighton in 1962, stream-tube methods (STM) have been used by a number of authors to make approximate waterflood and gas flood calculations. The principal justification for the methods is given by Higgins and Leighton, who present excellent agreement between their STM results and the experimental and numerical result of Douglas et al. for a wide range of M values in a repeated five-spot-pattern waterflood. Doyle presents fair to good agreement between STM results and laboratory model results for five-spot and direct line drive well configurations. The basic assumptions of the Higgins-Leighton STM arethat the streamlines are independent of the mobility ratio, andthat Buckley-Leverett theory can be used to calculate the fluid displacement between adjacent streamlines.
The first assumption allows the streamlines to be determined from singlephase flow and to be held fixed as the flood progresses. In their original work, Higgins and Leighton used potentiometric model results to determine the potentiometric model results to determine the streamlines. Other authors, including us, have used analytical and numerical methods involving pressure and stream-function solutions.

Discussion
Fig. 1 presents calculated oil recovery vs displaceable pore volumes injected for an isolated inverted fivespot pore volumes injected for an isolated inverted fivespot pattern for various values of M. pattern for various values of M. JPT
P. 151
Correlation Between Pore Structure of Sandstones and Tertiary Oil Recovery
Authors: Batra V.K. , Dullien F.A. 
Published: December 2007

An excellent correlation has been attained between pore structure and additional recoveries obtained in tertiary surfactant floods for 15 different sandstones. A reasonably good correlation exists between the reciprocal of mean neck diameter (as obtained from mercury porosimetry) and the additional recoveries obtained in tertiary surfactant floods.

THEORY AND EXPERIMENT
When conducting laboratory tertiary surfactant floods on a variety of different sands, sometimes great differences are found in the tertiary oil recoveries - the reasons for which are often not well understood. In the present study it has been demonstrated that, for the set of conditions used, the observed differences in tertiary oil recoveries could be correlated with the pore structure of the samples.
The problem of how pore structure might influence tertiary oil recovery has been discussed by Dullien et al. In the present study, 15 outcrop sandstones have been successfully ranked on the basis of their pore structure in the order of increasing amounts of tertiary recoveries expected under identical conditions of flooding.
How To Diagnose a Thief Zone
Authors: Felsenthal Martin 
Published: December 2007

Calhoun presented a classical method for determining the time required for tracer-tagged liquids to flow from injection wells to producing wells. This method can also be used for evaluating the permeability of the most conductive layer of the formation. This layer may turn out to be a "thief" zone that ought to be closed by subsequent remedial action. Calhoun's method of analysis unfortunately is time consuming because it involves either a graphical integration or an approximation using a summation of terms. A simpler method was therefore developed that achieves the same purpose with much greater speed and with sufficient accuracy. The method is based on a model of two radial-flow regimes illustrated in Fig. 1. Radial flow emanates from the injection well, which acts as a "source," and converges in the producing well, which acts as a "sink" . A unit mobility ratio for the displacing and displaced phases and a piston-like advance of the tracer-laden liquid are assumed. The derivation of the equations starts with the familiar radial-flow and material-balance relationships, which are modified so that they apply to the highest-permeability layer of the formation. Thus,(1)0.00707 k1h1 (p/2) qf = ln(d/2rw)(2)2 2 Wif = 0.1781 (r1 - rw) h1 (1-Sor),
where Subscript 1 refers to the high-permeability layer or "thief" zone and(3)f = k1h1/total kh of formation, q = injection rate for well, B/D, Wi = cumulative injection in well, bbl, ri = radius of tracer front in high-permeability layer
Eqs. 1 and 2 are combined through the relationship Wi = qt and the resulting equation is solved for t', the time required for the flood front to travel half way from the injection well to the producing well. The desired time, t, for first arrival of tracer-tagged liquid at the producing well is then set equal to 2 t'.
P. 839
First Jack-Up Production Platform in the North Sea
Authors: Cheng Aylmer P. , Kelewer Jerry F. 
Published: December 2007

Introduction
A jack-up gas production platform by Amoco International Oil Co. was installed in Aug. 1972 in 75 ft of water in the Leman field, British North Sea. It was the first jack-up production platform installed in the North Sea. production platform installed in the North Sea. The main advantage of using the jack-up platform rather than the conventional template-type platform is that all production, storage, and living facilities can be installed, tested, and checked out in the fabrication yard before it is removed for installation. As a result, considerable expensive offshore work is avoided, and more important, much less time is required to commission the production facilities and begin operation.

Design
Basically, the platform is designed as a flat-bottom, flush-deck barge with vertical sides and raked ends. Between the flat bottom and flush deck, the barge is subdivided into thirty compartments by six athwartships full scantling bulkheads, four longitudinal bulkheads and several division bulkheads. The barge is supported by six caissons 71-in. OD and 195 ft long, each extended through a well in the platform. There are three wells on the port side and three on the starboard. The dead weight of the barge and caissons is 3,070 kips. The dry weight and wet weight of the production facilities are 1,550 kips and 1,840 kips, respectively. The soils encountered in the boring to the maximum penetration explored (203 ft) are primarily fine sand. penetration explored (203 ft) are primarily fine sand. A laterally loaded pile computer program was used to develop soil-resistance caisson-deflection characteristics for the caisson design. The design penetration for the six caissons is 55 ft, with a 20-ft-long grout plug placed on top of the natural soil plug. The design analysis was performed with a staticelastic space frame analysis computer program. Stokes' fifth order wave theory was used to generate the wave forces on the caissons. The maximum lateral deflection of the barge under storm condition is 10 in. The natural period of the platform is computed by the Rayleigh method and is found to be 2.5 seconds, which is much less than the period of the storm wave. Thus the dynamic amplification effect is negligible. The limiting angle of roll of the barge under tow was 9.25 degrees, at which position the stress in the caissons would be equal to 80 percent of yield. The draft of the barge is 5.1 ft. The period of roll of barge under tow was calculated to be 4.8 seconds.

Construction
The platform, built in Holland during 1971 and 1972, was constructed in three sections - one each in Amsterdam, Sliedrect, and Rijn. The three completed sections were then assembled at DeGroot and Van-Vliet yard at Slikkerveer and then towed to the DeGroot International N.V. Yard at Zwijndrect.
JPT
P. 323
Production Engineering Aspects of Shannon Reservoir, Cole Creek Field, Wyoming
Authors: Gates C.F. , Brown G.G. 
Published: December 2007

Abstract
Performance of the Shannon Reservoir, Cole Creek field, Wyo., is summarized. Oil has been secured largely by water drive.
Calculated pressure-rate performance based on Hurst's water-drive equation for an infinite reservoir coincides with observed performance. An empirical relationship indicates that the difference in pressure between the perimeter and the oil producing area for a given oil rate by water drive is about proportional to the cumulative oil produced. Calculated future performance, based on Hurst's equation, the pressure difference relationship, and the reservoir oil rate equation, correctly indicated limitations on maximum oil rate which were not apparent before the calculations were made.
Net formation withdrawals have been reduced to about zero by the injection of water in six wells spaced around the perimeter of the field. About three-fourths of the injected water rate merely replaces the former natural water encroachment rate; the remainder supports an increased oil rate.
Productivity indexes are being maintained at a maximum by keeping producing pressures at a high per cent of the bubble-point pressure through the use of "bubble-point pumps" and shut-in casingheads. The maximum efficient rate of the reservoir is automatically produced thereby. Productivity indexes of wells were increased many-fold by shooting with nitroglycerin.
Indicated recovery efficiency is about 33 per cent but ultimately may he higher.

Introduction
Although the Cole Creek Shannon reservoir is relatively small, it is of especial interest to the production engineer for the following reasons:Reasonably complete field data have been secured throughout the 14-year life of the reservoir.The limited natural water drive is being supplemented by water injection.Present installations automatically produce the maximum efficient rate.The reservoir has behaved largely according to engineering calculations.There are enough diverse aspects of the reservoir history to warrant intense study.
This paper consists mostly of data and our interpretations of the data. For continuity and completeness the paper repeats some data given by Whitaker and Hoenshell.
Economics of Water Flooding
Authors: Brundred L.L. , Brudred Latham L. 
Published: December 2007

Abstract
Water flooding has progressed from the haphazard experimental stage through numerous phases to a somewhat precise engineering achievement. Unfortunately the economics, which are dependent on so many variables, have not yet lent themselves to particularly accurate interpretations.
Recognizing that technical studies are proceeding rapidly, there still are divergent schools of thought. Regardless of divergences of opinion, the first step in any proposed project is a complete engineering study, evaluated in the light of past experience.
The economics fundamentally boil down to the component parts of the following simple formula: Expected Gross Revenue less The Summation of Computed Acquisition Costs, Costs of Development, and Operating Costs (over the life of the flood) equals Estimated Gross Profit.
Estimated Gross Revenue can be fairly reliable determined from the initial engineering study. Acquisition costs must be based upon the true value of the property and are always subject to negotiation. Development costs are influenced by many factors, but are largely controlled by the depth and the spacing used. They can be estimated with reasonable accuracy once the spacing program has been adopted. Operating costs ]do not lend themselves to ready determination because of the variables involved, but reasonably accurate estimates are possible.
There is no substitute for experience. Approximately seven out of 10 waterflood attempts are failures. It is just as important to determine basic causes of failure as it is to study successful floods. Good floods are widely publicized, the poor ones never. Most of these failures can be attributed to improper engineering, lack of experience, or shortage of working capital.
Engineering and economics are inseparable, and a proposed flood, based on sound engineering, must meet heavy financial demands. While waterflooding is often considered one of the safest of oil ventures, it, too, can be hazardous. "First results" are often long delayed, and pay out is invariable slow.
The conclusion is inescapable that successful waterflooding requires three basic essentials: engineering, experience, and economics.
Design and Operation of Plants for the Preparation of Water for Injection Into Oil Reservoirs
Authors: Watkins J. Wade 
Published: December 2007

Abstract
Both the design of plants in which water is to be treated for subsurface injection and the operation of the plants are important to the success of waterflooding and pressure-maintenance operations. Treating plants should be designed specifically for conditioning of the water or brine to be used in the project. The principal factors to be considered in designing a plant are:characteristics of water to be treated;quality of treated water desired;primary and ultimate capacity of plant;most favorable location of plant site; andtype of plant and equipment that will best serve the purpose.
The operation of an injection-water-treating plant is at least as important as the proper design of the plant and judicious choice of treating methods. The important considerations in operating a plant are:qualifications and training of operating personnel;regularity and accuracy of water analyses;analytical equipment and reagents used; andprecise control of mechanical equipment.
The design of equipment for the various steps in the treating process are discussed independently in this paper. Criteria for the optimum characteristics of treated water also are given. It is concluded that a particular effort should be made in designing and operating an injection-water-treating plant to minimize corrosion, prevent plugging, and improve the water as a flooding medium.

Introduction
The choice of design for a plant in which water is to be treated for subsurface injection and the method of operating that plant determine to a large extent the success of an injection project. The efficiency of water treatment and, consequently, the quality of the treated water, will depend directly upon the kind of equipment employed in the plant and the manner in which it is used, as well as upon the chemicals used for treatment. The factors involved in the design and operation of a plant for treating a particular water to the best advantage are discussed in this paper.
Preparation of Water for Injection Into Oil Reservoirs
Authors: Torrey Paul Dwight 
Published: December 2007

Introduction
The most important item in the injection of water into oil reservoirs is the water supply itself. Not only is a certain source of supply essential, but the quality of the water is also of great importance.
Nature rarely provides chemically pure or bacteria free water in any substantial quantities. Water, whatever its source, ordinarily contains a variety of impurities which may be inorganic, organic, or both. Even though these impurities may be present in very minute quantities, their existence must be recognized in almost every water injection system. However, the taste, the odor, or the toxicity of the water, important items where water is to be used for human consumption, are relatively unimportant in oil field use. The two principal problems connected with the use of water to improve oil recovery are possible reaction with the reservoir and its contents, and whether the water will cause destruction of surface and subsurface equipment by corrosion.
In the early days of secondary waterflooding operations in the Bradford and Allegany fields, little attention was given to the preparation of water, for an ample supply of fresh water of good quality was available from shallow aquifers and from surface streams. In the Southwest and particularly in Texas no such fortuitous conditions exist. In most parts of Texas, suffering as they have from recurring and progressively ruinous years of drought, the oil industry will have little call on the limited supplies of fresh water, and therefore must resort to water resources of inferior quality. In almost every case such waters will require some form of treatment before they will be suitable for injection into oil reservoirs. Consequently, the importance of proper conditioning of water to be used for such purpose is now rather generally accepted.
The quantity of water that will be required for complete secondary recovery and pressure maintenance operations in the oil fields of Texas can be estimated in amounts of almost astronomical proportions. Studies recently completed by the Texas Petroleum Research Committee indicate some 10.5 billion bbl of oil that is physically recoverable by injection of water into the reservoirs. It is roughly estimated that approximately 15 billion bbl of water will be required for this purpose. The water that will be available for these operations will have to come largely from subsurface salt water-bearing formations and probably to some extent from the open sea.
Geothermal Energy Potential in Northern Appalachia
Authors: Rieke Herman H. , Skidmore Duane R. 
Published: December 2007

Introduction
Rising domestic energy needs in the face of limited supplies have led to various estimates of total energy consumption through 1985 and beyond. Increases in domestic energy production sufficient to meet demand by 1985 appear unlikely if energy sources are limited to fossil or nuclear fuel. The intent of this discussion is to delineate and evaluate the geothermal resource base of northern Appalachia, which comprises portions of the states of New York, Pennsylvania, North Carolina, Maryland, Virginia, Ohio, and West Virginia. Total development of geothermal resources in this region could provide additional amounts of energy for electrical provide additional amounts of energy for electrical power, commercial and process heat, valuable power, commercial and process heat, valuable minerals, and desalinated water for the eastern U. S.

Geothermal Resource Base
Determination of the resource base is supported by the assignment of quantitative values to the following parameters:geothermal gradient,heat flow parameters:geothermal gradient,heat flow in the subsurface, andheat capacity of the rocks.
It should be realized that even in the most intensely investigated geothermal areas but few of these values are known, and then often only within an order of magnitude.

Geothermal Gradients
Fig. 1 illustrates a re-evaluated distribution of geothermal gradient values for northern Appalachia. Unfortunately, these data show only a broad range in the variation of these values (0.7 degrees F/100 ft to 2.1 degrees F/100 ft). Localized high and low gradient values could readily occur within the contours of the map.

Heat Flow
In-situ heat transfer measurements provide information about the amount of geothermal energy available in the region. The global average measured heat flow is approximately 1.5 HFU (1 HFU = 1 cal/cm2-sec), whereas the average heat flux in the Appalachian system has been estimated to be 1.3 HFU. Local thermal resistivities were re-estimated for various lithological units in Appalachia. Horizontal heat transfer between adjoining rock bodies was ignored. Fig. 2 illustrates the variation of the regional heat flux, which ranges from 0.6 to 1.5 HFU. One area bordering southern West Virginia and western Virginia contains a mixture of anomalous high and low heat flux values. Further field work must be done to resolve the implied geological problem.

Geothermal Energy Potential
The sensible heat stored in the sedimentary rocks was calculated with the following equation:
Q = C, (1)
JPT
P. 1005
Pseudo-Relative Permeability for Well Modeling
Authors: Emanuel A.S. , Cook G.W. 
Published: December 2007

Several authors have described the use of pseudo-relative-permeability curves for modeling pseudo-relative-permeability curves for modeling the vertical performance of formation flow in areal reservoir simulators. The pseudo curves are usually determined from small cross-section or three-dimension models and then incorporated into large-scale areal models. The concept of pseudo-relative permeability can also be extended to the vertical performance of individual wells by a technique analogous to that for formation flow. In a cross-section model, the production of phase p from a well with nc completions can be expressed as(1)
Eq. 1 follows the form of the well potential equation of Ref. 4. For an areal model in which the well has only one completion, the production is(2)
The cross-section model can be constructed with the vertical detail necessary to account for phase segregation, partial penetration, etc. To obtain the same well performance in the areal model, we desire(3)
or combining Eqs. 1 through 3,(4)
If the cross-section model has been divided into nl layers, then an areal model block represents a composite of the nl layers and a well a composite of nc completions. Therefore, the following approximations are made.(5)
and(6)
Combining Eq. 4 through 6, the pseudo-relative permeability for the areal model well is obtained: permeability for the areal model well is obtained:(7)
The corresponding saturation is(8)
The wellbore pressure in the areal model, PwA, can be assumed to be an appropriate average of the Pw calculated in the cross-section model. Eqs. 6 Pw calculated in the cross-section model. Eqs. 6 and 8 am appropriate for an areal block equivalent to one column of the vertical model. If the areal block is larger, then the pressure and saturation must be averaged over the volume encompassed by the areal block.
P. 7