bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Investigation of Reduction of Fracture Pressures of Rocks by Intensive Borehole Heating
Authors: Clark Kenneth K. , Somerton Wilbur H. 
Published: December 2007

Abstract
The feasibility of reducing pressures needed to fracture formations by heating the borehole intensively has been investigated on a laboratory scale. Reductions in fracture pressures of heated Bandera, Berea and Boise sandstone cores were observed at various confining pressures, simulating reservoir stress conditions to a depth of 5,000 ft. Both permeable and impermeable borehole boundary conditions were tested.
Three heating conditions were used in the tests. One group of samples was heated in a furnace to a temperature of 600C, cooled to room temperature, and then tested for fracture pressures. Two other groups of samples were heated with a borehole heater to maximum borehole wall temperatures of 625 and 792C, then cooled and tested.
In all cases, heated samples showed substantial reductions in fracture pressures compared to unheated samples. The higher temperature borehole heated samples showed the greatest reduction, amounting to 70 per cent in the extreme case. In actual application to wells, it was concluded that fracture pressures may be reduced by 20 to 50 percent by intensive borehole heating before fracturing.

INTRODUCTION
Hydraulic fracturing of oil and gas wells is an accepted and effective technique for increasing well productivity in many areas, but is notoriously unsuccessful in other areas. The technique becomes less interesting for production stimulation purposes when excessive fracture pressures are necessary. Formations which do fracture but require high pressures, probably form horizontal fractures. There is good evidence to indicate that some formations do not fracture at all, but yield plastically under high pressure. Thus, any technique which will make formations easier to fracture or will reduce fracture pressures is potentially interesting to petroleum producers.
Horizontal fractures generally occur in planes of weakness, such as bedding planes, and at pressures equaling or exceeding the effective overburden stress. In the unusual case where planes of weakness do not exist, a slightly higher pressure must be applied to overcome the tensile strength of the rock. In general, high fluid-loss fracturing fluids are conducive to the formation of horizontal fractures.1
Vertical fractures, when they do occur, are initiated at pressures generally lower than overburden pressure and are favored by low fluid-loss fracturing fluids or impermeable boreholes. The pressure necessary to create a vertical fracture in an impermeable, elastic medium can be predicted from the so-called "thick-walled cylinder" equation:Equation 1
where pf = fracture pressure
sr=radial stress
st=tensile strength of medium.
This equation indicates that to fracture it is necessary to overcome a tangential compressive stress, induced by and equal to two times the radial confining stress, plus the tensile strength of the medium.
Collocation Simulation of Multiphase Porous-Medium Flow
Authors: Allen Myron B. , Pinder George F. 
Published: December 2007

Abstract
Hermite orthogonal collocation yields oscillatory and sometimes nonconvergent numerical solutions to convection-dominated oil reservoir flow problems. A new method of choosing collocation points emphasizes upstream values in the convective terms, yielding oscillation-free solutions to the linear convection-dispersion transport equation and convergent solutions to the Buckley-Leverett problem.
Determination of Alkalinity Losses Resulting From Hydrogen Ion Exchange in Alkaline Flooding
Authors: Novosad Zdenka , Novosad Jerry 
Published: December 2007

Abstract
Maintaining an effective level of alkalinity during an alkaline flood is of prime importance in design of this EOR process.
Alkaline solution can be consumed in the reservoir through interaction with both reservoir rocks and fluids. The rock/alkali interaction can be characterized as either chemical or ion-exchange reaction, and the magnitude of alkalinity consumption and its type must be considered when alkaline floods are designed for specific reservoirs. This is because alkalinity propagation in porous media is directly affected by the type of alkalinity loss. It has been shown previously that kinetically controlled mineral dissolution reactions may cause the produced alkalinity to plateau at a lower concentration than the injected concentration, whereas ion-exchange processes may cause characteristic delay in the produced alkalinity, which in turn delays tertiary oil production.1,2 The type and the magnitude of alkalinity loss therefore must be known to design a flood with alkaline concentration maintained at its optimum for the longest possible time.
This paper concerns determining alkalinity loss resulting from hydrogen ion exchange. The model describing the release of initially rock-bound hydrogen ions into solution in the presence of alkali has been previously proposed and investigated for California Wilmington and Huntington sands.1,3 According to this approach the mechanism for reversible alkalinity uptake is described by the following equation.
The Importance of Reliable Data in Gas-Condensate Recovery Calculations
Authors: Hinds R.F. 
Published: December 2007

Introduction
With the continued deep drilling of today, increasing numbers of high pressure and high temperature gas-condensate reservoirs are being discovered. Correspondingly, the ranges of properties of gas-condensate reservoir fluids are also being increased. The literature contains several excellent reviews of the property ranges in presently known condensate reservoirs. When one examines these property ranges, it becomes apparent that the need for reliable data is great if the engineer is to evaluate properly or appraise a gas-condensate reservoir.
It is the purpose of this paper to present phase-behavior data that will point out some of the important variables that influence recovery from gas-condensate reservoirs produced by pressure depletion. All these variables may be resolved into two major categories: the hydrocarbon composition of the reservoir fluid and the physical properties of the reservoir. But the variables which we will consider are those which are usually determined from well tests shortly after discovery and are, consequently, readily available to the engineer. They are as follows:the producing separator gas-stock-tank liquid ratio,stock-tank liquid gravity, andreservoir temperature.
Laboratory depletion studies have been performed on several reservoir fluids to illustrate the effect of changes in the considered variables upon ultimate recoveries. The deviation factors, Z, of a series of reservoir fluids were determined experimentally to illustrate their order of magnitude and their effect upon the calculation of in-place reserves existing at high pressures and temperatures, The procedures followed in conjunction with the performance of these studies and their associated calculations are illustrated in Fig. 1. For the purpose of this paper, the depletion recoveries are expressed only in terms of per cent of initial stock-tank liquid, with the abandonment pressure assumed to be 500 psig.
Gas Well Stimulation Increases Production and Profits
Authors: Clinkenbeard Paul , Bozeman J.F. , Davidson R.D. 
Published: December 2007

Abstract
Various acidizing and fracturing techniques have been developed to meet gas well stimulation problems. Case histories from four major gas producing areas show that considering such problems on an individual well basis, in light of previous experience in the area, allows planning each stimulation treatment for maximum effectiveness. Despite the common opinion that stimulating old gas wells is unprofitable, results show that stimulating such wells has often resulted in substantial and profitable production increases.

Basic Stimulation Methods
Gas producers have used many variations of the basic stimulation methods, acidizing and fracturing, to obtain maximum production from gas wells. These various techniques are necessary to meet individual well conditions found in different formations and fields. A knowledge of the various stimulation techniques available and of the advantages of each should enable an operator to plan gas well stimulation treatments that will bring maximum production from either old or new gas wells.

Acidizing Techniques
Acidizing treatments using inhibited hydrochloric acid to enlarge pores and flow channels have been used successfully for many years. Ordinarily, an acid treatment is conducted by spotting acid opposite the zone to be treated, and then pumping it into the formation.
High-injection-rate acid treatments are a variation of the normal acid treatment. In such treatments, large volumes of acid are injected into the formation at from 15 to 75 bbl/min. Acid is usually pumped down both tubing and casing. Advantages of this technique are that the rapid injection rate penetrates deeper into the formation and breaks down a larger vertical extent of the pay zone.
A special acid is often used to achieve deeper penetration. This acid contains an additive which retards the acid's reaction rate on portions of the formation already contacted. However, the acid reacts rapidly with new, untouched formation rock. This retarded acid is especially valuable in formations which are highly acid-soluble because it penetrates far into the formation before becoming spent. By contrast, normal hydrochloric acid reacts rapidly in such a formation, quickly becoming spent in the immediate vicinity of the wellbore.
Effects of Mobile Water on Multiple-Contact Miscible Gas Displacements
Authors: Tiffin D. L. , Yellig W. F. 
Published: December 2007

Abstract
Miscible gas flooding using an alternate gas/water injection process (AGWIP) is presently being applied for enhanced oil recovery (EOR) in several waterflooded reservoirs.1–4 A mobile-water saturation in the vicinity of the miscible displacement front can occur in this process. To design field applications of miscible gas floods properly, it is necessary to understand the effects of water saturations above the connate saturation on the oil-displacement efficiency. Previous research on AGWIP has involved water-wet long-core flow tests using an injected solvent that is first-contact miscible with the in-place oil.5–13 Miscible floods employing CO2, enriched gas, methane, and flue gases, however, are rarely first-contact miscible with reservoir oils; the oil miscibility is normally achieved by a multiple-contact mechanism.
This paper discusses the effects of mobile water on multiple-contact miscible displacements under water-and oil-wet conditions. Tests were conducted in 8-ft (244-cm) water- and oil-wet Berea cores in which CO2 and water were injected both separately and simultaneously to displace a reservoir oil. The data presented focus on effects of water in the oil-moving zone (OMZ) where the CO2 is generating miscibility with the oil and mobilizing residual oil to waterflooding. Special emphasis is placed on understanding the effect of mobile-water saturation on the oil-displacement efficiency and the component transfer between phases necessary to develop miscibility in the CO2/reservoir-oil system.
This study demonstrates that reservoir wettability is a key factor in the performance of AGWIP. Gas/water injection can, under certain conditions, have adverse effects on characteristics of the OMZ. These effects are in part caused by the water trapping portions of the oil and solvent. It was observed that mobile water did not change the mass transfer process by which miscibility develops in a multiple-contact miscible displacement.
A Numerical Method for Computing Recovery of Oil By Hot Water Injection in a Radial System
Authors: Fournier K.P. 
Published: December 2007

Abstract
This report describes work on the problem of predicting oil recovery from a reservoir into which water is injected at a temperature higher than the reservoir temperature, taking into account effects of viscosity-ratio reduction, heat loss and thermal expansion. It includes the derivation of the equations involved, the finite difference equations used to solve the partial differential equation which models the system, and the results obtained using the IBM 1620 and 7090–1401 computers. Figures and tables show present results of this study of recovery as a function of reservoir thickness and injection rate. For a possible reservoir hot water flood in which 1,000 BWPD at 250F are injected, an additional 5 per cent recovery of oil in place in a swept 1,000-ft-radius reservoir is predicted after injection of one pore volume of water.

INTRODUCTION
The problem of predicting oil recovery from the injection of hot water has been discussed by several researchers.1–6,19 In no case has the problem of predicting heat losses been rigorously incorporated into the recovery and displacement calculation problem. Willman et al. describe an approximate method of such treatment.1 The calculation of heat losses in a reservoir and the corresponding temperature distribution while injecting a hot fluid has been attempted by several authors.7,8 In this report a method is presented to numerically predict the oil displacement by hot water in a radial system, taking into account the heat losses to adjacent strata, changes in viscosity ratio with temperature and the thermal-expansion effect for both oil and water.
DERIVATION OF BASIC EQUATIONS
We start with the familiar Buckley-Leverett9 equation for a radial system:*Equation 1
This can be written in the formEquation 2
This is sometimes referred to as the Lagrangian form of the displacement equation.
A Model for Interfacial Activity of Acidic Crude Oil/Caustic Systems for Alkaline Flooding
Authors: Ramakrishnan T. S. , Wasan D. T. 
Published: December 2007

Abstract
The interaction of the alkali in floodwater and the acids in reservoir crude results in the in-situ formation of surfactants, which are responsible for the lowering of interfacial tension (IFT) in caustic flooding. The extent to which IFT is lowered depends on the specific properties of the crude oil and the injection water. Therefore, it is important to establish the relationship between IFT and the essential chemical properties of the acidic oil and the floodwater. This paper presents such a relationship.
In this discussion, the adsorption and the desorption of the active species at the interface are modeled as ionic processes using the Gouy-Chapman theory of the diffuse double layer. The interfacial potentials calculated using this model show a fair agreement with the experimentally measured trend of elcctrophoretic mobility. Also, the model rationalizes the experimentally observed effects of alkali concentration, salinity, and the oleic- to aqueous-phase ratio on IFT. We conclude that the acid number of the crude oil may not correlate directly with interfacial activity. Even in cases of low-acid-number crudes, significant interfacial activity could be obtained because of highly hydrophobic active species in the crude.
The Use of Simulation in Decision Making for the Kuparuk River Field Development
Authors: Clutterbuck Peter Richard , Dance Simon Edward 
Published: December 2007

Summary
A multicomponent system of simulators has been used successfully for development decisions on the Kuparuk River field. This paper describes the field, the simulators chosen, and some decision examples. The system was found to be fast, flexible, and cost effective.

Introduction
The Kuparuk River field, west of Prudhoe Bay in Alaska, shares many problems with recently developed fields in the offshore and Arctic environments because capital costs are extremely high, lead times are long, and many of the development plans are made before useful production history is obtained. During the early development-planning phase, reservoir data acquisition accelerated and facility design revisions were frequent. BP Alaska Exploration Inc, (BPAE) and the Sohio Alaska Petroleum Co. (Sohio) are major shareholders in the Kuparuk River Unit and contributed to development plans. The BPAE/Sohio development team faced the need to compare options by using a rapidly changing data base, recommending decisions for a program that was fixed by target startup dates and seasonal windows. Output from the studies formed the basis for discussion with ARCO Alaska Inc. (ARCO), the Unit Operator, and for the adoption of a mutually agreed development plan. ARCO carried out similar studies concurrently, and all major field-development decisions were made jointly. This paper explains the system used by BPAE/Sohio to arrive at several major decisions through both simulation and experienced judgment to obtain an acceptable degree of confidence. The system used five simulators, either separately or combined, allowing a small team of technical staff to check the validity of results at intermediate stages. This was fast, flexible, and efficient. The views expressed, and the reservoir parameters quoted, reflect the authors' opinion and do not necessarily imply full agreement with other Kuparuk River unit working-interest owners.

Field Description
BP Alaska Inc. and Sinclair Oil Co. discovered the Kuparuk River field in 1969 on leases now held jointly by ARCO, BPAE, and Sohio. The field is 25 miles (40 km) west of Prudhoe Bay and covers an area of up to 200 sq miles (518 km2) of developable acreage. Fig. 1 shows the location of the field, the route of the Trans Alaska Pipeline System (TAPS) to the ice-free port of Valdez for tanker loading, and the summer sealift route. Fig. 2 shows a map of the field, and Fig. 3 records the field's discovery, appraisal, and development. Since Dec. 1981, the field has been unitized and produced at an average rate of 90,000 B/D (14 309 m3/d) oil. Fig. 4 outlines the probable development plan. A gathering system supplies oil from 40 to 50 drillsites to three central production facilities (CPF's). The first, CPF-1, produced oil initially from five drillsites, each with eight 320-acre (1.3 × 10 6 -m2) producing wells.
JPT
P. 1893^
Pressure Drawdown Analysis, Variable-Rate Case
Authors: Odeh A.S. , Jones L.G. 
Published: December 2007

Abstract
A theoretical development is presented which provides a straightforward method of handling the drawdown analysis for both oil and gas wells flowing at variable rates. In the past our inability to analyze variable-rate drawdowns has been a major obstacle in using them for formation evaluation. This method should permit wider use of these tests in the future.
Introduction
Pressure build-up analyses are widely used to obtain reservoir data such as the effective flow capacity of the formation. On the other hand, although pressure draw- downs have been run for a long time, they have not been used extensively to evaluate reservoirs because they are difficult to analyze. one of the difficulties in analyzing pressure drawdowns has been that the theory developed until now has required the test to be run at a constant rate. For both oil and gas wells this is a difficult requirement to satisfy, especially during the early period of a well's life when drawdown tests are usually run. in spite of this limitation, drawdown tests are often run with build-ups as a check. In this paper a theory, which handles the drawdown analysis for variable rates, is presented for both oil and gas wells. Thus, one of the biggest deterrents to running drawdowns is removed, and they should become a much more useful engineering tool in the future.
THEORETICAL CONSIDERATIONS
OIL RESERVOIRS
The general equation used for describing the unsteady- state radial flow of slightly compressible fluids in homogeneous porous media can be written in cylindrical coordinates as
(1)
where r is the radial distance in cm, t is the time in seconds, p is the pressure at r and t in atmospheres, phi is the fractional porosity, mu is the viscosity in cp, c is the compressibility in vol/vol/atm, and k, is the permeability in darcies.
There are a number of solutions of Eq. I for various boundary conditions. One of these is the so-called "point- source" solution, which approximates the case of an infinite oil reservoir with a well located at r = 0 and produced at a constant rate. The point-source solution of Eq. 1 is
(2)
and h is the net pay thickness in cm, q is the production rate in cc/sec, p is the original pressure at t = 0, p is the pressure at any t and r, and r, is the well radius. Eq. 2 describes the pressure drawdown of a well where the formation around it is neither damaged nor improved. If a condition of permeability damage or improvement exists, the equation must be corrected for these effects. van Everdingen introduced an additional term:
where S is the total flowing time for n constant-rate flow periods, t - t, t - t, ...t - t with rates q, q, ...q .
If we use Eq. 4 in its present form to construct a straight-line pressure drawdown plot, k, r, phi, mu, c and S must be known. This is so because for every t a variable factor
is left at the right side of the equation. This has been a major difficulty in analyzing a variable-rate pressure draw- down.
JPT
P. 960ˆ
Effect of Composition and Temperature on Phase Behavior and Depletion Performance of Rich Gas-Condensate Systems
Authors: Jacoby R.H. , Koeller R.C. , Berry V.J. 
Published: December 2007

Abstract
The experimental phase behavior of several field gas-condensate systems, one field volatile oil system, and a series of synthetic systems having gas-oil ratios from 2,000 to 20,000 scf/bbl stock tank oil was measured. The data were used to calculate the depletion performance of the field systems at their respective reservoir temperatures and of the synthetic systems at various temperatures. The results of the performance calculations were used to prepare correlations of total stock tank oil and separator gas in-place, and the amount of each recovered by primary depletion. Data needed to use the correlations are initial gas-oil ratio, initial tank oil gravity, reservoir temperature and reservoir pressure.
The correlations presented should be useful for estimating recovery from reservoirs producing volatile oils or rich gas condensates having gas-oil ratios from about 2,000 to 30,000 scf/bbl of stock tank oil.

Introduction
Prediction of depletion performance for gas-condensate reservoirs usually requires extensive laboratory work or lengthy phase-behavior calculations. For many small gas-condensate bearing zones the expense of such work is often not justified. Furthermore, where large holdings are involved, it is useful to have estimates of future oil and gas production in advance of the results of a laboratory analysis, even if such work is ultimately planned. For these reasons, it would be of value to have a method for rapidly estimating the depletion performance of gas-condensate reservoirs from the type of field data usually available. Few data on the reservoir depletion performance are available for the purpose of developing correlations. The increasing number of gas-condensate discoveries and the advent of high-speed computers have stimulated the development of methods for predicting performance. Such calculated performance data have been shown to be reliable and are becoming accepted as a basis for reserve estimates and for engineering studies. It therefore seems satisfactory to use results of performance predictions themselves for the purpose of developing the desired correlations.