bluuebunny/crossref_metadata_2025_split huggingface dataset:
Nonstatic Reservoirs: The Natural State of the Geothermal Reservoir
Authors: Donaldson Ian G. , Grant Malcolm A. , Bixley Paul F. 
Published: December 2007

Summary
Above-hydrostatic-reservoir-pressure gradients are found in many geothermal fields before exploitation. In higher-temperature fields, steam and water also coexist in the upper levels. These factors indicate natural upflow in these reservoirs-i.e. the dynamic state of the fluid. Analysis of flow and pressure data under these dynamic conditions can lead to relevant large-scale reservoir information.

Introduction
It has been suggested that the existence of a natural surface discharge from an oil reservoir must imply a nonstatic pressure distribution down through the fluid in that reservoir. To date, however, no such nonstatic pressure distribution has been identified in any oil reservoir. In contrast, most liquid-dominated geothermal reservoirs -- i.e., both hot water and two-phase -- have significant natural throughflow, and hence the nonstatic pressure distribution has been sought with interest. Until recently, the data supporting the enhanced pressure gradient have been sparse because wells commonly have been discharged, and the reservoir disturbed, before a suitable spectrum of data has been obtained. The mere presence of a significant length of open hole, as is commonly the case in geothermal exploitation, also distorts the pressure pattern. Study and reinterpretation of early (1950–56) Wairakei data have led to a much better picture of the natural pressure/depth profile for that field. In this paper we use this new information with other information about the reservoir in its natural state to determine an average (field) vertical permeability and the depth to which boiling may have occurred. Because the horizontal permeability of the flow strata is usually at least an order of magnitude higher than the mean vertical component (which includes the effects of any lower-permeability cross strata), it is horizontal permeability that controls the pressure transients of pump and injection tests. The vertical component is, however, important once water begins to drain down to the well feed level as the field pressure declines, and it has a strong influence over long-term behavior. Although we now can distinguish between liquid/water and steam/water (two-phase) conditions around a well, we are not yet able to pick up the phase-change boundary unless it is close. Even in long-term field tests, the horizontal/vertical permeability contrast may result in the pressure transients sensing the side boundaries before they show any effect of this horizontal one. Since extraction and injection from and into a two-phase section of a reservoir result in different effects from extraction and injection from and into a liquid-charged section, a pre knowledge of the depth of the two-phase zone could result in some savings in both drilling effort and costs.

The Geothermal Reservoir
It first was suggested at the beginning of the century that hot spring water might be meteoric water that entered the ground some distance away and circulated deeply enough to pick up the required heat.
JPT
P. 189^
Nonstatic Pressure History Analyses for Gas Reservoirs
Authors: Rodgers J. S. , Boykin R. S. , Coble L. E. 
Published: December 2007

Abstract
A method has been developed for using nonstatic pressure measurements directly in gas reservoir material balances composed of various energy mechanisms. Applying this method leads to simultaneous determinations of the reservoir p¯ history, gas in place, and other parameters relevant to water influx and effective compressibility.
Well-known methods1–4 of determining average static pressure, p¯, have at least two shortcomings: (1) an estimation of reservoir shape and (2) an often-neglected implicit relationship between p¯ and the viscosity-compressibility product. Errors resulting from these deficiencies are minimized by the proposed method through a simple coupling of the well-known pseudosteady-state flow and material-balance equations. The solution of this coupling is obtained through nonlinear regression, and it allows simultaneous evaluations of gas initially in place, static pressure history, and several other reservoir parameters. These parameters can include the initial reservoir pressure, a stabilized gas-deliverability constant, the effective compressibility, aquifer diffusivity, and aquifer volume plus water-influx constants. The results of applying the method to six published cases are presented to illustrate the utility of the method.
Miscible Drive Field Applications in the Seminole City Pool
Authors: Walker R.E. , Engel J.D. , Jenks L.H. 
Published: December 2007

Introduction
This paper discusses a field test of a gas-driven liquid propane process being conducted by The Carter Oil Co. and supplements previously published information on the project. It presents a brief history of the still incomplete project and includes an evaluation of the method, based on present knowledge.
The process consists of injecting a predetermined volume of propane into a reservoir at a pressure above the vapor pressure of propane and driving the propane and oil to the production wells by means of an immiscible-phase gas drive. The test was carried out in the C–2 Block leases (Seminole, Okla.) in the Booch sand. The sand is about 3,600 ft deep, averages 30-md permeability and 18 per cent porosity, and ranges in thickness in the test area from 12 to 30 ft. Connate water is estimated at 35 per cent. The field was depleted by primary means for about 20 years and at the time the test started was producing 15 B/D at a gas-oil ratio of 7,500 scf/bbl.

History of Test
The reservoir was repressured with gas and 143,000 bbl of liquid propane were injected into two gas injection wells after which a gas drive of the propane was started. Since then total oil production has amounted to 142,000 bbl from five production wells. Approximately 12,000 bbl of this production is attributed to water injection which was used to create a barrier to hydrocarbon migration on the north end of the test area.
Breakthrough of injected propane into the production wells occurred almost immediately after the start of the test, contrary to laboratory experiments with linear, homogeneous models. About 73,000 bbl of propane have been produced for an over-all oil-propane ratio of 1.95. Approximately 600,000 Mcf of gas have been injected.
Because the field test is not only unconfined but also consists of incomplete well patterns, estimates have been made that only about 76,000 bbl of propane went into the test pattern and that approximately 40,000 bbl more oil would have been produced had the test been confined. This would yield a "recovery" of 2.2 bbl of oil per bbl of propane injected.
A New Device for Field Recovery of Barite: II. Scale-Up and Design
Authors: Burdyn R.F. , Hawk D.E. , Patchen F.D. 
Published: December 2007

Abstract
Earlier work on a mud separator for barite recovery is extended to the design and construction of a rugged field unit. Problems associated with scale-up for field use include the use of dilution water and its effect on capacity, power requirements and pressures developed. Equations for these quantities are derived and applied in maximizing the beneficial effects of dilution and minimizing the power required. Tests on the full-size rotor show that its performance can be predicted by theory. The completed unit is compact and lighter than current decanting types. Its capacity is from 10 to 22 gal/min with corresponding barite recovery efficiencies of 92 to 86 per cent.
Introduction
In an earlier publication a new type of centrifugal device was described for solid-liquid separations. In that paper an operating equation was derived, and its validity demonstrated in laboratory scale experimentation. Some of the features apparent in this new device seem particularly well suited to the conservation of barite in field drilling-mud systems, hence the development was extended to the design and construction of a field unit. In the present paper the design problems associated with scale-up are considered. A full-scale, rugged, self-contained field unit is described, and test results discussed which verify that the performance of the large field unit can be described by a simple operating equation.
PRINCIPLE OF OPERATION OF SEPARATOR
In principle, the new device is simply a perforated cylinder rotating within a body of fluid which is contained within a stationary case, as in Fig. 1. The frictional drag generated by the rotating cylinder causes part of the fluid to rotate. At the surface of the cylinder, assuming no slip occurs, the angular velocity of fluid and of the cylinder are identical. if there are suspended particles present of greater density than the fluid, the centrifugal force acting on these particles causes them to move radially away from the cylinder at some velocity, vp. Where the Stokes settling equation holds, this velocity may be expressed as:
....................(1)
If the case is provided with openings at both ends, a suspension can be pumped in at one end at a fixed rate. Part of the suspension can then be removed at a fixed rate at the other end of the case as underflow, and the remainder forced through the perforations and hollow shaft of the rotor to appear as effluent, also at a fixed rate. the radial component of the flow velocity of this stream as it reaches the rotor surface, is simply effluent flow rate divided by cylindrical surface area:
....................(2)
Because vp is a function of particle size, for some particular particle size, the velocities vp and vr will be equal in magnitude. This is defined as the critical particle size and represents the size above which all particles appear in the underflow and below which all particles appear in the effluent.
SPEJ
P. 100ˆ
Exploration, Development, and Reservoir Engineering Studies for the Tapis Field Offshore Peninsular Malaysia
Authors: Thu Goh Sing , Heacock D.W. , Loveless D.E. 
Published: December 2007

Summary
This paper presents the rationale for oil development in the sandstone reservoirs of the Tapis field offshore Peninsular Malaysia. Pressure maintenance plans, well Peninsular Malaysia. Pressure maintenance plans, well spacing, and completion plans have been modified in response to data from exploratory and development drilling. Reservoir simulation has been a valuable tool in optimizing field development.

Introduction
The Tapis field is located in the South China Sea, 130 miles (209 km) off the east coast of peninsular Malaysia in 210 ft (64 m) of water (Fig. 1). Esso Production Malaysia Inc. (EPMI) has explored and developed the field as a contractor to Petroleum Natl. Berhad (PETRONAS), the Malaysian national oil company. Development plans for the field have been modified several times on the basis of data obtained from ongoing exploratory and development drilling. The producing reservoirs at Tapis are Miocene Age Group J (Tapis formation 1) sandstones that contain rim-type oil accumulations with associated gas caps. The three primary reservoirs, J-20, J-25, and J-30, are shoreface/barrier bar deposits separated by shale sequences. Both faulting and stratigraphic variations cause localized discontinuities across the field. Development wells from 4 platforms and 10 exploration wells have delineated most of the field. Reinjection of casinghead gas and waterflooding are being used to increase ultimate oil recovery. Two fieldwide reservoir-simulation studies have helped to optimize field development. These modeling efforts enabled selection of optimal waterflood pattern and determination of water-injection requirements, relative merits of commingled production vs. selective completions, benefits of gas injection, and recovery efficiency for the field. Detailed reservoir description work allowed assessment of reservoir continuity and assisted in selection of workovers needed to implement the waterflood.

Exploration

Exploration History
The Tapis field was discovered in 1969 with the drilling of Tapis Well 1 near the crest of the structure (Figs. 2 and 3). The well, Esso's first in the Malay basin, found gas in the sandstones of Groups J and K. In 1974, Tapis Well 2, drilled downdip to Tapis Well 1, discovered oil in the Group J sandstones. It encountered a gas/oil contact (GOC) in J-20, establishing a hydrocarbon column of 740 ft (226 m) and a proved oil column of 170 ft (52 m). Pressure and fluid data indicated that the lower Group J sandstones (J-20, J-25, and J-30) had common fluid contacts and were in a separate fluid/pressure system from the upper Group J sandstones (J-10 and J-15). In 1975, Tapis Wells 3 and 4 were drilled to delineate the Group J oil columns on the flank of the structure. Both wells encountered oil in the Group J sandstones and the lower Group J proved-oil column was extended to 1,516 ft (462 m).
JPT
P. 1051
Simulation of Two-Dimensional Waterflooding By Using Mixed Finite Elements
Authors: Chavent G. , Cohen G. , Jaffre J. , Dupuy M. , Ribera I. 
Published: December 2007

Abstract
A new method to simulate incompressible diphasic flow in two dimensions (2D) is presented. Its distinctive features include (1) a reformulation of the basic equation using the premise of a global pressure and (2) approximation of convective terms by an upwind scheme for discontinuous finite elements.
A mixed finite-element method approximates both the scalar functions (pressure and saturation) and the vector functions (total velocity field and capillary diffusion vector). The pressure (resp. the saturation) is approximated by a discontinuous function piecewise constant (resp. linear) on the elements of the mesh. A basis of divergence-free vectors is used in the pressure equation, which accelerates computation. Several test examples, which include gravity and capillary effects, are presented.
Numerical Simulation of CO2 Flood Performance
Authors: Chase Curtis A. , Todd Michael R. 
Published: December 2007

AbstractA multicomponent, three-phase, three-dimensional (3D) reservoir simulator has been developed for predicting miscible flood performance with particular emphasis on CO2 flooding. Several features, not all normally found represented in either a black-oil or compositional simulator, are represented in the simulator described here. These features include (1) heavy-end dropout and concomitant reduction in phase mobility, (2) water blocking of oil from an invading solvent, (3) viscous instability (fingering) at the CO2 displacement front, (4) miscible/immiscible transition as a function of pressure and composition, and (5) loss of CO2 to the aqueous phase.The solution scheme employs an implicit in pressure, explicit in saturation and composition time integration scheme (IMPES). This scheme allows for ready use of a second-order correct spatial discretization. We have found that for field applications, a numerical grid fine enough to represent waterflood performance accurately is usually sufficient for representing CO2-miscible-type processes as well. The program automatically employs a stabilized Runge-Kutta time discretization to alleviate the usual stability limitations imposed by the IMPES procedure. Up to 49 times the usual stable timestep size can be employed for seven times as much computing work. Work required to simulate a given time period when stability is limiting was improved overall by a factor of seven. To date, we have not encountered a pattern flood displacement simulation where the increased timestep size provided by the Runge-Kutta scheme has not been adequate to maintain stability for timesteps chosen so as to limit truncation error.The CO2 flood simulator described has been in application for 4 years. The simulator has been used for design of CO2 EOR projects and interpretation of CO2 injectivity tests in several low-temperature west Texas San Andres dolomite reservoirs as well as high-temperature sandstone reservoirs. In addition to CO2 applications, the simulator has been used for the design of liquefied petroleum gas/dry gas flooding processes and for examining the effect of injection gas composition on oil recovery performance for immiscible gas drives.
General Purpose Compositional Model
Authors: Ács Gábor , Doleschall Sándor , Farkas Éva 
Published: December 2007

Abstract
A direct sequential method has been developed to simulate isothermal compositional systems. The solution technique is the same as that of the implicit pressure, explicit saturation (IMPES) method: one pressure is treated implicitly and (instead of the phase saturation) the component masses/moles are treated explicitly. A "volume balance" equation is used to obtain the pressure equation. A weighted sum of the conservation equations is used to eliminate the nonlinear saturation/concentration terms from the accumulation term of the pressure equation. The partial mass/mole volumes are used as "constants" to weight the mass/mole conservation equations.
The method handles uniformly a range of cases from the simplified compositional (i.e., black-oil) models to the most complicated multiphase compositional models of incompressible and compressible fluid systems. The numerical solution is based on the integrated finite-difference method that allows one- (ID), two- (2D), and three-dimensional (3D) grids of regular or irregular volume elements to be handled with the same ease. The mathematical model makes it possible to develop modular versatile computer realizations; thus the model is highly suitable as a basis for general-purpose models.
A Generalized Compositional Approach for Reservoir Simulation
Authors: Young Larry C. , Stephenson Robert E. 
Published: December 2007

Abstract
A procedure for solving compositional model equations is described. The procedure is based on the Newton-Raphson iteration method. The equations and unknowns in the algorithm are ordered in such a way that different fluid property correlations can be accommodated readily. Three different correlations have been implemented with the method. These include simplified correlations as well as a Redlich-Kwong equation of state (EOS). The example problems considered are (1) a conventional waterflood problem, (2) displacement of oil by CO2, and (3) the displacement of a gas condensate by nitrogen. These examples illustrate the utility of the different fluid-property correlations. The computing times reported are at least as low as for other methods that are specialized for a narrower class of problems.
Simplified Water Influx-Pressure Calculations Above the Bubble Point
Authors: Stewart F.M. 
Published: December 2007

Introduction
A paper by Hurst and van Everdingen in 1949 led to the practical solution of many nonsteady-state flow problems. Subsequently, applications of this material have been discussed by several authors. The purpose of this note is to outline a simplified direct procedure for water-influx pressure predictions for pressures above the bubble point. The proposed procedure is unique in that after the "time-conversion factor" and the "influx constant" are obtained, predictions are made without trial and error. The elimination of trial and error is made possible by expressing certain PVT characteristics as explicit functions of pressure. The procedure is applicable to fields producing at pressures above the bubble point and under radial water drive from an infinite aquifer. In the usual applications it is required to predict (1) withdrawals given future pressure history or (2) reservoir pressure, given future withdrawals or production.
The theory, assumptions and conditions under which the nonsteady-state solutions hold are covered in the references and are not repeated. The simplified direct procedure outlined here has been developed from published solutions for the so-called "pressure case". A similar direct procedure for the same special conditions has been developed for the "rate case"; however, in this instance the procedure is lengthy and offers no advantage over the trial-and-error so1ution. Consequently, this paper covers only the procedure based on the pressure case.

Discussion
Under the pressure case prediction of withdrawals from a waterdrive field, given the future pressure history, involves the use of a nonsteady-state water-influx term together with the material balance equation. The solution of a particular problem requires the following steps:division of past pressure and production data into equal time intervals;computation of cumulative water influx vs pressure drop for each time interval of past history using the material balance equation;determination of the best values for the "time-conversion factor" and the "influx constant" by equating the nonsteady-state influx term with the influx computed in Step 2 (this requires a trial-and-error procedure);prediction of influx for a given pressure drop using the influx term and the computed factors from Step 3; andcalculation of fluids produced using the predicted influx in the material balance equation.
A forecast of the water-oil ratio or water production rate is required to complete the calculation.
Influence of Block Size on the Transition Curve for a Drawdown Test in a Naturally Fractured Reservoir
Authors: Braester Carol 
Published: December 2007

Abstract
Block size is considered one of the main parameters of a fractured rock reservoir. In one-phase flow, it controls the transition from the early stages of production to asymptotic behavior, and in two-phase wettingnonwetting displacement it controls the rate of production by imbibition. In nonwetting-wetting displacement it controls the pressure difference between the extremities of the block, which, provided that the threshold pressure is exceeded, permits displacement of the nonwetting fluid from the blocks into the fractures.
Warren and Root1 relate the size of the block to the transient pressure variation from the first to the second straight line of the drawdown/buildup test.
The numerical solutions presented in this paper for reservoirs with ordered fractures and blocks show that the drawdown pressures are not sensitive enough to the variation in sizes of the block. This means that a drawdown/buildup test cannot yield a solution unique for the size of the block.
In most practical cases of the one-phase flow, transition to homogeneous behavior is reached in a relatively short time and not noticed, except in a narrow region around the well. Therefore, in terms of reservoir performance, only the homogeneous behavior is of practical interest and the size of the block is not a relevant parameter of the one-phase flow.
It is believed that in two-phase flow the displacing fluid circumvents the blocks in groups rather than singly. If so, the individual size of the block is not a relevant parameter, even in two-phase flow.
On the Relationship Between Formation Resistivity Factor and Porosity
Authors: Pérez-Rosales Candelario 
Published: December 2007

Abstract
A theory on the relationship between formation resistivity factor and porosity is presented. This theory considers that, from the standpoint of the flow of electric current within a porous medium saturated with a conducting fluid, the pore space can be divided into flowing and stagnant regions. This assumption leads to a general expression, and formulas currently used in practice are special cases of this expression. The validity of the new expression is established by the use of data corresponding to sandstones and packings and suspensions of particles. For the case of natural rocks, the theory confirms Archie's equation and gives an interpretation of the physical significance of the so-called cementation exponent.