bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Verification of Dimensional Analysis for Hydraulic Fracturing
Authors: de Pater C. J. , Cleary M. P. , Quinn T. S. , Barr D. T. , Johnson D. E. , Weijers Leen 
Published: December 2007

Summary
We have derived model laws that relate experimental parameters of a physical model of hydraulic fracture propagation to the prototype parameters. Correct representation of elastic deformation, fluid friction, crack propagation, and fluid leakoff forms the basis of the scaling laws. For tests at in-situ stress, high fluid viscosity and low fracture toughness are required. Tests on cement blocks agreed with the scale laws based on elastic behavior.
Generalized Equations Relating Pressure of Individual Wells and Grids in Reservoir Modeling
Authors: Odeh A.S. , Al Hussainy R. 
Published: December 2007

In a recent paper, van Poollen et al. presented equations relating observed field pressures to those calculated by a numerical simulator. The equations are applicable to steady- and semi steady-state flow for wells draining circular areas and using an equivalent block radius. They implicitly assume that wells are located at the center of the drainage area. In this note we present equations that generalize the previous method and relate field to model pressures for various shapes of drainage area, well pressures for various shapes of drainage area, well location and grid configuration. Using the generalized equations of flow of Brons and Miller, and following a method of derivation similar to that reported by van Poollen et al., we obtain:For steady-state flow:
.................(1)
For semisteady-state flow:
...................(2)
For unsteady-state flow:
.....................(3)
where subscripts m and f refer to the model and field, respectively, and P D theta of Eq. 3 is the dimensionless initial pressure. For a circular system A pi r, and CA = 31.6 from Ref. 3. If we substitute these values in Eqs. 1 and 2, we obtain the results of van Poollen et al. as represented by their Eqs. 14a and 14b. In a manner analogous to that of van Poollen et al. the average reservoir pressure can be related to the dynamic pressure by using a dimensionless time based on the drainage area A rather than radius. Also, the relation between the average reservoir pressure and the simulator pressure in Eqs. 1 and 2 can be based on producing time as well as shut-in time, since it is possible to generate one method from the other as was shown by Ramey.

NOMENCLATURE
A = area in sq ftB = formation volume factor, res. bbl/STBCA = shape factorDD =c = compressibility, 1/psih = thickness, ftk = permeability, md PD, m, t = dimensionless model pressure, [141.2kb/ PD, m, t = dimensionless model pressure, [141.2kb/(q B)]P PD = dimensionless average reservoir pressure PD = dimensionless average reservoir pressure P = pressure, psiq = production rate, STB/Drw = well radius, ftt = flow time, days= porosity fraction= viscosity, cp
P. 277
Statfjord Field: Field and Reservoir Management Perspectives
Authors: Aadland Atle , Dyrnes Olav , Olsen S. R. , Drønen O. M. 
Published: December 2007

Summary
The Statfjord field, the largest North Sea oil field, has been on production since 1979. We think that production decline is imminent; however, oil production was close to a record for the field in 1991. This paper discusses the reservoir drainage strategy; the situation after 13 years of production; and short- and long-range perspectives for further field development, which includes a high well activity level to maintain the well production potential. Most of the wells drilled and scheduled are either horizontal wells or extended-reach wells, extending toward the flanks of the field. A large effort has been put into mapping remaining reserves by developing detailed reservoir simulation models. The production and well activities have been optimized on the basis of the results from the new models. Exploitation of business opportunities, such as processing of third-party crude from tie-in and subsea satellite fields and external gas storage, gives a new perspective for an oil field on production decline. In addition to these long-range plans, studies of such recovery methods as water-alternating-gas (WAG), surfactant, and polymer injection are continuing.
Natural Gas at Any Price
Authors: Grinnell Bates M. 
Published: December 2007

Comprehensive studies of past and future demand, interfuel competition, and potential supplies of energy are essential to conclusions on the demand for and the supply of natural gas in the U. S. Refined petroleum products, gas liquids, gas, electricity, coal, and products, gas liquids, gas, electricity, coal, and nuclear fuel each was examined in the light of its past and probable future interaction with other fuels competing for the same markets. Although there are hundreds of end uses, consumption may be classified readily under three headings: Residential-Commercial, which includes space heating and cooling, cooking, and lighting; Industrial, including a myriad of boiler fuel, heating, lighting, and power uses; and Transportation, fuel for motor vehicles, aircraft, railroads, and vessels. Where electricity competes in these markets, a further analysis was made to determine the particular fuel to be used in generating it. Use of energy from nuclear fusion or fission undoubtedly will expand rapidly, but it is considered that its share of the total energy market will not be appreciable before 1980, the end of the period covered in these forecasts.

Requirements for Gas
Forecasts of demand for gas, summarized in Table 1, include consumption in specific end-use markets, plus relatively small annual amounts to fill pipelines, for underground storage, for losses, and amounts unaccounted for. The total, then, is more accurately termed requirements. Fig: 1 shows consumption by type of customer. The amount of gas required annually in the U. S. is expected to increase from 20.4 Tcf in 1968 to 28.1 Tcf by 1975, and to 32.8 Tcf by 1980. The forecast rates total more than 325 Tcf during this 12-year period, or an average of 27 Tcf/year. Unfortunately, period, or an average of 27 Tcf/year. Unfortunately, additions to reserves reported by the American Gas Association (AGA) never have been this great, coming close only in 1956 when discoveries of new fields and pools, and extensions and revisions of prevailing reserves amounted to 24.7 Tcf. Current estimates by this group show that in 1968 only 13.7 Tcf was added to proved reserves, making that year one of the poorest on record. poorest on record.
JPT
P. 937
Reservoir Simulation Grids: Opportunities and Problems
Authors: Aziz Khalid 
Published: December 2007

Summary
Grid selection is one of the most difficult and time-consuming tasks in the simulation of geologically complex reservoirs.
A grid is imposed on a reservoir so that we can solve the nonlinear flow equations that predict the reservoir's response to changes at wells or other boundaries.
Therefore, I first discuss the role of grid geometry in the evaluation of each term in the flow equations. Then I describe several conventional and some new gridding techniques, as well as their advantages and disadvantages. Next I make recommendations based on my own experience and discussions with colleagues. My assessment is that grids should be as close to orthogonal as possible. Also, local grid refinement should be used with care; its inappropriate use can be counterproductive. Considerable progress has been made recently on the use of flexible grids, but efficient use of unstructured, locally orthogonal grids requires further research. Techniques that automatically align the grid with major reservoir features (e.g., faults) are being developed and are expected to simplify grid generation.

Introduction
A reservoir simulator predicts reservoir performance by solving flow equations on a discrete grid chosen by the simulation engineer to represent the reservoir. The grid normally is selected with one or more of the following considerations in mind.Reservoir geology and size and the data available for reservoir description.Type of fluid displacement or depletion process to be modeled.Past and anticipated field development (location and type of wells).Numerical accuracy desired.Available software options.Objectives of the simulation study.Competence of the simulation engineer or team.Available computer resources, time constraints, or project budget.
In the early days of reservoir simulation, the last consideration often determined the number of gridblocks, and the available software limited the choice of grid type, usually to block-centered Cartesian or cylindrical grid. Research in reservoir simulation and hardware developments, especially over the past 10 years, has greatly extended the gridding options available.
A New Representation of Wells in Numerical Reservoir Simulation
Authors: Ding Yu , Renard Gérard 
Published: December 2007

Summary
Numerical PI's are used to relate wellblock and wellbore pressures and the flow rate of a well in reservoir simulations by finite differences. This approach is based on an "equivalent wellblock radius," req,o. When nonuniform grids are used, req,o may create an error in wellbore pressure or oil rate. This paper presents a new well representation. The analytical solution for near-well pressure is included by modifying the transmissibilities between gridblocks so that flow around a well is described fully. The new method is applicable to nonuniform grids and nonisolated wells.
Determining a Proper Flood Pattern from a Three-Well Pilot in a Channel Sand
Authors: Lane A.B. 
Published: December 2007

Introduction
This is a review of the performance and development of a waterflood project of a channel sand reservoir; it describes how, by carefully observing the performance of a skeleton three-well injection pilot, the flood pattern can be changed to flood a narrow channel sand pattern can be changed to flood a narrow channel sand successfully. The area involved is the 717-acre Lewis Booch delta, which were deposited in the northwest-miles northwest of Allen in Ponototoc County, Okla. (see Figs. 1 and 2).

Geology
"Most channel sands are elongated, lenticular, and commonly erratic. They may be completely isolated lenses of sand, enclosed in shale, or they may be spread out sheetwise in the uppermost part and in this manner merge laterally with other neighboring channel sands. The latter is exemplified by the sands of the Booch delta, which were deposited in the northwestern shelf of the McAlster basin of Oklahoma in early Pennsylvanian time. This delta covers an area of more than 2,000 square miles."*
The Booch Sand unit reservoir is a part of the generalized delta-type distributary system of channel sands that diverge south-southeast into the McAlester basin. Structure is of little importance in channel sands of this type. The maximum dip in any direction for this sand bar is less than 2 degrees. Lateral shale-out is very abrupt. a 10-acre offset to a producing well with 15 to 20 ft of pay can be void of any sand.

Development
The discovery well shown as Unit Well 22 was completed in April, 1944. Of the 50 Booch sand wells completed, 37 were drilled between 1952 and 1958. Approximately 15 Booch dry holes were drilled to define the sand bar (see Fig. 3).
JPT
p. 195
Fracture Treatment Design To Overcome Severe Near-Wellbore Damage, Mereenie Field, Australia
Authors: Papinczak Anthony , Miller W. K. 
Published: December 2007

Summary
The Mereenie field, located about 185 miles west of Alice Springs in the Northern Territory of Australia, consists of a large gas cap surrounded by a narrow oil rim. The oil rim has been the predominant target, with the majority of oil produced from the Pacoota P3-120/130 sandstone reservoir. At approximately 4,500 to 5,000 ft, the reservoir exhibits permeabilities of 5 to 100 md. Pressure-transient analysis and production characteristics of early wells indicated increasingly high levels of near-wellbore damage, discovered later to be associated with fines migration and an extensive illite clay network. In an attempt to overcome this impairment, seven hydraulic fracturing treatments were performed between 1983 and 1987; however, postfracture results were disappointing. Extensive well testing, laboratory work, and reservoir/fracture modeling identified major problem areas associated with both the reservoir and the fracture treatments. During 1991–92, seven additional treatments were performed to achieve a tip screenout (TSO) to form a short, highly conductive flow path to bypass the damage. These resulted in a significant increase in production, an upgrade in the field's recoverable reserves, and additional development drilling.
Prediction of Effective Acid Penetration and Acid Volume for Matrix Acidizing Treatments in Naturally Fractured Carbonates
Authors: Xiong Hongjie 
Published: December 2007

Summary
This paper discusses a new method and a corresponding computer model developed to investigate matrix acidizing in naturally fractured carbonates. With this method, the effective acid penetration distance and acid volume needed for acid treatments in naturally fractured carbonates can be predicted. The new model simulates acid flowing in the natural fracture network and the acid/rock reaction. During the simulation, the model considers the influence of formation temperature, reaction heat, and common ion effect on acid penetration. A set of graphs showing the relationship between acid penetration and the acid volume needed in different formations was developed from numerical simulation results. From these plots, the acid volume that should be used to remove the formation damage can be determined easily when the formation temperature and the damage radius are known or can be estimated.
Application of a 3D Hydraulic-Fracturing Simulator for Design of Acid-Fracturing Treatments
Authors: Morgenthaler L. N. 
Published: December 2007

Summary
Field experience during 1989-90 shows that application of a 3D hydraulic-fracturing simulator increases success of acid-fracturing well treatments. Fracture extension can be limited to the oil-bearing pay, maximum lateral extension can be realized within the height constraint, and acid/rock contact time can be increased by a factor of between 3 and 30. Oil-production response can be improved over other stimulation designs while water-production response can be limited. These methods have been applied in mature waterfloods of the Permian Basin and Cedar Creek anticline.
Rate/Depth Tubing-Performance Curves
Authors: Winkler H. W. , Eads P. T. 
Published: December 2007

Summary
An accurate method for predicting the range of multiphase flow rates through different tubing sizes is an important production tool. Properly sized tubing will prolong the flowing life of a well and minimize the injection-gas requirements for gas-lift installations. A tubing string can be oversized or undersized. This paper presents a method for relating the four basic parameters for different tubing sizes: daily liquid production rate, tubing length or depth of gas injection, flowing production pressure at depth or surface operating injection-gas pressure, and the gas/liquid ratio (GLR). This information is displayed as rate/depth tubing-performance curves, which are based on the Shell Ros-Gray multiphase flow program. These curves allow proper tubing-size selection for a predicted range of daily production rates.
Differentiating Formation Compressibility and Water-Influx Effects in Overpressured Gas Reservoirs
Authors: Poston S. W. , Chen H. Y. , Akhtar M. J. 
Published: December 2007

Summary
The material-balance equation for overpressured gas reservoirs was rearranged so that the outcome variables are original gas in place (OGIP), formation compressibility, and water-influx values. A set of typical curves is presented to allow comparison of field cases and theoretical situations.
Controlling Asphaltene Deposition in Oil Wells
Authors: Thomas D. C. , Becker H. L. , Del Real Soria R. A. 
Published: December 2007

Summary
The deposition of asphaltenes in oil producing formations and production systems has caused problems for years. Selection of chemical control agents in the past has been limited to bulk dissolution studies on samples retrieved from production systems. Until recently, the accepted way to treat these problems has been through the use of xylene, toluene or other aromatic solvents. This method requires the use of large amounts of these solvents, as well as a high frequency of treatment. This paper describes the results of field testing and application of asphaltene control chemicals, and the use of laboratory tests to select asphaltene deposition removal and prevention chemicals.
Preliminary dispersant and solvency tests are conducted by an asphaltene dispersant test in hexane. Chemicals which provide promising results in dissolving and dispersing asphaltenes in the non-solvent medium of hexane are selected as candidates for field application, or for additional testing in a core flow deposition removal test.
The core flow test apparatus provides a method to introduce asphaltene fouling into a core and study its removal by the use of chemical agents. Using core samples and asphaltenes from the production resource under consideration allows the selection of the best removal chemical.
Borehole-Stability Model To Couple the Mechanics and Chemistry of Drilling-Fluid/Shale Interactions
Authors: Mody F.K. , Hale A.H. 
Published: December 2007

Summary
A borehole-stability model that uniquely couples the mechanical and chemical aspects of drilling-fluid/shale interactions was developed. The model allows the user to determine the optimum drilling parameters (e.g., mud weight and salt concentration) to alleviate borehole-stability-related problems with oil- or water-based drilling-fluid systems. Chemically induced stress alteration based on the thermodynamics of differences in water molar free energies of the drilling fluid and shale is combined with mechanically induced stress. These two potentials are coupled by use of the framework of poroelasticity theory to formulate the physiochemical basis of this borehole-stability model.

Introduction
Shales make up more than 75% of drilled formations and cause more than 90% of wellbore-instability problems. Drilling shale can result in a variety of problems, ranging from washout to complete hole collapse. More typical drilling problems in shales are bit balling, sloughing, or creep. The problems are severe and have been estimated conservatively to be a $500 million/yr problem for the industry. These engineering problems are closely connected with the "bulk properties" of the shale, such as strength and deformation as a function of depositional environment, porosity, water content, clay content, composition, and compaction rates. The drilling-fluid bulk properties (such as the chemical makeup and concentration of the continuous phase of the mud; the composition and type of an internal phase, if present; the type of additives associated with the continuous phase; and the maintenance of the system) also are of utmost engineering importance. Other factors - in-situ stresses, pore pressure, temperature, time in open hole, depth and length of openhole interval, surrounding geological environment (salt stringers, dome, etc.) - also directly affect drilling and completion operations and must be integrated into any model and new mud system development. These variables are interconnected and influence the overall behavior of shales during drilling.
Development of Roller Cone Bits With Active PDC Shear Cutting Elements Improves Gage-Holding Ability
Authors: Scott D. E. 
Published: December 2007

SummaryA patented roller-cone bit that combines the conventional drilling mechanics of a roller-cone bit with the shearing action of polycrystalline diamond (PDC) cutting elements to trim gage has been developed.1 This paper reviews design features of the bits, laboratory tests demonstrating the shearing action, and presents case studies of bits with the shear-cutting PDC-gage elements.
Determination of Acoustic Velocities for Natural Gas
Authors: Thomas L.K. , Hankinson R.W. , Phillips K.A. 
Published: December 2007

Acoustic velocities for natural gas are calculated as a function of temperature, pressure, and gas gravity. The method is based on a generalized equation of state for natural gas that may also be used to calculate a number of thermodynamic properties such as specific internal energy and isentropic expansion.

Introduction
Some uses of acoustic velocities for natural gas are to determine liquid levels in gas wells and to locate hydrate freezes, lost ‘pigs’, or other obstructions in gas pipelines. These distances can be calculated from well defined acoustic records (Fig. 1a) by associating the number of pipe sections with their corresponding lengths. If, however, an uninterpretable acoustic record (Fig. 1b) is obtained, or if the lengths of the pipe sections of a given flow string are unknown, pipe sections of a given flow string are unknown, distance between the shot deflection and the reflecting surface can be obtained by integrating the relationship between velocity distance and time
(1)
The utility of this technique depends upon one's ability to calculate acoustic velocities and to measure system variables such as gas gravity or composition, temperature, temperature gradient and pressure. In the past, acoustic velocities have been calculated from an approximate relationship involving atmospheric heat capacity ratios rather than ratios that are a function of pressure. As has been pointed out, this approximate relationship provides a good working equation for calculating acoustic velocities at low pressure ranges but should not be used at higher pressures. The purpose of this work is to present a method for rigorously calculating acoustic velocities for natural gas over a broad range of temperatures, pressures and gas gravities.

Calculation of Acoustic Velocity
Starting from the equation for the speed of sound in a compressible fluid
(2)
it is possible to derive the following equation for a real gas (see Appendix).
(3)
Eq. 3 can also be expressed in terms of the isentropic expansion coefficient, n, since
(4)
Making this substitution yields
(5)
To compute the velocity of sound in a real gas from either Eq. 3 or Eq. 5, it is necessary to know the PVT behavior of the gas and the variation of the beat capacity ratio with temperature and pressure. To accomplish this, an equation of state for natural gas was developed.
JPT
P. 889