bluuebunny/crossref_metadata_2025_split huggingface dataset:
Some Considerations in the Pricing of Natural Gas
Authors: Hill Kenneth H. 
Published: December 2007

Introduction
In his paper entitled "A Management Look at Natural Gas", W.B. Golush discusses the natural gas industry thoroughly and capably, pointing to the various problems which confront it. The purpose of this article is to offer some additional thoughts, concerning the natural gas producing industry, which relate to the Golush paper.
It should not be construed from anything said herein that wellhead regulation of producer's prices by the FPC is favored. Quite the contrary, for we agree with the author that "the prices paid for natural gas at the wellhead should be set by normal supply-demand relationships".

Transport Costs Restrict Gas Markets
The first point to be made relates to prices paid at the wellhead for natural gas as related to oil and other forms of energy, in particular, on a Btu basis. It is true that natural gas is sold at an average price at the wellhead of about 12/Mcf, or around one-fifth of the equivalent Btu price for crude oil at the wellhead. But, new contracts are now negotiated at 16 to 24/Mcf in Louisiana and Texas. However, the low average price for natural gas relative to its energy value is due mainly to transportation costs to distant markets which, on an energy basis, are roughly five-fold greater than for petroleum. This very great differential in transportation costs seems to be ignored by many recent commentators on the natural gas industry, who deplore the apparent fact that the producer is giving away his gas and that revenues from gas are not carrying their share of exploration. This, at best, is only partially true. For, if natural gas were sold at the wellhead at 55/Mcf, its approximate crude-oil Btu equivalent, it would lose nearly all its market because it would be used only for very local and special uses.
As proof of this, even in California the price of natural gas in the field is at most 35/Mcf, or two-thirds of its estimated Btu basis, and is tied to fuel oil-not crude. Yet these reserves are adjacent to tremendous markets supplied principally from West Texas, some 1,200 miles distant, where the wellhead price averages only 12 to 14/Mcf. New gas contracts in Southern Louisiana, now being made at 20 to 24/Mcf, are probably approaching a level which renders the gas barely competitive with other fuels in New York. So, if prices in the field were to approach an energy basis, the industry would lose such a large proportion of its demand that it would suffer a reduction rather than a gain in revenues.
Peripheral and Line-Drive Water-Injection Projects
Authors: Stephens Fred 
Published: December 2007

Introduction
The question of the pattern to be employed is one of the most important considerations necessary to the proper planning of a water-injection project. Before the decision can be made as to what type pattern should be employed, a thorough study of the reservoir parameters must be made. In some reservoirs, it is impractical to employ the five-spot pattern; in others, peripheral or line-drive patterns cannot be used.
Table 1 lists the reservoir data on four waterflooding projects employed in peripheral and the line-drive waterflooding patterns. The results obtained from these projects to date indicate that high sweep efficiencies in water-injection projects can be obtained with a minimum of hazard.

The Sojourner Peripheral Flood
The Sojourner sand unit in Haskell County, Tex., is a waterflooding project which employs the complete peripheral waterflooding pattern (Fig. 1). This waterflooding unit has 57 wells drilled on irregular 40-acre spacing and is completed in the Strawn sand penetrated at approximately 5,100 ft. The average porosity and permeability for this sand are 14 per cent and 12 md, respectively, as determined from 35 complete core analyses. The peripheral pattern was recommended for this project primarily because of the irregular drilling pattern employed.
Because of the depth and the waterflood reserves anticipated, it was impractical to employ in-fill drilling to design a workable five-spot or conventional water-injection pattern. Because of the low natural permeability, however, it was questionable if sufficient water could be injected into the sand to obtain the desired injection rate for an economical floodout time of the reservoir. From calculations using air permeability as a criterion, it originally was estimated that the maximum injection rate per well would be approximately 300 B/D at 1,800-lb surface injection pressure. A pilot water-injection program was initiated in Feb., 1956, into three water-input wells. Results of this pilot indicated that 600 to 900 B/D injection rates were permissable with 600-lb surface injection pressure.
New Sand-Control Filter for Thermal Recovery Wells
Authors: Toma Peter , Livesey Declan , Heidrick Theodore 
Published: December 2007

SummaryA device was designed to solve a severe case of sand inflow into horizontal wells at the Athabasca Tar Sands pilot plant in Fort McMurray, Alta. The sand problem at this pilot resulted from a combination of three conditions: a fine-grained, cohesionless sand; the cyclic injection of steam; and the production of steam, water, and high-viscosity bitumen. A new type of filter, designed to overcome this problem, has application to the control of solids in wells drilled in a variety of formations producing liquids or gas. It was first designed and tested in the laboratory with a physical simulator; then it was fabricated and tested in vertical wells at the Athabasca pilot plant.
Oilfield Interference in Aquifers of Non-Uniform Properties
Authors: Mortada M. 
Published: December 2007

Introduction
Nonsteady-state flow of slightly compressible liquids in porous media of non-uniform properties has been the subject of a number of recent studies. Most of these studies considered one-dimensional flow in systems with cylindrical geometry and with the properties of the porous medium varying with radial distance only.
A. Houpeurt studied the problem in its general form by examining the solutions of the differential equation,
(1)
In Eq. 1, the permeability and the porosity are arbitrary functions of radial distance. Houpeurt concluded that, except for special forms of the functions the problem is not well suited for mathematical treatment, but lends itself to high-speed digital computation.
Carslaw and Jaeger discussed the solution of Eq. 1 for the case in which the permeability varies as a power of the radial distance. P. Albert analytically studied the pseudo steady-state solutions in systems of finite radial extent and non-uniform properties. He also obtained some numerical solutions for non steady-state flow using a high-speed computer. William Hurst examined the interference pressure drop due to a point sink located in an infinite system consisting of two permeability regions in series. In this case, the permeability changed at a radial distance from the point sink.

Interference Between Oil Fields in a Non-Uniform Aquifer
The interference pressure drop for oil fields located in an extensive aquifer of uniform properties is discussed in a number of places in the literature. This work considers the interference pressure drop for oil fields located in a non-uniform extensive aquifer comprising two regions of different properties as shown in Fig. 1.
Solubility and Extraction in Multiple-Contact Miscible Displacements: Comparison of N2 and CO2 Flow Visualization Experiments
Authors: Bahralolom Ibrahim M. , Orr Franklin M. 
Published: December 2007

Summary
Results of secondary and tertiary displacements of Maljamar crude oil by N2 and CO2 are compared to examine the effects of solubility and extraction on local displacement efficiency. The flow visualization experiments were performed in pore networks etched in glass plates. In those experiments, the much higher solubility of CO2 in the oil caused only marginal improvement in displacement efficiency over that observed for N2, which was much less soluble. At pressures high enough for CO2 to extract hydrocarbons efficiently, however, displacements were much more efficient.
Secondary and tertiary displacements in a more heterogeneous glass model are also compared. In a secondary displacement with high solubility but low extraction, adverse capillary and viscous effects limited the area swept to preferential flow paths. High CO2 solubility did not appear to have significant effects. When water was present in tertiary displacements with efficient extraction and high solubility, combined effects of viscous instability, capillary forces, and heterogeneity sharply reduced sweep efficiency below that observed in secondary displacements in the same model.
A Multiple-Porosity Method for Simulation of Naturally Fractured Petroleum Reservoirs
Authors: Wu Yu-Shu , Pruess Karsten 
Published: December 2007

Summary
This paper describes the application of the method of "Multiple Interacting Continua" (MINC) to the simulation of oil recovery in naturally fractured reservoirs. A generalization of the double-porosity technique, the MINC method permits a fully transient description of interporosity flow by numerical methods. We present examples to demonstrate the utility of the MINC method for modeling oil-recovery mechanisms by water imbibition and field applications for five-spot waterflooding and water coning problems in fractured reservoirs. All results show that the MINC method provides accurate predictions of the behavior of naturally fractured reservoirs, while requiring only a modest increase in computation work compared with the double-porosity method. The double-porosity method may result in large errors for matrix blocks of low permeability or large size.
Interference Testing of a Two-Layer Commingled Reservoir
Authors: Onur Mustafa , C. Reynolds Albert 
Published: December 2007

Summary
A two-well system in an infinite-acting, commingled, two-layer reservoir is considered. One well, the active well, is produced at a constant total rate, and the second well, the observation well, is shut in at all times. An analytical solution in Laplace space is presented, and the parametric groups that uniquely determine the pressure and rate solutions are identified. Results regarding crossflow through the observation well are presented. Conditions under which the line-source solution can be used to analyze observation-well pressure data are delineated. Results generally show that the analysis of such pressure data is tenuous unless individual layer flow rates are measured at the active well and the layers are isolated at the observation well, or unless layer flow rates are measured at both wells.
Use of an Ion-Selective Electrode for Determination of Free Chloride Ions in Water-Based Drilling Fluids
Authors: Kaland F. , Hakli U. , Ruoff P. 
Published: December 2007

Summary
The use of an ion-selective electrode (ISE) for the determination of chloride ions in water-based drilling fluids has several advantages: the measurement is simple, fast, easy to perform, and inexpensive. An ISE can be used for continuous chloride ion logging and allows analysis of colored samples where the traditional API-recommended method is difficult to use.
Pressure Drawdown and Buildup in the Presence of Radial Discontinuities
Authors: Bixel H.C. , Van Poollen H.K. 
Published: December 2007

Abstract
A treatment is given of the transient pressure behavior of a well located at the center of a circular region surrounded by a radial discontinuity. On either side of the discontinuity, the values of permeability, viscosity, compressibility and porosity are uniform but may be different from those on the other side of the discontinuity. The results are obtained by solving a pair of finite difference equations. The numerical solution to these equations is obtained using a digital computer. The results are compared with previously published, approximated analytical solutions to the same problem.
Solutions, presented graphically, show pressure decline for constant rate fluid production. The range of variables studied include dimensionless time from 0.001 to 100 and storage capacity ratio from 0.001 to 1,000. The well behaves as if it were in an infinite reservoir for dimensionless times less than 0.25. Reservoir properties near the well can be estimated in the usual manner.
An overlay technique is used to match an experimental curve with one of the theoretical curves. It is possible to estimate the distance to a discontinuity by substituting the actual time t and the corresponding dimensionless time tD at which a match occurs into the equation a=(0.000264 tkI/tD fI µIcI)1/2, where kI/fIµIcI is the diffusivity near the well, and may be estimated from data taken at early time. Several buildup curves are computed. These curves show that for early shut-in times, correct values for transmissibility are obtained from conventional analysis. However, erroneous values of static reservoir pressure are obtained unless data at large shut-in times are taken.

INTRODUCTION
A mathematical treatment of the transient pressure response of a well located at the center of a region bounded by a circular discontinuity is given. Within a region (Fig. 20) the properties of both the rock and the fluid are considered to be constant on either side of the discontinuity. While these properties are considered constant, they may be different on opposite sides of the discontinuity. A discontinuity of this type could be a fluid-fluid contact or a sudden change in rock characteristics such as thickness, porosity or permeability.
Analytical solutions to this problem are available.1-3 However, they are so involved that they are of little practical use. An approximate solution1 is available but the range of times over which it is valid has not been specified. A numerical solution to a pair of finite difference equations is used to obtain the solution given in this paper.

PREVIOUS WORK
One of the first solutions to the problem was published by William Hurst.1 Hurst considered unsteady-state flow of fluids through two sands in series with different mobilities in each sand. He used Laplace transforms to obtain a solution for a single well located at the center of the circle enclosing the first of the two sands. In this case, the solution for the pressure change in Region I (Fig. 20) is2Equation 1
for r a.
Use of Long-Period Seismometers To Determine Induced Fracture Geometry
Authors: Mauk Frederick J. , Mahrer K. D. 
Published: December 2007

Summary
A novel technique to determine the geometry of induced hydraulic fractures has been tried at five shallow (305- to 884-m [1,000- to 2,900-ft] depth) stimulation tests since 1983. Long-period (LP) seismometers with peak ground-motion sensitivities in the period range between 10 and 100 seconds were deployed on the surface at distances 115 to 732 m [377 to 2,402 ft] from the treatment wellbores. Identifiable transient waveforms with reproducible site-specific ground-motion polarizations were recorded during four of the five stimulations. Temporal coincidence of these LP waveforms with treatment-related events [e.g., bottomhole pressure (BHP) passing through the formation closure stress] suggested that the signals may contain useful information about the induced fracture. Unsuccessful attempts to simulate the polarization directions as stationary tilts and/or horizontal displacements from the overall expansion of the fracture demonstrated that the source of the signals was not static or quasistatic. An alternative kinematic source model was examined to simulate the waveforms as transient pressure/fracture interactions. Although many observed signal characteristics were consistent with this latter model, considerable doubt regarding the origin of these signals and their usefulness to determine geometry of induced fractures remains. Commercial application of this monitoring technique does not annear to be economicallv feasible.
Analysis of Coalbed Methane Stimulations in the Warrior Basin, Alabama
Authors: Layne Abbie W. , Byrer Charles W. 
Published: December 2007

Summary
An objective of the U.S. DOE's in-house coalbed methane R&D effort has been to improve coalbed hydraulic fracturing techniques by improving the understanding of stimulation treatments. Current efforts focus on examining data from coal mine excavations to observe stimulation results, conducting Nolte-Smith analyses to characterize fracture behavior, and exercising DOE/METC's stimulation modeling codes. Test Wells DHM-6 and DHM-7, two research degasification wells located in the Oak Grove field, AL, were analyzed in this project. METC's hydraulic fracture models predicted Well DHM-6 coalbed wing lengths 3 to 5% greater than the excavated wing length. This modeling was based on observation of fluid penetration into the shale roof rock and on guidelines derived from the Nolte-Smith method, which indicated vertical propagation into the bounding strata. Results to date indicate that the Nolte-Smith method may provide adequate interpretation of coalbed fracture behavior when the effects of variable injection rates, natural fracture fluid interaction, and the interface effects of coalbed and bounding formations are considered. Further evaluation of hydraulic fracture models that predict the effects of geologic discontinuities on coalbed fracture propagation is recommended. Additionally, a future mine excavation to expose the coalbed roof rock and to assess the extent of vertical fracture propagation is suggested.
Gas-Well Testing in the Presence of Desorption for Coalbed Methane and Devonian Shale
Authors: Bumb A. C. , McKee C. R. 
Published: December 2007

Summary
Very large potential gas reserves are present in both coalbeds and Devonian shales. In both formation types, long-term gas production is the result of gas desorption from the matrix. Experiments on core samples show that the desorption obeys a Langmuir isotherm.
An approximate analytic solution is derived for single-phase gas flow when gas is present as both free gas and gas adsorbed on the matrix. The solution was verified against a finite-difference solution; the agreement between the two methods is excellent.
The analysis of test data is simplest if the test is conducted at a constant mass flow rate. It is shown that the effect of desorption cannot be detected in production testing; therefore, analysis can be performed to obtain permeability as if the desorption effect is absent. The procedure to obtain desorption parameters is also given. The effect of desorption shows up in an increased compressibility, of the form cg +(αcm/ϕ)+[pscVLpLTz̅/ϕp̅gTsczsc(pL+pL+p̅g)2], which can be much larger than the gas compressibility. The effect of desorption on total production is substantial. When gases are adsorbed, total production over the life of a well can be an order of magnitude higher.
Elastic and Viscoelastic Calculations of Stresses in Sedimentary Basins
Authors: Warpinski Norman R. 
Published: December 2007

SummaryThis study presents a method for estimating the stress state within reservoirs at depth with a time-history approach for both elastic and viscoelastic rock behavior. The model can incorporate changes in pore pressure, temperature gradients, consolidation and diagenesis through time-varying material properties, and varying tectonic episodes. Example calculations are presented for simple cases and for a complete stress history of rocks in the Piceance basin.
A Microcomputer Program for Prediction of Bottomhole Assembly Trajectory
Authors: Birades Michel , Fenoul Robert 
Published: December 2007

Summary
This paper describes a two-dimensional (2D) static, finite-element microcomputer program capable of quantitatively predicting the inclination behavior of bottomhole assemblies (BHA's). A calculation module that is based on the finite-element method helps account for the forces generated between the components of the BHA and the wellbore wall. This module is used in an automatic iterative process to compute the "equilibrium curve" of the BHA, which gives the future inclination gradient of drilling. The analysis of horizontal wells drilled by Elf Aquitaine demonstrated the role played by the hole-diameter- enlargement/rate-of-penetration (ROP) relation in prediction improvements.
Microcomputer Analysis of Hydraulic Fracture Behavior With a Pseudo-Three-Dimensional Simulator
Authors: Morales R. H. 
Published: December 2007

SummaryThe theory describing a pseudo-three-dimensional (pseudo-3D) hydraulic fracturing model that solves the coupled fluid-flow and elastic-rock-deformation problem associated with a fracture propagating into a zone composed of three or more layers is presented. The fracture is initiated in the center layer. Fracture growth is formulated from the critical-stress-intensity-factor criterion, and fracture width is obtained from plane-strain elasticity solutions. Fluid fronts and proppant settling during fracture closure are tracked during the treatment.Fracture parameters obtained by this model show excellent agreement (6% maximum difference) with the solution given by a 3D simulator. Also, designs of hydraulic fracturing treatments depicting ways to minimize fracture growth and to optimize proppant distribution are described. The explicit expressions developed for modeling the fracture growth and fracture opening have reduced the complexity of the formulation and the computational effort.
A Viscoelastic Constitutive Model for Determining In-Situ Stress Magnitudes From Anelastic Strain Recovery of Core
Authors: Warpinski N. R. , Teufel L. W. 
Published: December 2007

SummaryA three-dimensional viscoelastic model is developed to describe the anelastic-strain-recovery (ASR) process. Measured ASR data are curve-fit to the model by a least-squares algorithm, and viscoelastic material properties are calculated. The stress state at depth can then be determined given some additional information. Examples and comparisons with measured stresses are given.
Effects of Capillary Pressure on Coalescence and Phase Mobilities in Foams Flowing Through Porous Media
Authors: Khatib Z. I. , Hirasaki G. J. , Falls A. H. 
Published: December 2007

Summary
The stability of foam lamellae is limited by capillary pressure. Consequently, as the fractional flow of gas in a foam is raised at a fixed gas velocity, the capillary pressure in a porous medium at first increases and then approaches a characteristic value, here called the "limiting capillary pressure." If the gas fractional flow is increased after the limiting capillary pressure has been attained, coalescence coarsens foam texture, the liquid saturation remains constant, and the relative gas mobility becomes proportional to the ratio of gas-to-liquid fractional flow. The limiting capillary pressure varies with the surfactant formulation, gas velocity, and permeability of the medium.
Static and Dynamic Three-Dimensional Bottomhole Assembly Computer Models
Authors: Birades Michel 
Published: December 2007

Summary
This paper presents two three-dimensional (3D) mathematical models to predict the directional behavior of bottomhole assemblies (BHA's). The first model describes BHA dynamic, stepwise, transient behavior. Displacements and lateral forces, computed for each step, account for friction against the borehole wall. The second model computes a static BHA equilibrium whereby simplified friction forces are assumed. The static lateral forces are found to be an average of the highly varying ones computed by the dynamic model, but the static computer run is much faster. The static model is therefore used iteratively to compute an oriented dogleg severity that balances lateral forces. This is used to derive the directional behavior of the BHA. Comparison and calibration against real field cases are performed.