bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case History of the Tensleep Reservoir, Torchlight Field, Wyoming
Authors: Willingham R.W. , Howald C.D. 
Published: December 2007

Abstract
The Torchlight field is located on the east side of the Big Horn Basin in Big Horn County, Wyo. Orchard Unit Well No. 1, the Tensleep discovery well, was completed in 1947. The 33 degrees API gravity Tensleep crude was highly undersaturated, and hydraulically contained in the anticlinal reservoir by a tilted water table. After development, fluid producing rate and reservoir pressure declined rapidly. Field performance indicated the reservoir was producing by a limited water drive and would require over 25 years for depletion. Comparisons are made between field producing rates and rates predicted by water influx theory. Predicted rates are 10 to 15 per cent higher than actual rates. The difference is due to reservoir pressure being higher than that assumed in the prediction. Supplemental water injection was started in Oct., 1957, to reduce reservoir life and increase oil rates. Oil response was immediate and reached a maximum rate of 1,785 BOPD in 1959. By Jan., 1965, the reservoir had been essentially depleted after producing 2,774,000 bbl oil. Supplemental water injections have reduced reservoir life at least seven years. Oil recovery by supplemental water injections of 43 per cent of original oil in place will be comparable to recovery by natural water drive. Predicted oil recovery by the Dykstra-Parsons and Stiles methods indicate recoveries of 46 and 50 per cent original oil in place, respectively. However, these two methods assume 100 per cent areal sweep efficiency, and reduction for areal sweep would result in close agreement with actual recovery.
Introduction
The Tensleep reservoir, Torchlight field, Wyo., is nearing depletion by natural water drive and supplemental water injections after producing over 2.7 million bbl of oil. Collection of extensive engineering data during early development permitted thorough evaluation of reservoir properties, early recognition of the producing mechanism and initiation of a water injection program which significantly increased oil rate and reduced reservoir life. Water injections did not influence or change ultimate oil recovery but provided a decrease in operating costs as compared to depletion by natural water influx. The advanced stage of depletion, plus availability of necessary engineering information, permits comparisons between theoretical and actual reservoir performance. The fluids, rocks and producing mechanism of the Torchlight Tensleep reservoir are characteristic of many Rocky Mountain Pennsylvanian Age reservoirs. A review of the history of the Torchlight Tensleep may assist in more efficient operation of similar reservoirs.
History of Development
Torchlight field is located on the east side of the Big Horn Basin in Big Horn County, Wyo. (Fig. 1). Wells were drilled as early as 1904, making Torchlight one of the oldest oil fields in Wyoming.
JPT
P. 1159ˆ
Injection and Energy Recovery in Fractured Geothermal Reservoirs
Authors: Bodvarsson Gudmundur S. , Pruess Karsten , O'Sullivan Michael J. 
Published: December 2007

Abstract
Numerical studies of the effects of injection on the behavior of production wells completed in fractured two-phase geothermal reservoirs are presented. In these studies the multiple-interacting-continua (MINC) method is employed for the modeling of idealized fractured reservoirs. Simulations are carried out for a five-spot well pattern with various well spacings, fracture spacings, and injection fractions. The production rates from the wells are calculated using a deliverability model. The results of the studies show that injection into two-phase fractured reservoirs increases flow rates and decreases enthalpies of producing wells. These two effects offset each other so that injection tends to have small effects on the usable energy output of production wells in the short term. However, if a sufficiently large fraction of the produced fluids is injected, the fracture system may become liquid-filled and an increased steam rate is obtained. Our studies show that injection greatly increases the long-term energy output from wells because it helps extract heat from the reservoir rocks. If a high fraction of the produced fluids is injected, the ultimate energy recovery will increase many-fold.
Factors Contributing to the Ability of Acrolein To Scavenge Corrosive Hydrogen Sulfide
Authors: Kissel Charles L. , Brady John L. , Gottry H. Nancy Clifton , Meshishnek Michael J. , Preus Martin W. 
Published: December 2007

Abstract
Acrolein can function under a variety of conditions as an effective hydrogen sulfide scavenger in oilfield waterflood systems. The scavenging ability is maximized in waters having a pH range of 6 through 8, a total dissolved solids level below 1%, and temperatures less than 149°F [65°C]. At least 4 ppm acrolein is necessary to achieve sufficient reaction of each original 1 ppm hydrogen sulfide. This reaction requires about 2 to 20 minutes, depending on the nature of me system. Although sand, garnet, or diatpmaceous earth filters do not affect the scavenging ability of acrolein, charcoal filters, large tanks, long pipelines, high-temperature Wemcos, and reboilers can produce diminished effects. Further diminished effects also can be produced when incompatible chemicals are used concurrently with acrolein. Some application techniques that can lessen or eliminate these adverse conditions are presented.
The Proper Interpretation of Field-Determined Buildup Pressure and Skin Values for Simulator Use
Authors: Odeh A. S. 
Published: December 2007

Abstract
Scaling factors for the proper application and interpretation of field-determined skin effect and pressure buildup values for use in simulators are derived. Reservoir engineering calculations for the actual well are based on a continuous physical system and the total effective formation thickness. For use with a simulator, the system is discretized, and the cell thickness replaces the total thickness. The scaling factors are to correct for the differences between the two systems. Without the scaling factors, the well inflow equations used in the simulators would calculate an erroneous pressure drop component as a result of the physical skin and the non-Darcy flow effect. In the case of pressure values, an equation is derived that gives the buildup time, ∆t, when the field-measured wellbore pressure becomes, equal to the wellblock pressure in a three-dimensional simulator. This is important for history matching. This paper shows that the pressure-Δt relation is strongly coupled to the skin scaling factor.
Chemical Evolution of a High-Temperature Fracturing Fluid
Authors: LaGrone C. C. , Baumgartner S. A. , Woodroof R. A. 
Published: December 2007

Abstract
Reservoirs with bottomhole temperatures (BHT's) in excess of 250°F [121 °C] and permeabilities of less than 1.0 md are commonly encountered in drilling and completing geothermal and deep gas wells. Successful stimulation of these wells often requires the use of massive hydraulic fracturing (MHF) treatments. Fracturing fluids chosen for these large treatments must possess shear and thermal stability at high BHT's.
The use of conventional fracturing fluids has been limited traditionally to wells with BHT's of 250°F [121 °C] or less. Above 250°F [121 °C], high polymer concentrations and/or large fluid volumes are required to maintain effective fluid viscosities in the fracture. However, high polymer concentrations lead to high friction pressures, high costs, and high gel residue levels. The large fluid volumes also increase significantly the cost of the treatment.
Greater understanding of fracturing fluid properties has led to the development of a crosslinked fracturing fluid designed specifically for wells with BHT's above 250°F [121 °C]. The specialized chemistry of this fluid combines a high-pH hydroxypropyl guar gum (HPG) solution with a high-temperature gel stabilizer and a proprietary crosslinker. The 6fluid remains stable at 250 to 350°F [121 to 177°C] for extended periods of time under shear. This paper describes the rheological evaluations used in the systematic development of this fracturing fluid.
In field applications, this fracturing fluid has been used to stimulate successfully wells with BHT's ranging from 250 to 540°F [121 to 282°C]. Case histories that include pretreatment and posttreatment production data are presented.
Application of the Alternating Direction Explicit Procedure To Two-Dimensional Natural Gas Reservoirs
Authors: Quon D. , Dranchuk P.M. , Allada S.R. , Leung P.K. 
Published: December 2007

Abstract
The alternating direction explicit procedure (ADEP) makes use of the boundary conditions to reduce multi-dimensional problems to a series of one-dimensional problems. The method, previously applied to reservoirs containing only an undersaturated oil, bas now been extended to cover the case of natural gas reservoirs. Although this involves solving a non-linear partial differential equation, application of the procedure is straight- forward and no calculational problems were encountered.
Introduction
There has been a growing interest in formulating mathematical models of petroleum and natural gas reservoirs - models which permit the engineer to examine and evaluate the physical and economic consequences of various alternative production policies. The tremendous reduction in the cost of solving such models in recent years has made possible their use as an almost routine management tool. This reduction is the result not only of improved computer hardware but also of the development of more efficient mathematical techniques. The present paper is concerned with the application of a recently proposed numerical method (ADEP) to two-dimensional gas reservoirs.
STATEMENT OF THE PROBLEM
Given a two-dimensional Region R, bounded by a closed Curve C (Fig. 1) such that the behavior on Curve is known, the differential mass balance for each fluid phase in R, neglecting gravitational effects and assuming Darcy's law for fluid transport, can be written as:
A typical and common set of boundary conditions is given by (1) / = 0 on Curve C where r is the direction normal to Curve C; (2) p is known throughout Region R at some time t; and (3) wf is known for all x, y and t. Physically, this represents the case where the reservoir is bounded by impermeable media, where the initial pressure throughout the reservoir at the beginning of gas production is known and where the production rate at each well is specified at all times. For single-phase reservoirs, the problem is to determine the pressure throughout Region R at all times; for multi-phase reservoirs, in addition to the pressure, the value of the fluid saturation is also required. Since analytical solutions to this equation for the general case are not available, we must resort to numerical integrating techniques, using finite-difference approximations.
SPEJ
P. 137ˆ
Tubular Corrosion in the West Sole Gas Field
Authors: Gair D. J. , Moulds T. P. 
Published: December 2007

Summary
Severe corrosion in West Sole tubulars resulted in a fieldwide workover program 4 years after the field was brought on stream in 1967. The optimum solution, balancing cost with efficiency of corrosion prevention, was considered at the time to be the installation of 13% Cr tubing in the upper section of the tubing string. Inspection with caliper surveys has proved the efficiency of such completions in combating corrosion, and the nominal tubing life has subsequently been extended to between 10 and 15 years.
Water Power Fluid for Hydraulic Oil Well Pumping
Authors: Brown F. Barton 
Published: December 2007

Abstract
Water is the obvious answer for a substitute to crude - fresh, sea or produced brine. This paper presents experimental work done on the development of additives to make water suitable for hydraulic pumping. Field testing and recent commercial applications have shown the numerous advantages, practicability and economy of using water as a power fluid.
Introduction
Fluid normally available for power is the produced crude which frequently lacks good lubricating properties, has too high a viscosity at times and contains sand, water, paraffin and other foreign materials. In the early days of hydraulic pumping, only the open system was available and there was an economic limit to improving the quality of the crude power fluid. Development of the free pump gave impetus to use of the parallel string. A natural sequence was the three-string closed system which provided a better, more economical method of cleaning the crude power oil and opened the door to use of other liquids for power fluids. Water is a liquid with a high bulk modulus and is the obvious Substitute for crude.
Search for Additives
In 1958 an intensive experimental program was initiated on the use of water as a power fluid for hydraulic pumping. Low viscosity, lack of lubricating properties, corrosive tendency and bacterial action all combined to make additives a necessity. The additive should provide the desired lubricity, and it should be a corrosion inhibitor, a bactericide, an oxygen getter and a thickener-all mutually compatible. The additives should also be suitable for sea water and oil- field brines. The commercial non-inflammable hydraulic fluids on the market included water glycol, phosphate ester, chlorinated phosphate ester and oil emulsions of 40 per cent water, 55 per cent oil and 5 per cent emulsifier. But the cost of each was prohibitive, running from $40 to $190/ bbl.
In this early work, an oil in water emulsion of less than 2,000 ppm was sought. Over 200 samples of different emulsions were investigated seeking those that would be stable in brine. Further evaluation of oil in water emulsions and film-forming lubricants was carried on in the wear test machine, the laboratory test well and by field tests. In the future, there may be different types of additives available and the choice will be determined by the particular pumping problem involved. Undoubtedly, the selection of additives will revolve around the type of water being used - fresh, very soft, brine or sea water.
Wear Test Machine
In 1933 a wear test machine was built that used reciprocating motion between the wear parts instead of the usual rotary motion. This machine more nearly duplicated the wear action in the bottom-hole pump and has always been useful in evaluation of both materials and lubricants. For evaluating a lubricant, nitralloy blocks, lapped flat to within one light band, are mounted (Fig. 1). Water runs into the bucket at a constant rate, gradually increasing the load on the blocks.
JPT
P. 172ˆ
Determination of the Economic Limit for Non-EOR Projects in Alberta
Authors: Rosenbaum Itzhak 
Published: December 2007

Abstract
This paper provides an easy-to-use procedure by which engineers and corporate planners can determine the economic limit for non-EOR projects in Alberta. The economic limit in this study is defined as the minimum average daily-oil-production rate needed to break even on a before- and/or after-income-tax basis. The economic limit for a single well, for a unit, and/or for a project can be determined by the procedure. The major advantage of this procedure is that it allows reservoir and production engineers to estimate economic limits quickly and accurately without the use of expensive economic models.
The First Oil Well
Authors: Dickey Parke A. 
Published: December 2007

Abstract
The birth of the oil industry on Aug. 27, 1859, was spectacular and its later history has been colorful and romantic.
During the early part of the last century the industrial revolution was in full swing. The demand for oil for lubricating the machinery and illuminating the factories had been supplied from tallow and whale oil. In the 1850's an industry based on the production of illuminating oil from coal was growing rapidly, and a refining technology utilizing thermal cracking and distillation was well developed. It was soon found that petroleum was superior to coal as a raw material, but it was a scientific curiosity, occurring in many places, but in small quantities.
At the same time along the tributaries of the Ohio River a considerable industry had grown up around the manufacture of salt. The brine was obtained from sands at depths up to 1,000 ft. A drilling technology had developed, and the methods of cable tool drilling were mostly invented between 1800 and 1830 along the Kanawha, Muskingum, Conemaugh and Allegheny rivers.
Petroleum was produced along with the brine at nearly all the salt manufacturing plants. At most of these it was used to illuminate the plants and grease the machinery. It was inevitable that this new source of oil should come to the attention of the coal oil refiners, and that attempts should be made to produce oil by drilling. The combination of a large and growing demand for oil, a well-developed refining industry and a highly developed drilling technology provided an explosive mixture.
The spark finally occurred at Titusville, Pa., on the site of a famous oil seep that had been exploited by the Moundbuilders and later by the Seneca Indians and the early settlers. Two New York promoters, George H. Bissell and Jonathan G. Eveleth, formed a company which purchased the farm on which the seeps were located. They were unable to sell stock until they published a glowing report on the commercial value of the oil written by Benjamin Silliman, Jr., a famous chemist and professor at Yale U. Financial support was finally obtained from James M. Townsend, a New Haven banker, and his associates.
Edwin L. Drake went to Titusville in Dec., 1857, to start operations for the company. The first year he opened up the old springs and attempted to exploit them. He decided to drill for oil and employed a salt well driller, W. A. Smith, who came to Titusville in the spring of 1859. Oil was encountered on Aug. 27 at the unexpectedly shallow depth of 69 ft. (Fig. 1). The well produced about 10 B/D. Land along the creek valleys was quickly leased and drillers, teamsters, coopers, speculators and others flocked to the area. The excitement exceeded that of the California gold rush 10 years before.
Surface Composition of Berea Sandstone
Authors: Ramirez W. F. , Oen A. C. , Strobel J. F. , Falconer J. L. , Evans H. E. 
Published: December 2007

Summary
Auger electron spectroscopy (AES) was used to determine the surface composition of Berea sandstone. Changes in the surface composition resulting from cation exchange and surfactant adsorption have also been observed. Surface compositions obtained by AES were compared to bulk analysis as well as X-ray photoelectron spectroscopic analysis (XPS).
Pressure-Transient Analysis for Naturally Fractured Gas Reservoirs: Field Cases
Authors: Samanlego-V. F. , Cinco-Ley H. 
Published: December 2007

SummaryThis paper analyzes three field tests performed in two naturally fractured gas reservoirs. The interpretation can properly be accomplished by use of a single infinite-conductivity vertical-fracture model that considers (1) the intersection of the well by a planar fracture and (2) a homogeneous and isotropic matrix. Conditions of the tests include almost constant flow rate before shut-in in the first case and variable flow rate before shut-in in the second case. A square-root group tpp−tpp+Δtp+Δtp2 is discussed for test analysis where final flowing conditions are linear flow and the shut-in period does not meet the restriction tp &gt; 10∆tmax. A new type curve in terms of pD/CfD vs. txfD/CfD2 corresponding to linear-flow conditions under the effect of wellbore storage is presented.
Natural Gas - Partner and Competitor
Authors: Davis W.B. , Schweizer J.L. 
Published: December 2007

Abstract
While producers look upon natural gas as a source of added income, it is also a direct competitor to products of crude oil at the consumer level. The growth rate of natural gas consumption has been greater than that of crude oil. This growth can be attributed mainly to the lower price per unit of energy for which gas is sold. The increase in the consumption of natural gas has had as great an impact on the domestic producer as have crude oil imports. The lower price of natural gas and its increased use have had the net effect of keeping the average wellhead price of hydrocarbon energy at approximately the same level for the past 30 years.
Therefore, it appears that many of the domestic producer's troubles today are caused not so much by the fact that he is selling two competing forms of energy, but that he is forced to sell one, natural gas, below its true market value because of artificially depressed prices. The best remedy for this situation lies in the freeing of natural gas prices from control and allowing them to compete in the open market. Every domestic producer of crude oil has a big stake in the solution of this problem whether he sells gas or not, since his oil is forced to compete with the under-priced gas for a portion of the energy market.

Introduction
The purpose of this paper is to emphasize the fact that natural gas is much more than just a source of additional revenue to the crude oil producer. We must recognize that while a small fraction of crude oil is used to make lubricants and for chemical feed stock, most of it is used as a source of energy. Natural gas, along with coal and other energy fuels, also serves the U. S. energy market. Consequently, natural gas is a competitor to crude oil at the consumer level, and the supply and price of natural gas are having a significant effect on crude oil demand. There is some question as to whether natural gas now is more important to oil producers as a source of revenue or as a competitor; however, it is reasonably certain that if artificial control of gas prices continues, the importance of gas as a competitor will grow much faster than its importance as a revenue source.
Dynamic Gas Slippage: A Unique Dual-Mechanism Approach to the Flow of Gas in Tight Formations
Authors: Ertekin Turgay , King Gregory R. , Schwerer Fred C. 
Published: December 2007

Summary
A mathematical formulation, applicable to both numerical simulation and transient well analysis, that describes the flow of gas in very tight (k∞ &lt;0.1 md) porous media and includes a dual-mechanism transport of gas is developed. Gas is assumed to be traveling under the influence of a concentration field and a pressure field. Transport through the concentration field is a Knudsen flow process and is modeled with Fick's law of diffusion. Transport through the pressure field is a laminar process and is modeled with Darcy's law (inertial/turbulent effects are ignored). The combination of these two flow mechanisms rigorously yields a composition-, pressure-, and saturation-dependent slippage factor. The pressure dependence arises from treating the gas as a real gas. The derived dynamic slippage is most applicable in reservoirs with permeabilities ≤0.01 md. The results indicate that in reservoirs of this type, differences between recoveries after 10 years of production with the dynamic-slip and constant-slip approaches were as great as 10%, depending on the initial gas saturation. If an economic production rate is considered, differences as great as 30% can be expected.