bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Wettability Alteration on Water/Oil Relative Permeability, Dispersion, and Flowable Saturation in Porous Media
Authors: Wang F. H. L. 
Published: December 2007

Summary
Wettability alteration was shown to affect strongly water/oil two-phase flow behavior in Berea and Loudon reservoir cores. Two examples of wettability alteration were realized by core aging and core extraction. With a steady-state method coupled with tracer analyses, these changes in wettability were shown to affect relative permeabilities, dispersivities, and flowable saturations in the cores. The changes in wettability were also confirmed by waterfloods and spontaneous-imbibition tests.
Dispersion in steady-state two-phase flow was found to be a strong function of saturation and wettability. Dispersivity of each phase increases with decreasing phase saturation. Flow of the non wetting phase was dispersed much more than that of the wetting phase.
A large fraction of the nonwetting-phase saturation was found to be bypassed or nonflowable, while the wetting phase was completely flowable. The correlation between the flowable phase saturation and in-situ phase saturation was strongly affected by wettability alteration.
Tubingless Completions: A Review of Equipment, Economics and Techniques
Authors: Muse John F. 
Published: December 2007

Abstract
The economic advantages in completions utilizing 2%-in. tubing as casing are, generally speaking, quite obvious. In today's atmosphere of rising costs and increased competition, this completion method is being viewed with interest by practically every operating company. The number of completions actually made has increased greatly in the past year. It will increase even more when companies not now experienced with this type of completion are made aware of the methods successfully being utilized and the equipment being made available.
Companies interested in starting a program of tubingless completions are naturally concerned with the results which have been achieved in the past. They are also concerned with the difficulties that have been encountered. They want to know the savings that actually have been made in these completions and, also, what possible ultimate savings are now predicted. They want to know which methods and equipment have been tried and which have proved most successful. Also, they want to know what major problems still are unsolved and what limitations are becoming apparent.
In a rapidly developing technological change such as this, periodic reports are necessary to keep the industry advised of the progress made. This paper attempts to report the latest equipment, how it is being utilized, and what problem areas are evident.

Introduction
To date, most of the work done in the United States in tubingless completions has been performed in relatively shallow areas where production could adequately be handled by the 2%-in. casing. These areas are Southwest Texas, West Texas, the Texas Panhandle, Kansas and Oklahoma.
Many companies in these areas were contacted for information concerning the methods and equipment which were being utilized most successfully and, also, concerning the general economic results obtained. This permits the presentation of a wider scope of information than would a review of one company's results and methods in one area only; however, it presents somewhat of a reporting handicap because the information obtained must be discussed in general, rather than specific, terms.
Effects of Pumping Equipment on Sand-Laden Slurries
Authors: Roll D. L. , Himes R. , Ewert D. P. , Doerksen J. 
Published: December 2007

Summary
Effects of pumping equipment, gravel-packing devices, and fracturing equipment on proppants and fluids were investigated. Generation of fines was not significant, but some crosslinked gels were severely damaged by shearing forces in the equipment.
Comparison of Steady- and Unsteady-State Flow of Gas and Foaming Solution in Porous Media
Authors: Huh D. G. , Handy L. L. 
Published: December 2007

Summary
Relative permeabilities of foaming-agent solution/nitrogen gas were measured by steady- and unsteady-state methods in Berea sandstones. Results show a significant difference between steady- and unsteady-state flow. Unsteady-state experiments show a small change of relative permeability to gas over a wide range of saturations and exhibit no complete blocking effect. In steady state, however, the simultaneous flow of liquid and gas could be stabilized only above a minimum gas saturation of about 35 to 40%, probably because of the formation of a large number of foam lamellae by the continuous supply of foaming solution. The permeability reduction factor calculated from the ratio of the gas permeability in the presence of foaming agent to that in the absence of foaming agent is mainly a function of lamellae stability.
Pressures as a function of distance were measured at three pressure taps spaced at equal distances along the core. The pressure history shows abrupt jumps in pressure with advancement of the gas phase owing to capillary pressure. After gas breakthrough, the pressures at each tap were stabilized. The results during steady-state flow showed that the pressure gradient increases with increasing distance from the inlet end of the core sample, indicating that the higher gas fraction results in a greater blocking effect.
The surfactant effluent concentrations were measured by a UV spectrophotometer to calculate the adsorption isotherm of this foaming agent. The dynamic adsorption of Suntech IV™ showed a Langmuir-type isotherm. The adsorption was &lt; 2 μmol/g sand for up to 1.0% concentration.
The Effect of an Initial Gas Content on Thermal EOR as Applied to Oil Sands (includes associated papers 18399, 18568 and 18743 )
Authors: Frauenfeld T.W.J. , Ridley R.K. , Nguyen D.M. 
Published: December 2007

Summary
This paper discusses the results of a number of physical model experiments on thermal EOR. Seven experiments were performed, three in which a "dead" heavy oil was used, and four in which the oil sand was saturated with methane. For oils without an initial gas content, coinjection of CO2 with steam was capable of improving oil recovery over that obtained with steam alone. When an initial dissolved gas was present, coinjection of CO2 was not beneficial. Injection of CO2 or CH4 slugs just before steam injection was beneficial in increasing oil recovery for experiments where an initial dissolved gas was present.

Introduction
Numerous researchers have reported results on thermal EOR in heavy oil. These results refer to field experience and to numerical modeling studies. Little experimental work is available on the significance of dissolved gas in thermal recovery processes. This work was done to provide data on the effects of dissolved gas on cyclic steam stimulation. The work consists of seven large physical model experiments with and without an initial dissolved gas content. Meldau et al. reported on a field application of air injection with steam in a reservoir containing 11° API [0.99-g/cm3] oil. They also performed a numerical study that indicated that injecting gas with steam produced substantial improvements in oil production. Their model assumed a dead oil and therefore did not study the effect of an initial gas saturation. They found that the mechanisms responsible for improved oil recovery were trapping of gas below the critical saturation value, increased gas drive of oil near the wellbore, movement of heat into the upper layers of the reservoir, and higher reservoir pressure during drawdowns.
Hong and Ault performed a numerical simulation of a heavy-oil and a light-oil steamflood. They compared steam-only injection to the injection of steam with a noncondensable gas. They assumed a 14° API [0.97-g/cm3] heavy oil in 4,000-md sand and no initial gas saturation in their oil. Coinjection of CO2 or N2 with steam improved the early oil recovery from a steamflood of a heavy-oil reservoir. However, the ultimate oil recovery was the same as that for a steam-only injection. The enhanced early recovery was a result of the sweep of the reservoir by injected gas.
Fluid Flow and Sand Production in Heavy-Oil Reservoirs Under Solution-Gas Drive
Authors: Smith Gerald E. 
Published: December 2007

Summary
The production of heavy oil in Canada has led to a number of anomalous results, most of which have been excused as high-permeability channels resulting from sand production. The methods of soil mechanics predict gross formation failure resulting from high fluid compressibility, small cohesion, and high viscosity. Gross failure results in excellent productivity but reduced in-situ stress (and fracture stress).
Solution-gas drive in these reservoirs involves simultaneous-mixture flow of gas as very tiny bubbles entrained in heavy oil. Stress, geometry, and permeability alteration resulting from matrix deformation combined with peculiar pressure-dependent multiphase-flow properties result in a new model of reservoir performance. A field observation of stress modification is discussed, as are the contributions of the four components discussed previously to the observed phenomena.
Multiple-Well Interference Testing in the Ohaaki Geothermal Field
Authors: Leaver J. D. , Sageev A. , Ramey H. J. 
Published: December 2007

SummaryMultiple interference tests were carried out in the Ohaaki geothermal field between 1979 and 1983. Data were collected for periods of up to 200 days per test with both wellhead-mounted water-level recorders and quartz crystal pressure gauges, each with a resolution of about 0.0145 psi [100 Pa], Data are analyzed by conventional log-log type-curve matching techniques, followed by application of recently developed semilog type-curve matching techniques that allow linear boundary detection without developing two semilog straight lines. One type curve exists for each of the drawdown and buildup data, which are produced by mathematically collapsing the family of curves produced in the solution for a system containing a line source and linear boundary. The type curve for die buildup data has not been previously published. The method allows the inference ellipse for a linear boundary to be determined without any knowledge of reservoir parameters.The data in some tests show the presence of a no-flow boundary for which inference ellipses have been located. Four interference tests performed on the same doublet show that vastly different reservoir parameters can be found unless careful interpretation is made.
Fractured Geothermal Reservoir Growth Induced by Heat Extraction
Authors: Tester J. W. , Murphy H. D. , Grigsby C. O. , Potter R. M. , Robinson B. A. 
Published: December 2007

Summary
Field testing of a hydraulically stimulated, hot, dry rock (HDR) geothermal system at the Fenton Hill site in northern New Mexico indicated that significant reservoir growth occurred as energy was extracted. Tracer, microseismic, and geochemical measurements provided the primary quantitative evidence for the increases in accessible reservoir volume and fractured rock surface area that were observed during energy extraction operations that caused substantial thermal drawdown in portions of the reservoir. These temporal increases suggest that augmentation of reservoir heat-production capacity in an HDR system may be possible.
Application of the Boundary Integral Method to Immiscible Displacement Problems
Authors: Masukawa Junichi , Horne Roland N. 
Published: December 2007

Summary
This paper presents an application of the boundary integral method (BIM) to fluid displacement problems to demonstrate its usefulness in reservoir simulation. A method for solving two-dimensional (2D), piston-like displacement for incompressible fluids with good accuracy has been developed. Several typical example problems with repeated five-spot patterns were solved for various mobility ratios. The solutions were compared with the analytical solutions to demonstrate accuracy. Singularity programming was found to be a major advantage in handling flow in the vicinity of wells. The BIM was found to be an excellent way to solve immiscible displacement problems. Unlike analytic methods, it can accommodate complex boundary shapes and does not suffer from numerical dispersion at the front.
Williston Basin: An Analysis of Salt Drilling Techniques for Brine-Based Drilling Fluid Systems
Authors: Stash Sandra M. , Jones Mark E. 
Published: December 2007

Summary
Williston Basin salt intervals, ranging in depth from 5,000 to 12,500 ft [1525 to 3810 m], have been responsible for widespread casing collapse because of the plastic movement of evaporites and the subsequent point loading of casing. This phenomenon is attributable to poor cement jobs across excessively eroded salt sections. A 2-year study led to the realization that this erosion is a function of not only salt dissolution but also the mechanical action of turbulent flow in the wellbore. A laminar flow regime can be realized and salt enlargement limited by careful control of annular flow rate, jet velocity, and drilling-fluid rheology.
Practical Techniques in Two-Pseudocomponent Black-Oil Simulation
Authors: Shank G. D. , Vestal C. R. 
Published: December 2007

SummaryAn efficient black-oil simulator based on a two-pseudocomponent representation of standard hydrocarbon physical-property data has been developed. This simulator solves the differential equations describing three-phase flow in a porous medium for black-oil, volatile-oil, condensate, and dry-gas systems. The fluid system consists of two-pseudocomponents—separator gas and stock-tank oil—and water. Descriptive equations are obtained by writing molar balances for the water phase, the stock-tank oil component in the hydrocarbon vapor and liquid phases, and an overall balance in the hydrocarbon vapor and liquid phases. The set of equations is solved by use of either a sequential method or a fully implicit method. The mathematical formulation allows rigorous simulation of reservoir problems involving variable bubblepoint or dewpoint pressures. Practical aspects, such as comparing the simulator physical property data to the laboratory PVT tests, performing flash calculations, and calculating phase boundary pressures, are discussed.
LaBarge Project: Availability of CO2 for Tertiary Projects
Authors: Hunter J.K. , Bryan L.A. 
Published: December 2007

Abstract
Exxon Co., USA is constructing a large gas processing facility northeast of Kemmerer on the Lincoln-Sweetwater County line in southwest Wyoming. The plant will process raw gas from three Exxon operated units northwest of LaBarge, in Sublette County.
The LaBarge Field is being developed primarily to recover and sell methane; however, the field is also a significant source of carbon dioxide, sulfur and helium. As a source of CO, the LaBarge Field will provide oil producers in the Rocky Mountain area an opportunity to increase production in their mature fields through EOR projects.
A 649-mile pipeline is planned to transport up to 650 Mcfd of CO, to users throughout Wyoming and Willisiton Basin. Exxon's CO, marketing survey indicates potential CO, demand of 4.4 trillion cubic feet in the planned marketing area for enhanced oil recovery. About 25% of the CO2 demand identified is already contracted. LaBarge CO2 will allow Northern Rocky Mountain 'operators to potentially recover an additional one billion barrels of oil reserves.

Introduction
Exxon's gas plant, scheduled for startup this year, is designed to process 480 million cubic feet per day of raw gas yielding 114 Mcfd ( m = million, G = billion, T = trillion) of methane, and 250 mcfd of CO2. The initial phase of the plant is currently being built and a future expansion is under evaluation. Expansion timing will depend on the economic climate and commitments for plant products. while methane is the primary product being developed in the LaBarge Project, the field will also produce marketable quantities of CO2, sulfer, and helium. The CO2 is being offered for sale to operators in Colorado, Wyoming, North Dakota, Montana, and Canada as an injectant for their EOR projects.

Background
The well field consists of three Exxon operated units covering over 63 square miles (see Fig. 1). These units are located about 10 miles northwest of the town of LaBarge in Sublette County. Exxon owns an average of 95% (Jan.'86, leased committed acreage) of the Lake Ridge, Fogarty Creek, and Graphite Units. Production is from the Madison, a 900 foot thick carbonate reservoir ranging in depth from 14,000 to 18,000 feet. Structurally the Madison Reservoir is located on a large NW-SE trending anticline. The boundaries have not yet been accurately defined but do extend beyond the three Exxon operated units. The National Petroleum Council estimated that the LaBarge-Big Piney area contains 20–25 Tcf of CO2 reserves alone (EOR, p.33, 1984).
P. 249^
A Random-Scission Model for Chemical Degradation of Polymer Solutions
Authors: Khorrami P. , Radke C. J. 
Published: December 2007

Summary
A rigorous but simple deterministic model is presented to quantify chemical degradation of high-molecular-weight polymer solutions undergoing random bond scission. Molecular-weight alteration is characterized by a fundamental rate constant, k, whose inverse represents the average lifetime of a polymer chain bond. Evaluation of the proposed random-scission model (RSM) against known Monte Carlo (MC) calculations shows complete agreement.
Given the molecular-weight decline from the RSM, we establish the corresponding polymer solution viscosity loss using the semiempirical Martin equation along with the Mark-Houwink relationship for intrinsic viscosity. Comparison of the RSM viscosity predictions against the chemical degradation data of Shupe for partially hydrolyzed Polyacrylamide gives good agreement. Thus, a new tool is available to predict polymer chemical degradation and viscosity loss at reservoir time scales and conditions.
Unique Characteristics of Barium Sulfate Scale Deposition
Authors: Weintritt D.J. , Cowan J.C. 
Published: December 2007

Abstract
Methods of studying oilfield mineral scale deposition in the laboratory do not work for barium sulfate because only small nonadhering crystals are formed. On the other hand, barium sulfate scale found in down-hole or surface equipment is strongly adhering and may contain very large crystals. Results suggest that most of the difference derives from the extremely low solubility of barium sulfate. Firm adherence of scale and the consistent development of oriented crystals 100 microns and larger suggest a relationship between scale adherence and crystal growth. Data from this study indicate some reasons for barium sulfate's occurring as a deposit in oilfield waters. The unique characteristics as well as the associative properties of barium sulfate scale as related to calcium carbonate and calcium sulfate are shown.

Introduction
The first observed deposition of barium sulfate scale in oilfield production equipment is unknown but probably coincides closely with the beginnings of the oil industry itself. Moore described barite oolites in some producing wells in the Saratoga field, Tex., in 1914. Currently, positive identification of barium sulfate deposition is recorded in most of the major oil-producing areas of the United States. As efforts continue to identify the composition and functions of the materials found in scale deposits. the geographic and economic importance of the part played by barium sulfate will become even more important. This belief is based on the following facts.Many oil fields in the U. S. are in or entering their mature phase and the volume of produced water is increasing; thus, the cumulative effects of low-solubility minerals become more significant.Secondary recovery techniques and increased emphasis on waste disposal systems require controlling the behavior of all constituents of water to prevent formation plugging.The more general use of instrumental analysis has reduced the time and improved the accuracy of complete scale and water analysis.Once formed, barium sulfate scale is resistant topresent methods of chemical removal; therefore, costly mechanical methods are necessary.
Thus, new methods of prevention and control will require specialized chemical techniques and better knowledge of the causes of scaling. Consider the results of some simulated field deposition studies illustrating this need (Fig. 1). The studies utilized a Scale Deposition Test Cell* and each coupon was exposed to 8,000 ml of a 300 me/liter solution of the various types of mineral scale. All tests were conducted at 140F. Only the calcium sulfate and calcium carbonate deposited scale. The solution containing 300 me/liter of barium sulfate exhibited copious amounts of precipitate, but none of the precipitate adhered. The fluids from the effluents were also allowed to impinge on glass slides. Fig. 1 shows the relative adherence of the three types of scale on unetched glass. The barium sulfate failed to deposit in the same manner as the calcium carbonate and calcium sulfate solutions.
JPT
P. 1381ˆ
The Stimulation of a Tight, Very-High-Temperature Gas-Condensate Well
Authors: Economides Michael J. , Cikeš Marin , Pforter Harry , Udick Thomas H. , Uroda Pavle 
Published: December 2007

SummaryWell KAL-5, completed in the Moslavacka Gora formation of the Pannonian basin in Yugoslavia, was tested at a flow rate of 75 Mscf/D [2124 std m3/d] of gas and 2.8 B/D [0.45 m3/d] of condensate and at a last bottomhole pressure (BHP) of 1,083 psi [7.5 MPa]. Pretreatment evaluation determined a reservoir permeability in the 0.003- to 0.004-md range. The high formation temperature (354°F [179°C]) poses problems for most fracturing fluids.This paper presents a pretreatment analysis of the well, its geologic setting, and thermal and lithological characteristics as they relate to the choice of the fracturing-fluid system. An outline of the stimulation design and execution is included.After a modest hydraulic fracture treatment, the well flowed for 21 days at a last flow rate of 1,925 Mscf/D [55×103 std m3/d] of gas and 117 B/D [18.7 m3/d] of condensate at a flowing BHP of 912 psi [6.3 MPa]. This substantial increase was apparently caused by the successful hydraulic fracture; geometric features of the fracture were estimated from interpretation of a posttreatment well test. Posttreatment evaluation assesses the effectiveness of the job, calculates the geometric dimensions and the conductivity of the fracture, and presents forecasts of future performance. Finally, the effects of the evolved gas condensate on the reduction of the apparent reservoir permeability are investigated and evaluated. A correlation between pressure, in-situ condensate saturation, and permeability is offered.