bluuebunny/crossref_metadata_2025_split huggingface dataset:
Economic Evaluation of a CO2 EOR Flood at the Rock Creek Field, Roane County, West Virginia
Authors: Brummert A. C. , Ammer J. R. , Watts R. J. , King P. , Boone D. A. 
Published: December 2007

Summary
The U.S. DOE Morgantown Energy Technology Center and the Pennzoil E&P Co. predicted the recovery and economic potential of a full-field, CO2 miscible EOR flood at the Rock Creek field, Roane County, WV. Data used in this evaluation were obtained from two miscible CO2 Rock Creek field tests: (1) a pilot test consisting of two contiguous normal five-spot patterns, each containing 10 acres [4 ha], and (2) a 1.55-acre [0.63-ha] normal four-spot minitest. Core data from the eight injection wells and three observation wells were used to determine reservoir input parameters, and fluid samples were analyzed to obtain fluid properties. A predictive model was used to calculate oil recovery and project economics. The model’s base-case run showed that an oil price of $39/bbl [$245/m3] was required to produce a 15% discounted cash flow rate of return (DCF ROR). A sensitivity study was then conducted on operating parameters [i.e., pattern size, water-alternating-gas (WAG) ratio, total HCPV of WAG injected, and injection rate] and economic parameters (e.g., oil price and CO2 cost) to determine their effect on project performance and project economics.
Partially Decoupled Modeling of Hydraulic Fracturing Processes
Authors: Sattarl A. , Puchyr P. J. , Bachman R. C. 
Published: December 2007

Summary
A new method of partial decoupling of the problem of modeling a hydraulic fracture in a reservoir is described. This approach has significant advantages over previous methods with either fully coupled or completely uncoupled models. Better accuracy can be achieved in modeling the fracture propagation, and the new system is very efficient and versatile. Virtually any reservoir model can be used for predicting postfracture productivity. Examples of single- and multiphase applications for modeling fractured wells are discussed.
Nonisothermal Effects in Water-Injection Well Tests
Authors: Barkve Tor 
Published: December 2007

SummaryThis paper discusses models for one- and two-phase injection-well tests where the injected fluid has a temperature different from that of the reservoir fluid. After a brief discussion of the relative significance of different nonisothermal effects, an integral form of the model equations is used to develop approximate analytical expressions describing temperature and pressure in the reservoir during injection. The expressions are valid for a general variation in viscosity with temperature, and different analytical viscosity functions are used to study the influence of this variation.
Shale/Mud Inhibition Defined With Rig-Site Methods
Authors: Chenevert M. E. , Oslsanya S. O. 
Published: December 2007

Summary
The successful drilling of troublesome shale requires evaluation of the shales and muds during the drilling process so that the proper methods and muds can be selected. With rig-site testing in mind, six tests were studied for their usefulness in defining the severity of the shale/mud chemical reaction. All tests showed some value in the analysis of wellbore problems and solutions; however, the swelling, rolling, and cation-exchange-capacity (CEC) tests proved most useful.
The swelling test uses a newly developed device to describe the early-time swelling properties of native or recompacted shale and provides an analytical method for classifying shales according to their reaction rates. In general, soft shales have a short reaction time, which increases with its hardness. This test also shows the inhibition state of a mud and can therefore be used in mud monitoring and mud-treatment design. The rolling test provides useful information on the dispersion tendencies of a shale-cuttings/mud mixture, and the CEC test provides basic information on the effective clay content of a shale.
This paper discusses techniques used to evaluate shales and muds at the rig site and presents the procedures, results, and parameters that affect each technique. Information concerning a new device for measuring shale swelling and the procedure for reconstituting shale cuttings is given.
Modern Solids Control: A Centrifuge Dewatering-Process Study
Authors: Wojtanowicz Andrew K. 
Published: December 2007

Summary
The concept of a modern solids-control system for drilling rigs is introduced and experimentally investigated. The system incorporates a conventional solids-control arrangement followed by a diversion of part of the drilling mud for chemical conditioning and centrifugation. The dewatering effluent is returned to the mud system makeup-water storage. The dewatered colloidal solids are then stabilized by being mixed with the shaker discharge and the surrounding soils. The system can provide an effective control of colloidal-solids concentration in drilling muds. It can also minimize the volume of drilling waste.
The new process was examined in full-scale experiments to evaluate process efficiency and to identify the effects of field installation, operational variables, solids classification before dewatering, dilution, and the stability of the dewatering and its sensitivity to chemical dosage. In the chemical destabilization tests, a successful treatment was found for flowline samples of five different drilling-mud systems. The conceptual design of the modern solids-control system is presented and discussed. This process is also related to conventional solids-control and wastewater treatments.
Simplified Slurry Design Increases Wellsite Success
Authors: Grant W. H. , Dodd E. L. , Gardner C. A. 
Published: December 2007

Summary
Highly flexible cement systems can be designed to accommodate a broad range of well conditions with a relatively small number of additives that are readily available from any cementing service company. Fluid-loss additives can be used with dispersants and small amounts of KCl (when applicable) to design slurries for most primary cementing applications—e.g., cementing in CO2 and salt-zone environments and prevention of annular flow after cementing. This paper illustrates how materials and slurry properties that are easily specified can be used to improve wellsite success.
Wellsite Information Transfer Specification (WITS) for Digital Rig-Site Data
Authors: Jantzen R. E. , Foreman R. D , Keltner L. , McCoy R. S. 
Published: December 2007

Summary
Information of many kinds, including drilling and mud-logging parameters, is transmitted electronically from rigs to central sites. The format of the transmitted information depends, at present, on the business entities involved in the information-transfer transaction. Many different formats exist, decreasing the overall utility of information obtained at the rig site and increasing processing costs for the industry. Standardization of formats for information content and telecommunication requirements was attempted by the Information Transfer Committee (ITC), a subcommittee of the Intl. Assn. of Drilling Contractors’ (IADC's) Rig Instrumentation and Measurement (RIM) Committee, which formulated a set of guidelines addressing the broad needs of the industry. This paper explains the rationale for the standardization effort; outlines the process by which the specification was established; and describes the requirements, concept, components, and benefits of the resulting WITS.
A New Method of Coating Oilfield Core for Laboratory Studies
Authors: Menzie D.E. , Dutta S. , Shadizadeh R.S. 
Published: December 2007

Summary
A new method has been developed for coating oilfield core for laboratory studies. It consists of applying a steel coating and aluminum wraps around the outer surface of a core. The strength of the coating, the short time needed to apply it, and its low cost are the major advantages of this new method.

Introduction
Laboratory core studies are commonly conducted to evaluate reservoir rock properties. In the past, epoxy, wax, and plastic coatings of cores have been used conventionally to conduct experimental studies. Because of various problems, such as leakage or fractures even under low pressures in these and other conventional coatings, a new method of coating and mounting a reservoir rock core was investigated. This new method of core coating and mounting was tested for leaks, fractures, and pore invasion and was found not to have leaks or fractures or to invade pore spaces up to a test pressure of 400 psig [2758 kpa]. The cores were not tested for higher pressures, but these metal-coated cores are expected to withstand a pressure of about 1,000 psig [6895 kPa] safely. Experiments may also be conducted at high pressures ranging from 2,000 to 3,000 psig [ 13.8 to 20.7 MPa] with an increased number of coatings and uniformly tight mounting connections.
Relative Permeability From Unsteady-State Displacements With Capillary Pressure Included
Authors: Civan F. , Donaldson E. C. 
Published: December 2007

Summary
A semianalytic method for calculation of relative permeabilities from unsteady-state displacement data is developed. The method is based on the simultaneous solution of the fractional-flow equation and an integro-differential equation, derived from the material-balance and Darcy equations for immiscible displacement of two incompressible phases, including the capillary pressure by use of various volumetric relationships. This method for calculating two-phase relative permeabilities from unsteady-state displacement data is not restricted to the high-flow-rate experimental conditions used to overcome capillary end effects. Removal of this restriction allows the analysis of low-permeability cores with water and oil where the flow rates are low and capillary end effects are important. Our method allows direct calculation from the experimental data without intermediate interpretations of graphs.
Suspended Solids Specifications for Water Injection From Coreflood Tests
Authors: Eylander J. G. R. 
Published: December 2007

Summary
A method based on the results of laboratory coreflood tests is proposed for predicting the injectivity decline rate of water injectors. The aim of this method is to provide design specifications for water treatment and injection facilities and procedures with which well injectivity behavior can be analyzed. To illustrate the results that can be obtained with the proposed method, data from coreflood tests are used to construct injectivity-decline-rate curves for an arbitrary injection well.
A Solvent Extraction Approach to Oil-Recovery Calculations From Laboratory Displacement Tests
Authors: Mezzomo R. F. , DeHolleben C. R. C. , Ferreira P. A. 
Published: December 2007

Summary
An experimental method is proposed for quantification of oil in effluent samples from displacement tests with liquids. On a mass basis, this new procedure is offered as an alternative to the classic volumetric approach.
A known amount of a suitable organic solvent with good selective solubility and density contrast relative to the oil phase is thoroughly mixed with the effluent sample. After centrifugation, the oil/solvent mixture is analyzed for density. Subsequently, the oil mass fraction in the pseudobinary mixture (oil/solvent) is obtained through a previously determined correlation of this parameter vs. density. With these data—amount of solvent and oil mass fraction—plus the definition of the latter in a binary mixture, one arrives at the actual mass of oil in the effluent sample.
The method is applied to a crude oil from Miranga field in the Reconcavo basin (northeastern Brazil). Accuracy is thoroughly analyzed and compared with that of the volumetric approach. The method is also tested under such severe conditions as emulsified oil production. Finally, recommendations are made to implement the method in continuous oil-recovery monitoring, which would be a major step in the full automation of laboratory displacement tests.
The Kern River Horizontal-Well Steam Pilot
Authors: Dietrich J. K. 
Published: December 2007

Summary
Sluggish oil response in the Kern River horizontal-well steam pilot was caused by placement of the wells in a reservoir environment unfavorable for application of either conventional oil recovery processes or novel oil-mining techniques. Encouraging pilot operational experience and the tremendous potential for improved ultimate oil recovery shown by preliminary simulations suggest that future pilot testing of horizontal-well steam technology is warranted in a more favorable environment.
Platform-Well Tieback Procedures at Island Esther
Authors: Jackson Elizabeth M. 
Published: December 2007

Summary
On March 2, 1983, Island Esther, a man-made producing island located 1 xh miles [2.4 km] offshore southern California, was destroyed by a severe winter storm. The 90 completed wells survived the storm, but some were badly damaged. In 1985, a platform was erected over these wells, and work to repair the wells began. This paper discusses the methods and equipment used for that operation.
Mechanisms Controlling Fracture-Height Growth in Layered Media
Authors: Ben Naceur Kamel , Touboul Eric 
Published: December 2007

SummaryThis paper considers the mechanisms that affect the lateral and vertical extension of a hydraulically induced fracture. These include natural mechanisms—such as contrasts in stresses, moduli, toughness, and leakoff—and those induced by leakoff and fluid heterogeneities. Treatment trends during the injection and closure are analyzed with a state-of-the-art 3D fracture model. The effect of the vertical fracture penetration on conductivity and water coning and the parameters influencing them are then quantified.
Calculation of the Leak Location in an Aquifer Gas Storage Field
Authors: Burnett Peter G. 
Published: December 2007

Abstract
A leak location method for aquifer gas storage fields utilizing nonsteady flow calculations is presented. The calculation method uses pressure responses in observation wells completed in a permeable zone in or above the caprock overlying a gas storage reservoir to locate leakage which exists in a single area. The leakage considered is localized - different from the leaky aquifer case which is well known to ground water hydrologists. Field data from an operating gas storage field where gas leakage exists are used to calculate location of the leakage. The location is determined graphically using water level changes in three observation wells. The leak location is calculated to be at distances from the observation wells proportional to the square roots of the times of equal pressure responses at the wells. No absolute values of porosity, permeability, sand thickness or composite water and rock compressibility are required in the graphical solution. The leak location method presented is generally restricted to gas storages which have single-point leaks. However, the method is also applicable in cases where all observation wells are relatively close to one leak, with distances from other possible leaks too far, or other leaks too small, to affect appreciably the water level responses of the observation wells.

Introduction
In underground gas storage operations leakage from the storage reservoir to higher porous formations sometimes occurs through fractures in the caprock, behind the casings of improperly cemented wells or through improperly plugged abandoned wells. If the leakage rate is too great, the storage field may be uneconomical to operate. Sometimes it is feasible to collect gas from wells drilled to the higher formations for reinjection into the storage reservoir. Nevertheless, leakage is an economic burden to the storage operation, and gas injection pressures and corresponding injection rates must be limited to control the leakage rate. Accordingly, it is highly desirable to determine the nature and location of the leakage and to correct it if possible. In the storage field discussed in this article, tracer tests were conducted which indicated that major leakage was occurring in the southern end. Three wells were drilled almost through the caprock surrounding the indicated general area of leakage, and an attempt was made to hydraulically seal off the leak by injecting water through a porous sand stringer in the caprock. Water injection proved unsuccessful in sealing the leak, probably because permeability of the sand stringer was too low to permit injection of water at sufficiently high rates. Following the attempt to seal the leak hydraulically, water levels of the three wells were measured continuously and calculations were made from data obtained to try to determine location of the leak. The calculation method developed considers lateral flow in a permeable sand within the caprock.
Electric-Submersible-Pumping Success in the Beatrice Field, North Sea
Authors: Kilvington Lindsay J. , Thomson Jack Y. , Brown Julien K. 
Published: December 2007

Summary
When the Beatrice field came into production in Sept. 1981, it was the first North Sea offshore oil field to depend from the outset on artificial lift to maintain production. In view of the low GOR of Beatrice crude, the use of electrical submersible pumps (ESP's) was the only feasible option. Maximization of the operating life of the downhole pump was obviously critical to the economic viability of the project.
This paper describes how the ESP performance at Beatrice has been progressively improved through diligent analysis of completion- performance data and failed equipment. The results have led to the optimization of completion design and the development of new and improvement of existing mechanical and electrical components.
On-Site Diagnosis of Cement Job Problems: The Concept of Job Signatures
Authors: Beirute R. M. 
Published: December 2007

Summary
Since the introduction of free-fall models for primary cementing, several companies have been monitoring cementing operations by continually measuring the rate of returns, the rate of pumping, the density of the fluids pumped, the density of the fluids returned to the surface, and the surface pressure.' Measured values of surface pressure and rate of returns have been compared to predicted values obtained with cementing simulators. 1–7 Discrepancies between measured and simulated behaviors that cannot be explained as normal simulation and job measurement limitations are attributed to problems that develop during the cementing operation. Although problems have been detected by this approach, in some cases it has not been possible to ascertain the exact cause of the misbehavior. Therefore, proper and timely corrective adjustments have not always been made during the job.
To improve our ability to diagnose cement job problems while the cement job is in progress, we investigated six potential job problems with a cement job simulator that includes free fall. The job problems were channeling, unsuspected (unmeasured) washout, lost circulation, influx, flow restrictions, and slurry dehydration. Representative graphs show the behavior trends for each of the six potential cement job problems. The graphs show the normal (without trouble) behavior and the departure from the norm for the problem situation. Lists of generalized "job signatures" for each case are also given. Characteristics that are considered the main indicators of each job problem are highlighted. Three field cases illustrate how the concept of job signatures can be used effectively to assist in detecting potential job problems during the actual job.
A New Calcium-Tolerant Polymer Helps To Improve Drilling-Mud Performance and To Reduce Costs
Authors: Ujma K.-H. W. , Plank J. P. 
Published: December 2007

Summary
Drilling fluids suitable for German Zechstein formation wells require fluid-loss polymers that tolerate up to 140,000 ppm of Ca/Mg and have temperature stabilities that exceed 350°F [177°C]. Problems experienced in previous wells with carboxymefhylcellulose (CMC) and poly anionic cellulose (PAC) are described. The use of starch with a new sulfonated polymer improved drilling mud performance and reduced costs. Major benefits come from a synergism of the new polymer with starch, resulting in a 50°F [25°C] gain in starch thermal stability. A similar temperature extension effect was found for such cellulose products as CMC or PAC after addition of the polymer. Field experience with the starch/new-polymer combination in Zechstein formation wells with depths to 15,750 ft [4800 m] shows excellent filtration control, hardness tolerance, and temperature stability for this system. A cost analysis confirms saving of 20 to 50% on fluid-loss polymer costs.
Mutual Solubility of Salts in Drilling and Completion Fluids
Authors: Kemp Nantelle P. 
Published: December 2007

SUMMARY
This paper describes models for predicting crystallization temperatures for pure- and mixed-salt brines. The models can be used to determine the solubility behavior of salt-containing fluids. Model predictions are compared to published mixing tables for heavy-brine completion fluids and to crystallization temperatures measured in the laboratory. Examples show how the models were used to formulate brine muds and to predict how much additional salt could be added to a produced brine mud to increase mud density without producing excess solids.
Method for Fracture-Gradient Prediction for Vertical and Inclined Boreholes
Authors: Aadnoy B. S. , Larsen K. 
Published: December 2007

SummaryA new method for the prediction of fracture gradients in deeper wells has been developed. The method is based on the principles of mechanics but uses a correlation method in the application of field data. The new, improved method (1) gives both leakoff and lost-circulation pressures; (2) works for vertical and inclined boreholes; and (3) identifies lithological effects. The result is given as a simple equation where only well depth, pore pressure, borehole angle, and lithology are needed to predict the fracture pressure. Because borehole inclination is included, the method can be used during both production and vertical-well drilling. The method was applied in a field study offshore Norway. The results show a remarkably good correlation with field observations.
Using Oligomeric Surfactants To Improve Oil Recovery
Authors: Chou S. I. , Bae J. H. 
Published: December 2007

Summary
Oligomeric surfactants are a unique class of surfactants that differ from conventional surfactants in their molecular structures. The hydrophilic portion of conventional surfactant molecules is usually smaller than their hydrophobic portion. For oligomeric surfactants, however, several polar and ionic functional groups, distributed along a hydrocarbon chain, form the hydrophilic part of the molecule. In addition, the hydrophilic part has a size comparable with or greater than the hydrophobic counterpart.
A number of surfactant/alcohol/oil/brine systems were investigated to evaluate the efficacy of oligomeric surfactants as cosurfactants in surfactant formulations. When used at a concentration of about 110 of the active surfactants, the resultant formulation exhibited higher solubilization capacity, lower interfacial tension (IFT), somewhat higher optimal salinity, higher salt tolerance, higher viscosity, and lower adsorption loss. These benefits may improve the economics of the surfactant flooding process and broaden its application range.
The mechanisms by which oligomeric surfactants affect the properties of surfactant formulations were investigated. Surface tension and potentiometric measurements showed that they formed mixed micelles with other surfactants and that they bound with divalent cations. These interactions lowered the activity coefficients of surfactants and counter-ions, thereby increasing the salt tolerance of the surfactant formulation while lowering the adsorption of surfactants on rock surfaces.
Oligomeric surfactants may also be used at low concentrations to improve waterflood performance in oil-wet reservoirs. Oil recovery in preferentially oil-wet Berea cores was significantly increased by use of a low-concentration surfactant slug. The higher oil recovery resulted from alteration of the rock wettability.