bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Results of Miscible-Displacement Program Using Liquid Propane Driven by Gas, Parks Field Unit, Midland County, Texas
Authors: Marrs Doyle G. 
Published: June 2014

Abstract
A miscible-displacement program utilizing a propane slug driven by residue gas has been in operation in the Parks field unit approximately three years. A total of 1,540,000 bbl of liquid propane was injected into 23 wells between June, 1957, and July, 1958. During July, 1958, residue gas injection was begun at an injection rate of approximately 10 MMcf/D. Gas has been injected at this rate to the present time, and cumulative gas injection to July 1, 1960, has totaled 6,871 MMcf. It is concluded at this time that the project can be declared an engineering success since field results indicate an oil bank has been created by a gas-driven propane slug. It is further concluded that the project will be an economic success insofar as additional oil recovery over primary is concerned. However, the project has not been in operation a sufficient length of time to declare it an economic success in regard to oil recovery over that which it is believed could have been obtained by water injection. The answer to this question is yet to be determined. It is estimated that the ultimate recovery of the oil originally in place would have been 17 per cent by primary depletion, 41 per cent by water injection and will be 55 per cent by propane-gas-water injection.

Introduction
Miscible displacement is an oil-recovery process which is rapidly gaining popularity inasmuch as the process recovers 100 per cent of the oil in place in the swept volume. In comparison, straight gas injection normally recovers only 45 to 55 per cent, and water injection recovers 60 to 70 per cent of the oil originally in place in the swept area. The Parks field unit is an early field-wide example of the slug-type miscible-displacement process wherein a slug of fluid is injected into the reservoir which is miscible with both the reservoir and displacing fluids. In the Parks project, the slug was composed essentially of propane, and the displacing fluid is residue gas which is miscible with the propane at the existing reservoir conditions. Laboratory tests indicate extremely high recoveries from the swept reservoir volume by the miscible-slug process, but this is only a partial answer to the economic applicability of the process in an actual reservoir. The final answer can only be determined by field tests. The two main questions which must be answered through field testing are the following. How much volume will be swept? What minimum-size LPG slug can be utilized and still maintain miscibility throughout the process? Obtaining answers to these questions were two of the many objectives considered in arriving at the decision to install a field-wide miscible-slug process of such magnitude as the Parks project.
Simplified Analysis Aids in Optimizing Drilling Factors for Minimum Cost
Authors: Wardlaw H.W.R. 
Published: June 2014

Abstract
This paper shows how the cost of the drilling operation per 100-ft drilled can be related directly to bit weight, rotary speed and hydraulic horsepower variations. This enables optimum drilling conditions to be determined in a rapid and concise manner. The paper also shows how data/or such calculations can be obtained quickly and accurately by the "drill-off" method suggested by Lubinski. Examples are given to illustrate the principles and methods used.

Introduction
The problem of drilling oil wells at lowest cost and hazard needs little introduction, since it has been with us virtually from the earliest days of our industry. With better understanding of the effect of the various factors of bit weight, rotary speed and hydraulic jet action, however, the problem has recently taken on a more scientific aspect, and engineers or groups of engineers have been assigned to study many of the facets of this problem not immediately apparent to the general observer. Moreover, the availability of better equipment and materials has enabled certain practices to be adopted which were hitherto impractical or uneconomic. This has paved the way for further efforts to reduce footage costs, and so on. The improvements to be made in drilling technology and cost reduction are by no means exhausted, and we still frequently hear of new records being set and new materials and equipment becoming available. Some of the analytical methods used by the author to assist in promoting faster and more economic methods of drilling, particularly in Venezuela, form the basis for this descriptive study.

Statement of Theory and Definitions
In a highly competitive industry, it is no longer permissible to regard penetration rate as the sole criterion for drilling efficiency. Every new technique, however spectacular, must nowadays be viewed in the cold light of whether it will eventually lead to lower cost per foot drilled. In the exposition which follows, therefore, actual drilling rates will play only a secondary role, and attention will be focused on the more important aspect of cost per foot drilled. Changes in drilling factors such as weight and rotary speed will be studied in the light of how they directly affect the cost of operations.
Novel Large-Hydrophobe Alkoxy Carboxylate Surfactants for Enhanced Oil Recovery
Authors: Lu Jun , Britton Christopher , Solairaj Sriram , Liyanage Pathma J. , Kim Do Hoon , Adkins Stephanie , Arachchilage Gayani W. , Weerasooriya Upali , Pope Gary A. 
Published: June 2014

Summary
A new class of surfactants has been developed and tested for chemical enhanced oil recovery (EOR) that shows excellent performance under harsh reservoir conditions. These novel Guerbet alkoxy carboxylate (GAC) surfactants fulfill this need by providing large, branched hydrophobes; flexibility in the number of alkoxylate groups; and stability in both alkaline and nonalkaline environments at temperatures up to at least 120°C. The new carboxylate surfactants were recently manufactured at a cost comparable to other commercial EOR surfactants by use of commercially available feedstocks. A formulation containing the combination of a carboxylate surfactant and a sulfonate cosurfactant resulted in a synergistic interaction that has the potential to reduce the total chemical cost further. One can obtain both ultralow interfacial tension (IFT) with the oils and a clear aqueous solution (even under harsh conditions such as high salinity, high hardness, and high temperature with or without alkali) with these new large-hydrophobe alkoxy carboxylate surfactants. Both sandstone and carbonate corefloods were conducted, with excellent results. Formulations were developed for both active oils (contains naturally occurring carboxylic acids) and inactive oils (oils that do not produce sufficient amounts of soap/carboxylic acid), with excellent results.
Experimental Stress Analysis of Tool Joints
Authors: Gormley John F. 
Published: June 2014

Introduction
Drill pipe, and the connections used to join the pipe together, have had a long history of development and improvement. With the growing use of high tensile-strength pipe, the rotary shouldered connections used to join the lengths of drill pipe have become more critical. Fatigue-type failures of rotary-shouldered connections, or tool joints, have become a cause of much concern to operators and manufacturers. Most fatigue tests on tool joints have been made on the basis of bending moment applied vs number of cycles, rather than on the basis of stress vs cycles. A desire to learn more about the nature of stress in a tool joint due to bending caused a rather intensive experimental study to determine what actually happens to cause fatigue failure. It was known that a tool joint with insufficient make-up torque was subject to early fatigue failure. Therefore, the establishment of the relationship between make-up torque and allowable bending moment would enable a testing engineer to better correlate the results of various tests. The problem of calculating the stress in a tool joint due to an applied bending moment was complicated by: the effect of unknown stress concentrations; the applicability of the well known formula S = Mc/I; and the question of whether to use the combined cross section of the pin and box in calculating the moment of inertia I.
The Characteristics of Relative Permeability Curves in Naturally Fractured Carbonate Reservoirs
Authors: Lian Peiqing , Cheng Linsong 
Published: June 2014

Summary
In naturally fractured reservoirs, fractures are the main flowing channels, while matrix is the dominant storage space. The oil/water relative permeability curve for the fracture in this kind of reservoir is very important to water-injection field development. In this study, we conducted experiments on the oil/water relative permeability of carbonate cores from Kenkiyak oil field and compared the differences in relative permeability curves between natural matrix cores and artificial-fracture cores. After the fracturing process, the two-phase flow area of tested cores becomes narrower, the permeability of the equal-permeability point gets higher, the relative permeability curve rises or drops more rapidly, and the displacement recovery efficiency decreases. The stress-sensitivity characteristics of the relative permeability curves were also studied on the basis of experiments on naturally fractured cores. With increasing effective confining pressure, the irreducible water saturation increases, the residual-oil saturation changes slightly, the equal-permeability point moves downward, and the displacement recovery efficiency declines. Numerical-simulation results indicate that for a given recovery factor, the water cut would increase more slowly but ultimate recovery factor would decrease using the relative permeability curve under higher confining pressure. Therefore, the water injection should be operated when the reservoir pressure is relatively higher to maintain formation pressure during waterflooding and lower the impact of stress sensitivity accordingly.
Review on Materials for Corrosion Prevention in Oil Industry
Authors: Arora Anshul , Pandey Siddharth Kumar 
Published: June 2014

Abstract
Among the many challenges faced in production and refining of crude oil, corrosion stands out due to its potential impact and associated economic and safety concerns. The primary cause of corrosion is the presence of mineral acids such as hydrogen chloride formed by hydrolysis of salts present in crude oil. Currently, significant research efforts have been devoted to design and develop new materials and procedures to reduce the water content and neutralize the acids in crude. These efforts have resulted in development of new corrosion-proof materials for coating in pipelines, chemical reagents and surface active substances for neutralization of acids as well as breaking of emulsions. Anionic, cationic and non-ionic surface active reagents are reported to be effective in demulsification application. Particularly the amphiphilic block copolymers, such as polyetyleneoxide-block-polypropylene oxide are used globally for the process of demulsification. Various organic amines are used in the overheads of atmospheric columns for neutralization of acids. Numerous nitrogenated compounds are also used as corrosion inhibitors in different refining operations. HERCULES-30617, KEMLIX-1123X and DEOL-4241 are some of commercial names used for the purpose of corrosion inhibition.
Hence we are deeply motivated to review all the recent research progresses that will provide us the impetuous to analyze the existing shortcomings and design and develop new materials with possible applications in above mentioned areas.
Impact of Different SAGD Well Configurations (Dover SAGD Phase B Case Study)
Authors: Tamer Mohamed R. , Gates Ian D. 
Published: June 2014

Summary
The volume of heavy oil and bitumen in the oil-sands deposits in western Canada is similar to that of conventional crude oil in the Middle East. This resource is immense but is difficult and energy intensive to extract because the viscosity of the oil is high, typically greater than 100,000 to 1,000,000+ cp at original reservoir conditions. Current commercial thermal-recovery processes used include steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). These methods are energy intensive, emit significant amounts of CO2 into the atmosphere, and use large volumes of water to recover the oil. In this work, the focus is on SAGD processes. It has been demonstrated that operating strategy can be altered to improve SAGD performance, but it is not clear how well configuration can be changed to improve recovery, energy intensity, thermal efficiency, water use, and flue-gas emissions. This paper examines the impact of position and geometry of steam injectors on the performance of steam-based gravity-drainage processes in a heterogeneous reservoir. Different injection-well configurations including single horizontal (typical SAGD), offset SAGD, and vertical/horizontal well combinations have been evaluated by using a detailed, 3D, geostatistically populated, large-scale thermal reservoir-simulation model derived from core-data examinations of the Dover pilot site. The research reveals how injection-well configuration impacts energy delivery to the reservoir, how it affects thermal efficiency, and how it changes the evolution of the steam-conformance zone and oil-flow dynamics in the reservoir. The results suggest that several vertical injectors have the potential to deliver steam more efficiently than a single horizontal injector.
Reliability and Uncertainty of Prediction of Dynamic Elastic Constants in Reservoir Rock
Authors: Nejati Hamid Reza , Ghazvinian Abdolhadi , Saemi Mohsen 
Published: June 2014

Summary
The prediction of dynamic elastic constants of reservoir rocks is one of the most important aspects of petroleum engineering. In recent years, several studies have been performed for this purpose. Because of uncertainty and variability in natural materials, deterministic prediction of rock properties in the reservoir is not reasonable. The purpose of this study is to evaluate uncertainty in dynamic-elastic-constant prediction for reservoir rock. Dipole-shear-sonic-image (DSI) log data from one of the Saudi Arabian reservoirs are used to evaluate uncertainty in dynamic-elastic-property prediction. For this purpose, a multiple linear regression (MLR) is carried out to present an empirical equation for shear-wave (S-wave) velocity prediction. Then, probabilistic analysis using Monte Carlo simulation (MCS) is performed to evaluate the uncertainty and reliability in prediction of dynamic elastic constants (Young's modulus and Poisson's ratio). On the basis of the analysis, uncertainty and variability of rock elastic constants are considered, and the value of Young's modulus and Poisson's ratio in a special interval from the reservoir are determined with a certain probability. Finally, the impact of log-data parameters on the value of rock elastic constants in the reservoir interval is assessed.
Deep Ground Bed for Casing Cathodic Protection
Authors: Daly John P. 
Published: June 2014

Abstract
This paper deals with the application of a deep ground bed (1,000 ft) for casing cathodic protection. While several ground beds of this type have been used successfully in the cathodic protection of surface lines, this is the first attempt to control external casing corrosion with a ground bed located in the corrosive zone.
Early and incomplete data indicate favorable results, with certain minor mechanical problems still to be solved. Actual corrosion protection has not been determined, but field surveys correlate with anticipated equipment performance.

Introduction
Severe external casing corrosion has been apparent for years in the West Kansas area, more precisely through the Dakota sandstone, a large water-bearing reservoir. New casing has been known to fail within a year, and repair costs average $5,000 per failure. Since casing corrosion protection is a relatively new field and has frequently shown poor results, the majority of the wells drilled in this area are still without protection of any kind.
A cathodic protection program study indicated that conventional ground bed designs have three major disadvantages.Poor current distribution occurs along the casing string. The conventional rectifier-ground bed system involves burying numerous non-sacrificial anodes about 100 ft from the well head and some 10- to 20-ft deep. It is from these anodes that current is supplied to the casing. However, corrosion usually occurs opposite, water-bearing formations located at a remote distance from the ground bed. Logically, a large amount of current is ineffective in the protection of the corrosive areas.High top-soil resistances during dry seasons result in overdesign of equipment and expensive electric-power bills or insufficient current densities.Interference with surface equipment occurs. Since the immediate ground bed area is highly corrosive to all structures not electrically connected to the system, it is always time-consuming and expensive to locate and protect all buried equipment in the vicinity of the anodes.
The logical solution to these three problems is to locate the ground bed in the Dakota water, approximately 1,000-ft deep. Early investigation indicates that satisfactory results can be anticipated from this type installation.
Quantitative Properties From Drill Cuttings To Improve the Design of Hydraulic-Fracturing Jobs in Horizontal Wells
Authors: Ortega Camilo , Aguilera Roberto 
Published: June 2014

Summary
The study proposes a method for quantitative determination of porosity, permeability, and rock-mechanics properties from drill cuttings of at least 1 mm. The porosity value is used for determining a brittleness index by implementing sonic-derived porosity theory and a dipole sonic log from an offset well. A new parameter is introduced in this work to give a quantitative value to microscopic observations related to natural-fracture features in drill cuttings. It is called “frac value” and in conjunction with the brittleness index and permeability constitutes the main result of the methodology: the cut log. Quantitative data extracted from drill cuttings are important because the amount of information collected in horizontal wells drilled through tight formations, including cores and well logs, is rather limited in most instances. This paper is based on a Canadian case study with implications for selecting optimum intervals for hydraulic fracturing in a tight gas reservoir. However, the method should also be suitable for global applications in all types of reservoirs (unconventional and conventional) where good-quality drill cuttings might be available. Data extracted from the previous steps are useful for multistage hydraulic-fracturing 3D simulation of horizontal wells. This provides additional information to stimulation designers for deciding where to initiate hydraulic fractures and how to optimize fracture spacing and fracture size per stage instead of considering a homogeneous reservoir volume throughout the whole lateral section. It is concluded that the proposed method provides a useful tool for evaluation of direct sources of information that are available in many cases (drill cuttings) but are rarely evaluated quantitatively. The proposed method allows improved design of multistage hydraulic-fracturing jobs in horizontal wells.
The Effect of Coil Design on the Performance of the Induction Log
Authors: Duesterhoeft W.C. , Hartline Ralph E. , Thomsen H. Sandoe 
Published: June 2014

Abstract
The attenuation and phase shift which formations produce in the electromagnetic field of an induction-type electrical well-logging instrument are great enough to substantially affect the response of the tool to formation conductivity under normal logging conditions. The application of the general equations for the propagation of an electromagnetic field in a conductive medium to the transmitter receiver coil pair of an induction-logging-tool coil system gives an expression for the response which properly takes the propagation effects into account.
A comparison of a calculation of this type with the response computed from the commonly used geometric factor concept, which does not include the propagation effect, leads to a factor G representing the ratio of the responses computed by the two methods. The value of G decreases not only with increasing formation conductivity, but also with increasing transmitter-to-detector coil spacing. For a single coil pair with a 40-in. spacing, the value of G is 0.972 in a 20-millimho/m formation. The value is reduced to 0.915 and 0.812 for conductivities of 200 and 1,000 millimhos/m. As a result, the basic signal generated by the induction-logging coil system is not linearly related to formation conductivity as expected from the geometric factor concept. A uniform conductivity scale can be obtained only by adding a suitable nonlinear element to the recording system. The addition of auxiliary coils, having spacings less than the main-coil span, to achieve focusing results in an even greater departure of the basic signal from linearity with conductivity.
The solution of the field equations near the interface between two formations of different conductivity gives the curve shape on an induction logging tool in crossing the interface. The addition of auxiliary coils to achieve focusing can add anomalous character to the curve shape in crossing the interface, which might be mistaken for lithological detail.
Preliminary calculations which include the propagation effects in the determination of the conductivity correction for thin beds lead to correction factors which are substantially smaller than those obtained from geometric factor considerations. It is apparent that thin-bed corrections derived from geometric factor calculations are of doubtful validity.
Benchmarking of Biocidal Chemistries for the Control of Corrosion Biofilms
Authors: McGinley Heather R. , van der Kraan Geert M. 
Published: June 2014

Abstract
Description of the Material Corrosion-associated biofilms found in oilfield pipelines are complex systems that typically form anaerobically under turbulent flow conditions, consume the metal substrate on which they form, produce hydrogen sulfide, and often have corrosion products or waxes embedded in their extracellular matrices. A model pipeline has been constructed in the laboratory to approximate these conditions. The development of this laboratory capability has enabled the screening of a series of biocides as treatments for corrosion-associated biofilms in a seawater system.
Application Corrosion in general is a constant concern in production and transmission systems, and the carbon steel pipelines that carry water, mixed phases, or water-laden hydrocarbons, are especially at risk for microbiologically influenced corrosion (MIC). The presence of water and nutrients encourages the propagation of bacterial communities and the formation of biofilms, especially on internal surfaces of pipelines. Once these biofilms are established they can quickly develop into breeding grounds for pitting corrosion. In order to control MIC, it is essential to have a method, such as properly applying an effective biocide, to control corrosion biofilms.
Results, Observations, and Conclusions The benchmarking process identified candidate chemistries that are effective at killing biofilm-associated bacteria in the model pipeline system. Further testing suggested that a periodic slug dose can help to kill and remove biofilm while preventing undesirable increases in planktonic cells and hydrogen sulfide levels. These results and treatment recommendations will be discussed in this paper.
Significance of Subject Matter The benchmarking results indicate that corrosion biofilms can be effectively treated with biocides. Guidelines have been established for the effective dosing of these formulations to help control MIC in pipelines, and will be presented herein.