bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design and Operation of Jet-Bit Programs For Maximum Hydraulic Horsepower, Impact Force or Jet Velocity
Authors: Kendall H.A. , Goins W.C. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 238–250.

Abstract
Several investigations in recent years have shown that drilling rates are increased significantly with increased hydraulic horsepower. But, there has been no overall method of designing jet-bit programs that efficiently uses the surface power. A study of present practices indicates that frequently as little as 50 per cent of the possible effects at the bit are used.
Some observers have indicated that the best utilization of hydraulic horsepower (maximum effect on drilling rate) occurs when the bit hydraulic horsepower is maximum; others have stated that jet impact force is more important, and others have believed that maximum jet velocity is required. Limited efforts to date have shown some optimum conditions for bit hydraulic horsepower and impact, but these conditions cannot exist during drilling of a large part of the hole and do not provide a basis for designing a complete jet-bit program.
This paper shows the maximum obtainable bit horsepower, impact force and jet velocity at all depths, taking into account the limitations of the pump, piping, hole and minimum circulating rate for adequate cuttings removal. Ranges of operation are developed; and flow rates, surface pressure and bit pressures are specified for each range to provide a maximum of any one of the desired effects. It also is shown that, by proper selection of nozzle sizes and by following the rules presented, the maximum obtainable quantities can be effectively utilized from surface to total depth.
Finally, a simple graphical method of selecting nozzle sizes and flow rates is presented which can be used with familiar bit-company hydraulic tables and calculators to design jet-bit programs for maximum bit hydraulic horsepower, impact or jet velocity, as desired. These programs make most effective use of the pumps.
Heretofore, there was no method available for designing field tests which adequately separated the effects of bit horsepower, impact and jet velocity. The programs and procedures developed in the paper are dissimilar and, when used in future field testing, should demonstrate which program is the most important in obtaining the fastest drilling rate.
Chromatographic Transport of Reverse-Wetting Agents and Its Effect on Oil Displacement in Porous Media
Authors: Michaels Alan S. , Timmins Robert S. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 150–157.

Abstract
A study of the effect upon oil recovery from an unconsolidated porous medium of chromatographic transport of selected reverse-wetting additives during water displacement is described. Flow tests were performed on hydrocarbon oil-saturated sand columns (containing connate water) into which small volumes of short-chain aliphatic amine solutions were introduced during water flooding. Concurrently, measurements of oil-silica contact angles, oil-water interfacial tensions and oil-water distribution coefficients were measured as a function of additive concentration.
Certain treatments were found to cause a slight reduction in oil recovery, while others produced a significant increase (up to 50 per cent of the normal irreducible minimum oil saturation). Recovery efficiency was correlated most satisfactorily with the maximum degree of reverse wetting produced during additive transport; conditions which resulted in only mild oil wettability of the sand reduced recovery, while those favoring strong oil wetting increased recovery.
A mechanism of reverse-wetting additive action during chromatographic transport is developed which ascribes the results to transient changes in oil-solid contact angle during flow, with consequent release of oil trapped by capillary forces. implications of these observations with regard to improved waterflood efficiencies are discussed.

Introduction
The need for finding improved methods of oil production is amply illustrated by the large volume of oil considered economically unrecoverable by existing production practice. Water flooding has long been an excellent method of secondary recovery. However, even in those areas of a formation which are well swept by a water flood, 20 per cent or more of the oil remains trapped within the formation and is not recovered. This trapping of oil within the pores of the rock structure results primarily from interfacial forces. If these interfacial forces were altered, it is possible that the trapped oil could be released and recovered.
Performance Predictions for Low Productivity Reservoirs
Authors: Carter R.D. , Tracy G.W. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 195–200.

Abstract
Numerical calculations were made to determine the behavior of reservoirs with high-pressure drawdown and wide well spacing where the initial productivity is low and the wells are completed by hydraulic fracturing. The two-phase flow equations were solved for the flow into a single well. This well was assumed to be producing from a reservoir with hydraulically created horizontal fractures (four different systems with fractures were studied).
For comparison purposes, additional two-phase flow calculations were made assuming a reservoir with uniform rock properties. The two-phase flow results were also compared with the conventional calculation methods, which do not include the effect of saturation gradients resulting from a simultaneous flow of oil and gas which are normal to this type reservoir.
It was found that the conventional methods predicta high and too optimistic value of ultimate recovery,a high producing rate and a high reservoir pressure at a given oil recovery anda low trend of gas-oil ratio with oil recovery.
Included in the two-phase flow calculations were provisions to control the oil production rate by an allowable rate and, also, by a gas-oil ratio penalty rule. For the systems with hydraulic fractures, the producing rate was controlled by the gas-oil ratio penalty rule for most of the life. This is in contrast to the system with uniform rock properties which went "on decline" almost immediately. An unexpected characteristic of the systems which included fractures was the early rise in producing gas-oil ratio from 730 cu ft/bbl to approximately 1,200 cu ft/bbl, followed by a "leveling off" before the normally expected gas-oil ratio rise began. Additional features which are a result of hydraulic fracturing aregreater ultimate recovery,higher average producing rates anda lower average reservoir pressure at a given oil recovery.
Calculation of Crude-Oil Recoveries by Steam Injection
Authors: Landrum Bobby L. , Smith James E. , Crawford Paul B. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 251–256.

Abstract
A method is presented by which the displacement efficiency of a steam-injection process may be determined. The method consists of a determination of the position of the steam front at a particular time and the application of the Buckley-Leverett theory to the hot and cold regions of the reservoir with the appropriate hot or cold fluid properties. A uniform, linear flow system is assumed for this study.
The method is applied to a number of reservoir conditions. The primary properties which affect the results of a steam-injection process are the oil viscosities at steam and reservoir temperatures, injection rate, pay thickness and oil saturation.
The efficiency of steam injection is compared with that of water injection for a 10-acre, linearly flooded reservoir. In reservoirs where the oil viscosity is about 35 times the water viscosity, the steam process yields recoveries about 20 per cent higher than the waterflood. Where the oil viscosity is near 500 cp, the steam process may recover from three to four times as much oil as a water flood.

Introduction
In a previous paper, a method was suggested for evaluating a steam-injection process. Emphasis was placed upon the determination of the steam-front position in the reservoir at various times. In the present paper, the displacement process is studied in more detail. The approach is essentially that employed by Jordan, Rayne and Marshall in their study of hot-water injection.
The steam-injection process is quite complex, and an exact description of the process has not been found; however, a qualitative description can be made. When a quantity of steam is injected into a relatively cold reservoir, the leading edge of the steam front continually flows into cool sand, and some steam condenses. As more and more steam condenses, a bank of condensed water will form which is augmented by displaced connate water. The reservoir may be divided in three regions,a region containing displaced fluids at reservoir temperatures,a region containing water at reservoir temperature anda region occupied by steam. The reasons for the lack of a region of hot water or oil of any appreciable size have been discussed.
Design and Operation of Stage 1 of the KMA Waterflood, Southwest Unit
Authors: Calhoun G.H. , Sleeper W.J. 
Published: February 2020

Secondary Recovery Conference, 2–3 May, Wichita Falls, Texas

Abstract
The design and early operation of Stage 1 or this 4640-acre water flood unit, involving 45 working interest owners and 175 royalty owners, are described and illustrated. The KMA sandstone (Zones I and II), whose subsea depth is about 2800 feet, is the reservoir being flooded. Unitization was effected July 1, 1958, and Stage I, which covers 1800 acres, began operating on May 8, 1959.
The fundamental design principle, whose objective was to effect the maximum oil recovery from the minimum combined capital and operating costs, is no different than the aim of most well-planned projects; however, some of the flood facility features - such as centrifugal injection pumps, bare steel lines, simplicity of water conditioning, and the degree of automation - are somewhat pioneering for a secondary recovery project. For example, the automation, which includes complete electrification, affords routine operating control and emergency shutdown of any part or all the system.
As a result thereof, only four men - each working five 8-hour days per week- are required to operate Stage I, which includes 14 water source wells, 118flood wells (58 injection and 60 producing), and the central injection and treating plant having a nominal injection capacity of 40,000 barrels per day.
The system is entirely unattended 128 hours per week. Any operating upset or emergency, that might occur during an unattended period, automatically signals the local telephone exchange, which in turn calls the Operator's appropriate personnel who correct the defect.
Some 8,700,000 barrels of water had been injected at the end of January,1960, or an average of 32,400 barrels per calendar day. Limited yet encouraging flood response was realized by the end of 1959.

Introduction
The unitization for water flooding purposes of the southwestern portion of the KMA Field, which is now designated "KMA Water Flood, Southwest Unit", was first envisioned about 1949. The geographic location of the Unit is shown on Figure 1. Subsequent cooperative studies by several of the major leaseholders in the subject area indicated the engineering feasibility and economic justification of the project.
ESP Failures: Can We Talk the Same Language?
Authors: Alhanati F.J.S. , Solanki S.C. , Zahacy T.A. 
Published: February 2020

Abstract
Several operators have recently launched a new industry-wide initiative focused on sharing failure information, operational practices and other pertinent data, in an effort to gain a better understanding of the various factors that affect ESP run life in any one application. Early on, the companies involved acknowledged that there were many challenges in such an effort, one of the main ones being how to achieve consistency in the data collected by several operators.
This paper presents an approach to establish consistent practices for collecting, tracking and sharing ESP run life and failure information. The approach is based on two key elements:
- a general and common data set; and
- a standard nomenclature for coding ESP failure information.
The general data set contains basic information on operating conditions, ESP equipment, and the observed failures. While this data set is not overly detailed, in that the information is typically already collected by most operators and relatively easy to obtain, it is comprehensive enough so that meaningful analyses can be performed. The nomenclature standard builds on the International Standard ISO142241 and on the API Recommended Practice (RP) 11S12. Broad definitions and failure attributes follow the guidelines of ISO 14424, while nomenclature for components, parts and possible teardown observations follow the terminology suggested by API RP 11S1.
The paper also provides a review of the past practices in the industry, with regards to the types of data collected, and the main types of analysis performed with the data. Comments are included on difficult related issues, such as the tracking of used equipment and the treatment of running systems, when evaluating current operations or making future failure rate predictions.
It is hoped that the paper will encourage discussion on the topic, and help the industry share ESP run life data in a more consistent manner. The ultimate goals are to assist the industry improve ESP run life, expand the use of ESP's, and better realize the full potential of the ESP technology.

Introduction
Operators and vendors have long identified that having a failure tracking system in place is key to reducing failure rates of ESP systems3–33. Problems with system design, equipment specification, manufacturing, installation, and day-to-day operation can be identified and corrected, contributing to increased run lives, lower operating costs and increased profits. As a result, many operators and vendors have set up database systems to track ESP run life and failure information.
There's No Free Lunch, Pumping Two Phase Fluids with ESP
Authors: Wilson B.L. 
Published: February 2020

Abstract
This paper examines the conjecture that a properly designed centrifugal pump will have no problem with free gas. The centrifugal pump is a dynamic pumping device. One of the traditional limitations has been their inability to handle significant quantities of gas. This doesn't mean that it can't handle gas but there is a cost. The user must recognize the operation boundaries that depend on the situation and the equipment selected.
This presentation reviews the nature of gas in its relation to well production with Electrical Submersible Pumps and examines some gas handling methods and devices more recently introduced to the industry. It also attempts to quantify limitations to two phase production with ESPs.

What is Gas?
Crude oil is not by nature a homogeneous substance. It is a mixture of a large variety of elements and short, medium and long chain hydrocarbons. The API gravity of an oil can be interpreted as a bulk average of the substances present at standard conditions. Under sufficient pressure, the natural gas and the oil exist together in a liquid phase. When the pressure is decreased, the mixture expands. As pressure is continued to decreased, the elemental gases and lighter hydrocarbons molecules have sufficient energy to liberate themselves from the liquid to form a separate gas phase. The point at which the gas phase first appears is the bubble point. The composition of the gas at this point is a function of the solubility of the individual constituents in the remaining liquid. The lighter gasses tend to come off first. The gas phase is in a complex equilibrium state between the evolved substances and the substances still left behind in solution. As pressure continues to decrease, the gas phase expands and the liquid phase shrinks.
The Bubble Point is a property of the bulk solution. High bubble point crude oils may have larger volumes of gas in solution, and/or greater percentages of the light substances in the gas phase. Removing a portion of the dissolved gas changes the properties of the remaining crude. For a given sample of crude with a 5,000 psi bubble point, if the pressure is lowered to 3,000 psi and the gas cap is bled off, the remaining crude will have an increased API gravity, viscosity and a 3,000 psi bubble point.
The relation between the liquid phase and the gas phase is represented by the gas oil ratio (GOR). It represents the volume of liberated gas in contrast to the volume of liquid at standard conditions of temperature and pressure. This can be expressed as a direct ratio, (barrels per barrel, or cubic meter per cubic meter) or in Oil Field Units as standard cubic feet of gas per barrel of oil (SCF/BBL). GOR values of several hundred are common and values exceeding1000 are not unknown. The goal of artificial lift is to maximize the production of oil from a well and it is accomplished by drawing the well pressure down as far as practical.
Determination of Fracture Orientation from Pressure Interference
Authors: Elkins Lincoln F. , Skov Arlie M. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 301–304

Abstract
Inclusion of anisotropic permeability in mathematical analysis of pressure transients observed during development of the huge Spraberry field indicates a major fracture trend which is in good agreement with that observed by fluid-injection tests spread over a 12- by 17-mile area. Delineation of this trend is important in selecting a pattern of injection for the pending large-scale water flooding in this field. Determination of reservoir parameters yielding best agreement between calculated pressures and observed reservoir pressures in newly completed wells was made using an IBM 650 computer.

Introduction
The Spraberry field covering 400,000 acres is a tight sand of less than 1-md permeability cut by an extensive system of vertical fractures. Primary recovery dominated by capillary retention of oil in the fractured sand matrix blocks is less than 10 per cent of oil in place. Strong forces of capillary imbibition of water into the sand, coupled with water flow under dynamic pressure gradient, indicate considerable increase in oil recovery can be achieved through water flooding. Best results will occur if the pattern of water injection is selected to force the water flow across the grain of the major fracture system.
Existence of an oriented vertical fracture system in the Spraberry, observed first in cores, was highlighted more recently by the 144-fold contrast in permeability along and at right angles to the major fracture trend required to match relative water breakthrough times in Humble Oil and Refining Co.'s waterflood test there. Spraberry Operators since have conducted two gas-injection tracer tests for further areal confirmation of the fracture trend. Re-analysis of early reservoir pressure transients for evidence of anisotropic permeability has permitted many more local determinations of major fracture trend without resort to further field tests.
This paper is limited to updating analysis of reservoir pressure transients to include anisotropic permeability as a test for orientation of the major fracture trend in the Spraberry. The reader is referred to Ref. 1 and 2 for information about general Spraberry reservoir performance and to Refs. 3 and 4 for information about significance of fracture orientation in selection of the injection well pattern for water flooding the Spraberry.
Successful Application of Volatile Acid System to Treat Water Blockage in a Gas Well: A Case Study
Authors: Hussnain Muhammad Sana-ul , Anjum Zulfiqar Ali , Arif Muhammad , Ansari Mansoor Ahmed , Dar Afnan Ahmed , Temuri Saqib Jah , Yousaf Arif , Ali Yasir , Khokhar Saad Yousaf 
Published: February 2020

Abstract
Formation damage associated with water blockage is a common problem in oil/gas producing wells. Water blockage is a damage mechanism which occurs when water saturation increases near wellbore, resulting in reduced hydrocarbon saturation and relative permeability to gas. When pore spaces around the well get nearly saturated with water, it reduces gas saturation to near irreducible level that block the gas flow. It decreases the gas production and may recover naturally by extended flow back or excessive drawdown. However, in depleted reservoirs, gas production may completely be lost and shall require chemical treatment. In this paper, a case study has been presented illustrating the complete loss of production of a gas well owing to the water blockage and the treatment mechanism to restore the production (SPE 102383).
Well ‘A’ was drilled in Sindh, Pakistan in 2010 in Lower Goru Formation. Later, the well was put on compression and was found on natural decline. By Feb 2019, well was producing 1.14 MMSCFD gas, 6 BPD condensate, and 43 BPD water with 123 psi FWHP. In March 2019, well was shut-in for the pressure build-up (PBU) survey. However, when the well was opened to flow, there was complete loss of production.
Identification of the causes of production loss was a major challenge in designing the job. After analysis of well behavior, gradient survey data and formation properties, it was found that the loss of production was attributed to water blockage caused by prolonged exposure of water.
Based on above analysis, a stimulation treatment using Volatile Acid System was designed to address the water blockage. The improved cleanup with volatile acid can be expected for two reasons; (1) increased volatility and (2) lower surface & interfacial tensions (SPE-191292-MS). The increased volatility results in lower water saturation and improving relative permeability to gas. Volatile acid system lowers the surface tension and increases the vapor pressure (gas saturation/relative permeability of gas near the damaged zone) and improves the clean-up of spent acid and retained water. In addition, presence of alcohol in acid system helps in achieving deeper penetration into the rock matrix. The proposed solution of Volatile acid system proved successful not only in reviving well's production but also with a gain in production of about 300%.