bluuebunny/crossref_metadata_2025_split huggingface dataset:
Future Trends in Supply of Petroleum Engineering Manpower (Glenn)
Authors: Glenn Wayne E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction
It is my distinct pleasure to be here with you today to talk on a subject that has great interest for me—petroleum engineering. Having worked as a petroleum engineer for a good part of my oil career and being directly associated as a manager for the remainder of it, I feel a strong sense of allegiance and concern for the future of petroleum engineering. As a discipline, it has had spectacular growth and contributed immensely to the technological capability of our industry. It will influence in large measure where we as an industry will be tomorrow.
Petroleum engineering began to emerge shortly after Drake drilled his first well at Titusville, Pa. Men without formal engineering training began to grapple with problem aspects of drilling, production, and oil reservoirs, which in our day have come to be known as petroleum engineering. A formally taught and petroleum engineering. A formally taught and practiced discipline was not on the oil scene practiced discipline was not on the oil scene really until about 1915. From that time on, it grew rapidly and fostered a breed of men from which much of the leadership for the industry has come. They were and still are a group with great breadth of understanding in relating human problems and skills, economics, risks, technical problems and skills, economics, risks, technical and practical know-how, all of which interplayed to help mold a great and bold industry. It is an industry capable of yielding results against difficult odds generated from complexity and from the physical environment. The understanding of risk and probabilities (generated from natural factors) is a game we must play to be in this business. Over the past 50 yews, we have overcome some risks through new technology, and other risks have cropped up. The net result is that the business is still risky.
A point that consistently emerges is that the best leadership for the production part of the business was and continues to be found in those who have a thorough understanding of all the factors involved in locating, drilling, producing, and employing economic and technical producing, and employing economic and technical analysis of reservoirs. This is the widely accepted broad definition of petroleum engineering.
Since the upstream side of the oil business will continue to drill wells and produce reservoirs for some time to come, there will be a need for experienced oil men to provide leadership, operational know-how and technical and economic assessment.
When we view what is occurring in the oil industry in the United States, we get concerned as to what the future holds.
Enhanced Wireline Formation Tests in Low-Permeability Formations: Quality Control Through Formation Rate Analysis
Authors: Lee Jaedong , Michaels John 
Published: December 2007

Abstract
Wireline Formation Test (WFT) tools are used to measure formation pressures at discrete depths and to obtain fluid samples. From these pressure tests, fluid density and fluid contacts can be derived.
The transient pressure response created by a WFT pressure test has typically been analyzed by methods that originated from well test analysis. In 1996 a new method based on the formation flow rate was developed that simultaneously considers both drawdown and buildup portions of the data. Because the new method is based on material balance from the beginning of the test, it accounts for the storage effect in the tool. By a simple, graphical technique or multi-regression analysis, the method determines fluid compressibility, mobility, and undisturbed formation pressure (P*).
Pressure tests in low-permeability formations have been hampered by problems, such as excessively long buildup time, supercharging, and loss of packer seals. In addition, pressures with insufficient drawdown volume are confused with tight formation tests. These problems result in abandonment of tests or incorrect formation pressures that eventually give false pressure gradients, and waste rig time.
We have analyzed numerous field and test-well jobs and have found that good pressure tests in a low-permeability formation can be achieved in less time by implementing quality control procedures through the new method. The ability to repeat a pressure test provides a good basis for applying quality control measures while logging. When the new method indicates a tight formation for the initial test, the drawdown rate for a subsequent test is controlled to a very low rate (less than 0.5 cc/s) and a real time cross plot of formation rate versus pressure is monitored to ensure the quality of the data.
The new method can also detect tool plugging and the presence of pressure supercharging. These abilities can assess the validity of a test during testing and thereby provide a way to assure that a test is successful.
Pressure Transient Response for a Naturally Fractured Reservoir With a Distribution of Block Sizes
Authors: Spivey J. P. , Lee W. J. 
Published: December 2007

Abstract
A number of authors have questioned the assumption of pseudosteady-state matrix-fracture flow in the Warren and Root model. The assumption of uniform block size has not been investigated extensively, however. The consensus is that fracture spacing, rather than being uniform, follows a distribution similar to an exponential distribution.
This paper examines the effects of an exponential distribution of fracture spacing on the distribution of block size, interporosity flow coefficient, and the resulting pressure distribution. The paper also discusses a number of alternative models for naturally fractured reservoirs that give rise to pressure behavior very similar to that predicted by the Warren and Root model.
Variation in Fracture Permeability in Chalk Core Plugs
Authors: Olsen D. , Nielsen C. M. , Bech N. 
Published: December 2007

Abstract
A miscible displacement experiment where D2O brine was displaced by H2O brine was conducted on a North Sea chalk sample with an induced fracture. The experiment was monitored by a 2D NMR technique. Differential pressure and production of D2O were logged.
The displacement process was a combination of a pistonlike displacement proceeding from the inlet end plane, and a displacement proceeding from the fracture into the matrix. NMR images show large axial variations in the amount of fluid transport across the fracture-matrix boundaries, indicating the presence of a significant permeability variation along the fracture.
The variation in fracture and matrix permeabilities are determined numerically by matching measured and calculated pressure drops, H2O/D2O concentration profiles and cumulative production. An ECLIPSE model with a fracture containing two partial blockages closely simulates the concentration profiles and the production. Calculated results indicate that the permeability at the blockages is below one tenth of the fracture permeability. The pressure drop across the plug increases with time indicating that the degree of fracture blockage is growing with time.
Economic Fracturing of Bypassed Pay: A Direct Comparison of Conventional and Coiled Tubing Placement Techniques
Authors: Marsh J. , Zemlak W. M. , Pipchuk P. 
Published: December 2007

Abstract
This paper presents a study of low-permeability gas wells located in the Rocky Mountain foothills of Alberta, Canada, where production enhancement often involves various stimulation techniques to improve well production. We evaluated conventional techniques to a novel fracturing technique using the latest in fracturing fluid and coiled tubing technologies to concurrently and selectively place fracture treatments into multiple pay zones or stringers.
The coiled-tubing hydraulic stimulation technique was an excellent method for stimulating multi-zone wells, resulting in savings of $300,000 per well on the three Wildcat Hills Viking wells. The minimal operation and improved clean up time accounts significantly in being able to bring the wells on production 4 to 8 days sooner than with conventional methods for multi-zone wells.
Our approach describes the background, history and the impact of our successful utilization of coiled-tubing technology to convey hydraulic fracturing in the Wildcat Hills. The impressive benefits of this alternate and selective approach is improved control of net height and optimized effective fracture length. In addition to the substantial return in favorable production and economics, the design is acceptable for use in the ecologically sensitive area of the Canadian Rockies.
Acquisition, Calibration, and Use of the In Situ Stress Data for Oil and Gas Well Construction and Production
Authors: Avasthi Jitendra M. , Goodman Harvey E. , Jansson Ray P. 
Published: December 2007

Abstract
In situ stress data plays a vital role in various stages of oil and gas well construction and production, such as drilling, well completion, well stimulation, production, and waste reinjection. But generally, its acquisition does not receive as much attention as it deserves, and some times no attempt is made to collect this significant information. Most of the time lack of this information is compensated by the guess or indirect stress related information. This situation is evident from the scarcity of directly measured stress data in oil and gas fields throughout the world. Within Chevron, we have used open hole log data, pore pressure measurements, leak-off tests, formation integrity tests, mini-frac tests, drilling performance data, and caliper data to decipher in situ stress information. The collected data is calibrated using an open hole log based algorithm, linking stress profiles, mechanical properties from core tests, mini-frac and drilling performance data. In situ stress data provides valuable insight into wellbore stability problems, fine tuning fracture stimulation designs, the prediction of sand production, and to analyze the waste (drilling mud and cuttings) injection situations into selected formations. Essentially, the strong linkages created between various engineering applications are put to practical use in constraining the earth stress solution. This approach helps ensure that the final product is an integrated solution that solves the well design problems at hand. This paper discusses various aspects of in situ stress data acquisition, calibration, and use within Chevron with relevant field examples.
Reduce Power and Maintenance Costs of Power Fluid Conditioning Units by Improving Overall Operations
Authors: Justus Marvin W. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Single-well hydraulic pumping units are commonly called Power Fluid Conditioning Units (PFCU). The power cost per barrel of fluid lifted with a PFCU was reduced significantly by the installation of a four-speed transmission and a new style low-volume subsurface pump. The changes provided the flexibility necessary to obtain economically maximum production from both low and high volume wells.
The hydrocyclones were resized for proper operation which reduced the volume of abrasive solids in the power fluid. When the solids load was reduced, the operating life of the hydraulic pump and engine was increased.

Introduction
Presently, in a West Texas oil field, there are 39 single-well hydraulic pumping systems in operation. A single-well hydraulic pumping system contains two basic components, a surface unit and a subsurface unit. The surface unit consists of a high pressure multiplex pump, volume tank and solids removal device. The subsurface equipment includes a reciprocating positive displacement hydraulic engine which is positive displacement hydraulic engine which is direct-connected to the reciprocating production pump. High pressure fluid from the surface pump pump. High pressure fluid from the surface pump actuates the subsurface engine and pump.
Approximately 56 percent of the units are considerably oversized for the present producing rates. The multiplex pump is powered with a direct-drive electric motor. Therefore, if the subsurface pump is oversized for the fluid producing capacity of the well, a portion of the producing capacity of the well, a portion of the high pressure power fluid is bypassed and power is wasted. The units are installed in a relatively new secondary recovery project; therefore, the fluid production of the wells is expected to increase. Until the anticipated production increase is realized, modification of equipment is required for the reduction of excessively high power and maintenance costs.
The first consideration was to reduce the amount of bypassed, pressured power fluid. Five different methods were evaluated.Change existing gear ratios in the original gear reducer.Change plunger sizes in the multiplex plunger power fluid pump.Add belt drive speed reduction.Remove one plunger from the multiplex pump.Add a multi-speed transmission between the motor and pump.
Three-Phase Oil Relative Permeability Models
Authors: Dietrich James K. , Bondor Paul L. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Two variations of an indirect technique for predicting three-phase oil relative permeability are described in this paper. permeability are described in this paper. Relative permeabilities and the dependence of waterflood residual oil saturation on trapped gas saturations predicted by these two models are compared with the three-phase experimental data available in the literature.
Both models provide acceptable schemes for interpolating in the three-phase region, and qualitatively match the curvature of isoperms generated in the more carefully conducted (and previously published) threephase experiments.
Limitations of each model are described, including the need for establishing derivative constraints to prevent calculation of relative permeabilities greater than unity. Guidelines are also presented for determining which model should be used in specific applications.

Introduction
Thorough analysis of a displacement process in which three-phase flow predominates process in which three-phase flow predominates (viz. steam drive and alternate gas/water) requires three-phase relative permeability data. The effort involved in determining these data experimentally suggests that indirect methods should be investigated. The difficulty in direct experimental work lies mainly in determination of saturation distributions along the length of the core. Electrical resistance circuits and either gamma-ray or x-ray absorption techniques are required to measure two of the three saturations in a three-phase system. Only nine experiments concerning three-phase relative permeability have been found in the literature.
As an alternative to the direct methods, Stone has suggested that more easily measured two-phase data can be used to predict relative permeability to both the predict relative permeability to both the wetting and nonwetting fluids in three-phase flow. Then an indirect approach involving a technique which uses two sets of two-phase data-water/oil and gas/liquid - can be used to predict the relative permeability of the predict the relative permeability of the intermediate wettability phase.

THE TWO RELATIVE PERMEABILITY MODELS
Two variations of the indirect technique are described here. The first is a three-phase oil relative permeability expression developed by Hirasaki. This is a modification of a model originally proposed by Stone in 1970. The second model was presented in a paper by Stone during 1973, as a revision paper by Stone during 1973, as a revision of his first technique.

Model I
It has been observed experimentally in water-wet systems that the water relative permeability is approximately only a function of permeability is approximately only a function of the water saturation, and that the gas relative permeability is approximately only a function of permeability is approximately only a function of the gas saturation.
Casing Stresses Caused by Buckling of Concentric Pipes
Authors: Christman Stan A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A technique is developed to analyze the buckling stability of multiple, concentric pipes If the system is unstable and buckles against a lateral support such as an irregular open hole, an estimate is made of the elastic stresses and pipe curvature. Example applications are pipe curvature. Example applications are presented in offshore platform wells, in floating presented in offshore platform wells, in floating drilling, and for partially cemented surface casings.

Introduction
In the design of oil and gas wells, it is often necessary to consider the stability (tendency to buckle) of casing and tubing. Previous literature has shown methods to Previous literature has shown methods to determine the stability of a single pipe under complex loadings, and methods are available to determine the resulting geometry and stresses of a pipe which has elastically buckled into a helix inside of a uniform outer pipe.
The technique in this paper describes the behavior of a system of concentric pipes. It further provides an approximate calculation methods of the system geometry after helical buckling has occurred against a lateral restraint of non-uniform diameter.
Three example applications of the concepts are given:The effect of drill pipe tension on the stability of a marine riser in floating drilling,the required spacing of lateral supports for oil-well conductors on an offshore platform, andbuckling of an oil-well casing nest against a partially uncemented open hole.

Stability of Concentric Pipes
The following derivation shows how the tensions and compressions of the individual pipes contribute to the overall stability of a multiple pipe system. Specifically, the stability load pipe system. Specifically, the stability load of the system is shown to be the arithemetic sum of the individual loads (Eq.1), and the total system stiffness is the sum of the individual moments of inertia (eq. 2).
Prediction of the Permeability of a Fragmented Oil Shale Bed during In - Situ Retorting with Hot Gas
Authors: Needham R.B. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The operability of in-situ oil-shale retorting has been established by retorting beds of crushed shale under lithostatic loads simulating the column loads to be encountered in practical operations. The resulting compaction practical operations. The resulting compaction and reduction in permeability were correlated to predict the final permeability behavior of an actual fragmented in-situ bed with particles averaging 6 in. in diameter.
Two compaction cells, 1.25 and 5 in. in diameter, were used for the retorting experiments in which the permeability of the compacted bed was determined for average shale particle size from 0.046 to 1.0 in., shale richness from 18 to 58 gal/ton, lithostatic load from 70 to 900 psi and heating rate from 5 to 100 deg. F per hour. A correlation was developed that predicts the permeability using the lithostatic pressure, shale richness, and particle size for a shale heating rate of 10 deg. F per hour. The modified Kozeny equation was used as the theoretical basis for the correlation and the measured permeabilities could be predicted with an permeabilities could be predicted with an average error of 21 percent.

Introduction
The initial permeability of an in-situ bed of broken shale will be more than adequate for the injection of heating fluids, but retorting drastically reduces the permeability as a result of compaction caused by heating the oil shale under an overburden load. To estimate the permeability of the fragmented shale bed during permeability of the fragmented shale bed during retorting, the influence of shale particle size, lithostatic pressure, temperature history, and shale richness was determined by laboratory experiments. These experimental data were correlated and then extrapolated to a larger average particle size to predict the permeability of fragmented shale beds anticipated for commercial in-situ retorting. Green River oil shale from the Piceance Creek Basin in Colorado was utilized throughout these studies.

EXPERIMENTAL APPARATUS AND PROCEDURE

Large-Scale Compaction Cell
A simplified sectional view of the large-scale compaction cell is shown in Fig. 1. The cell is cylindrical and holds about 5,000 to 7,000 gm of crushed shale, depending upon the shale richness.
Engineering the Oil Loan Under Conditions of Economic Uncertainty
Authors: Miller Richard J. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The paper examines the impact of current petroleum economics on the valuation procedures used by banks to determine the value of oil and gas properties for production loan purposes. properties for production loan purposes. In the past determination of collateral value and debt repayment ability was generally made using rule of thumb methods derived from actual lease sales during periods of economic stability. Increasing oil prices, FEA price regulations, and cost inflation have made former rules unreliable for determining current property values. The paper studies the Rate of Return discount method as a means of relating Fair Market Value determinations to prevailing economic conditions.
The paper expands on previous work by developing a variable discount rate system for determination of the appropriate Rate of Return for discounting. The variable system combines long-term projections of prime lending rate and projections of prime lending rate and investment interest rate with historical industry earning trends. The variable system allows the Rate of Return method of valuation to be applied to all properties regardless of economic category properties regardless of economic category or location. The addition to the system of lending and investment rates in foreign countries along with a country risk factor allows the variable rate approach to be used in foreign property valuations.
The techniques described in the paper are primarily designed to provide the production loan borrower a means of production loan borrower a means of evaluating the financing potential of his existing properties. Secondary applications include the general determination of the value of properties for sale or acquisition. The paper concludes that traditional rule of thumb models based on historical lease sales are unreliable in terms of prevailing economic conditions and both domestic and foreign regulation and tax structures.