bluuebunny/crossref_metadata_2025_split huggingface dataset:
Formation Clay Chemistry
Authors: Perricone A.C. , Browning W.C. 
Published: December 2007

Publication Rights Reserved
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper.

Abstract
It is apparent that improvement in the chemistry of drilling fluids leading to improved drilling efficiency is dependent upon increased knowledge of sub-surface geology and geochemistry. Because of the significance and prevalence of sub-surface clays and shales, the study of formation clay chemistry is of fundamental importance to drilling production. This paper presents certain aspects of formation clay chemistry that open new avenues of approach in drilling fluid design.
Of utmost significance in formation clay chemistry is the avidity with which hydroxyl ions react with clays. This hydroxyl reaction of clays was found to cause a radical increase in total surface area and rate of cleavage in non-swelling clays such as illite, as well as clays of the expanding lattice type. It is indicated, therefore, that it is the hydroxyl reaction of clays that is primarily responsible for the weakening of the borehole formations and "mud-making" drilling fluid tendencies.
Clay base exchange reactions promoted by aqueous drilling fluids of selected cation composition are indicated to be more detrimental than beneficial when viewed from the standpoint of formation chemistry. In fact, non-reactivity of the drilling fluid with formation clays appears to be a most important drilling fluid requisite. Non-reactivity or inertness of the water phase is shown to be achieved by maintaining the absence of base exchanging cations and hydroxyl ions, and is distinct from the older ideas of inhibition or "inhibited muds".
Because of chemical reactivity and mechanical effects, it is concluded that any invasion of drilling fluid media into borehole or producing formations is damaging no matter whether the liquid is aqueous or non-aqueous. In fact, it appears that advantages previously claimed for certain drilling fluids were probably due to filtration control rather than composition of the liquid phase.
Prediction Of Pressure Gradients For Multiphase Flow In Tubing
Authors: Fancher George H. , Brown Kermit E. 
Published: December 2007

Abstract
An 8000 ft. experimental field well was utilized to conduct flowing pressure gradient tests under conditions of continuous, multiphase flow through 2-3/8 in O.D. tubing. The well was equipped with 10 gas lift valves and 10 Maihak electronic pressure recorders as well as instruments to accurately measure the surface pressure, temperature, volume of injected gas and fluid production.
These tests were conducted for flow rates ranging from 75 to 936 B/D at various gas-liquid ratios from 105 to 9433 SCF/BBL. An expanding orifice gas lift valve allowed each flow rate to be produced with a range of controlled gas-liquid ratios. From these data an accurate pressure traverse has been constructed for various flow rates and for various gas-liquid ratios.
A comparison of these tests to Poettmann and Carpenter's correlation indicates that deviations occur for certain ranges of flow rates and gas-liquid ratios.
The Transmission of Gaseous Hydrogen
Authors: Wurm Jaroslav , Pasteris Robert F. 
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The paper considers both the economics and the technical aspects of an onshore hydrogen transmission pipeline. Compressors and hydrogen embrittlement problems are discussed.
The main conclusions are -The current natural gas transmissionlines can handle the equivalent amount of hydrogen on the basis of equal energythroughput, when both the capacity and power input of the section's compressorstation are increased.Using the current economic factors and disregarding the initial compression, theoptimum hydrogen transmission costs approach 2.5 cents/million Btu-100 miles for a 2000-psia average operating pressure and a fuel cost of $3/million Btu compared with about 1.5 cents/million Btu-100 miles for natural gas.

Introduction
The potential of hydrogen as a future fuel is being generally recognized as a way of meeting our energy "challenge." Recently, an energy concept based on this potential termed "the Hydrogen Economy" or "Eco-Energy" has been proposed. Studies indicate that there would be no insurmountable problems for such a system. They have also shown the reasons why hydrogen is so attractive as a means of transporting energy: Hydrogen is a clean fuel, and it would be relatively less expensive to transport and distribute compared with electricity.

HYDROGEN AS A MEANS OF ENERGY TRANSMISSION
Currently, energy is mainly delivered to the consumer in electrical and chemical forms. Statistical data are available for evaluating the cost that transmission contributes to the price the consumer pays for energy. For instance, a typical 36-inch natural gas pipeline is capable of moving energy at a rate of about 1 billion Btu/hr, or 12, 000 MW, at a cost of about 1 cent-2 cents/million Btu-100 miles ($0.03 to $0.07/MW hr-100 miles).
Unique Hydraulic Lift System
Authors: Bell C. Allen , Spisak Charles D. 
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
Oil producing companies are continually seeking new ways to cut production costs through the production costs through the development of new ideas.
This paper discusses a unique, economical hydraulic lift system installed by the Lafayette Division of Continental Oil Company. This system combines a new venturi, hydraulic bottom-hole pump and a compact, centrifugal power fluid cleaning system into a single installation. This jet eductor pump, or jet pump, is relatively unaffected by high gas-liquid ratio production or dirty power fluid and requires very little maintenance. The fluid cleaning system provides power fluid which meets the quality power fluid which meets the quality requirements of the jet pump for considerably less initial investment and lower operating costs than a conventional power fluid system. This combination is power fluid system. This combination is particularly adaptable to single well particularly adaptable to single well leases or fields.
Currently, two of these compact systems are in operation producing sour crude from the deep Smackover formation in Mississippi. Excluding the problems corrected during an initial startup period, no system operating problems have been reported after a cumulative twenty-nine months of service.

Introduction
The Lafayette Division of Continental Oil Company has in operation two hydraulic lift installations which incorporate a new venturi hydraulic pump and a compact power fluid cleaning system, to be called "POCS" (power oil centrifugal separation) unit, into a unique system. To our knowledge, these were two of the first uses of this combination in the industry and the first installations designed specifically for use of a jet pump.
The two single well systems were installed on wells in the deep Mississippi Smackover trend.
Fourteen Years of Progress in Catalytic Treating of Exhaust Gas
Authors: Barstow W.F. 
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
In the year 1959, the first successful system for producing noncorrosive inert gas from internal combustion engine exhaust was installed and put on-stream in a Louisiana oil-producing field. It employed a four cycle, naturally aspirated, integral engine compressor and delivered 1.0 MMscfd of catalytically purified dry inert gas at a maximum pressure of 4500 psig.
Many abortive attempts had been made in the preceding forty years to produce a compressible inert gas from engine exhaust, from boiler stack gas or from combinations of the two. In most cases, they were complete failures or had only limited success because of the corrosive qualities of the gas. The one known successful plant in operation at that time was Pan American's installation at Elk Basin, Wyoming. It had been put on-stream in 1949 and made use of stack gas from specially designed steam boilers. The design capacity of this facility was 15.0 MMscfd. In early stages of operation, they too encountered severe corrosion in compression and related equipment. It was later alleviated, but not completely eliminated, through ammonia injection into several points within the system in sufficient points within the system in sufficient quantities to render all condensate with a pH between 6.5 to 7.0.
Since 1959, progress in the field is quite evident. Inert gas plants employing engine exhaust have grown remarkably in size and in pressure capabilities. Today there is one located in a California oil field that can deliver in excess of 16.0 MMscfd at a maximum pressure of 6000 psig. Larger plants that will deliver more than 50.0 plants that will deliver more than 50.0 MMscfd are required and are in the design stage. A steam boiler stack gas plant incorporating steam turbine driven centrifugal compressors is now in service generating in excess of 50.0 MMscfd with plans on the drawing board for a facility to produce over 120.0 MMscfd.
While no significant changes have been made in the process that was successful in 1959, many progressive improvements have been discovered and employed in operating techniques and in the many components incorporated in the system.
Salt water Gel Packer Fluid for High Pressure Completions
Authors: Mayell M.J. , Stein F.C. 
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
Past completion techniques in the middle Past completion techniques in the middle to lower miocene abnormally pressured gas sands in the Gulf Coast area have involved the use of a weighted mud as a packer fluid. Workovers on these wells incur extremely high costs associated with recovery of tubing stuck in settled mud solids. To reduce the workover costs and expense of lost or damaged tubing, packer fluid requirements were reexamined to select a fluid that would prevent these problems. Two unweighted systems were selected from an overall review and comparative tests were run to determine long term stability, sealing properties, and handling ease. Results of the properties, and handling ease. Results of the tests determined a suitable solution for use in Gulf Coast high pressure completions.
A fluid composed of 25#/bbl. attapulgite gel in a saturated saltwater solution with a chromate corrosion inhibitor and the pH adjusted to 10.5 with soda ash showed a clear superiority. It has been used in Gulf Coast wells for three years and field experience in producing and workover situations has supported producing and workover situations has supported the test results.

Introduction
It has been standard practice to use drilling mud as a packer fluid in high pressure wells in many companies since that type completion was first made. The apparent advantages of drilling mud are:The fluid is available at no additional cost.In the event of a tubing leak, the hydrostatic column may be sufficient to kill the well and may avoid troublesome casing pressure.In the event of a casing leak, drilling mud solids have excellent sealing characteristics against moderate differential pressures.
The disadvantages of drilling mud packer fluids, however, appear later in the life of the well and have a significant effect on workover costs. The problems surface in the following forms:Barite settling results in extensive fishing operations to pull the tubing.High temperature gellation of lime base fluids requires washover operations to clean out the well.Lignosulfonate degradation to H2S in lower pH environments causes tubular stress failures.
Energy Development: A Resource Allocation Problem
Authors: Fore James G. 
Published: December 2007

Fore, James G., Member AIME
This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The actions of both the producer and consumer in the energy market have been very rational as each tries to maximize his position. The producer is motivated by profits while the consumer is seeking to maximize his total level of utility. The problems that are occurring in the energy market can be traced in most cases to one of market restrictions or failure of the market to fully reflect costs due to externalities. It is these restrictions and/or externalities that have led to our present energy crisis and not any overt acts by present energy crisis and not any overt acts by the producers or consumers.

Introduction
Most people acknowledge that as the demand for resources increases and these resources become scarcer the price would move higher. The effect of this increase in price would be to reduce demand for that price would be to reduce demand for that resource by causing some individuals to substitute more abundant resources for scarcer ones, or it would increase the supply of that resource by development and application of new technologies to permit the use of poorer quality resources. This in turn would lead to an optimal use of resources.
The price referred to here is the market price, the market price being established by price, the market price being established by bringing together the demand curve of consumers and the supply curve of producers, Figure 1. The purpose of the price is to help our economic system achieve efficiency. It does this in two ways. The first concerns the allocation of the currently available goods and services. The second concerns the production of goods and services, that is, production of goods and services, that is, what quantities of what goods and services should be produced.
This price is completely impartial in the allocation of goods to consumers as well as to who shall produce the goods. So one would expect to hear complaints about the price being too high from some consumers and being too low from some producers. After all, allocation is the purpose of the market price. price.
A New General Optimization Method - Application to Gas Gathering System
Authors: Ghez Fabien 
Published: December 2007

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The object of this paper is to present a new optimization method developed for problems concerning operating policy in oil or gas fields. Several mathematical procedures have been used, but none permits the handling of problems that are, at the same time, nonlinear, problems that are, at the same time, nonlinear, discrete and submitted to constraints.
The method proposed here is based on probability concepts, and the algorithm probability concepts, and the algorithm described is shown to converge, in probability, to the optimal solution.
An example of a gas-gathering system optimization illustrates the method. This example seems appropriate as it is similar to many exploitation problems. Indeed, most of them are nonlinear (friction losses, as an example), discrete (such as connecting point locations and pipe diameters), submitted constraints (pressures at wellheads and fluid speed in flow lines).
The computing efficiency of the method is then tested.

Introduction
While, in every industry, decision problems are important, this is certainly most evident in the oil- or gas field development strategy where almost always, the "best policy" must be at the very beginning, despite the small amount of available information.
The various decisions to be made relative to the development or abandonment of a field, on the basis of a very small number of exploration wells, are far from obvious. In practice, all operational aspects are concerned. It is not sufficient to search for a technical-economic optimum by successive trials without taking all variables into account. The following examples require particular accuracy in calculations that is not always reached:well drilling schedules and well locations during field life,design and construction of a gas-gathering system andcompressor positions and required power, if necessary.
Several methods have already been developed, but their mathematical limits have forced users to simplify their problems. A general optimization method is presented here. It will be seen that the described algorithm converges to the best technical-economic decision or "optimum decision" in a probability sense. It is applied to the development of a gas-gathering system in the case of a dry gas field.
Good Operating Strategy Saves Compressor Fuel in Natural Gas Transmission
Authors: Rachford H.H. 
Published: December 2007

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The fuel used for compression in modern long transmission systems is about 5% per thousand miles under full-capacity steady load. For a long system the minimum required compression work needed for steady loads is approximately proportional to the ratio of the cube of the delivery rate to the square of the mean flowing pressure. However, demand usually varies periodically, causing systems to operate in the transient state with an average delivery rate less than the design value. In this case, the work (and fuel) required should be substantially lessened.
This paper applies a transient model to study a realistic theoretical system delivering 90% of design rate with +10% daily demand variation. An iteration for improving the strategy of using existing compression equipment 'was developed. This procedure led to a mode of operation which required 16.7% less fuel than that for a conventional operation of this system.

Introduction
Long line transmission systems are designed to optimize the use of initial investment capital in pipe and compression facilities for a specific, steady delivery rate. Application of such design criteria in the past has led to pipe and compressor sizing so that about 5% of the gas delivered is burned as fuel each 1000 miles. While the supply shortage may change such design criteria in the future, it appears timely to study possible ways of saving fuel usage in existing systems now. It is the purpose of this work to examine whether the required fuel can be decreased for existing systems in conventional operation by simply changing operating strategies.
Demands at sales points are usually variable in time, and as a result the average throughput of a system in practice may fall 10–20% or more below the design rate. This follows since constraints on the system, such as minimum delivery pressures and maximum pipe pressures, fix pressures and maximum pipe pressures, fix the maximum sustained delivery rate at the steady state design figure.
Virgin Damage Surface of a Synthetic Analogue to a Reservoir Sandstone
Authors: Unander Tor Erling , Holt Rune M. 
Published: December 2007

Abstract
This paper is based on laboratory investigations of synthetic sandstone cemented under stress making it possible to perform mechanical tests directly from the simulated in situ stress state. We have mapped the acoustic emission damage surface, or Holcomb surface as we have called it here, around this stress state. The results show that this surface does not coincide with the "true" damage surface as damage is induced in the material even for very small load deviations from the forming stress state. The Holcomb surface mapping is done with a new technique that is able to better describe and quantify onset of acoustic emission.
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