bluuebunny/crossref_metadata_2025_split huggingface dataset:
Simplified Method for Gas-Lift Well Problem identification and Diagnosis
Authors: Mayhill T.D. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. 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 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. 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 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
A system is described for detecting and diagnosing problem gas lift wells based on well test data. Wells are screened so that only those with abnormal producing conditions are identified for further analysis. The analysis utilizes well tests and installation specifications to define troubles and predict efficient gas injection rates. This method circumvents the need for numerous flowing pressure and temperature traverses in pressure and temperature traverses in continuous flow gas lift facilities.

Introduction
Gas lift wells are subject to the following kinds of design and operating problems:

Surface
Excessive flowline restriction Tubing or casing choke plugging Undersized flowlines High separator pressure Undersized gas distribution systems Wet gas

Subsurface
Leaks in the flow string Improper flow valve operation Improper design of string Changing well conditions Excessive aeration Excessive slippage of fluid or fallback Foam conditions Low fluid heads or submergence heading or surging conditions
Conventional methods to detect and diagnose inefficient gas lift wells can require many of the following:
Well tests Casing-tubing pressure recordings Surface temperature recordings Pressure traverse surveys Temperature surveys Fluid levels determined by acoustic methods
But in a large scale gas lift field, it is expensive and time consuming to get the necessary down-hole data.
Deep Drilling and Completion Practices Uinta Basin
Authors: Collings B.J. , Layton J.A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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
Drilling and completion costs in the Uinta Basin have been high for several reasons, mainly, 1) tough, abrasive formations, 2) long rig moves into the Basin, 3) weather, and 4) high inflationary rate. Other author have discussed these problems in detail. This report discusses some of the cost reducing practices which Gulf has used. The objective practices which Gulf has used. The objective has been to develop efficient, safe, drilling and completion practices. Savings of approximately 10 per cent have resulted even though the inflationary rate has been at a record high during this period.

Introduction
The Uinta Basin, located in Northeast Utah (Figure 1), came into recent drilling prominence in May, 1970, with the field prominence in May, 1970, with the field discovery, Shell-Miles No. 1. This well flowed, initially, at a rate of 1100 barrels of oil per day from an interval near 12,900 feet. Subsequently, 210 wells have been drilled and completed (Figure 2), by a drilling force varying from 25 to 40 rigs.
Production has been principally from the Wasatch formation with a small amount being produced from the Green River formation. produced from the Green River formation. The producing trend stretches 40 miles northeast-southwest and is 10 to 15 miles in width. Daily production from this area has risen to approximately 62,000 barrels oil per day (Figure 3).

DEPTH DIFFERENCES
An earlier report by Findley in 1972 described drilling and other difficulties associated with operations in the Uinta Basin. At that time only two Gulf development wells had been completed. Currently, 37 development wells have been completed, with 6 of the 37 wells reaching depths ranging from 16,200–19,500 feet. The other 31 wells were drilled to depths ranging from 10,000 to 14,800 feet.
Figure 4 indicates the reason for the differences in depth. This northwest-southeast cross-section, covering approximately 16 miles, shows Duchesne River, Uinta, Green River, Basal Green River, Wasatch and Cretaceous formations dipping northwest toward the axis of the Basin, while surface ground level is rising northwest, toward the Uinta Mountains. This combination provides more interval to penetrate to the provides more interval to penetrate to the northwest, accounting for increased depth across the field.
Detection and Mitigation of Weight Loss Corrosion in Sour Gas Gathering Systems
Authors: Gerus B.R.D. 
Published: December 2007

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

Abstract
The production of sour gas through steel gathering lines usually presents serious corrosion problems to the facility. This report discusses some of the basic corrosion mechanisms involved in such a system. Most of the available corrosion monitoring techniques are discussed with regard to their principle of operation and their advantages and disadvantages. The third section of the report deals with mitigation techniques that can be applied to sour gas systems for the purposes of corrosion control. Explanation of the technique and some advantages and disadvantages are presented.
Experience gained through Shell Canada's operations is interjected throughout the report. It should be noted that experience is related to specific situations and should not be blindly applied to all other situations.
II.

Introduction
The detection and mitigation of weight loss corrosion is a constant problem in sour gas gathering systems. Pitting corrosion rates of over 200 mil/year have caused extensive damage and necessitated the expenditure of hundreds of thousands of dollars on one particular sour gas gathering system in Shell's operation (see Figs. 4 through 8). Similar experiences have been reported by other companies operating in the hydrogen sulfide-carbon dioxide environment of Alberta's natural gas reservoirs. Every year millions of dollars are spent in the restoration of corroded systems and on the treatments that were initiated for the purposes of mitigating sour gas corrosion. Corrosion of sour gas gathering systems also presents a potential threat to human safety and potential threat to human safety and environmental damage possibilities. Most sour gas gathering systems contain sufficient quantities of hydrogen sulfide to make any escaping gas fatal to exposed humans and animal life. Thus, from the foregoing discussion, it is apparent that it is not only economically advantageous to prevent sour gas corrosion, but its prevention is also necessary to maintain prevention is also necessary to maintain environmental safety.
In order to efficiently detect and mitigate corrosion in sour gas gathering systems, the corrosion mechanism occurring in the system should be understood. If the corrosion mechanism of a particular system is known, then disruption of that mechanism has a greater probability of success, since blind trial-and-error attempts at mitigation are eliminated.
Due to the necessity of understanding the basic corrosion mechanisms, this report has been divided into three sections.
Drilling and Completion in Jay-Little Escambia Creek
Authors: Howell Frank R. 
Published: December 2007

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

Abstract
Since discovery of the Jay Florida - Little Escambia Creek Alabama Field in June 1970, Exxon Company, U. S. A. has had a successful and rapid development drilling program in an H2S environment. Fifty-one wells with 45 completions have been drilled by Exxon (100 for all participants) with no H2S related drilling participants) with no H2S related drilling problems. Available sour gas drilling problems. Available sour gas drilling technology has been applied while average rig days to drill and complete the 16,000-foot wells has been reduced from 68 to 46. Extensive safety and contingency plans developed initially have been plans developed initially have been followed throughout the development program. Blowout preventers and well head program. Blowout preventers and well head equipment are fabricated or modified for H2S service. Temperature effect on hydrogen embrittlement for various grades of tubulars is considered in casing and tubing design to minimize cost. However, drill pipe grade is limited to 95,000 psi or lower grades. The Smackover psi or lower grades. The Smackover formation pressure is slightly abnormal but causes no appreciable drilling problems. More drilling fluid precautions are required to drill a 150–200 foot Haynesville Salt section at approximately 15,300 feet than are required to drill the H2S bearing Smackover.
Production was initiated in time to utilize production experience in completing or working over subsequent wells in Jay - Little Escambia Creek and surrounding fields. Wellbore problems experienced resulted from elastomers seizing in the packer bore.

Introduction
In June, 1970, Exxon Company, U.S.A. discovered Jurassic oil production at 15,550 feet in the Smackover Limestone in the Jay Field, Santa Rosa County, Florida. Development drilling extended the field into Escambia County, Alabama which was designated as Little Escambia Creek Field. From the outset it was apparent that the sour crude discovery was significant. Subsequent drilling defined the reservoir limits as seven miles in length and three miles in width. Geographically, the field is located 35 miles north of Pensacola, Florida and 60 miles east of Mobile, Alabama. (Figure 1)
Drilling and Completion Safety for Hydrogen Sulphide Wells
Authors: Goolsby Bill M. 
Published: December 2007

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

Introduction
Drilling for and producing hydrocarbons containing hydrogen sulphide gas from deep, high pressure reservoirs can be a profitable venture, but its presence presents hazards that are abnormal to routine oil field operations. A drilling venture of this type can be safely conducted if all personnel concerned are aware of the unusual risk involved and are trained in proper safety procedures. Hydrogen Sulphide, synonymous with such names sour gas and H2S, is a poisonous gas that can destroy life in very low concentrations and can also cause the instantaneous failure of high-strength steels and other metals. This means that all personnel must not only be thoroughly familiar with safety procedures and safety equipment but, also, the kinds of materials that are safe for use in hydrogen sulphide environments. This paper will deal with the safety aspects of sour gas operations.

HYDROGEN SULPHIDE GAS
Personnel involved in the drilling, testing, Personnel involved in the drilling, testing, and completion of wells containing hydrogen sulphide gas should first of all be familiar with the characteristics of this gas and its principal hazards. The following points principal hazards. The following points should be learned and discussed by everyone involved.A. Characteristics of H2SExtremely toxic (poisonous).Heavier than air, and colorless. Specific gravity of 1.192.Has odor of rotten eggs, in smallamounts.Burns with a blue flame and produces Sulphur Dioxide (SO2) gas, which is very irritating to eyes and lungs. The SO2 is less toxic than H2S, but can cause serious injury.H2S forms explosive mixtures with air, between 5.9% and 27.2% by volume.H2S is soluble in water but becomes less soluble as the water temperature increases.H2S is almost as toxic as hydrogencyanide and is between 5 and 6 times as toxic as carbon monoxide.Produces irritation to eyes, throat and respiratory tract.Threshold Limit Value (TLV) maximum of eight hours exposure without protective respiratory equipment - 10 PPM.B. Principal Hazard - Poisoning by Inhalation
All personnel involved in sour gas operations should become extremely familiar with the H2S toxicity contained in Table 1.
Implementation of a Flux-Continuous Finite Difference Method for Stratigraphic, Hexahedron Grids
Authors: Lee S. H. , Tchelepi H. , DeChant L. F. 
Published: December 2007

Abstract
In this paper we present a three-dimensional flux-continuous finite-difference formulation designed for flow simulation of models with nonorthogonal hexahedron grids with general tensor permeability. Our development follows that of Aavatsmark et. al1, but we do not operate in transformed space. The new 27-point discretization formula has been implemented in a finite difference reservoir simulator. This stencil has many desirable properties including collapsing into a consistent form in two-dimensions.
We demonstrate that there are many practical situations where neglecting the influence of the nonorthogonality and general tensors results in first-order errors in flow predictions. A rigorous implementation for this 27-pt difference operator as a control-volume finite-difference method determines the winded convection terms associated with multiphase computations. Results and issues associated with implementation of this operator in a conventional finite difference reservoir simulator are discussed.
As an alternative to directly solving the linear matrix associated with the 27-pt stencil of the flux-continuous operator, we examine iterative methods that split the matrix into a 7-pt stencil part and a remainder. The 7-pt stencil part is solved by a direct or iterative method with the remainder part updated from the previous time step or iteration. This split operator may permit retention of the linear solver for the standard 7-point formulation while retaining non-orthogonal tensor and grid information.
An Update on the Practical Aspects of Handling High-Pressure Sour Gas
Authors: Mottley J.R. 
Published: December 2007

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

Abstract
Sour gas condensate production was discovered in the Smackover lime of New Hope Field, Franklin County, Tex., in 1953. The gas contained 13 percent hydrogen sulfide and 5 percent carbon dioxide, which results in a very percent carbon dioxide, which results in a very corrosive environment. In addition to corrosion, equipment was especially susceptible to failure from hydrogen embrittlement because of the relatively high operating pressures.
Experience has shown that this combination of conditions can be controlled economically and safely with a well planned corrosion inhibition program, standard, readily available program, standard, readily available materials can be used for most applications. Procedures can be established for monitoring the Procedures can be established for monitoring the condition of equipment that will forewarn of impending failure. This, in conjunction with a good safety program, will afford effective protection to operating personnel. protection to operating personnel

Introduction
In 1953, when the first well penetrated the Smackover lime in the New Hope field, two important questions came to the minds of those involved. The first was, will it produce? The second was, if it does produce, how severe will be the operational problems? Core analysis showed the formation was very tight, with porosity ranging between 5 and 8 percent and a porosity ranging between 5 and 8 percent and a composite average permeability of 0.12 md. The reservoir fluid contained 13 percent hydrogen sulfide and 5 percent carbon dioxide at a pressure of 6,000 psi and a temperature of pressure of 6,000 psi and a temperature of 275 degrees F. The question of productivity was partly answered when acidizing indicated partly answered when acidizing indicated that the meager flow rates from the initial drillstem test could be improved. At the time there was very little industry experience to draw from to answer whether sour gas, at these pressures, could be safely and economically pressures, could be safely and economically produced and processed. This would have to be produced and processed. This would have to be determined by experimental work and in the field itself.
Development drilling proceeded and, by 1957, the productive limits were substantially defined to cover some 3,200 acres. The structure is an anticline with a water level at approximately 12,400 ft. Maximum productive thickness at the crest is 600 ft.
While drilling was going on, studies were made to determine the best method of recovery and indicated that cycling would be necessary. In mid 1957, a pilot plant was constructed to evaluate the cycling possibilities and methods for controlling the sour gas. At this time, no provisions were made for removing the hydrogen provisions were made for removing the hydrogen sulfide. After stripping the condensate, the sour gas was injected into the reservoir.
Hydrogen Sulfide Embrittlement in Oil Country Tubular Goods
Authors: Casner J.A. , Schneider E.J. 
Published: December 2007

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

Abstract
The background of research on the hydrogen and hydrogen sulfide embrittlement of steels is reviewed. The factors required for embrittlement and the probability of their occurrence in field conditions are discussed.
A laboratory program to evaluate the relative susceptibility of various steels to hydrogen sulfide embrittlement in a simulated sour well condition was designed. Samples of oil country tubular grades ranging from J-55 to V-180 as well as laboratory heats of steel designed to measure the effect of yield strength tensile strength and heat treatment on hydrogen sulfide embrittlement were tested. The most significant factor observed was the strength of the steel.
The results of these tests and other data are described and reviewed from the standpoint of a designer of casing, tubing and drill pipe strings. Available grades are sorted into three groups:those grades which are unlikely to fail even in a severe environment;those grades which are unlikely to fail in a mild environment; andthose grades which would be expected to fail even in a mild environment.
The data and the discussion of the results of these tests presented herein are not to be construed as a warranty of Youngstown's pipe or tubular goods for a particular service.

Introduction
Hydrogen and hydrogen sulfide embrittlement of steels is a phenomenon which has received an extraordinary amount of attention during the past 25 years. Must of the early attention to hydrogen embrittlement was promoted by failures in military aircraft landing gear assemblies fabricated from high-strength steels. In addition, as sour oil and gas wells were encountered, the specific problem of hydrogen sulfide embrittlement became problem of hydrogen sulfide embrittlement became more and more significant, particularly as wells were drilled deeper and stresses in the drill pipe, casing and tubing increased.
Despite the time and money devoted to studying H2 and H2S embrittlement, a complete understanding of the process does not exist.
Logging Operations in Sour Gas Wells
Authors: Connell James G. , Shapiro Robert M. 
Published: December 2007

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

Abstract
The presence of hydrogen sulfide gas in a well has, in the past, imposed severe limitations on wireline logging services. Operations were sometimes attempted in wells containing low concentrations of H2S (less than two percent by volume), but these attempts often led to trouble. With continued discoveries of wells having appreciable concentrations of hydrogen sulfide, it became evident that new operating techniques must be developed to overcome the associated problems.
These problems fall into three main areas: danger to personnel, failure of the logging cable, and failure of the pressure-control equipment.
People must be educated in the safety procedures for working around hydrogen sulfide. procedures for working around hydrogen sulfide. The operation of monitoring and safety equipment must be understood.
Standard logging cables, whose armor is made of high-carbon steel, can fail after quite brief exposure, even to low concentrations of hydrogen sulfide. However, it has been found that, in these concentrations, the standard cable can often be used if proper precautions are taken.
For wells having hydrogen-sulfide concentrations greater than two percent, it has been necessary to develop a new cable-material technology. A hydrogen-sulfide-resistant monocable design has been developed, and such cables are available upon request.
Standard blowout preventers and lubricators for use with logging cables are also subject to early failure in a hydrogen sulfide environment. In low concentrations of the gas and low pressures, standard blowout preventers and pressures, standard blowout preventers and lubricators can be used if proper precautionary steps are taken. However, for high H2S concentrations, it was again necessary to develop new technology for the fabrication of H2S-resistant blowout-preventer and lubricator systems.
Logging and other wireline operations can now be performed safely, even in wells having heavy concentrations of hydrogen sulfide. Careful planning on the part of the lease operator and logging company are needed for safe and systematic operations.