bluuebunny/crossref_metadata_2025 huggingface dataset:
Neutron Decay Time in the Subsurface: Theory, Experiment, and an Application to Residual Oil Determination
Authors: Robinson J.D.
Published: December 2007

Robinson, J.D., Member SPE-AIME, Shell Development Co.

Theoretical solutions are given for the determination of thermal neutron decay time in the formation from measurements in the borehole with a capture gamma detector. Laboratory data from a sandstone formation of 17 percent porosity, saturated with water of various salinities, are in agreement with the principal theoretical predictions for the case principal theoretical predictions for the case of a capture gamma detector. The time derivative of the logarithm of the gamma activity is equal to the reciprocal of the neutron decay time in the formation plus a term that is, in general, time dependent. However, at source-detector spacings of 60 cm or larger, becomes independent of time at sufficiently long times following the neutron pulse. Also, is independent of the salinity of the aqueous phase.

The determination of residual oil saturation near the borehole of a nearly watered-out producing well in a sandstone reservoir in southern Louisiana is given as an application of this study. Stationary measurements with a specially constructed sonde and a time-of-flight analyzer were made. The FORTRAN programs used and an example of the input data programs used and an example of the input data are included.

Introduction

Two years ago we began a theoretical study of pulsed neutron logging, seeking to provide a quantitative understanding of how the measured apparent neutron decay time of a formation is related to the true neutron decay time, the decay time implied by the capture cross-section of the formation. A strong motivation for this study was the desire to determine the residual oil saturation in cased, watered-out wells by the use of log-inject-log techniques that require a measurement of true neutron decay time.

The Russian literature on pulsed neutron logging is more extensive than the American, and a model suggested by Polyachenko, Gavrina, Tseitlin, and Shaposhnikova was found most useful for the study of pulsed neutron logging with a gamma detector. Deductions from this model will be presented, and the data from experiments done at Schlumberger-Doll Research Center at Shell's request will be compared to those deductions. Finally, as an application of this study, we shall describe how measurements with a specially constructed sonde opposite a sandstone reservoir in a cased well in southern Louisiana were used to estimate the fraction of bulk volume of formation occupied by water. From this estimate and an independently known value of porosity, the residual oil saturation is immediately deducible.
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.

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.

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.

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.

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

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.

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.

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.

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.
H2S Need Not Be Deadly, Dangerous, Destructive
Authors: Samuels Alvin
Published: December 2007

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

IRONITE SPONGE is a significant new product specifically formulated to scavenge hydrogen sulfide from drilling, completion and workover fluids. The material is believed to be unique both in terms of its composition and its reaction with H2S. Because of this it can result in a level of safety not now possible using any other method of possible using any other method of treatment. When added to the drilling, completion or workover fluid in recommended concentrations it is capable of eliminating the danger to personnel, equipment and the environment even when a high pressure, low volume feed-in containing high H2S concentrations is encountered and this even if high strength drill pipe is in use!

This is possible because IRONITE SPONGE reacts on contact with H2S to form mainly FeS2, pyrite, which is safe and stable. The reaction appears to instantaneous, complete and irreversible and the efficiency is directly proportional to bottom hole pressure. proportional to bottom hole pressure

Introduction

Hydrogen sulfide, commonly referred to as rotten egg gas, is deadly poisonous. Concentrations above 600 poisonous. Concentrations above 600 ppm can be fatal in 3–5 minutes, Table ppm can be fatal in 3–5 minutes, Table 1. Its toxicity is comparable to cyanide. It is the most destructive gas known! Fifty ppm will cause highly stressed, high strength steel to fail in only minutes and small concentrations can reduce drill pipe life by a factor of ten. Even 0.1 ppm will greatly reduce the time to failure of highly stressed, high strength drill pipe. In addition to being the only pipe. In addition to being the only gas which causes embrittlement, H2S also contributes to corrosion fatigue of any grade of drill pipe.

Heretofore there has never been a satisfactory method of scavenging H2S except in small quantities and involving less than desirable situations. The use of zinc and copper compounds results in time, temperature and pH sensitive reactions. Slow reactions, the need for high pH, plating tendencies and corrosive and unstable by-products are but a few of the problems wholly eliminated by the use problems wholly eliminated by the use of this new material. Most important, however, is the ability to protect people, pipe and the environment even people, pipe and the environment even with the well on choke due to a kick containing high concentrations of hydrogen sulfide.
Recovery Of A Fuel From Waste Solvents Generated In The Chemical Laboratory
Authors: Cerceo Eugene
Published: December 2007

Introduction

For years clinical laboratories have been conducting routine quantitative analyses on hormones (steroid and peptide), vitamins, drugs, enzymes, and a variety of other relatively small molecules in physiological fluids. Many of these test methods require the use of organic solvents as a means of separating the component to be analyzed from interferring substances. The separating techniques are either extraction of the component into an organic phase or chromatography (thin layer or column) of the substance from its interferrants utilizing organic solvents.

In a relatively large number of tests the solvents used are petroleum-related; such as, petane, hexane, isooctane, benzene, petroleum-related; such as, petane, hexane, isooctane, benzene, toluene, and xylene. For reasons of safety, many laboratories take the extractant to dryness in a distillation apparatus recovering the solvent in a separate vessel. Thus, under no circumstances can explosive combinations of air and vapors build up in the fume hood. From thin layer and column chromatography excess solvents are recovered from trays and columns. Therefore, as the laboratory conducts these routine analyses on a daily or weekly basis, waste solvents tend to accumulate and the problem becomes one of disposal of these fluids. Since these organic compounds are an intrinsic part of gasoline, it was summarized that quite possibly these solvents could be recovered and blended into a fuel very similar, if not identical to it. Thus, a recovery program was initiated in our laboratories from those clinical test program was initiated in our laboratories from those clinical test methods utilizing petroleum-type solvents. The wastes were placed in five-gallon metal containers and stored in cabinets specifically designed for the storage of flammable organic fluids.
Low-Stress-Level PinUp Drillstring Optimizes Performance in Southern Oklahoma
Authors: Dudman Rick A. , West Cory , Hubbard Jeff
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Mid-Continent Operations Symposium held in Oklahoma City, Oklahoma, 28-31 March 1999.
Feasibility Study of the Stability of Openhole Multilaterals, Cook Inlet, Alaska
Authors: Moos D. , Zoback M. D. , Bailey L.
Published: December 2007

A study of in situ stress, rock strength and wellbore stability was initiated within the Hemlock Sands of the McArthur River Field, Cook Inlet, Alaska, to evaluate the potential of leaving the near-wellbore portions of multi-laterals uncased. A NW-SE direction of maximum compression and a strike-slip faulting regime were predicted from analysis of leakoff test data and observations of failure (breakouts) in adjacent wells. Caliper, well-log, and core data indicated that cementation, and hence rock strength, is highly variable within the reservoir. Thus, it was decided to evaluate the stability of the lateral sections (that is, the likelihood of wellbore failure during production) as a function of both stratigraphic position and well orientation. Laboratory rock strength measurements were carried out on cores selected from target intervals in adjacent wells to provide sufficient precision to quantify the results. The results indicated that, while some reservoir intervals have high enough strengths to be left uncased when drilled in the most stable direction, these intervals are too thin to provide sufficient support at the point where the laterals leave the parent well. This justified the decision to case back the laterals to the parent well in spite of the cost.
A Numerical Description of Hot-Water and Steam Drives By The Finite-Difference Method
Authors: Vinsome P.K.W.
Published: December 2007

A stabilised-'IMPES' method has been developed for the hot-water and steam-injection processes. While the method is much simpler processes. While the method is much simpler than implicit methods, it maintains second-order accuracy on the space derivatives, and large time steps may be realised. The techniques can easily be incorporated into existing simulators to increase their efficiency, and have a wide range of applications e.g. coning, and miscible drives. Simulations have already been performed both on laboratory and field scales. Examples of steam drive in tar sands and steam soak are presented. The finite-difference equations presented. The finite-difference equations contain some peculiarities when applied to steam drives, which are illustrated and discussed by means of numerical examples.

Introduction

Numerically, steam drive is a tough problem. Consider what happens in a typical 'IMPES' (implicit potential, explicit saturation) finite-difference potential, explicit saturation) finite-difference simulator. Under normal conditions about half a pore volume of any fluid may be pushed through a pore volume of any fluid may be pushed through a grid block per time step before the calculation goes unstable. If this is the flow rate of steam just behind the condensation front, then because of the large density difference between steam and water, the water flow rate just after the front will be of the order of 1/100 of a pore volume per time step. One difficulty is obvious: that of stability. In order to keep the conventional IMPES scheme stable, it is necessary to have thousands of time steps for a simulation. Pioneering attempts to simulate the steam-injection process utilised an explicit calculation of either the mass balance or the energy balance, and as a consequence suffered from this severe stability limitation.

Traditionally, the method used to remove the high flow-rate stability limitation has been to calculate the volume, mass, and energy balances implicitly, either sequentially or simultaneously. This approach has been particularly successful on coning problems but it does particularly successful on coning problems but it does have certain drawbacks. The programming effort involved is much greater. The programs become larger and more unmanageable. Only single-point upstream mobilities are used, which leads to significant loss of accuracy in the space derivatives. Overshoot problems occur, especially near residual saturations, and these must be checked out and corrective measures taken. Other non-linearities such as potential reversal can cause trouble, even bomb-out, especially when the flow rates are high.

A third major problem with steam-drive calculations is the treatment of the condensation term. It can vary rapidly at a grid point during a simulation, which means any explicit evaluation of this term causes computational difficulties. Coats has presented a novel formulation of the condensation term which attempts to eliminate such troubles.
The Current Status of Commercial Deployment of the Freeze Thaw Evaporation Treatment of Produced Water
Authors: Boysen J. E. , Harju J. A. , Shaw B. , Fosdick M. , Grisanti A. , Sorensen J. A.
Published: December 2007

Evaporation is an economical way to dispose of oil and gas produced water in warm, arid climates. During colder seasons, it is not as effective. The freeze-thaw-evaporation (FTE®) process couples freezing with evaporation. By combining these natural processes, produced water can be treated economically on a year-round basis.
Glycol Used for Natural Gas Dehydration: Evaluation of Subsurface Transport and Fate Issues
Authors: Sorensen J. A. , Hawthorne S. B. , Gallagher J. R. , Harju J. A.
Published: December 2007

Triethylene glycol (TEG), diethylene glycol (DEG), and ethylene glycol (EG) are commonly used to dehydrate the natural gas stream. These compounds may be introduced into the sub-surface environment as a result of spills, leaks, mechanical failures, and past disposal practices. The toxicity of the dehydration glycols at concentrations typically found in the subsurface in the vicinity of a dehydration unit is generally considered to be low. However, the miscibility of the glycols suggests that they may act as cosolvents for other more toxic, less soluble, organic compounds such as polycyclic aromatic hydrocarbons (PAHs), thereby increasing the subsurface mobility of those compounds. In 1998, a series of laboratory-based research activities was initiated to determine 1) the nature of cocontaminants that may be associated with the gas dehydration process, particularly spent glycols, 2) the biodegradability of the dehyradation glycols under environmentally relevant conditions in soils from three different gas-producing regions of North America, and 3) the potential effect of the dehydration glycols on the subsurface mobility of PAHs in the same three North American soils.
Training Techniques in Well Control
Authors: Kendall H.A.
Published: December 2007

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

Blowouts must be prevented if the drilling industry is to survive. While most governments are anxious to produce oil and gas, this may be produce oil and gas, this may be secondary to avoidance of environmental pollution. A sequence of such pollution. A sequence of such incidents can shut down drilling efforts, perhaps temporarily, or perhaps permanently. Most incidents perhaps permanently. Most incidents occur due to a failure to understand the basic principles involved in well control.

Not only must drilling personnel be thoroughly trained in the basics of well control, but all personnel involved in any position who can influence drilling operations must also understand the consequences of any order or command given. Training should also be given to personnel not directly involved in drilling operations but who are normally in the vicinity of the drilling rig.

In addition to the many articles written and published on this subject, there are several excellent well control simulators available worldwide, where firsthand experience can be obtained in well control without the hazards of learning in the real world. This paper illustrates what Amoco has done to promote as well as carry out well control training seminars to all personnel associated with our European personnel associated with our European drilling operations.
Low-Stress Level PinUp Drillstring Optimizes Drilling of 20,000 ft. Slim-Hole in Southern Oklahoma
Authors: Dudman Rick A. , West Cory , Hubbard Jeff
Published: December 2007

This paper was prepared for presentation at the 1999 SPE/IADC Drilling Conference held in Amsterdam, Holland, 9-11 March 1999.
Installation of Fixed Steel Piles Platforms in Deep Water
Authors: Heerema P.S.
Published: December 2007

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

This paper was prepared for the SPE-European Spring Meeting 1975 of the Society of Petroleum Engineers of AIME, held in London, England, April 14–15, 1975. 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A fixed platform consists normally of:A substructure: a space frame of pipes welded together, called jacket or template.A pile foundation, to nail the substructure to the sea bottom.A deck construction over the substructure.Prefabricated units containing production and/or drilling equipment.

With deep water is meant, depths of over 150 feet. Presently structures are being designed and fabricated for water depths up to some 500 feet.In water depths up to some 300 feet, the jackets weigh normally less than 6000 tons and may be transported and launched at location from specially designed launch barges. The load-out of such structures is usually done by sliding them from the fabrication site on a barge over a rail system with surfaces of steel or wood or teflon, overgrease.In greater water depths, the jackets usually weigh more than 6000 tons and up to 20,000 tons. Although launching of such huge structures is possible, they are usually built so that they will float, and are towed to location, and upended by a system of selected flooding of the legs.The piles for deep water structures vary from an O.D. of 36" to a maximum of 72",with wall thicknesses varying from 7/8"to 2 1/4".Penetrations vary from 100 feet to 350 feet depending on soil conditions and required bearings. Ultimate design loads on piles vary from 1500 tons to 5000 tons. If the piles cannot be driven to the penetration required to obtain the necessary design bearing, drilling out of the plug, or other means, like the patented Heerema "slip joints", to obtain more penetration, may be used. As a last ressort insert piles, pin piles or underreaming may be used.

The first length is then driven to a practical penetration, usually with the use of a drilled pilot hole. Then a smaller diameter hole is drilled inside the first pile and well below of the tip of the pile, with mud circulation, to maintain the hole and grouted with a cement mix to obtain adherence to the walls of the hole.
Laboratory Test Performance Methods For Additional Products Used In Petroleum Production Processes
Authors: Couget Paul
Published: December 2007

Couget, Paul, ELF, R.E., Department Recherche Technique et Etudes Nouvelle, BOUSSENS, FRANCE

Oil field development is characterized by the fact that many problems arise which could not be foreseen at the beginning of operations (or were underestimated when they were not purely or simply unknown)

Among the problems most often encountered are those of:–corrosion due to dissolved carbon dioxyde and/or hydrogen sulfide–corrosion due to dissolved oxygen–sulfate reducing bacteria corrosion–emulsions–paraffin dirt-minerals salts deposits–foams.

When these problems have not been foreseen at the beginning, they often require the injection of appropriate products.

The choice of these depends of course on their SPECIFIC EFFICIENCY for the purpose. But it also depends on the INTERACTION that these products may have either with each other when used simultaneously, or with the environment in which they are used or due to their SECONDARY EFFECT or the CONDITIONS in which they are used.

So a product, for example a bactericide, may have the best characteristics of its kind without however being the most suitable product for use in a given working site, because of its incompatibility product for use in a given working site, because of its incompatibility with the other additives or with the environment.

The laboratory specialist who must make a choice from among a large range of products, will have to consider all the conditions of utilization for selecting the most suitable product.
Recent Developments in Numerical Simulation Techniques of Thermal Recovery Processes
Authors: Tamim M. , Abou-Kassem J. H. , Ali S.M. Farouq
Published: December 2007

Numerical simulation of thermal processes (steamflooding, cyclic steam stimulation, SAGD, in-situ combustion, electrical heating, etc.) is an integral part of a thermal project design. The general tendency in the last ten years has been to use commercial simulators. During the last decade, only a few new models have been reported in the literature. More work has been done to modify and refine solutions to existing problems to improve the efficiency of simulators. The paper discusses some of the recent developments in simulation techniques of thermal processes such as grid refinement, grid-orientation, effects of temperature on relative permeability, mathematical models, and solution methods.

The various aspects of simulation discussed here will promote better understanding of the problems encountered in the simulation of thermal processes and will be of value to both simulator users and developers.
Long-Stroke Pumping System at Shell Canada's Peace River Multilateral Thermal Wells
Authors: Zatka Mirko J.
Published: December 2007

Shell Canada Limited produces 6-9° API bitumen from a number of multilateral horizontal ("SoakRadial") cyclic steam wells as part of its thermal recovery project at Peace River in Alberta, Canada. These wells typically utilize a conventional beam lift pumping system with a variable frequency drive for speed control. In seeking ways to optimize the artificial lift system, Shell Canada initiated, in 1998, a controlled test of a mechanical long-stroke pumping unit as a possible alternative to conventional pump jacks. The objective of the test was to evaluate the unit for operating reliability, its ability to lift available production, lifting cost (power consumption) and frequency of maintenance. In addition, the test included a pump-off controller system on one long-stroke and one conventional pumpjack, enabling close monitoring of well conditions and differences in operating parameters.

Variations in productivity due to the cyclic nature of the steam soak operation of these wells present unique challenges to conventional pumping systems. Ability to closely match pumping rates to well inflow is expected to result in lower operating and maintenance costs, a feature that long-stroke units were expected to offer. Field tests have in fact shown that these units can increase daily production rates through better pump efficiencies and longer stroke lengths, while reducing the amount of power consumed and thus operating cost. Other benefits include reduced wear in downhole pump components and comparable equipment reliability to conventional pumpjacks. While some issues arose around servicing of wells equipped with the long-stroke units, changes to wellhead and surface facility design on future wells is expected to overcome most of these.
Storage Of Natural Gas In Salt Caverns
Authors: Medley Alfred H.
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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Introduction

Natural gas can be stored in many ways but when geologically feasible, salt cavern construction is usually the method of choice. Salt caverns permit the highest rate of gas delivery, provide a secure for of storage, permit full product recovery, and usually require the least cost for construction. This paper presents a review of cavern paper presents a review of cavern design parameters.

GENERAL CONCEPT

Three ingredients are necessary to develop a solution mined storage caverns: a thick salt formation, a supply of fresh (or low salinity) water, and a means of brine disposal. The fundamental principle of development is to simply expose the salt in a drilled hole, inject fresh water into the hole, allow time for dissolution, and withdraw the resulting brine from the hole, As the salt dissolves, the hole enlarges into the form of a cavern.

In actual practice, the procedure for cavern development is somewhat more complex. In the case of a thick salt mass, a single leaching well is usually sufficient as shown in Figure 1. Thinner salt may require two fracture connected wells as shown in Figure 2. In either case, each well should have a fully cemented string of casing extending from surface into the salt. Leaching is conducted by injecting the light fresh water down a tubing string with sufficient pressure to force the heavier brine up the other tubing string. Concentric tubing strings must be used in the single well configuration but separate strings can be run when dual wells are available. In either case, the annular region enclosed by the cemented casing must be filled with a light nonleaching and noncorrosive fluid such as oil or propane.