bluuebunny/crossref_metadata_2025_split huggingface dataset:
Design Of Treatment For Stimulation Of Low Permeability Formation
Authors: Halepeska Bill F. 
Published: December 2007

Publication Rights Reserved

Introduction
Numerous low permeability reservoirs, most of which cover long vertical sections, have been developed commercially in the last few years as a result of advancements in the field of stimulation technology. Many of these had been tested previously and unsuccessful completion attempts made. Lithologically, these formations include cherty limestones of Devonian age, silty limestones from the Mississippian and limey sands of Canyon age, as well as others. Measured formation permeabilities range from 0.01 to about 0.4 md. with some naturally fractured sections indicating greater values as fracture permeability. Gross vertical thicknesses vary from 100 feet in some more homogeneous lime sections to 1,000 feet or more in highly broken sand and shale sections. Most of these occur at depths below 6,000 feet, and some in excess of 10,000 feet. For some time, stimulation techniques which were then considered applicable failed to provide flow systems necessary for commercial production. Based upon past experience, stimulation programs were designed and completion practices altered where practical to meet treatment demands. Industry's willingness, even in an atmosphere of increasing cost consciousness, to spend greater amounts than ever before for stimulation has contributed to the development of such programs. Research provided through field operations, supported by mathmatical analyses and laboratory experimentation, has contributed to improved techniques. To date, hydraulic fracturing appears to be the only method which will affect the desired results in these low permeability formations.

ELEMENTS OF DESIGN FOR STIMULATION TREATMENT
The elements of treatment design are numerous and difficult to define unless associated with plans for stimulation of a specific well. Consideration must be given to both materials and technique of application in light of individual well conditions and formation characteristics. Design of treatment for low permeability reservoirs is essentially the same as for any other, with some modifications providing greater vertical coverage and radial extent of fracture system. This is usually reflected in greatly increased fracture volumes and/or injection rates. A brief general discussion of several major factors in treatment design is presented.
Planning of Directionally Drilled Wells in the Offshore Wilmington Field Using the Hand-Held Calculator
Authors: Clark D. D. , Barth J. W. 
Published: December 2007

Abstract
As of July 1982, 901 wells have been directionally drilled in the Long Beach Unit of the East Wilmington Field from 4 man-made islands and land based drilling sites. As more wells are added to each site the planning of new well courses has become more complex. The hand held calculator with Long Beach Unit developed programs has been ad aid in laying out new wells which will avoid existing cased bore holes.
Review—Esso Resources Canada Ltd., Norman Wells Expansion Project Drilling Program
Authors: Schaef D. G. 
Published: December 2007

ABSTRACT
Esso Resources Canada Limited has embarked on a project to increase production from its Norman Wells Oilfield located 145 km south of the Arctic Circle, from 475 m3/D to 4000 m3/D of crude oil. This paper provides details on the development drilling portion of the project which is comprised of 150 wells to be drilled in 3 years utilizing 2 drilling rigs from July 1982 through September 1985. The majority of the wells will be directionally drilled from multiwell land pads and artificial islands to shallow reservoir targets underlying the Mackenzie River, a major river intersecting the field boundaries. Experience from the initial 27 wells completed is provided.
Effect of Core Surfacing and Mud Filtrate Flushing on Reliability of Core Analysis Conducted on Fresh Cores
Authors: Burkhardt J.A. , Ward M.B. , McLean R.H. 
Published: December 2007

Abstract
Reliability of core analysis information for use in formation evaluation studies is essential if results of such studies are to predict reservoir behavior accurately. This paper presents results of an experimental study of factors which might cause the behavior of cores to be nonrepresentative of the reservoir.
For this study, extracted cores were brought in contact for 12 to 16 hours with bottom-hole samples of East Texas crude and formation water at the East Texas reservoir temperature and pressure; their water-flood behavior at these conditions was observed. The effects on core properties of reduction of temperature and pressure from reservoir to surface conditions, both with and without prior flushing of the cores with drilling mud filtrates, were investigated.
The water-flood behavior of the cores was no significantly altered by a reduction of temperature and pressure from the environments of the East Texas field to atmospheric conditions nor by flushing with the filtrates of two caustic quebracho muds or with a high-pH saline water.

Introduction
An evaluation of oil reserves may be separated into two parts, an estimate of total reserves and an estimate of recoverable reserves. Each of these estimates is based on laboratory information obtained from samples of the reservoir rock. This paper presents a laboratory study of reliability of core analysis information used in estimation of recoverable oil reserves.
In the estimation of recoverable reserves of a water-drive reservoir, water-oil relative permeability relations are the data of prime importance. For this reason, laboratory determination of these functional relations has received considerable attention in the past. Most of the early activity, however, was confined to measurements made on rock samples previously cleaned by solvent extraction.
The Bank Engineer's Viewpoint On Oil Loans
Authors: Evans Richard L. 
Published: December 2007

Publication Rights Reserved

Introduction
It is no secret that banks have had excellent experience with loans secured by oil and gas properties. Their competition for these loans creates a constantly changing environment, largely encouraged by increasing recognition of, and reliance on, the ability of the engineer to evaluate the security.
Two by-products of this trend prompt this paper: First, the accumulation of literature on economics, evaluation and banking becomes increasingly fragmented and burdensome for engineers acquainting themselves with the field. Second, engineers serving industry eventually confront bank engineers in supporting loan applications, and it is important that they know what to expect if the work is to be done quickly and well a This paper attempts a comprehensive survey of current petroleum production financing from the bank's standpoint: Its attitudes, engineering practices, and standards, together with a brief survey of the available kinds of bank loans.

Bank Responsibility
For those who are not acquainted with commercial banking economics, the starting point for a discussion of bank attitudes is a bank balance sheet. (Fig. 1) The important features are identified by asterisk.
On the Liability side, reflecting the source and ownership of resources, the principal item is deposits. These funds are entrusted to banks for a variety of reasons, but the most important reason is safety. They are placed in this bank, as opposed to other banks, for the interest paid on savings accounts and the services offered to checking account customers. Interest and services are the main elements of the cost of doing business, and are largely determined by competitive forces.
The Asset side reflects the bank's deployment of funds for income, after providing for current obligations and cash reserves required by law.
Shock Absorbers—Are They Necessary?
Authors: Worford S. W. , Craig P. G. 
Published: December 2007

Abstract
The economic benefits of running a shock absorber seem evident from their growing use in oil and gas drilling operations. However, some controversy still exists over when they should be used, how to get the greatest benefit from them, and whether there are some negative effects such as hole deviation associated with the usage of some shock absorbers. Extensive experience in recent years has included results with a wide variety of shock absorber designs in the full range of hole depths and sizes. The results show that lateral stiffness of the tool, the type of spring or other energy absorption system, and tool length have a significant influence on shock absorber performance. The energy absorption system and its location in the drill string, in conjunction with the type of bottom hole assembly design, bit selection, and formation characteristics, determine whether the maximum benefits possible from the shock absorber are attained
Major benefits from proper use of the appropriate shock absorber are longer bit life, higher drilling rates, longer drill-string life, reduced hazard from bending fatigue of the threaded connections in the drill string, and reduced wear on the rig equipment. These all result in a significant reduction of the overall drilling costs. Guidelines for shock absorber selection, placement in the drill string, and operating practices which yield the greatest overall benefit from the use of a shock absorber in oilfield drilling are described. Ultimately, the decision to use a shock absorber will be based on economics. Does the use of a shock absorber reduce the overall drilling cost?
Improve Drilling Efficiency with Two Nozzles and More Weight-On-Bit
Authors: Tsai C. R. , Robinson L. H. 
Published: December 2007

Abstract
Field tests evaluated the performance of three-cone insert bits using only two nozzles sized from pressure measurements made at the rig to give maximum hydraulic impact. The tests were conducted on two rigs in California and three in Texas.
Test techniques entailed finding a suitable formation that required two identical bits to drill through. The first bit was operated with three nozzles while the subsequent bit was operated with two nozzles. During the test the drilling parameters (such as weight-on-bit, rotary speed, nozzle flow area, pump pressure, circulation rate, and mud weight) were kept as constant as possible. Drilling rates of the two bits were then compared and analyzed with the aid of mud-logs, electric-logs, and drilling recorder information. The depth and the relative position of the formation were also carefully compared with offset well bit records.
Test results showed an average increase of 20% in drilling rate by the two-nozzle bits. One bit run showed a 3% increase and two bit runs showed 42% and 52% increases. These extreme cases were observed in Texas. The two California rigs showed 15%-19% increases.
These test results together with a careful analysis of offset well bit records lead to the following conclusions:
Under the conditions tested, two nozzles drilled faster than three. A moderate increase of bit loads with emphasis on weight-on-bit rather than rotary speed can significantly increase the drilling rate without shortening the length of bit run.
Management of the Contract Drilling Industry: Failure and Opportunity
Authors: Meyer P. K. 
Published: December 2007

Abstract
The principal purpose of this paper is to access, the management practices of the contract drilling industry. As a part of this assessment senior oil industry operating executives and leading investment analysts were asked to identify those oilfield services and products segments that are the best managed and the worst managed. Both survey groups singled out the onshore contract drilling industry as the worst managed supplier segment by a significant margin. Generalized, the respondents characterized the domestic onshore contract driller as suffering from poor market research, excessive debt financing, inadequately trained crews, weak rig supervision, poor general management training, and nominal technical innovation. Respondents cited the industry's ease of entry and its highly fragmented structure as a major cause of these deficiencies. This paper discusses these management deficiencies and how they have contributed to the industry's current problems. It proceeds to characterize the industry as ripe for consolidation. The paper concludes that the onshore contract drillers that will be the ascendant, prosperous forces in this consolidation process will be those aggressively redressing the poor management practices typifying their industry.
The Use of Water-Oil-Ratio Control Agents To Improve Oil Production
Authors: Pace J. R. , Weaver J. D. 
Published: December 2007

ABSTRACT
The treatment of several wells in a Middle East field with a new WOR (water-oil ratio) control agent is described including well selection, treatment application and treatment results. This WOR control agent is polymeric and is designed to reduce the mobility of formation water while not interfering with the oil mobility. A review of other chemical water control methods is also presented.
The wells selected for treatment with this new material were in a field experiencing a rapid increase in water production. Some of the wells are on artificial lift. The increase in water production is thought to be due to water coning.
These wells are completed in a dolomitic limestone with high vertical permeability. The use of plugging type treatments was ruled out because the vertical and horizontal permeabilities are near equal and would require very delicate placement procedures. Treatment with conventional flooding polymers, such as polyacrylamides, was ruled out due to the short term effectiveness which has been observed in producing wells.
Several applications have been made using the WOR control agent with promising results. The production curves indicate a change in the expected recovery of hydrocarbons and a reduced water production rate.
Leak Detection Using Time-Lapse Technique and Wellsite Computer Processing
Authors: Mohamed S. K. , Tongue Richard , Doran Tom 
Published: December 2007

ABSTRACT
A time lapse technique has been developed in order to enhance the conventional methods of interpreting flowmeter surveys that are performed in high rate injection wells to locate small leaks particularly at or near liner laps.
The time lapse technique compares current surveys with several historic surveys on the same well and has proven effective in locating small leaks. The stationary measurements of the historical surveys are compared to each other to establish trends and any major deviation from these trends indicates a likely change in the condition of the casing. This method has successfully located small leaks that were otherwise unnoticed.
In addition a wellsite computer (CSU) is used for an accurate calculation of flowrate across a liner lap. This work was done on a new injection well with various Schlumberger flowmeter tools, at rates from zero to 45 MBD (7.15 × 103 m3 PD) with logging in both 7″ (17.78 cm) and 9-5/8″ (24.4 cm) casings. Results can be plotted and flow rates in the two casings compared as an additional method to define liner lap leaks.
The combination of these two methods should improve monitoring casing integrity throughout the life of injection wells.
A Multicomponent Isothermal System for Efficient Reservoir Simulation
Authors: Blaskovich F. T. , Cain G. M. , Sonier Fernand , Waldren David , Webb S. J. 
Published: December 2007

ABSTRACT
A new model has been developed specifically to study very large, heterogeneous oil and gas reservoirs. By using unique approaches to the simulation of fluid properties and dual porosity/permeability systems, the model is able to accurately simulate complex reservoir flow performance that was previously difficult or not feasible to model. Descriptions of the fluid flow characteristics of the model are included in the Appendix. Potential applications to several real field simulation problems are discussed to show the advantages of the model as compared to more traditional approaches. Additionally, several actual simulations of hypothetical reservoirs are shown and the results are compared with both standard single porosity and dual porosity black oil models currently available. The enhanced representation of the physical system compared to classical black oil models is achieved in a way which is efficient in the use of both the memory and processor resources of the computer, whilst the modular nature of the simulator, coupled with advanced programming and documentation standards, will facilitate its further development and maintenance.
The Use of a 3-D Compositional Numerical Reservoir Model in the Design of a Miscible Gas Injection Project
Authors: Arthur K. B. , Rioche M. A. , Sakthikumar Soma 
Published: December 2007

ABSTRACT
Miscible gas injection may lead to increased recovery in many Middle-Eastern reservoirs. However, to obtain satisfactory results from numerical reservoir models of this process, the models must include a realistic description of the thermodynamic exchanges that take place.
Two approaches are possible : a fully compositional model using as many components as the user desires, or a model with a limited number of components whose properties are chosen to give a realistic thermodynamic description at reservoir conditions. Whilst the first approach is more appealing, the second is cheaper and may be shown to give equivalent results.
This paper describes the use of a 3-D compositional reservoir model to derive a suitable spacing for the first phase of a pattern miscible gas injection scheme and to predict its performance.
A fully compositional thermodynamic programme based on the Peng-Robinson equation of state was used to derive pseudo-components for the 3-D compositional reservoir model. The validity of the pseudo-components has been proved by matching laboratory experiments using slim tubes, three meter cores and traditional PVT properties.
Due to the limited number of pseudo-components required, the computing costs were comparable to those of a black oil model with an equivalent number of cells. And while the use of fully compositional models for a full field study requiring a minimum of several thousand cells cannot yet be performed at a reasonable cost, a model using the approach proposed in this paper is practical.
High-Temperature Gelled Acid—Laboratory Development and Field Results
Authors: Norman L. R. , Conway M. W. 
Published: December 2007

Abstract
In the past few years, the use of gelled acid has become well known, and the benefits of its use in oil and gas well stimulation have been discussed.1,2,3 Also, results obtained from the use of gelled acid treatments have supported their application.
Polymer systems are often used as viscosity-building agents for well stimulation fluids and other acidizing operations. These polymer systems must be functional under the desired acidizing conditions. Three systems published as useful in acidizing are a liquid gelling agent1; xanthan polymer2,4, and a metal cross linked polymer system3. These systems impart viscosity effectively in acidic fluids only below 200°F.
In the patent literature, various systems are discussed which possess utility for gelling acids. Examples of some polymer systems included are acrylamide and acrylamide copolymers cross linked with various aldehydes5, ethylene oxide-propylene oxide block co-polymers used at high concentrations6, branched or emulsion polymers of diallyldimethyl amine7, cellulose derivatives cross-linked with chromium salts8, and branched polymers prepared by reacting ethylene oxide with acrylamidomethylpropane sulfonic acid (AMPS)9.
Planning Production Casing Strings for Deep Well Completions
Authors: Mudge J. K. 
Published: December 2007

ABSTRACT
Production casing for deep high pressure corrosive environment wells requires special planning. The criteria by which production casing is chosen for wells shallower than 20,000' is quite different for deeper wells. If the worst case condition for internal pressure is a tubing leak, then the most accurate method of predicting shut-in tubing pressure must be employed.
The use of the appropriate restricted yield materials is advisable in many high pressure completion systems, even in areas not normally associated with sulfide stress cracking problems.
Uniaxial design analysis is not sufficient to adequately predict load condition in deep high pressure completion systems. A triaxial stress analysis should be performed to insure the yield strength of the material is greater than the worst case stress condition for the most cost effective size/material combination.
A casing connection that has demonstrated performance under extreme combined loads should be chosen to insure the integrity of the production casing system.
Recent Development in Hydraulic Stimulation Treatments in the Fletcher Field in the Deep Anadarko Basin
Authors: McMechan D. E. , Conway M. W. 
Published: December 2007

Abstract
In 1981, over 1,000 new wells were drilled below 15,000 feet1. Although bottom hole temperature in these wells vary widely, all have a number of similar characteristics which make hydraulic fracturing treatments very difficult. Completions in the Springer Trend in the Fletcher field are from 16,000 to 22,500 ft. The experience gained in the design and execution of these treatments should be beneficial to treatments in other deep fields.
The similarities of these treatments to other deep reservoirs include high bottom hole pressure and temperature, small diameter tubing, high closure pressures, low permeabilities, and tubing contraction problems while treating. The high treating pressures encountered necessitate the use of fluids with minimal pumping friction pressures. The high closure pressures often require the use of high strength proppants which are more difficult to transport than sand. Low formation permeabilities dictate the need for long propped fractures to achieve the desired production increase and thus long term treating fluid stability is required. To minimize contraction in the long tubing strings, treating fluids often must be preheated (100-140°F). The high initial fluid temperatures can alter fluid properties downhole.
Data and case histories will be presented to demonstrate the role various reservoir characteristics have on the design and execution of successful stimulation treatments. Examples of the problems to be addressed include high pore pressures which complicate drilling and cementing operation, unexpected fluid loss in stimulation treatments and the need for a more comprehensive pre-stimulation evaluation to identify candidates for hydraulic stimulation.
The Mancos Formation: An Evaluation of the Interaction of Geological Conditions, Treatment Characteristics and Production
Authors: McLennan J. D. , Roegiers J. -C. , Marx W. P. 
Published: December 2007

ABSTRACT
In general, the Mancos Formation is an underpressured sequence composed of intimately interbedded siltstones and shales in a relatively faulted geologic environment.
Apparently sporadic production trends from the Mancos Formation in northwestern Colorado led to an intensive evaluation program. This encompassed laboratory determination of the mechanical and fluid transport properties of the formation as well as evaluation of treatment and production records. Production trends were compared with known geological conditions as well as stimulation procedures. Mechanisms for the variability in production and the local effectiveness of treatments are outlined. General procedural approaches for optimum recovery are discussed. These procedures include resource determination guidelines and general stimulation guidelines.