bluuebunny/crossref_metadata_2025 huggingface dataset:
Design Of Treatment For Stimulation Of Low Permeability Formation
Authors: Halepeska Bill F.
Published: December 2007

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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

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

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

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

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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

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

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

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

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

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

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

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

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

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

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

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.
Lateral Variability in the Corcoran and Cozzette Blanket Sandstones and Associated Mesaverde Rocks, Piceance Creek Basin, Northwestern Colorado
Authors: Lorenz J. C.
Published: December 2007

The widespread sandstone members of the Lower Mesaverde Group (the Iles Formation) in the Piceance Creek basin have significant lateral variability within an overall blanket morphology. This variability can be seen in the Corcoran and Cozzette Sandstone members in the Department of Energy's closely-spaced Multi-Well Experiment (MWX) wells, and can be interpreted from nearby outcrops along the Grand Hogback. Much of the lateral variability consists of thickness changes of both the sandstones and the interbedded lithologies. The number and thickness of depositional units which comprise a bed may change, but the overall sedimentation event is always represented. This type of variation can be ascribed to local variations along widespread, regressive, wave-dominated delta and shoreline environments. Distinctly lenticular sandstones occur in the upper zones of each progradational sequence. These are best represented in the overlying Cameo Coal Member, and can be shown to be distributary channel and splay deposits of a lower delta plain.

The locations of the thickest blanket deposits (the best potential reservoirs) may be a function of the locations of principal distributary systems. For the delta plain deposits, however, the main source of natural gas is the interbedded coals which should be thickest where distributaries were least abundant. Therefore, the best reservoirs for this zone should be in those areas of intermediate sandstone and coal thicknesses.
Prop Transport in Vertical Fractures: Settling Velocity Correlations
Authors: Clark P. E. , Guler Nihal
Published: December 2007

The settling velocity of propping agents is a critical variable in the calculation of proppant distribution in a fracture. Most computer programs available in the industry today base estimates of settling velocity on a Stokes' Law type calculation. We have found that significant deviations from Stokes' Law settling velocities occur In cross-linked fluids and uncross- linked fluids (concentrations in excess of 0.48%).

This paper will discuss experimental results obtained with a dynamic system and the implications which these data have on prop transport calculations. In addition, correlations have been derived which can be used to predict the settling velocities of particles in cross-linked gels. A discussion of these correlations will be included.
Multi-Well Experiment: A Field Laboratory for Tight Gas Sands
Authors: Northrop D. A. , Sattler A. R. , Westhusing J. K.
Published: December 2007

The Multi-Well Experiment (MWX) is a research-oriented field laboratory whose objective is develop the understanding and technology to allow economic production of the several years supply of natural gas estimated to be within the low permeability, lenticular gas sands of the Western United States. Features of MWX include: (1) close-spaced wells (~125 ft,~38 m) for reservoir characterization, interference testing, well-to-well geophysical profiling, and placement of diagnostic instrumentation adjacent to the fracture treatment: (2) complete core taken through the formations of interest; (3) a comprehensive core analysis program; (4) an extensive logging program with conventional and experimental logs; (5) determination of in situ stresses in sands and bounding shales; (6) use of various seismic surveys and sedimentological analyses to determine lens morphology and extent; (7) use of seismic, electrical potential and tilt diagnostic techniques for hydraulic fracture characterization and (8) a series of stimulation experiments addressing key questions. This paper presents the current MWX accomplishments in the above areas since drilling started at the site in September 1981 through December 1982.
Technique for Thermodynamic Crystallization Temperature of Brine Fluids
Authors: Clark D. E. , Hubbard J. T.
Published: December 2007

The application of high density solids free brine fluids has proven to be technically and economically successful in hydrocarbon completion and workover operations. The use of inorganic salts such as calcium chloride, calcium bromide, zinc bromide, and sodium bromide has contributed to the development of complex salt systems. As the density and complexity of these systems becomes more detailed, the requirement for proper fluid design becomes increasingly important.

When a brine solution is cooled sufficiently, a temperature is reached where the solution will be saturated. A further decrease in temperature will result in the precipitation of salt from the solution. The temperature at which this transpires, provided no super-cooling occurs, is the crystallization point of the solution.

A correctly formulated solids free brine should have the optimum crystallization point for the temperature conditions it will encounter. A recently developed semiautomatic procedure constructs a cooling curve plot of each brine tested. This cooling curve plot allows the determination of the super-cooling potential, the Thermodynamic Crystallization Temperature, and the Last Crystal To Dissolve Temperature.

The device provides a permanent record of the cooling curve with repeatable accuracy, which assists in the development of error free brine formulation tables, brine density, and/or crystallization point adjustment, and brine analysis.
Open Cycle Cogeneration Project—Placerita Field
Authors: Doscher T. M. , El-Arabi M. A. , Stiglic Paul
Published: December 2007

The Placerita Oil Field is underlain with thick Pliocene sands containing several hundred feet of oil saturated sand in the Shepard Zone (Saugus) and the Upper and Lower Kraft Zones (Pico). These sands have been exploited somewhat haphazardly since 1920. However, the oil content beneath some of the acreage in the field is of the order of 200,000 barrels per acre. Steam injection will be required to recover the oil, which has a gravity as low as 11° although in some intervals it is as high as 20° API.

Since Placerita is in Los Angeles County, there are many restrictions on what fuel may be used in the steam generators. Natural gas is the preferred fuel, but at this time gas supplies in the area are somewhat more expensive on an equivalent BTU basis than crude oil. In order to be able to contemplate economic development of the field using steam, it is necessary to employ highly efficient processes for burning purchased gas. The scheme that recommends itself is the use of a cogenerator which produces both steam for subsurface injection and merchant electric power.

Tosco Enhanced Oil Recovery Corporation selected GWF Power Systems of Irvine, California to design and install a natural gas-fueled cogeneration system to supply steam and electric power for sale in order to keep the net cost of the former at a sufficiently reasonable level to permit economic recovery of Placerita crude oil by steam injection.
Fluid Management: Predicting and Controlling Viscosity During Weight-Up
Authors: Wilde D. N. , Wilton B. S.
Published: December 2007

This paper presents the development of a procedure that enables the user to predict the increase in plastic viscosity when barite is added to drilling fluid to raise the mud weight. The use of this method makes it possible to adjust viscosity at the lower mud weight when it is more economical to do so.

The equations presented are derived from sound hydrodynamic theory found in the references. Along with the equations, a graph and two handheld calculator programs are included to assist the reader in performing the calculations.
Three-Dimensional Simulation of Steamflooding with Minimal Grid Orientation
Authors: Potempa Thom
Published: December 2007

Steamflooding is a tertiary oil recovery mechanism with proven economic potential. Reliable numerical simulations of candidate injection schemes can aid in the optimization of process parameters. State-of-the-art numerican models exhibit varying degrees of grid effects which affect their reliability with respect to the modeling of pattern floods. This paper presents a numberical steamflood model which does not exhibit a significant amount of grid orientation. This model utilizes a numerical discretization technique which is an admixture of finite difference and finite element methods. Fluid properties are determined as a function of primary variables in a manner that allows a straight forward implementation of Newton's method for solving the nonlinear system of discretized equations. Fractional flows are defined using mass rather than volumetric mobilities, and are used to upwind the convective flow terms.
San Ardo—A Case History of a Successful Steamflood
Authors: Traverse E. F. , Deibert A. D. , Sustek A. J.
Published: December 2007

Texaco's largest steam flood project is in the San Ardo Field in California, and is a model of a successful steam flooding operation. This reservoir still has about 600 million barrels of 11 to 14° API oil in place, and now produces about 20,000 BOPD. The San Ardo Field is located approximately halfway between San Francisco and Los Angeles in Monterey County, California.

Several characteristics of the San Ardo operation make it a rather unique steam flood. But the most unique and significant characteristic relates to demonstrated recoveries of from 40% to over 80% of the OOIP in the active portion of the steam flood. An extension of the performance to date indicates that over 65% to 70% of the OOIP will eventually be recovered. Effective reservoir management, including the development of innovative pattern strategy, and proven operational practices have formed the basis for the current performance.

This paper will review the evolution of the field operation and stress new activities that Texaco is implementing at San Ardo to produce more oil and to do it more efficiently. These activities include a field test of a downhole steam generator.
Surfactant, Polymer, and Alkali Interactions in Chemical Flooding Processes
Authors: Krumrine P. H. , Falcone J. S.
Published: December 2007

Surfactants, polymers and alkaline chemicals are the major components of any chemical flooding process. Interactions of these chemicals can be extremely important to the final outcome of field trials, since the desired effect of each chemical may be enhanced or degraded as the various chemical slugs become mixed in the reservoir. In some instances it may be desirable to inject these various chemicals together in the same slug because of synergistic effects or to shorten the duration thereby improving the economics for the project. It is important to understand and anticipate the nature of these interactions to optimize flood design and recovery performance.

Specific interactions among these chemicals have been examined by interfacial tension (IFT) and viscosity measurements and core displacement studies. Many polymers contain small amounts of surfactant which contribute to IFT reduction, and also polymers slow diffusion and mass transfer to and from the oil and water phases thereby affecting consumption and adsorption phenomena. Certain alkalis have a dramatic effect on the ionic environment which affects both surfactant activity and optimal partioning between phases and polymer hydrolysis, stability, and viscosity. Also alkalis can modify mineral surfaces leading to reduced adsorption of the more expensive chemical components. These observations correlate well with core flood performance where the various chemicals are used either together or in successive slugs of various combination. In general at low concentrations most of these chemicals are compatible with each other and appear to enhance overall performance when used together.
Detection of Linear Impermeable Barriers by Transient Pressure Analysis
Authors: Martinez-Romero Nestor , Cinco-Ley Heber
Published: December 2007

This work presents a new simple method to detect a.linear impermeable barrier by analysis of transient pressure data. This technique is based on the desuperposition method (negative superposition) discussed by some authors and considers the calculation the pressure change caused by the presence of the barrier. The pressure change is analyzed to estimate the distance between the well and the barrier by using the type curve matching technique. Type curves are provided for both drawdown and build tests.

The advantage of the technique presented in this work is that pressure data can be analyzed even if the second semilog straight line, whose slope is twice the slope of the first semilog straight line, is not reached. Examples of application are discussed for illustration.
Stimulating Tight Sands in the Presence of Weak Stress Barriers by Modified Hydraulic Fracturing Techniques: A Status Report
Authors: Ahmed Usman , Strawn Jon , Schmidt Rich , O'Shea Patrick , Veghte Richard
Published: December 2007

Tight gas formations bounded by base rock and/or overlain by an overburden rock, that are not barriers to vertical fracture migration, are not amenable to "successful" large stimulation treatments by hydraulic fracturing as practiced today. Reservoirs of this nature are abundant. The example to be considered here is the North Douglas Creek Arch Field, east of Rangeley, Colorado. The objective of this paper is to present the preliminary findings of a project sponsored by the Gas Research Institute of Chicago and conducted by Terra Tek, Inc. of Salt Lake City and Chandler & Associates of Denver. The program is aimed towards developing technology that can provide deeply penetrating fractures in formations lacking barriers to vertical migration.

Four prospective techniques are being evaluated in the laboratory and in the field: fracture initiation placement (perforation placement), fracture packing with lightweight additives, controlled process zone fracturing, and electrical heating/fracturing followed by hydraulic fracturing. Each of the techniques is being evaluated for feasibility by analysis and tests performed in a polyaxial test machine that is capable of accommodating rock samples one cubic meter in volume. The program intends to validate and optimize the most effective technique in the field. It is anticipated that the optimum technique will probably be a combination of the several proposed techniques. The program includes stimulation technique evaluation in four new wells in the North Douglas Creek Arch Field.

Among the work reported in this paper are: preliminary studies related to the development of the four different techniques, fracture geometry prediction under adverse stress distribution condition, and drilling, coring, drill stem testing, transient pressure testing, in-situ stress measurements, log analysis, and routine and special core testing on core materials from two of the new wells.
Analysis Of The Pressure Behavior Of A Production Well Subject To Interference And Its Application To Reservoir Models
Authors: Thomere R. , Arthur K.B.
Published: December 2007

Publication Rights Reserved

This paper was prepared for the 40th Annual Fall Meeting of the of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., Oct. 3–6, 1965. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made.

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

A method is presented which may be used to analyze the pressure behavior of a well in which some part of the pressure drop is due to interference from other wells in the field. While it is customary to ignore the effects of interference and to assume each well to have a fixed drainage area, it is shown that this approach can produce anomalous results if the production rate of the well in question has varied in a certain fashion. In such a case, it is demonstrated that a consistent analysis is possible only if interference is introduced. As a corollary it is then shown how, under favorable circumstances, the use of an appropriate sequence of flow-rate changes can permit the determination of the interference to which the well is subjected. This determination still permits the average production rate of the well to exceed some 50 per cent of its maximum capability.

The analysis is made possible by the use of a digital computer and is designed primarily to allow accurate matching of field data to a reservoir model. Rather than treat each build-up or flow test separately, we have treated the complete pressure and production history of the well as a unit. In addition, no assumptions need be made regarding reservoir homogeneity or shape. The work described represents a generalization of a previously published analysis, and has been field-proven over a period of several years in the Hassi-Messaoud reservoir in Algeria.

Introduction

The field of Hassi-Messaoud in Algeria, although producing undersaturated oil, poses some difficult problems in the interpretation of pressure behavior. These problems arise because of a combination of extreme heterogeneity, wide well spacing and large changes of skin factor with time. Some four years ago a method of interpretation was introduced, in which a simultaneous analysis was made of all flowing and shut-in pressures measured on a well. As a result of this analysis the effects of changes at the wellbore [skin], were separated from the effects due to the properties of the reservoir around the well.
Effects of Temperature & Pressure Rheology of Less Toxic Oil Muds
Authors: De Wolfe R C , Coffin G B , Byrd R V
Published: December 2007

Studies in the past have looked at the pressure and temperature effects in respect to diesel-based mud systems, but with the introduction of new mineral-base oils, the need for pressure/temperature testing has again become an item of great interest.

Questions have been raised as to the possible differences in characteristics which muds might have in the areas of annular flow dynamics, bit hydraulics, and carrying capacity under actual downhole temperatures and pressures.

The prime reason that there has been little inspection into these areas has been the lack of good base data which could be used in some of the already existing calculation methods available to the industry.
The New Remote-Controlled and Multiangle Bent Sub (Telepilote) for Drilling Trajectory and Corrections
Authors: Boulet J G , Morin P E
Published: December 2007

A down hole adjustable and multiangle bent sub is now available to remotely control the well bore path during directional drilling operations, with he same bottom-hole assembly (BHA) configuration. This new patented tool is called Telepilote. SMF International (SMFI) and the Institut Francais du Petrole (IFP) have developed two different modes of actuation, either by dropping steel balls into the string bore (Mechanical Telepilote) or by sending an electrical signal (Electrical Telepilote).

The paper describes the main dimensional and operational data and procedures and indicates the potential range of application in directional drilling due to the very specific characteristics of this new remote-controlled tool.
Time-Shared Computers For Gas Well Measurement And Control
Authors: Scholes George A. , Darnell Quinton
Published: December 2007

Publication Rights Reserved

This paper was prepared for the 40th Annual Fall Meeting of the of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., Oct. 3–6, 1965. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made.

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

Automated gas well control systems, using radio transmission or telephone type cable, have been operated by the industry. The more advanced previous installations have utilized individual computers for each well stream for integration of flow rate from instantaneous orifice differentials and static pressures.

The system described in this paper utilizes time-sharing of a single computer for measurement and control of a number of gas wells and in-plant gas streams. This system includes a centralized control panel with computer, cable transmission links, and transducers at the meter runs for gas flow measurement and control. Return signals from the central control point are used to adjust individual well rates. An accumulated monthly production record is maintained in digit form for each gas stream. Automatic closed-loop control of selected wells maintains the processing plant thru-put at a maximum.

This installation is inexpensive, sufficiently accurate and easy to control. Since accumulated volume for each production unit is displayed at all times, maximum permissible monthly well allowables can be achieved without hand calculation.

EARLIER SINCLAIR SYSTEMS

Radio Control Systems

Various Oklahoma, New Mexico, and Texas gas plants have radio transmission equipment to open and close selected gas wells on signal. None of these systems transmit information back to the control point.

Sligo System

This Louisiana system utilizes electrical transducers at each orifice to transmit differential and static signals by way of underground cable to a central control station.
The Planning, Execution, and Evaluation of Acid Treatments in Sandstone Formations
Authors: McLeod H. O. , Ledlow L. B. , Till M. V.
Published: December 2007

Pretreatment analysis, job planning, and well preparation lead to acidizing success in sandstones with permeabilities greater than 50 md. Formation mineral analysis improves success in sandstones with lower permeabilities. Injection pressure responses to acid injection provide data for onsite decisions.
Critical Design Parameters to Prevent Gas Invasion During Cementing Operations
Authors: Bannister C. E. , Shuster G. E. , Wooldridge L. A. , Jones M. J. , Birch A. G.
Published: December 2007

Subterranean hydrocarbon deposits often contain low-molecular-weight gaseous hydrocarbons at various pressures, temperatures and depths. Failure to prevent the invasion of this gas into a cement slurry during completion can result in numerous problems. A few of the known manifestations of gas channeling are poor zonal isolation, annular pressure buildup, loss of hydrocarbons to nonrecoverable zones, required squeeze cementing and flow of gas to the surface.

The invasion of gas into cement slurries has been studied using a simulated wellbore model. Results indicate that a cement slurry loses its ability to transmit pressure with time. This loss is caused by gel structure development due, in part, to cement hydration and fluid loss. Gas flow can be initiated when the pressure transmitted by the fluid column becomes less than the gas pressure. The relationship between gas flow and this pressure differential has been determined for several cement systems. This relationship has been termed "gas conductivity" and is a measure of gas permeability of cement slurries prior to the development of compressive strength.

Two different design approaches were investigated in order to reduce gas conductivities in cement slurries. One involves inhibition of gas flow by the deposition of an impermeable cement filter cake against the formation. The second design incorporates a modified cement slurry which interacts with incoming gas to form an impermeable barrier in the cement pore spaces, thereby inhibiting further gas flow. The use of this "gas-induced" cement barrier to prevent gas flow has been successfully applied in Canada, Europe and the United States. Several case histories are discussed.