bluuebunny/crossref_metadata_2025 huggingface dataset:
Fracture Conductivity Comparison of Ceramic Proppants
Authors: Cutler R. A. , Enniss D. O. , Jones A. H. , Swanson S. R.
Published: December 2007

Lightweight, intermediate-strength proppants have been developed that are intermediate in cost between sand and bauxite. A wide variety of proppant materials is characterized and compared in a laboratory fracture conductivity study. Consistent sample preparation, test, and data reduction procedures were practiced, which allow a relative comparison of the conductivity of various proppants at intermediate and high stresses. Specific gravity, corrosion resistance, and crush resistance of each proppant also were determined.

Fracture conductivity was measured to a laminar flow of deaerated, deionized water over a closure stress range of 6.9 to 96.5 MPa [1,000 to 14,000 psi] in 6.9-MPa [1,000-psi] increments. Testing was performed at a constant 50°C [122°F] temperature.

Results of the testing are compared with values from the literature and analyzed to determine proppant acceptability in the intermediate and high closure stress regions. Fracture strengths for porous and solid proppants agree well with calculated values.

Several oxide ceramics were found to have acceptable conductivity at closure stresses to 96.5 MPa [14,000 psi]. Resin-coated proppants have lower conductivities than uncoated, intermediate-strength oxide proppants when similar size distributions are tested. Recommendations are made for obtaining valid conductivity data for use in proppant selection and economic analyses.
Calculating Recovery by Cycling a Retrograde Condensate Reservoir
Authors: Sheldon W.C.
Published: December 2007

The theory and principles covering cycling a retrograde condensate reservoir have been presented by some excellent papers. Methods for calculating recovery have also been discussed. However, calculating rate of dry gas invasion or dilution when cycling a thick reservoir presents some problems. The vertical sweeping depends upon the permeability range or distribution of permeabilities in reservoirs where thickness of the productive zone approaches the distances between wells. This paper discusses the concept of permeability variation, or V factor, and presents curves to relate sweeping efficiency with pore volumes of dry gas injected for various permeability variations. From these considerations a "dilution factor" has been developed for various permeability variations.

Introduction

Many cycling operations have been initiated to obtain a greater recovery of liquids otherwise lost by retrograde condensation within the reservoir. One of the problems which confronts those concerned with such a project is to determine anticipated recovery for any proposed plan of cycling operation. After a project has been started it is important to be able to determine whether it is operating satisfactorily at any given time. The subject has been covered by some outstanding papers.

The purpose of this paper is to clarify some concepts previously presented. Some curves have been developed which have been useful in following the cycling performance of reservoirs with thick sections.

Method

In cycling a reservoir that is relatively thin, one in which sand thickness is small compared to distance between wells, transition from producing reservoir wet gas to driving dry gas is sharp. In such cases there is little dilution of reservoir gas by injected dry gas. A producing well changes rapidly from wet gas production to dry gas shortly after the first dry gas is produced. In these cases the permeability variation concept, as discussed by Law and by Standing, et al. is valid but less apparent.
Case History of Steam Soaking in the Kern River Field, California
Authors: Long Robert J.
Published: December 2007

Crestmont Oil Co.'s 42-acre May Fee property is located in the Kern River field, and consists of eight wells in the China Grade zone and seven wells in the Kern River zone. The average well declined from an initial production of 70 to 4 BOPD in seven years, while recovering only 9 per cent of the oil in place. A thermal recovery program was initiated using the steam soak method of injecting, soaking, and then producing. After injecting an average of 10,000 bbl of water as 80 per cent quality steam in six of the 15 wells, production increased from 1,635 to 13,374 bbl/month. The eightfold increase in production can be accounted for by the fact that these zones are ideally responsive to steam stimulation, due to the large decrease in viscosity realized by small increases in temperature and the large amount of 12.5 deg. gravity oil remaining at relatively shallow depths.

Introduction

Primary production from the seven- and 15-year-old wells on the 42-acre property had declined to 2 to 6 BOPD/well, even though only 9 per cent of the original oil in place had been produced. Late in 1962 Crestmont Oil Co. decided to investigate various methods of thermal recovery to see if the remaining oil could be economically recovered. The purpose of this paper is to

present the reservoir conditions prior to steam injection, describe equipment used and the method of injection, tabulate the results before and after the wells were steamed, and tabulate techniques and conclusions regarding steam injection.

Geological Description

The Kern River zone contains 190 net ft of oil sand from 700 to 1,000 ft. There are several strata of shale throughout the zone, with a 60-ft interval occurring at 850 ft. The formation has 35 per cent porosity, 20 per cent connate water, and a 1.05 formation volume factor. The viscosity of the oil at the ambient reservoir temperature of 80F is 7,000 Saybolt-seconds. The gravity averages 12.6 at 60F. The Kern River zone contains approximately 1,900 bbl of oil/acre-ft. A zone of fresh water, identical to the produced water, exists from just below the surface to the top of the Kern River zone. Fig. 1 shows a composite log of the Kern River and China Grade zones. The China Grade zone contains 20 ft of oil sand in Te 35 ft from 1,200 to 1,235 ft. The China Grade zone exhibits a more uniform vertical homogeneity than the Kern River zone. The ambient temperature, viscosity and gravity are closely related to the Kern River zone.

JPT
Acid Stimulation of a Fractured Shale Zone
Authors: Dewar R.M.
Published: December 2007

Honolulu Oil Corp., operator for the Antelope Shale Zone Unit, Buena Vista Hills, initiated a program for oil well acid treatment for the purpose of removing precipitated carbonate scales from production equipment and for well stimulation, Oct. 23, 1956. This program was active through Feb., 1958. In this period 35 wells were acid treated yielding a net increase in oil of 1,390 B/D and gas increase of 3,265 Mcf/D. The total cost of acidizing the 35 wells was $80,000.

Introduction

Acid stimulation of California oil wells has been used to a limited extent, primarily for dissolving precipitated carbonate scales and other plugging agents within or adjacent to the wellbore.

In the Antelope Shale Zone in Buena Vista Hills, some producing wells showed evidence of rapid carbonate scale precipitation on the tubing and rods in early phases of production. Observation of this scale led to the belief that acid treatment of a well might be beneficial both to production equipment and to production rate, if liner and adjacent wellbore were suffering plugging. Initial application of acid to an oil well was made almost solely to clean up production equipment.

History of Development

The Buena Vista Hills field is located in Kern County near Taft. The field is on a large anticlinal structure including two domes and containing several productive sands from about 2,300 to 3,900 ft, and also containing the Antelope Shale Zone which is predominantly a fractured shale. The shallower sand zones were developed over a period from 1909 to the present time. The fractured shale zone has been developed in the last six years and development is still progressing to a minor degree. This report is confined to the East Dome. The upper sands have been acid treated on occasion over a period of years in a spotty manner giving spotty results. A few jobs were quite beneficial, but the majority were of moderate or no success. The predominant basis for treatment of these upper sands was also the observation of precipitated scale on production equipment.
An Efficient Fully Implicit Simulator
Authors: Ponting D. K. , Foster B. A. , Naccache P. F. , Nicholas M. O. , Pollard R. K. , Rae J. , Banks D. , Walsh S. K.
Published: December 2007

This paper describes Program for Oil Reservoir Simulation (pores), an efficient general-purpose black-oil simulator now in production use for modeling North Sea fields. The fully implicit finite-difference equations are solved for each timestep with a Newton-Raphson procedure. The resulting large sets of linear equations are usually solved simultaneously by a new and powerful iterative method that uses a preconditioned conjugate gradient algorithm with an enforced column-sum condition to accelerate convergence. A sequential solution option is available, and direct matrix inversion methods also are provided. Gas condensate problems are handled by a variable switching technique. Four examples are presented to illustrate the power and efficiency of the program.
Economics of a Computerized Oilfield Control System
Authors: Bowler D.L. , Queen J.A.
Published: December 2007

The economic aspects of the online, programmable computer for supervisory control of producing operations are discussed. The material presented reflects the performance and economics of a pilot supervisory control installation that has been supervising and controlling producing operations for one year in two widely separated fields in southeastern New Mexico. Expansion of this pilot supervisory system is necessary to obtain an actual payout, but the performance of the pilot project does provide a reliable basis for predicting the economics of full scale computer controlled producing operations.

Introduction

A pilot installation to evaluate a supervisory, monitoring and control system for properties operated in southeastern New Mexico by Continental Oil Co. was installed in Oct., 1964. The pilot project included 56 wells in two fields to be controlled from the district office in Hobbs, N. M. Results of the pilot project would serve to evaluate the economics of expanding the system to include three additional areas and 326 additional wells in a full scale operation, with possible future expansion to a total of 600 to 700 wells. The pilot installation and three additional areas to be included in the full scale project are shown in Fig. 1.This supervisory control system is similar in concept to an earlier system installed during 1962 in the Big Horn Basin of Wyoming by the Rocky Mountain Region of Conoco. The pilot project has been sufficiently complex to prove equipment capability and performance, but limited enough to keep installation costs within reason should results indicate the total project to be economically unattractive leases in the Hobbs and El Mar fields of New Mexico comprise this two-field pilot project. These areas are separated by approximately 56 air miles (Fig. 1). The Hobbs field, located two miles from the central supervisory in the city of Hobbs, consists of three leases with 14 flowing or pumping wells producing 5 1 8 BOPD into one central tank battery. The El Mar field includes three leases with 42 pumping or flowing wells producing 700 BOPD into a central tank battery. The objective of the pilot program was to determine if a significant portion of the pumper functions could be performed by the supervisory system while maintaining producing efficiency at a level equal to or greater than before. It was recognized that not all of the pumper duties could be performed by computer control but that almost all of the check-and-see type routine could be surveyed by the system. The majority of pumper time involves travel and inspection duties; therefore, it was estimated that approximately 50 per cent of his assignments could be supervised by the control system.

JPT

P. 48ˆ
One Hundred Years of Progress in Petroleum Production Engineering
Authors: Power Harry H.
Published: December 2007

Comparison of petroleum production engineering practices in the United States throughout the past century shows:the profession has been represented ipso facto from the beginning, andrecognition as a separate and distinct engineering profession has occurred only during the last half of the 100-year history.

The coal-oil industry was already of sizeable extent in 1859, and industrial and domestic needs were well established for illuminating oils and lubricants.

Although commercial incentives are credited with the initiation of the petroleum industry, "Colonel" E. L. Drake has been recognized for his application of salt-well drilling techniques to the recovery of oil. Development, first confined to Pennsylvania, spread to at least four other states before the close of 1860. The demand for competent labor, trained "on the job" increased as migration proceeded to new areas of flush production.

Early Exploration

When embryo development at Bradford was found as a direct continuation of the Clarion County oil trend, transit lines served as "conclusive proof that all the lands through which that line passed were ‘on the oil belt!’". This procedure was criticized severely by John F. Carll, often recognized as the first petroleum production engineer in the United States. His vision of the real importance of geology and reservoir performance predicted present day theories and techniques with remarkable clarity.

Of importance to exploration, however, were the oil, gas and water seepages; and asphaltic, paraffinic and bituminous deposits closely associated with the oil and gas areas developed initially.

In addition to topographic features and surface indications, "creekology" prevailed for a short time, followed by a general resort to sorcery and divining rods.

However, early drilling activities served to provide considerable knowledge of geologic structures for the accumulation of oil and natural gas. The anticlinal theory, as first developed by T. Sterry Hunt in 1861, was not given credence by geologists and producers until its revival 20 years later by I. C. White. Oil found in non-anticlinal areas served to discredit the first proposed theory. Hence, few geologists were employed by the producers prior to 1900.
A Review of Foreign Oil Production in 1960
Authors: Mayhew Zeb
Published: December 2007

The petroleum industry during 1959 was characterized by one dominant theme - overcapacity to produce. This problem continued to dominate 1960 and will undoubtedly be a sore thumb for many years to come.

In the Free Foreign area, spare capacity to produce increased only slightly, barrelwise, during 1960 and as a per cent of total capacity, it leveled off. However, this adjustment is qualified by the fact that some major investments currently being made abroad soon wilI result in the availability in the world market of substantial volumes of new crude. This can only result in another upward cycle of the over-all spare producibility curve.

Of course, a certain level of spare is necessary because the oil industry is a growing business and cannot afford simply to exist from day to day. A certain amount of extra capacity is necessary to allow for the unavoidable downtimes which occur in producing operations; and, finally, there is the need to have some spare for handling emergencies.

All these factors require that money be invested in spare capacity, but the big question is, "What level of spare is desirable and when does it become a burden?". It would be an oversimplification to make a general statement about the worldwide industry because both the location and ownership of spare capacity have a great deal to do with its effect.

Fig. 1 shows spare capacity as a per cent of total capacity for the last decade for the United States, Free Foreign, and Free World areas.
Fluid and Heat Flow In Gas-Rich Geothermal Reservoirs
Authors: O'Sullivan M. J. , Bodvarsson G. S. , Pruess K. , Blakeley M. R.
Published: December 2007

Numerical simulation techniques are used to study the effects of noncondensable gases (CO2) on geothermal reservoir behavior in the natural state and during exploitation. It is shown that the presence of CO2 has a large effect on the thermodynamic conditions of a reservoir in the natural state, especially on temperature distributions and phase compositions. The gas will expand two-phase zones and increase gas saturations to enable flow of CO2 through the system. During exploitation, the early pressure drop primarily results from "degassing" of the system. This process can cause a very rapid initial pressure drop, on the order of megapascals, depending on the initial partial pressure of CO2. The flowing gas content from wells can provide information on in-place gas saturations and relative permeability curves that apply at a given geothermal resource. Site-specific studies are made for the gas-rich, two-phase reservoir at the Ohaaki geothermal field in New Zealand. A simple lumped-parameter model and a vertical column model are applied to the field data. The results obtained agree well with the natural thermodynamic state of the Ohaaki field (pressure and temperature profiles) and a partial pressure of 1.5 to 2.5 MPa [217 to 363 psi] is calculated in the primary reservoirs. The models also agree reasonably well with field data obtained during exploitation of the field. The treatment of thermophysical properties of H2O/CO2 mixtures for different phase compositions is summarized.
Water/Oil Displacement Characteristics in Crossbedded Reservoir Zones
Authors: Kortekaas T. F. M.
Published: December 2007

Festoon crossbedding is a typical sedimentary structure in sandstone reservoirs. It is especially common in fluvial deposits. The important elements are the foreset laminae, which vary in permeability, and the bottomsets of lower permeability.

To understand the complex, direction-dependent displacement characteristics of a crossbedded reservoir zone, we first conducted numerical simulations on a centimeter scale in a small part of a water-wet crossbedded reservoir zone. The simulations indicate that, during water/oil displacement, considerable amounts of movable oil initially are left behind in the higher-permeability foreset laminae with fluid flow perpendicular to the foreset laminae, while with flow parallel to the foreset laminae the displacement efficiency is good.

To describe the displacement characteristics on a reservoir scale, we developed a procedure for calculating direction-dependent pseudo relative-permeability and capillary-pressure curves to be used as input for the simulations of water/oil displacement in a crossbedded reservoir zone. On a reservoir scale, the displacement characteristics in a water-wet crossbedded reservoir zone are slightly more favorable with the main fluid flow perpendicular to the foreset laminae.

In addition, the sensitivity of the displacement characteristics to moderate reductions in interfacial tensions (IFT's) and to increases in water viscosity was investigated, both on a centimeter scale and on a reservoir scale. The simulations indicate the potential for substantial improvement in recovery from crossbedded reservoir zones if diluted surfactant or polymer is added to the drive water.
Analytical and Numerical Modeling of Immiscible Gravity-Stable Gas Injection Into Stratified Reservoirs
Authors: Ypma J. G. J.
Published: December 2007

A two-dimensional (2D) analytical model is presented for gas/oil gravity drainage in a homogeneous, dipping reservoir. The sensitivity of gas/oil gravity drainage to key variables such as injection rate, oil relative permeability, and permeability anisotropy can be determined quickly with this model.

Example calculations show that miscible-like recovery efficiencies are possible with immiscible gas injection into high-permeability dipping reservoirs with light oil.

A procedure based on the analytical model has been developed to simulate immiscible gas injection into highly stratified reservoirs accurately. This simulation procedure allows a great deal of geological detail to be incorporated into reservoir models, because it permits relatively coarse grids.

Application of the simulation procedure to a reservoir containing many discontinuous shales reveals that the presence of shales may favorably affect the recovery efficiency of an immiscible gas-injection process.
How Oil Wells Are Completed in the Paradox Basin
Authors: MacAlister R.S.
Published: December 2007

This paper covers the common completion practices for oil wells in the Paradox Basin fields near the Four Corners. The nature of the producing formations is described and the pertinent drilling problems are discussed. Since the pay consists of carbonate rocks, stimulation by acidizing is the principal ingredient of completions. These methods of acidizing which have been tailored to the reservoir characteristics are described.

Introduction

As in any other geologic province, the Paradox Basin requires its own combination of the myriad of drilling and completion techniques if optimum productivity is to be obtained at minimum cost. With the boom in development activity since the oil pipelines from this basin were constructed the process of making an oil well has undergone considerable refinement so that today better wells are being completed for less money. This treatise describes how this is done. To facilitate an understanding of the problems peculiar to this area and the reasons for the methods used to cope with them, a complete but generalized description of the reservoirs is presented.

Pertinent Drilling Information

The proved commercial productive horizons in the Paradox Basin are, for all practical purposes, the porous carbonates of the Pennsylvanian Hermosa formation and those of the Paradox member. In the area of greatest exploration and development, this formation is generally between 5,000 and 6,000 ft deep. Drilling times in the Aneth and Ratherford fields are approximately 25 days, and generally somewhat more in wildcats and outlying fields. Most operators drill 9-in. hole and set 7-in. production casing or drill 7 ⅞-in. hole and set 5 ½-in. production casing. Reservoir pressure of the productive zone is less than hydrostatic, and mud weights of 9.2–10.4 lb/gal have been found to be satisfactory after setting surface casing. The mud weight depends on the weight that is necessary to control the water flow from the De Chelly, which lies some 2,000 ft below the surface. For development wells it is frequent practice to emulsify some oil into the mud before reaching the objective zone which improves drilling characteristics, reduces mud costs, and probably reduces contamination of the pay section.
Modification of Welge's Method of Shock Front Location in the Buckley-Leverett Problem for Nonzero Initial Condition
Authors: Mohsen M. F. N.
Published: December 2007

In the analytical solution of the Buckley-Leverett problem, Welge1 recommends that to locate a front, one should draw a tangent to the fractional saturation curve from the origin. In this paper I establish that this procedure will be correct only for the case of a zero initial condition. For a nonzero initial condition, a mass-conserving front will be located farther down the flow direction. The implications of this finding for error analysis in comparing numerical solutions to the analytical one are discussed.
Laboratory Studies of a Pulsed Neutron-Source Technique in Well Logging
Authors: Tittman J. , Nelligan W.B.
Published: December 2007

Introduction

Refinements in radiation logging techniques during recent years have involved increasing usage of scintillation detectors. These detectors produce voltage pulses whose heights are related to the energies of the gamma rays which initiate them. Analysis of the gamma-ray spectrum, as indicated by the pulse heights, yields information about the chemical elements composing the formations surveyed. Refined scintillation counter techniques can furnish chemical information concerning earth formations in situ, from a study of the gamma-ray spectra emitted by the formation either naturally or as a result of neutron bombardment.

Accompanying the rising interest in gamma-ray scintillation spectroscopy, there has been increased activity in the development of accelerator-type neutron sources (in contrast to encapsulated chemical-mixture sources). Such neutron generators are attractive for several reasons:they greatly reduce radiation hazards to personnel;there is a great reduction in contamination danger if they are lost in the hole;they can produce larger neutron intensities than can conveniently available encapsulated sources; andthey are capable of being pulsed, thus permitting new techniques in logging.

In the past, both accelerator and encapsulated neutron sources have been used by others in conjunction with scintillation-detector pulse-height analysis. The results have not been too encouraging, due to the interference among different gamma-ray spectral lines and to the fact that the gamma-ray peaks were not too clearly distinguishable above the large and ill-defined background "noise".

This paper is a status report on laboratory studies of a technique using a borehole accelerator as a neutron source, which gives an improved scintillation spectrum, thus permitting more accurate chemical analyses of the formations penetrated. The Schlumberger-accelerator neutron source is presented; the origins of inelastic and of thermal-neutron, capture gamma rays are discussed, and results are given for some laboratory measurements performed in borehole geometry.
Dip-Log Computer Chart
Authors: Swift Gilbert
Published: December 2007

The Dip-Log

A conventional Dip-Log consists of a set of three formation logging curves which register the depths of formation changes at three points around the face of the borehole, together with records of the orientation of the logging tool and the diameter of the well. The three curves may be electrical (resistivity) or mechanical (caliper) recordings.

The three curves which define the bedding planes are presented in essentially the same manner on all commercial dip-surveys. The orientation data, however, is presented in a variety of ways, one of which is illustrated by the Dip-Log shown in Fig. 1. In this form of presentation the direction of the well deviation with respect to the north-seeking end of the compass and the compass direction with respect to the direction of the No. 1 Arm are each recorded, by a separately identified trace, together with the three resistivity traces, in the right-hand column of the log. The compass trace is identified by being recorded as a series of dots while the deviation direction trace consists of dashes.

The diameter of the borehole and the angle of deviation from vertical are recorded by separate traces operating in the left-hand column of the Dip-Log.

While there are numerous other ways of presenting the orientation data the task of computing the amount and direction of dip is substantially the same regardless of the way in which the basic data is read from the log.

Computing Dip

The problem facing the user of the Dip-Log is that of computing from the observed depth differences and the recorded tool orientation data, the amount of dip relative to a horizontal plane (the true dip) and its direction with respect to north.

A number of different methods have been used in the past to solve this problem. Some of these require complicated computations involving the use of trigonometric tables. Others require several separate graph sheets together with numerical computations; while still others employ costly mechanical devices which model the subsurface situation. In contrast, the present computer chart is an 8 1/2 X 11 in. printed sheet on which a simple sequence of graphical steps enables the user to obtain the solution. This chart is used with a transluscent tracing paper overlay which becomes a permanent and reproducible record of each solution. The simplification is obtained primarily through the use of a grid based on the gnomonic projection instead of the stereographic net employed in the previous graphical methods.
Identification of Crude Oil Components Responsible for Foaming
Authors: Callaghan I. C. , McKechnie A. L. , Ray J. E. , Wainwrigh J. C.
Published: December 2007

The foaming characteristics of a number of crude oils from a variety of sources were determined by Bikerman's pneumatic method. Extraction of these crudes with both alkali and acid indicated that the crude oil components responsible for the foam stability were removed by the alkali extraction. Further examination of the alkali extract revealed that after neutralization it was the chloroform-soluble part of this extract (0.02% wt% of the whole crude) that was responsible for the foaming properties of the crudes investigated. This latter point was confirmed by demonstrating that the surface rheological properties of one of the extracted crudes could be restored by adding back the chloroform-soluble portion of the neutralized alkali extract. Analysis of this extract indicated that the foam-stabilizing materials were short-chain carboxylic acids and phenols of molecular weight ≤400. In principle, such analytical information could be used to identify crude oils likely to present severe foaming problems in the field. Such information could enable the process engineer to take appropriate corrective measures early in the life of a new field, thus avoiding the need for high capital expenditure at a later stage.
A Service-Life Model for Casing Strings
Authors: Klementich Erich F. , Jellison Michael J.
Published: December 2007

Conventional casing design is based solely on the achievement of adequate design factors in burst, collapse, and tension from the loads generated by the hanging weight of the pipe, internal and external surface pressures, and fluid densities. The effects of cementing, temperature changes, ballooning, changes in cross-sectional area, bending, and helical buckling are virtually never considered. This paper describes a service-life model for the design analysis of casing strings that includes the significant factors that affect the performance of the string.
Pressure Transient Analysis in an Elongated Linear Flow System
Authors: Ehlig-Economides Christine , Economides Michael J.
Published: December 2007

Prominent examples of linear flow behavior in the well test literature describe flow within or to a fracture penetrated by a producing well. The characteristic pressure transients generally are exhibited in the early portion of a well test and are followed by infinite-acting radial flow behavior and/or boundary effects. In contrast, if a formation is of a predominantly linear shape, linear flow is expected to develop in late time.

In this paper, analyses of interference, drawdown, and buildup tests that are applicable to linear flow systems are described theoretically and illustrated by practical examples. The necessary equations for the analyses are provided for testing oil, gas, and geothermal steam wells.

In elongated linear flow systems, the pressure transient behavior associated with linear flow occurs late in the drawdown or buildup test. The type curves provided in this work show that this pressure behavior is distinguishable from conventional well tests, particularly in interference tests.
Hydraulic Fracturing in Waterflood Operations in Kermit, Cherrykirk and Pecos Valley Fields
Authors: Riley E.A.
Published: December 2007

A limited amount of published data is available which presents results of hydraulic fracturing in waterflood operations. To add to this knowledge, this report presents data resulting from frac programs performed in three different reservoirs. These programs were performed to effect both injectivity and productivity increases. The majority of applications were performed at a time during flood life which affords valid and conclusive interpretation of results.

Conclusions based upon results obtained from the frac jobs may or may nor be indicative of benefits to be gained in every field. Therefore, no panacea for lagging, negligible, or hesitant well performance is offered. However, it is suggested that sub par well performance in water flood operations may be alleviated and improved by proper applications of the popular hydraulic fracturing technique.

A total of 20 producers and four injectors were treated in the three fields. Only two applications can be termed failures; these are believed to have been due to mechanical features (handout or improper frac technique).

Theoretically, the most beneficial fracture system for flooding operations can be obtained by use of either low injection volumes and high injection rates or medium injection volumes and low injection rates. A resultant multiple fracture system of limited radial distance from the wellbore should occur.

Introduction

Requisite levels of well receptivity of productivity in waterflood operations are not necessarily incurred in every operation. Several factors attributable to local wellbore damage are possible causes.

Until quite recently, no method to improve individual well performance, other than formation fracturing with explosives (nitroglycerin) or acidization, was considered safe enough to be used. Even these methods were unsure and often created expensive cleanout work after the shot.
Pressure Maintenance in SACROC Unit Operations January 1, 1959
Authors: Allen H.H. , Thomas Jim B.
Published: December 2007

The SACROC Unit pressure maintenance plan does not depend on water injection alone for improving reservoir conditions, but in conjunction with 66 water injection wells located along the longitudinal axis of the Kelly-Snyder field, some 400 producing wells along the edge of the field have been shut in and their allowables transferred to more efficiently producing wells in the central portion of the field on either side of the line of injection wells.

This supplemental history will generally follow the pattern of the previous paper, bringing reported operations tip to date and also presenting additional data pertinent to the stages of development occurring thus far in the life of SACROC Unit.

Introduction

It is one thing to discover an oil reservoir of 2,800 million STB, but quite another thing to produce it. The comparison between estimated recovery by pressure maintenance and ultimate recovery indicated by primary production resulted in the creation of SACROC Unit. The organizational setup of SACROC is most complex and little understood except by those intimately involved with overall operation, but no space will be taken to discuss that subject in this paper.

Original Reservoir Conditions

The Canyon Reef reservoir of the Kelly-Snyder field encompasses some 50,000 productive acres. The field was developed by approximately 82 operators with the wells drilled on 40-acre spacing. The Canyon Reef reservoir is encountered at an approximate depth of 6,700 ft, and varies from 0- to 795-ft thick. It is a low mound shape with gently dipping flanks. Average porosity of net reef is 10.03 per cent, and average porosity of gross is 7.11 per cent. Net pay is defined as reef having 3 per cent or greater porosity. The average permeability is 30.6 md to air. Initial oil saturation was 100 per cent of hydrocarbon pore space. Average interstitial water saturation was 28.2 per cent and the average reservoir temperature 130°F. The characteristics of the reservoir fluids are shown in Table 1.
Effect of Dynamic Bit Forces on Bit Bearing Life
Authors: Dareing D.W. , Radzimovsky E.I.
Published: December 2007

This paper presents theory which is used to predict rock-bit bearing life reduction due to simple harmonic variations in bit forces. The theory is based on the premise that it a constant load acts for a certain fraction of the life which the bearing would have if that constant load were applied for its entire life, then the same fraction of the life of the bearing is consumed. Total bearing life is related to simple harmonic variations in bearing life associated with instantaneous bearing loads. The results show that rock bit bearing life is not affected appreciably by forces commonly impressed upon a bit, but it is affected appreciably by relatively large dynamic bit forces occasionally encountered during drilling. In addition, the results show that the life of sealed bearings is more sensitive to bit force variations than is the life of unsealed bearings.

Introduction

Roller bearings are important components in roller cone rock bits because they transmit a large portion of the drill collar weight to the formation being drilled. Unfortunately, they have a relatively short life under down-hole drilling conditions. Roller bearings are usually the first bit components to fail, and their failure leads immediately to failure of the entire bit. Short roller bearing life, and thus short bit life, is due mainly to high unit loads transmitted by the bit and to the adverse environment in which the bearings operate. The results of the study discussed in this report show how dynamic bit forces also affect roller bearing life. The purpose of this paper is to discuss theory developed to predict the effect of different magnitudes of periodic bit forces on roller bearing life. Theoretical results are used to compare the life of rock bit roller bearings subjected to steady forces to the life of rock bit roller bearings subjected m unsteady forces similar to the type of unsteady forces measured at the bit with a special downhole recording instrument.

Background

Manufacturers of bearings have conducted laboratory tests which show how bearing life is affected by steady bearing load. The well-known empirical equation which defines bearing life follows from bearing test data. It is:

L = ...................(1)

where L = bearing life, hrP = bearing load, lbC = constantq = exponent (constant).

The effect of environment on bearing performance is manifested through the exponent q and the constant, C. King, in similar tests conducted on roller bearings used in rock bits, showed that, in addition to the load, the environment (abrasive materials, chemical components, etc.) greatly affects bearing life. His data, which show how the life of roller bearings in a 7–7/8-in. W7R bit rotating at 60 rpm is affected by bit weight and fluid environment, are displayed on a log-log plot by broken lines made up of straight line segments. Each broken line corresponds to a given environment.

SPEJ

P. 272ˆ
Transient Pressure Distributions in Fluid Displacement Programs
Authors: Landrum Bobby L. , Crawford Paul B.
Published: December 2007

The use of a new laboratory model for studying transient fluid flow problems, is described. The theory of the model is based on the analogy between the equations which describe the flow of compressible fluids in porous media and the conduction of heat in solids.

The "thermal model" is used to study the transient pressure distributions during fluid displacement in five standard well patterns. The studies indicate quantitatively how the pressures change with time at any point in the reservoir. It was found that, in general, the equipressure contours are more radial about the wells early in the program than after steady-state conditions are established. In addition two studies of fractured five-spot patterns are presented to illustrate the applicability of the model for a wide range of reservoir conditions.

Introduction

In reviewing the oil recovery techniques involving fluid displacement it was found that a very considerable quantity, if not all of the fluid within the pattern, may be displaced during a time-dependent or transient period rather than the usually applied steady-state conditions. Since the oil is displaced during a transient period, it was believed desirable to study the nature of the transients for several of the commonly used fluid displacement patterns.

A literature review indicated fairly complete studies of the streamlines and isopotentials for steady-state, yet few data were available on the transient displacement process. Several simulated steady-state multiwell displacement programs were carefully mapped by Foster and Lodge on an electrical conducting sheet as early as 1875, but the more recent work of Muskat provides the best source for steady-state phenomena having direct petroleum production applications.

In order to study the transient phenomena a new laboratory model was developed which is based on the similarity of the equations that describe the flow of fluids and the conduction of heat. The equations describing heat flow were developed early in the nineteenth century. Rigorous solutions for most transient problems are in general complex and usually limited to fairly restricted boundary conditions. The thermal model may be used to obtain approximate solutions for many transient problems without some of the restrictions required for analytical solution.
Linear-Stability Analysis of Immiscible Displacement: Part 1—Simple Basic Flow Profiles
Authors: Yortsos Y. C. , Huang A. B.
Published: December 2007

The linear stability of immiscible, two-phase-flow displacement processes in porous media is examined. Multiphase-flow characteristics are included in the stability description through relative-permeability and capillary-pressure functions.

A linear-stability analysis of the steady-state saturation and pressure distributions is carried out in terms of normal modes. The resulting linearized eigenvalue problems describing the early evolution of unstable modes show a certain similarity in the respective cases of negligible and non-negligible capillary effects to the Rayleigh and Orr-Sommerfeld equations governing the stability of unbounded shear flows.

The stability of noncapillary displacement is first examined. Growth rates of the unstable modes as a function of the wavelength of instability are explicitly obtained for specific classes of initial total-mobility profiles. The Saffman-Taylor1 instability and layer instability2 follow directly as limiting cases of the initial-mobility profiles.

The effect of capillarity on flow stability is examined next. Stability curves are obtained for step-saturation initial profiles. Both capillary pressure and a smooth initial-mobility profile exert a stabilizing influence on the flow displacement. The linear-stability-analysis predictions are compared to the results of Chuoke et al.,3 and an estimate for the effective interfacial tension (IFT) is derived. The results find application in prediction of the onset of instability and description of the early stages of unstable growth in immiscible displacement.
Oxygen Fireflooding: Combustion Tube Tests With Light, Medium, and Heavy Crude Oils
Authors: Shahani Goutam H. , Hansel James G.
Published: December 2007

Five light, medium, and heavy crude oils were evaluated in a combustion tube, primarily at 750 and 2,000 psig [5.2 and 13.8 MPa] and with O2 concentrations between 21 (air) and 95%. The overall characteristics of combustion with O2 appear to be superior to those with air. For light and medium crude oils, when the combustion conditions are marginal (e.g., at low temperatures at which the kinetics appears to control coke combustion), the apparent kinetics and the quality of the combustion were substantially improved when O2 enrichment was used.

Three of the crude oils in this study did not burn in air; however, with the same flux of contained O2, high levels of O2 enrichment could sustain combustion. For two of the crude oils, as the O2 concentration was increased, the peak front temperatures actually decreased slightly while the O2 use efficiency increased significantly with no change in the coke loading. Further, for a heavy oil at 2,000 psig [13.8 MPa], it was found that O2 enrichment, which provided a higher partial pressure of combustion-derived CO2 and (perhaps) steam because of O2 removal, may have served to reduce the coke loading in comparison with air.

An attempt was made to correlate the relative combustion performance of four of the crude oils. It was found that a high coke loading alone was not adequate to ensure satisfactory in-situ combustion. The relative reactivity of the coke with O2 also appeared to be critical.
Effect of Fractional Wettability on Multiphase Flow Through Porous Media
Authors: Fatt Irving , Klikoff Waldemar A.
Published: December 2007

The concept of fractional wettability is examined. Fractional water wettability of a reservoir rock is defined as the fraction of the internal surface area that is in contact with water. Capillary pressure and relative permeability of unconsolidated sand are shown to be functions of fractional wettability.

Introduction

The petroleum industry has long recognized that wettability of reservoir rock has an important effect on multiphase flow of oil, water and gas through reservoirs. As early as 1928 the American Petroleum Institute sponsored a study of wettability as part of API Project 27 at the U. of Michigan. Despite 30 years of research, there is still little exact knowledge of the wettability of reservoir rocks.

There are two parts to the wettability problem. After agreeing to a uniform nomenclature in regard to wettability, the first question to be answered is, "What is the in situ wettability of a given reservoir rock?" If this can be answered the next question is, "What part does wettability play in determining the characteristics of multiphase fluid flow through the rock?" This paper represents an oblique attack on the problem of wettability. No attempt is made here to answer the basic question of wettability in situ. Instead the consequences of the concept of fractional wettability are examined. Multiphase flow in sandpacks is shown to be highly influenced by fractional wettability.

Jennings has given a definition of wettability and the other terms used in discussing wettability. These terms must be applied to the physical situation existing in reservoir rock. A survey of the pertinent literature from 1928 to 1956 indicates that the concept of a contact angle was applied to reservoir rock in the same way it would be applied to a flat, homogeneous surface. Attempts were made to state quantitatively the wettability of a reservoir rock in terms of a contact angle which was presumably constant at all points on the very rough and heterogeneous interior surface of a porous rock. Calhoun, et al, prepared synthetic consolidated and unconsolidated porous media in which they claimed there was a known uniform contact angle. They then showed the effects on the capillary pressure and relative permeability characteristics of varying this angle.