bluuebunny/crossref_metadata_2025 huggingface dataset:
Slim Hole Technology - An Economic Key to Future Drilling Developments
Authors: McLaughlin Philip L.
Published: December 2007

Introduction

"Based on present allowables, probably more than half the wells in Texas today could be produced through 1.5-in. tubing", stated Philip L. McLaughlin, president of The McLaughlin Co., Dallas, at a recent meeting of the Mid-Continent Section Study Group in Tulsa, Okla. McLaughlin, who was very closely associated with slim hole drilling and completion techniques and equipment while employed by the Cardwell Manufacturing Co., spoke to the Mid-Continent Section Study Group on the economics of slim hole drilling and completions.

McLaughlin, owner of a firm which specializes in product market research and "assistance programs" for oil companies, opened his discussion by warning the group that since the oil industry is in a period of dynamic transition; oil companies, drilling contractors, service companies and equipment manufacturers must continually make themselves stronger as an industry and more alert to opportunity if they expect to continue their past progress.

Oil Industry Needs New Ideas for Economic Survival

"If oil is to economically survive in our lifetime, it must show a greater willingness to seek out, test, develop and adopt new ideas and new methods. Many research departments are thinking too small to create big deeds. There is a dire need of a freer exchange of information at all levels of each segment of our industry." Much of our present day equipment has outlived its economic usefulness-demanding an engineering revolution similar to the one the auto industry experienced in the late thirties.

To cope with this transition which is resulting from keener competition, poorer economic conditions, higher dry hole ratios and fewer reserves found for each well drilled, coupled with technical and management complacency, he advised that the oil industry must either develop methods of economizing, change "fixed idea" and "ivory tower thinking", or receive a much lower return on investments. "If 15 per cent depletion allowance is passed, I expect a great engineering and economy revolution that must come, will develop in a hurry or the oil industry is likely to wake up some day and find itself, joining the railroad industry, as the second biggest ‘sleeping giant’ in U. S. history.
A Summary of Unitization and the Engineering Functions in Unitization
Authors: Landis Bruce A.
Published: December 2007

Introduction

A wealth of valuable, well documented information about unitization exists today. Consequently, the scope of this presentation will be confined to (1) a summary of the over-all picture of unitization and (2) a review of the specific function of the petroleum engineer in the formation of fieldwide producing units involving secondary recovery operations.

A fieldwide producing unit can be defined as a unit comprised of lands that are producing or are reasonably proved to be productive at the time the unit is formed. Such lands usually embrace all or substantially all of a reservoir (common source of supply) in an established field. Such units are usually formed for the purpose of initiating some type of secondary recovery operations, but they may be formed for more efficient operations such as selectively producing certain wells, etc. which will have the effect of increasing ultimate recovery.

Sometimes units of substantial size involving a number of wells, but which do not include all or most of a field, are classed as fieldwide producing units to distinguish them from so-called spacing units. In fieldwide producing units, usually the entire 8/8 interest is unitized; i.e., the oil company's interest and all of the royalty interest are unitized. It is recognized, of course, that the engineer also plays a primary role in the formation of exploratory units, drilling and spacing units, partial units, communitization agreements and other species of joint operating programs.

The History of Unitization

In 1948 Robert E. Hardwicke wrote a truly informative and interesting book called Anti-Trust Laws et al vs Unit Operation of Oil and Gas Pools, which was published by AIME as a service to the industry. Hardwicke defines, in form of questions, two problems which were facing the industry in 1925.

First, what could be done to increase efficiency in oil and gas development and production, or how could recovery of oil and gas be materially increased and the expense of operation materially decreased? Second, what could be done to prevent the haphazard development of new pools, with resultant over-production, waste, inefficiency, and the demoralization of markets and prices? The answer to both problems is, in a large measure, unitization.
Production From a Fractured Well With Well Inflow Limited to Part of the Fracture Height
Authors: Schulte W. M.
Published: December 2007

A study is presented on the production behavior of hydraulically fractured wells in which gas or oil in the fracture enters the wellbore over a limited vertical interval, smaller than the fracture height. Such a limited communication interval between fracture and wellbore can be expected when the fracture is created from a deviated or a partially perforated well.

Type curves of the production behavior, derived with a numerical, single-phase simulator, show that in semiradial fractures with a limited communication interval, the early transient flow period exhibits the characteristics of a newly defined linear/radial flow regime. The characteristics of bilinear flow will be seen only when the fracture is in communication with the wellbore over the total fracture height.

An analytical derivation of the pressure response during pure linear/radial flow is given, and an analysis method that is capable of estimating fracture conductivity, effective well inflow interval, and fracture height has been developed by making use of the characteristics of linear/radial flow.

A small communication interval may also influence the long-term productivity of the well (especially a gas well) because of an increased non-Darcy flow effect near the communication interval. An expression for the expected skin value as a result of a limited communication interval is presented. The productivity of the well may be significantly reduced if the inflow interval is much smaller than the fracture height.
Propagation of Electromagnetic Waves Along a Drillstring of Finite Conductivity
Authors: DeGauque P. , Grudzinski R.
Published: December 2007

An evaluation of the electromagnetic communication capability of a drillstring used to transmit data from the bottom to the surface of a well, or measurement while drilling (MWD), must take into account the finite conductivity and permeability of the drillstring. The choice of frequency is a compromise between a relatively fast transmission rate and a great depth of operation. Theory and experiments show that, because of the finite conductivity of the drillpipe, decreasing the frequency below a few hertz does not improve the communication because the current distribution along the string remains nearly constant.

The current distribution has been resolved numerically by a matrix formulation that takes into account the series or internal impedance of the drill, and a comparison with experimental results has been made.
Using Simultaneous Downhole Flow-Rate and Pressure Measurements To Improve Analysis of Well Tests
Authors: Guillot A. Y. , Horne R. N.
Published: December 2007

The development of reliable spinner tools may help avoid much of the ambiguity that often accompanies well tests, resulting from interlayer flows through the wellbore. The use of both pressure and flow- rate changes, however, requires new methods of well test interpretation. Computer-based techniques have been developed for the simultaneous analysis of pressure and flow-rate measurements. This procedure consists of two key steps: (1) the nonlinear regression is achieved by calculation of the gradients of the response (with respect to the unknown reservoir parameters) in Laplace space and a numerical inversion; and (2) the variable flow rate is represented in terms of a superposition of many step changes, which was found to work better than a spline fit to the data. One problem was encountered when we attempted to analyze data in which the spinner stalled, causing a jump to zero flow rate.

The method shows great promise in that the degrees of freedom on the interpretation are greatly reduced, the wellbore storage effect disappears, and interlayer flows do not affect the results.
Use of Inverted-Emulsion Mud Proves Successful in Zones Susceptible to Water Damage
Authors: Trimble Glenn A. , Nelson M.D.
Published: December 2007

Extreme difficulties in well completions in Pennsylvanian age sands in Central Oklahoma led to the use of an inverted-emulsion mud for drilling-in, completion and workover operations in this area. This mud, containing about equal volumes of oil and water or water-base mud and emulsified by a modified wood product, has been employed successfully in over 150 operations over a six-year period. In zones that are susceptible to water damage, improved formation evaluation, better well completions and effective recompletion of damaged wells have been achieved. Mud is stored and re-used extensively. Testing and maintenance are relatively simple and inexpensive. The geological interpretation of formations has been adequate where the hole has been drilled with this mud. The mud offers no advantage in limestone or dolomite completion, and it may slow drilling rates in shale.

Early Well Completion Experience

In Central Oklahoma the majority of wells are in and the greater part of oil production is from sands of Pennsylvanian age. A number of formations are represented, of which the Springer and Hart sands are two of the better known.

Prior to 1953, the Mobil Oil Co. (then Magnolia Petroleum Co.) experienced severe difficulties in many well completions in various of these sands. Other operators in this area were having similar difficulties.

A characteristic experience follows. Drilling with a water-base mud (as was customary in this area), a well penetrated one or more Pennsylvanian age sands. At the time of penetration, drill-stem tests indicated fair producing rates. When completion of the well was attempted after further exposure of the sand to drilling mud or water, production was often much lower than indicated by the drill-stem test. In some extreme cases, no production could be obtained. In an outstanding example, oil flowed at 30 bbl per hour on drill-stem test, but could not be made to produce afterwards.

Well stimulation techniques, including acidizing and fracturing, were not effective in obtaining satisfactory completions. In some cases, attempted stimulation procedures, as employed, caused further decreases in production of oil.
Partitioning of Nonionio and Anionic Surfactant Mixtures Between Oil/Microemulsion/Water Phases
Authors: Graciaa A. , Lachaise J. , Bourrel Maurice , Osborne-Lee Irvin , Schechter Robert S. , Wade W. H.
Published: December 2007

Mixtures of different surfactant types have been proposed for application in polymer/micellar flooding processes. In some cases, severe fractionation of such mixtures is found even in short core experiments. In this paper, a new theory of surfactant partitioning between phases is developed and tested. Polydisperse nonionic surfactants blended with an anionic surfactant are considered. Important parameters in the theory are the critical micelle concentrations (CMC's) of surfactant mixtures in water and the partition. coefficients of the surfactant between oil and water measured at total surfactant concentrations less than the CMC. From these simple experiments, surfactant fractionation in microemulsion systems can be modeled.

We also show that the fractionation of polydisperse ethoxylated nonionic surfactants between excess oil and water phases is not as severe in the presence of anionic surfactants as it is in systems containing only nonionic surfactants.
Field Results of Liner Rotation During Cementing
Authors: Lindsey H. E. , Durham K. S.
Published: December 2007

Improving liner cementing has been a constant objective of the industry. Recent developments in rotating liner hanger technology have made this cementing technique applicable to more wells than before. Presented here is an analysis of 45 jobs done during 1 ½ years. The study examined mechanical success ratios as a function of liner size, depth, length, method of rotation, setting tool types, deviation, casing hardware (centralizers, scratchers, etc.), and bearing load. The results give the drilling and completion engineer a better understanding of the chances of a mechanically successful job.
Application of the Pressure-Derivative Function in the Pressure-Transient Testing of Fractured Wells
Authors: Wong D. W. , Harrington A. G. , Cinco-Ley H.
Published: December 2007

A new technique is presented for the analysis of wells with a finite-conductivity fracture. The technique simultaneously uses the pressure and pressure derivative for cases with no fracture skin and no wellbore storage and for cases with fracture skin and wellbore storage during the bilinear-flow period. New type curves are presented and applied to three field cases. The paper concludes that use of the pressure derivative with pressure-behavior type curves reduces the uniqueness problem in type-curve matching and gives greater confidence in the results.
Analysis of Variable-Rate Well-Test Pressure Data Using Duhamel's Principle
Authors: Thompson L. G. , Reynolds A. C.
Published: December 2007

This work considers the use of Duhamel's principle to analyze pressure drawdown and buildup data when both bottomhole pressures (BHP's) and sandface flow rates are available. This analysis procedure uses Duhamel's principle to convert pressure data obtained when the sandface rate is variable to the equivalent pressure data that would be obtained for a constant sandface rate of production. The equivalent constant-rate pressure data then can be analyzed with standard procedures (semilog analysis or type-curve matching).
Phase Behavior of Several CO2/West-Texas-Reservoir-Oil Systems
Authors: Turek Edward A. , Metcalfe Robert S. , Fishback Robert E.
Published: December 2007

The design of miscible CO2 recovery methods and the evaluation of laboratory CO2 coreflood and pilot field studies require knowledge of the phase behavior encountered in such processes and the ability to make reliable predictions. Because of the complexity of CO2/hydrocarbon phase behavior, experimental measurements are necessary as a basis from which to develop an understanding. In this paper, measured phase equilibria and volumetric properties are reported for several west-Texas-reservoir-oil/CO2 systems. Reservoir oils studied were from the San Andres, Grayburg, and Devonian Chert formations. Both static (single-contact) and multiple-contact measurements have been conducted in a visual fluid property cell. Static data cover a wide range of CO2 compositions and provide a general understanding of CO2/reservoir-oil phase behavior. Multiple-contact measurements in which the CO2-rich phase is repeatedly contacted with recombined reservoir oil (oil cycling) simulate phase behavior occurring at the flood front. Multiple-contact measurements in which the oil-rich liquid phase is repeatedly contacted with pure CO2 (CO2 cycling) simulate the phase behavior exhibited by residual oil near a CO2 injection well. The multiple-contact data cover narrow compositional paths encountered in displacement processes and serve as a basis for equation-of-state (EOS) evaluation. Phase behavior trends common to all systems are discussed.
Method for Laboratory and Field Evaluation of a Proposed Polymer Flood
Authors: Castagno Richard E. , Shupe Russell D. , Gregory M. Duane , Lescarboura Jaime A.
Published: December 2007

The relevant components of a proposed polymer flood in the Tensleep reservoir of the Frannie Phosphoria-Tensleep Unit in Park County, WY, were investigated. Laboratory testing consisted of polymer injectivity, stability, retention, and effective viscosity measurements. On the basis of polymer viscosity and retention tests, a polysaccharide polymer was chosen over a Polyacrylamide polymer for extensive laboratory evaluation and field pilot tests. Field testing included injectivity, biological stability, and in-situ viscosity measurements. Pressure falloff tests following variable-rate injection of a polysaccharide polymer solution indicated the presence of a non-Newtonian, low-mobility bank. Even though good injectivity was obtained during injection of a 15% PV polymer slug, the proposed field project was not done. This was primarily because of low in-situ (reservoir) polymer solution viscosity and lack of proven microbial control in the near-wellbore region.
Down-Hole Injection of Butane to Control Paraffin Deposition in Pumping Wells
Authors: Lukehart Charles O.
Published: December 2007

Results of field tests indicate that butane can be injected easily and economically down the tubing-casing annulus of pumping wells. The quantity and frequency of butane injection varies with each well and, if injected properly, will effectively control paraffin deposition in the tubing and flow lines. Butane has the effect of increasing the solution capacity of the crude oil for the waxy substances being deposited.

In the 12 wells tested, a reduction in the cost of paraffin control by as much as 90 per cent was obtained, and in one well the annual reduction totaled $1,000. The expense necessary to install the surface equipment is $165.00 per well, and the injection process is performed by a pumper as a routine duty.

The injection of butane to control paraffin deposition at the present time is limited to wells that pump off or pump and flow off and to paraffin or mixed base crudes. Further study may indicate that the process can be utilized in other types of wells.

Introduction

Paraffin accumulation in tubular goods is a costly problem that has long been associated with crude oil production. One method for the control of this accumulation in pumping wells is the down-hole injection of a butane-crude oil mixture. The purpose of this paper is to outline the process and to indicate the saving that may be obtained in using this method for a more economical recovery of crude oil.

Solubility of Paraffin in Hydrocarbon Systems

Crude oil, as it originally exists in a reservoir, contains varying percentages of waxes, gums, resins and asphaltic materials which remain in solution until the solution equilibrium has been sufficiently disturbed; then these substances separate from the crude oil and form what is generally known as paraffin deposits. There are a number of factors involved in the separation and deposition of paraffin in crude oil wells; however, temperature decrease and loss of lighter fractions are the most important causes of solubility change and the resultant paraffin separation.
Controlled Solubility Phosphates--A Versatile Solution To Oilfield Scale Problems
Authors: Sloat Ben
Published: December 2007

Water flooding has focused attention on the problem of scale in producing wells. Four reasons why scale forms are discussed. A new theory which will help explain the severe scale build-up that occurs in many producing wells at the time of water breakthrough is presented.

A recently developed family of scale preventives - the controlled solubility phosphates - are described chemically and physically. Factors which influence the performance of these unique phosphates in oilfield brines are evaluated in terms of laboratory test data.

Case histories of producing wells treated with controlled solubility phosphates are summarized. The importance of bottom-hole temperature, the role of produced-fluid mineral characteristics and the value of knowing down-hole flow conditions are pointed out.

Economic considerations well known to engineers and production men are used to compare the cost of conventional treatment and the cost of the new controlled solubility phosphate scale-prevention approach.

Introduction

General acceptance of the artificial water drive as a secondary producing mechanism for the recovery of oil has made many petroleum engineers and production men extremely "water conscious" during the last few years. Scale and corrosion problems of a type seldom encountered in primary production soon become evident as leases are placed under flood. In attempting to find solutions to these newly created problems, the oil industry has learned that standard municipal and industrial water-treatment practice is going to be of little value. The reason for this is that, until the oil industry started to emphasize water flooding and the conditioning of produced fluids, no one had ever attempted to make use of water of as poor quality as that now being handled by many secondary-recovery operators. The need for processing brines saturated with corrosive gases, scale-forming minerals and insidious microbiological growths has opened up a completely new field of water-conditioning technology.

This paper deals with scale in oilfield brines. Factors which influence the formation of scale are discussed along with how petroleum engineers can get the most out of a unique family of chemicals which will effectively prevent scale.
EPT Interpretation in Carbonates Drilled With Salt Muds
Authors: Kenyon W. E. , Baker P. L.
Published: December 2007

Laboratory measurements of rock dielectric permittivity show a dependence on water conductivity. The laboratory measurements were fitted by a model in which the rock microgeometry is represented as a collection of grains, some platy and some spherical, in water. The model can be used in a variety of log interpretation methods for the electromagnetic propagation tool (EPT), with or without microresistivity logs.
Analysis of Interference Data in a Highly Heterogeneous Naturally Fractured Geothermal Reservoir
Authors: Benson S. M. , Lai C. H.
Published: December 2007

An approach consisting of a combination of composite and naturally fractured reservoir models has been proposed to interpret pressure-transient data from an 11-well interference test in a highly heterogeneous geothermal reservoir. The approach leads to an integrated interpretation that accounts for all of the salient features of the data.

An initial appraisal of the data indicates excellent agreement with theoretical results for double-porosity reservoirs. For some of the wells, however, the bulk storativity, calculated with the double-porosity model, differs significantly from the average value of this parameter. Furthermore, it increases systematically as the distance between the active and observation wells decreases. To explain this peculiar result, an alternative method of analyzing data from composite reservoirs is presented. The method demonstrates that local permeability variations can result in enormous variations in the apparent storativity without causing variations in the apparent permeability-thickness of the reservoir. A simple graphical technique, based on analyzing systematic variations in the apparent storativity, has been developed to determine the size of the region and the mobility contrast between different regions of the reservoir. By using this technique, we show that the observed variations in the storativity are the result of a small, high-permeability region that surrounds the pumped well and is penetrated by several of the observation wells.
Experimental Studies of Salt-Cavity Leaching by Freshwater Injection
Authors: Reda Daniel C. , Russo Anthony J.
Published: December 2007

Salt-cavity-leaching experiments were conducted in the laboratory in support of the U.S. Strategic Petroleum Reserve (SPR) program. Cavities of an initially cylindrical geometry were created by hollowing out salt cores from one end, leaving the circular wall and bottom as an integral piece. In three experiments, a salt cavity was placed vertically in a pressure vessel and its interior was filled with saturated brine. The vessel was sealed and pressurized to actual SPR-cavern pressure. Fresh water was injected down a tube into the cavity, while brine was removed simultaneously from the cavity through a withdrawal tube.

Both direct (injection-below-withdrawal) and reverse (injection-above-withdrawal) leaching procedures were investigated for essentially the same flow rate conditions and total withdrawal time. A traversable gamma-beam densitometer was positioned between the injection and withdrawal locations in each case and was used as a nonintrusive diagnostic technique to investigate transient phenomena that occurred during the leaching and post-leaching (return-to-equilibrium) periods. Beam attenuation measurements yielded a quantitative measure of the total, time-integrated, salt-wall recession and the instantaneous, path-length-averaged, brine salinity. Final cavity shapes were measured by gamma-beam densitometry and by sectioning/micrometer techniques. Transient and steady-state measurements were compared with numerical predictions. Experimental results and numerical predictions were in good agreement.
Production Potential Changes During Sweep-Out in a Five-Spot System
Authors: Caudle B.H. , Witte M.D.
Published: December 2007

In predicting the performance of a pattern injection operation, the engineer needs to know both the amount of oil to be recovered and the rate at which the recovery will take place. This paper describes fluid flow model studies on the effect of mobility ratio on the rate of oil recovery in a five-spot. The results show the change in fluid conductivity (total flow rate/ pressure drop) as the sweep-out pattern increases for mobility ratios between 0.1 and 10. These data, when combined with a knowledge of reservoir permeabilities and sweepout pattern efficiencies, can be used to predict the cumulative oil production as a function of time for homogeneous five-spot injection systems.

Introduction

The flow potential in a pattern flood element is a function of the mobility ratio and how far the injected flood front has gone. For a waterflood project having a mobility ratio of one, the conductance - which is the flow rate per unit pressure drop (q/ Δp) - will remain the same throughout the life of the flood. If the mobility ratio is favorable < 1), the conductance of the project will drop continuously throughout the operation. If, on the other hand, the mobility ratio is unfavorable, the conductance ratio will increase continuously. Therefore, if the reservoir engineer wishes to predict either the rate at a specified pressure or the pressure at some rate for a secondary recovery project, he must know how the conductance will vary during the flood.

Other investigators have studied this problem using potentiometric models or analytical solution. The method described in this paper uses fluid flow models to study the variation in conductance with mobility ratio and flood front advance. Fluid flow models are more directly analogous to the reservoir and the resulting data can be directly applied to secondary recovery projects. This method was developed to yield reservoir engineering data which can be applied directly from graphs to the reservoir problem.
Analysis of Natural Hydraulic Fracturing of Shales During Sedimentation
Authors: Ozkaya I.
Published: December 2007

An approximate mathematical model of the time variation of excess head at the middle of a shale layer during burial is obtained and used in the analysis of natural hydraulic fracturing by excess pore pressure. The fundamental variables that control fracturing are critical stress intensity factor, hydraulic conductivity, specific storage, Poisson's ratio, sedimentation rate, and shale-layer thickness. A simple fracture criterion is derived that shows that for usual values of the above variables, natural hydraulic fracturing is not possible. Fractures form only if the shale is excessively thick and has a low hydraulic conductivity. Depth bracket of fracture generation and closure is shallow. However, porosity may restrict the depth of fracture initiation. An abrupt increase in the sedimentation rate may cause fracture reopening at great depths.
An Approach to the Evaluation of Oil - Production Capital Investment Risks
Authors: Wansbrough R.S.
Published: December 2007

Methods of analyzing the profitability of proposed capital investments have received considerable attention in recent literature. The discounted-cash-flow rate of return, particularly, has been advocated as a means for discriminating among new investment opportunities. Examination of the characteristics of this rate of return led to the conclusion that such rate is seriously misleading at rates of return which are higher than an appropriate interest rate used to determine the present value of future income. Such relatively high rates of return are ordinarily encountered in the oil and gas production industry and are commensurate with the high risk of normal industry ventures.

The difficulty inherent in this use of the discounted-cash-flow rate of return stems from the fact that the relative value of each future year's income from a project is weighted according to the discount-factor characteristic of the rate of return determined from the project. If this rate of return is higher than the realistic present-value interest rate, income from the later years in the life of the project is penalized at a rate which is higher than is needed to compensate for the deferment of this income.

A method of evaluating new capital investments of unequal risk on a commensurable basis is suggested. This method provides a rational framework into which an estimate of the probabilities of success or failure of each facet of a given project may be fitted.

General

The objective of investment evaluation is to provide a measure of the ability of an investment to generate profits. If a quantitative measure of this ability is available, all opportunities for investment can be measured, and an optimum disposition of the funds available for investment can be made.

In the opinion of the writer, the most serious obstacles to be overcome in providing such a measure are encountered, first, in adequately measuring the value today of cash to be received at some future date and, second, in measuring (on a commensurable basis) investments which involve different degrees of risk. These problems are of particular importance in the petroleum production field. This industry provides investment opportunities which yield patterns of cash flow vs. time which vary over a wide range. Individual risks to which investors are exposed cover a continuous spectrum from rank wildcat to interior development well.
Case History of the Development Drilling of the Southwest Sabine Tram and West Devil's Pocket Fields
Authors: Penny R. C. , Eustes A. W. , York D. W.
Published: December 2007

Drilling and evaluating the Wilcox formation have long been challenging tasks. Lithology changes have made pore-pressure prediction difficult, while Wilcox water salinity and clays have made formation evaluation by openhole logging techniques virtually impossible. Optimization of very basic parameters—such as casing setting depths, mud properties, hydraulics, and evaluation techniques—have led to substantial reductions in time and, therefore, well cost. This paper outlines several improvements, learned from experience, that contributed to cost and time reductions in drilling and completing these Wilcox wells.
The Use of Higher-Order Differencing Techniques in Reservoir Simulation
Authors: Taggart I. J. , Pinczewski W. V.
Published: December 2007

Uniformly second- and third-order finite-difference schemes are developed for convection-dominated flows in porous media. The schemes are applied to immiscible and miscible displacements characterized by low levels of physical dispersion. The high-order schemes developed are shown to reduce significantly both dispersion of sharp fronts and sensitivity to grid orientation when compared with solutions obtained with the commonly used one-point upwind differencing schemes. Moreover, for explicit timestepping simulators, such as those based on implicit-pressure, explicit-saturation (IMPES) formulations, the improved performance of the high-order methods is obtained with only a modest increase in computational effort.
Properties and Behavior of Reservoir Oil in the Aneth Field, Utah
Authors: Zaffarano R.F. , Cupps C.Q. , Fry J.
Published: December 2007

Data are presented which show the PVT characteristics of the reservoir oil in the Aneth field, San Juan County, Utah. The data were obtained principally from the analysis of subsurface oil samples taken from seven wells within two years after discovery of the field. The uniformity of the oil across the large producing area is discussed and information on the development history and geology of the area is also given. The Aneth field is the first of several fields to be studied to provide data for a general investigation of the relative characteristics of Pennsylvanian reservoir oils in the Paradox basin.

Introduction

PVT characteristics of reservoir oil in the Aneth field, as reported here, were determined to provide part of the information needed for a comparative study of the characteristics of Pennsylvanian reservoir oils in the Paradox basin. The study proposes to determine if variations in oil characteristics occur in the basin which may reflect the source and migration history of the oil and also provide evidence of the effect of differential entrapment, as proposed by Gussow.

The Paradox basin appeared opportune for this study because of the recent development of several producing fields and an oil potential indicated to be of national significance. Aneth is the largest field discovered thus far and is the first field studied. Other studies are in progress of the McElmo Creek, Ratherford and White Mesa fields to the south and southeast of Aneth and will be covered in future reports.

Results of the Aneth and other field studies are being reported to inform the oil industry of the nature and behavior of reservoir oils in this new productive area and to make these data generally available for use in control of reservoir performance. A more detailed presentation of results of the Aneth field study may be obtained from a Bureau of Mines report.
An Analysis of Reservoir Chemical Treatments
Authors: Dria M. A. , Schechter R. S. , Lake L. W.
Published: December 2007

In chemical well treatments, success or failure is often difficult or impossible to anticipate. The near-wellbore pressure drawdown and fines migration contribute to the overall well damage, but the effect of the chemical treatment alone can induce damage by reprecipitation when the spent treatment solution is produced over the treated zone. The identity, amount, and rate of return of this reprecipitation damage are discussed here.

Our procedure considers the chemical interaction of formation minerals and brine with the treatment solution in the presence of an immiscible phase. Although this analysis contains several simplifying assumptions, the results can be applied, with care, to lend insight and direction to practical problems. If relative permeabilities and mineral and injected water compositions are known, the analysis procedure will estimate the success of the treatment and indicate approximate treatment duration.
Two- and Three-Phase Relative Permeabilities of Micellar Fluids
Authors: Delshad Mojdeh , Delshad Mohammad , Pope G. A. , Lake L. W.
Published: December 2007

Two- and three-phase relative permeabilities have been measured for a low-interfacial-tension (IFT) brine/oil/surfactant/alcohol mixture in Berea sandstone cores. The measurements were done at steady-state conditions with a constant nominal capillary number of 10−2. These are the first three-phase micellar relative permeabilities reported to date.

Continuous and slug displacements of both partitioning and nonpartitioning radioactive tracers were run for each steady-state experiment. The effluent tracer data from these experiments were analyzed by a capacitance model.

Both excess phases flowing with the microemulsion showed significant capacitance effects, but the microemulsion did not. The absence of capacitance indicates that the microemulsion was probably the wetting phase in these low-IFT flows, even more wetting than the excess brine phase. The relative permeability of each phase is a function of only its own saturation during three-phase flow. Polymer dissolved in brine had little effect on the relative permeabilities of brine and microemulsion in two-phase flow.
Chemical Stability Limits of Water-Soluble Polymers Used in Oil Recovery Processes
Authors: Ryles R. G.
Published: December 2007

This work describes long-term thermal stability limits of water-soluble polymers under anaerobic conditions. Polymers investigated included polyacrylamide, xanthan, scleroglucan, cellulose sulfate, and a heteropolysaccharide of unknown structure. The primary mechanism of polyacrylamide degradation was found to be amide group hydrolysis. Interaction between hydrolyzed polyacrylamide and divalent metal ions present in solution caused significant losses in solution viscosity, and phase Separation ultimately occurred in extreme conditions of high degrees of hydrolysis or high concentrations of divalent ions. The rate of hydrolysis was found to depend mostly on temperature. At 50°C [122°F], the rate was quite slow and polyacrylamide solutions were stable for many months, evert in the presence of high concentrations of divalent ions. At 60 to 70°C [140 to 158°F], the rate of hydrolysis was moderate and the rate of viscosity loss depended on the precise temperature and divalent ion concentration. At 90 °C [194°F], hydrolysis was rapid and polyacrylamide solutions were stable to precipitation only when the divalent ion concentration was less than about 200 ppm. When the divalent ion concentration was zero, solution viscosity increased because of a further expansion of the polyelectrolyte coil.

The stability of xanthan was determined primarily by temperature and was independent of divalent ions. Although performance varies from xanthan to xanthan, the useful limit was generally found to be < 70°C [< 158°F]. Viscosity retention was also found to be extremely shear-rate dependent. Other naturally occurring polymers exhibited variable performance. In alkaline brines, polyacrylamides were stable up to 90°C [194°F] for long periods of time, whereas xanthan was degraded at > 50°C [> 122°F].
Dissolution and Condensation Kinetics of Silica in Alkaline Solution
Authors: Thornton S. D. , Radke C. J.
Published: December 2007

Chemical loss through long-term rock reactions is a major impediment for practical application of alkaline waterflooding. This paper addresses the viability of soluble silicates reducing hydroxide consumption by siliceous rock reactions. A convenient differential rate method is used to obtain new experimental kinetic data for the dissolution/condensation rates of quartz at 23 and 70°C [73 and 158°F] and amorphous silica at 23 °C [73 °F] over the pH range from 11 to 12 and in 1 M NaCl. The role of added silicates is studied from zero solution concentration to considerably above the solubility limit.

Silica dissolution rates are observed to slow as the solubility limit is reached and become negative (i.e., net precipitation occurs) above the solubility limit. The kinetic rates decrease with increasing solution silicate in a parabolic fashion. Most important, the solubility limit of quartz (amorphous silica) controls the deposition rate of quartz (amorphous silica) over the range of pH values and temperatures investigated. That is, crystalline quartz grows directly on solid quartz particles, rather than deposition of amorphous silica with subsequent alteration to the crystalline habit. This means that relatively small amounts of soluble silicates, approaching the solubility limit of quartz, can protect against hydroxide consumption by quartzitic rock reactions.

A molecular dissolution/condensation reaction scheme is proposed, based on equilibrium adsorption of unionized silicic acid. With this reaction path, a mathematical model is developed that agrees quite well with the measured kinetic rate data.
Another Look at Future Demand for Petroleum Engineers: We Can Prevent the Coming Shortage
Authors: Campbell John M.
Published: December 2007

In the past several years questions have been raised about the future status of the petroleum industry. Some of this has been triggered by rather vague notions of the probable effect Of nuclear and solar energy along with many pessimistic public pronouncements that were designed to influence legislation. Superimposed on this has been the so-called recession, or what might better be called "re-adjustment". The net result has been the development by many individuals of a rather gloomy outlook which is largely unwarranted by the facts. Regardless of how valid this pessimism might be, we must recognize that it could have a long-range deleterious effect on petroleum engineering as a profession.

This is illustrated by the results of a recent poll taken among petroleum engineering schools on enrollment and hiring trends, reported by Robert L. Whiting in the April, 1959, issue of the JOURNAL OF PETROLEUM TECHNOLOGY. The poll was as good as any can be, and Professor Whiting made a conscientious effort to present the results fairly. The article "shook up" many people, and well it should.

The conclusions presented were fine as far as they went, but they did not fully answer the basic questions of, Why the decreasing enrollment?" and "What will be the demand for petroleum engineers?". Because of the rapidly changing technology, I do not believe the latter can be answered by a mere extrapolation of data. Instead, we must try to analyze the factors involved. There is certainly no doubting that a shortage of qualified engineers exists, even though there is a plentiful supply of engineering graduates.

This is the purpose of this article. I have concentrated on the negative factors, not because they are paramount but because they are the ones we usually choose to ignore. In doing this, I am not motivated by pessimism but by the optimistic feeling that careful thought will at least minimize the two problems presented. I hope that those who might be offended by some of the following comments will accept them in the intended spirit.
Gel-Block Technique: A Successful Application for Zonal Isolation in a Depleted Reservoir
Authors: Mbaba P. E.
Published: December 2007

This paper discusses the successful application of a polymer gel during a cement squeeze of a depleted zone in a gravel-packed producing well. The process involves proper placement of polymer gel to isolate zones in a gravel-pack completion during a cement squeeze. The report also discusses diagnostic well tests before and after the cement squeeze. The use of polymer gel as a blocking agent during a cement squeeze of a gravel-pack completion of a thermally stimulated well does not appear to be a common practice and has not been reported previously.
Well Test Analysis of Naturally Fractured Reservoirs
Authors: Aguilera Roberto
Published: December 2007

Methods are presented for matching observed pressure data during drawdown or buildup tests. The methods, illustrated with step-by-step examples, allow calculation of fracture transmissivity, storage capacity coefficient, skin, size of matrix blocks, fracture porosity, fracture storage, and radius of investigation. The effect of matrix block shapes in the transition period has been investigated by use of a stratum model, a model made of cubes with spaces between the cubes, and a model made of "matchsticks" separated by two orthogonal fracture planes. Consideration has been given to a gradient flow model as well as to unsteady-state and pseudosteady-state interporosity flow. Because many naturally fractured reservoirs are fault-related, the effect of single and intercepting sealing faults has been investigated.

Even after a match of observed pressure data is obtained, there is uncertainty about calculated parameters. Consequently, a synergetic approach integrating geologic models, logs, cores, outcrops, and well testing is the only sound procedure for evaluating naturally fractured reservoirs.
Computer Image Processing: A New Tool for Studying Viscous Fingering in Corefloods
Authors: Peters Ekwere J. , Broman John A. , Broman William H.
Published: December 2007

Computer image processing technology was used to study the patterns of viscous fingering in laboratory corefloods. The fingering patterns in unstable immiscible corefloods were captured and photographed with the aid of a fluorescent dye. The photographs were digitized and stored as computer image files for subsequent processing. A program was written to count the fingers, to determine their sizes, to compute the sweep efficiencies at the core cross sections, and to determine the frequency contents of the fingering patterns. The frequency contents were used in conjunction with stability theory to estimate the effective interfacial tension (IFT) required for calculating the stability numbers of the floods. Results show that computer image processing technology can be used to study the performance of laboratory corefloods quantitatively.
Analysis of an Interwell Tracer Test in a Depleted Heavy-Oil Reservoir
Authors: Ohno Kenji , Nanba Takao , Horne Roland N.
Published: December 2007

This paper presents field data and analyses of an interwell tracer test conducted in the Niitsu oil field, which is a fully depleted heavy-oil reservoir of unconsolidated sand formation. Water containing a chemical tracer was injected at a constant rate into an injector surrounded by three production wells. Effluent analyses showed very early breakthrough of injected water at two of the producing wells. The test results suggest a strong areal heterogeneity of the tested formation.

An appropriate analytic model was used to obtain a preliminary interpretation of the results. A modified three-dimensional (3D) black-oil model developed to simulate the polymer flood process was then used for analyzing the data in more detail. The model treats tracer solution as a fourth component and can also account for adsorption of tracer. Simulation efforts were concentrated on matching the breakthrough times and tracer profiles after breakthrough. Through both the analytic and the simulation work, the reservoir is characterized by a highly heterogeneous distribution of horizontal permeability, a thin layer of high permeability, and a natural waterdrive that cause a preferential flow trend in a direction toward one producer. We conclude that the interwell tracer test is an effective tool for evaluating reservoir heterogeneities and a quantitative analysis of test data is done with the polymer option of a black-oil simulator.