bluuebunny/crossref_metadata_2025 huggingface dataset:
The Salinity-Requirement Diagram–A Useful Tool in Chemical Flooding Research and Development
Authors: Nelson Richard C.
Published: December 2007

Optimal salinity, the level of brine salinity at which a chemical flooding surfactant displaces oil most efficiently, is related to midpoint salinity and to the range of salinity over which the phase environment is Type III. These three conditions are functions of surfactant concentration—usually decreasing as surfactant concentration decreases, particularly if the brine contains multivalent cations. A salinity-requirement diagram, constructed from phase equilibrium data, expresses quantitatively the dependency of midpoint salinity and the Type III range on surfactant concentration. Because surfactant coneentration decreases as a flood with a small-pore-volume chemical slug proceeds, a salinity-requirement diagram can provide insight into the performance of chemical floods. Examples are presented that support the proposal that chemical flooding is most efficient when conducted in a salinity gradient. A phenomenon in which a "wedge" of oil is left on the bottom of the core by a chemical flood is related to the salinity-requirement diagram for the system, and the effect of ion exchange on such diagrams is discussed.
Estimating Air Emissions for BP's Permian Basin Gas Plants and Oil and Gas Properties
Authors: Johnstone James E. , Stobbe Alan
Published: December 2007

A system to estimate emissions from large numbers of oil and gas producing properties and gas plants was developed by BP's Permian asset environmental group. The system estimates air emissions on a quarterly basis for both internal and external reporting requirements. An additional benefit has been increased lease revenues from improved operating efficiencies identified by the system.

The results of the emissions-reporting system enabled BP to accurately estimate the emissions from each property. Emissions for the Permian asset were quantified. Internal and external reporting requirements were integrated. Lease-gas use was reduced by optimizing fuel burned and the use of bleed-gas-operated equipment. The study also helped prioritize additional engineering work to look at fuel consumption in fired equipment.
Identified Models for Gas Storage Dynamics
Authors: Chierici G. L. , Gottardi G. A. , Guidorzi R. P.
Published: December 2007

The classical approach to forecasting hydrocarbon reservoir behavior is through modeling. Traditional models are based on equations describing the physical behavior of the reservoir-plus-aquifer system; usually the parameters describing aquifer behavior are not known beforehand and are evaluated by a trial-and-error procedure based on the best fit of past reservoir performance. This approach leads to models that are intrinsically realistic, as they reflect the physical nature of the phenomena involved.

A completely different approach, based on system theory techniques, is presented in this paper. This technique, called identification, consists of the determination of a mathematical model equivalent to the process under test, the word "equivalent" meaning that the process and the model show the same input/output behavior. As a consequence, an identified model of this type can be used to predict the response of an actual reservoir-plus-aquifer system to different inputs – i.e., to different production schedules.

Case histories of the application of the identification technique to actual gas storage reservoirs are presented.
Application of the Time-Dependent Overall Heat-Transfer Coefficient Concept to Heat-Transfer Problems in Porous Media
Authors: Satman Abdurrahman , Zolotukhin Anatoly B. , Soliman Mohamed Y.
Published: December 2007

Prediction of temperature distribution behavior during thermal recovery processes is necessary for engineering evaluation of field operations. Such a prediction can be used in the case of hot- and cold-water injection into a reservoir and also applies in some other thermal recovery processes, such as in-situ combustion and steam-flooding.

The mathematical formulas discussed involve the concept of a time-dependent overall heat-transfer coefficient. In the first portion of the paper, we discuss two new analytical solutions that describe the temperature distribution in linear and radial reservoirs in the case of hot- and cold-water injection. A comparison with published laboratory hot-water injection data demonstrates the validity of the solution for linear geometry. Since the new analytical model considers the heat conduction in addition to convection and heat loss, it describes the thermal behavior in a more general form than does Lauwerier’s model. These two models are compared also.

The application of the time-dependent overall heat-transfer coefficient concept to the thermal behavior of the steam plateau portion of the in-situ combustion process is discussed in the second part of the paper. The result is fairly satisfactory.
Natural Gas Potential of the New Albany Shale Group (Devonian-Mississippian) in Southeastern Illinois
Authors: Cluff Robert M. , Dickerson Donald R.
Published: December 2007

Data from geologic and geochemical studies of the New Albany shale group indicate that a 19-county area of southeastern Illinois is a favorable area to explore for gas in Devonian shale. Although gas shows in the shales have been encountered in several wells drilled in this area, no attempts were made to complete or evaluate a shale gas well until 1979.

In 1979, core samples from two Wayne County wells were obtained, permitting the first quantitative assessment of gas content of the shales in this area. Seventy core samples from the two wells were sealed in airtight canisters at the drilling site for off-gas analysis. The quantities of shale gas released from the core samples in a 34-day period ranged from 0.16 to 2.40 cu ft HC/cu ft (0.16 to 2.40 m3 HC/m3)* of shale. This gas is richer in heavy hydrocarbons than is the average "pipeline gas." It has a calculated average BTU value of 1,240 Btu/cu ft (46 200 kJ/m3). Because the proportion of nonhydro-carbon gases is unknown, the calorific content of produced gas would necessarily be slightly lower. The gas-bearing intervals generally correspond with high radioactivity intervals on gamma-ray logs. The quantities of shale gas in core samples from these wells are similar to those in gas-producing areas of Devonian shale in the Appalachian basin. However, because the New Albany shale is much thinner than its Appalachian basin equivalents, the total gas resource is probably much smaller.

Conventional rotary drilling with mud base drilling fluids likely causes extensive formation damage and may account for the paucity of gas shows and completion attempts in the Devonian shales; therefore, commercial production of shale gas in Illinois probably will require novel drilling and completion techniques not commonly used by local operators.
The Effect of Hydrotropic Salts on Phase Relationships Involving Hydrocarbons, Water, and Alcohols
Authors: Ho Patience C. , Kraus Kurt A.
Published: December 2007

Hydrotropic salts, which can increase the solubility of organic materials in aqueous solutions, are of interest in a variety of industries including those related to tertiary oil recovery. We have examined effects on solubility of hydrocarbons in water (with and without alcohols) by adding inorganic hydrotropic salts such as Perchlorates, thiocyanates, and iodides (high in the usual Hofmeister series), organic salts such as short chain alkyl benzene sulfonates, and other salts based on substituted benzene derivatives. Although the inorganic salts are relatively ineffective in increasing solubility of hydrocarbons in water, many of the organic salts are excellent hydrotropic agents for hydrocarbons.

We have examined the phase relationships for several series of aromatic salts such as sulfonates, carboxylates, and hydrocarboxylates as a function of alkyl-carbon substitution in three-component (hydrocarbon, salt, water) and in four-component (hydrocarbon, salt, alcohol, water) systems. We also have examined miscibility relationships for a given hydrotropic salt as the chain length of alkanes and alkyl benzenes is varied systematically.

While miscibilities decrease with increase in chain length of the hydrocarbon, the hydrotropic properties in these systems increase rapidly with the number of alkyl carbons on the benzene ring of the salts, and they arc relatively insensitive to the type of charged group (sulfonate vs. carboxylate) attached to the benzene ring. However, there are significant increases in hydrotropy as one goes from equally substituted sulfonates or carboxylates to salicylates. A number of salts have been identified that have much greater hydrotropic properties for hydrocarbons than well-known hydrotropic materials such as toluene and xylene sulfonates.
Divalent Ion Exchange With Alkali
Authors: Bunge A. L. , Radke C. J.
Published: December 2007

Exchange of hardness ions is important in EOR with chemical additives. In both micellar/polymer and caustic flooding processes, multivalent ions released from rock surfaces can interact with anionic surfactants, rendering them preferentially oil soluble and/or insoluble in water. Because hardness cations are sparingly soluble and precipitate in alkaline solutions, such solutions may be more efficient as surfactant-flood preflushes than are softened brines. Multivalent ion precipitation may also occur in alkaline waterflooding. To permit design of such processes, this paper presents a chromatographic theory for simultaneous ion exchange with precipitation of divalent ions.

Theoretical effluent histories and concentration profiles are presented for the cases of finite pulses and continuous injection of hydroxide ions into linear cores. Complete capture of the insoluble salt particles is assumed. Results are given for the case of instantaneous equilibration of the solution with the precipitate, as well as for the case of complete nonequilibrium, in which the solid precipitate does not redissolve. These two physical extremes predict field performance and laboratory results, respectively. Data for Berea sandstone and an argillaceous sand compare favorably with the proposed theory.

The efficiency of alkaline preflushing is shown to depend on the exchange isotherm, initial divalent loading of the rock, injected pH and salinity, the solubility product of the precipitated salt, and pulse size. The effect of pulse size on complete equilibrium removal of hardness ions is reduced efficiency with increasing size until a critical volume approximating continuous injection is reached. Increasing injected pH and salinity provides a more favorable response.

The theoretical model, when applied to field conditions, predicts redissolution zones that have not been previously recognized because solution residence times in laboratory columns are too short. Calculations show that precipitate redissolution by the low-pH solutions following alkaline pulses may introduce high concentrations of calcium behind the preflush where interference with micellar or polymer solutions is likely. These results suggest that reservoir preflush design from laboratory tests, while possible, must be made carefully.
Surfactant Flooding 1: The Effect of Alkaline Additives on IFT, Surfactant Adsorption, and Recovery Efficiency
Authors: Krumrine Paul H. , Falcone James S. , Campbell Thomas C.
Published: December 2007

This paper examines the effects of alkaline additives on dilute surfactant systems for improved oil recovery. The study was limited to the determination of the effects of alkaline additives on interfacial tension (IFT), surfactant adsorption or retention in Berea cores, and improvement in oil recovery. The alkaline chemicals studied were sodium silicates, sodium phosphates, sodium carbonate, and sodium hydroxide. In addition, optimal salinities and surfactant average equivalent molecular weight for the recovery of two midcontinent crude oils were determined through a combination of IFT determinations and oil displacement tests.

The laboratory results show that the alkaline chemicals have two major effects. First, IFT is reduced further by the high pH surfactant/alkali solution combinations, and second, certain alkaline species significantly reduce surfactant retention. This leads to recoveries of residual oil from 40 to 70% with surfactant solutions containing only 0.25 wt% surfactant.
A Method for Determining Optimum Second Stage Pressure in Three Stage Separation
Authors: Whinery Kenneth F. , Campbell John M.
Published: December 2007

Introduction

This investigation was prompted by the absence of a simple, accurate method to predict optimum second stage separation pressure in three stage separation operations. Three stage separation as used here includes two separators plus the stock tank. The first stage pressure is usually fixed by gas sales conditions and the third stage is at atmospheric pressure. Thus, the second stage pressure is the only one that may be varied indiscriminate during production operations. No variations in temperature were considered in this study, even though it will vary among systems, for a change in temperature has little effect on the optimum pressure. Optimum pressures may be determined from flash calculations, but these are tedious unless a computer is available. An early attempt to develop a simpler method yielded an equation which gave the optimum pressure only as a function of initial and final pressure. Experience, however, confirms theoretical relationships which show that composition as well as pressure and temperature must be a factor.

Development of New Correlation

Wellstreams having 17 different analyses, ranging from low gravity crude to condensate, were used to determine the effect of composition. Each wellstream was flashed through three stages to determine the optimum second stage pressure for each first stage pressure. Equilibrium vaporization ratios proposed by Latham and Campbell were used throughout. The heptane plus fraction, for simplicity, was assumed to have the properties of octane.
Modeling Natural Gas Reservoirs – A Simple Model
Authors: Collier Richard S. , Monash Ellis A. , Hultquist Paul F.
Published: December 2007

A mathematical model is developed and tested for the production of natural gas with water encroachment and gas entrapment. The model is built on the material and volumetric balance relations, the Schilthuis water drive model, and a gas entrapment mechanism which assumes that the rate of gas entrapment is proportional to the volumetric rate of water influx. This model represents an alternative to the large grid models because of its low computer, maintenance, and manpower costs.
Performance of the Pickton Field
Authors: Barton H.B. , Dykes F.R.
Published: December 2007

The Pickton field, located in Hopkins County, Tex., produces from the Bacon lime reservoir of the Lower Glen Rose formation. The discovery well initially produced 50.2 API gravity oil with a gas-oil ratio of 1,350 cu ft/bbl, and subsurface samples of the reservoir fluid obtained soon after completion showed that the Pickton crude is unique in that it has an extremely high dissolved gas-oil ratio and is subject to very severe shrinkage. Reservoir studies indicated a recovery of only 19.4 per cent of the oil originally in place during primary depletion by dissolved-gas drive. It was also estimated that pressure maintenance recovery by gas displacement would total 36 per cent of the oil originally in place. Pressure maintenance by injection of dry Pickton field gas and extraneous gas from the Yantis field has increased the reservoir pressure to 90 per cent of the original pressure, and a satisfactory gas-sweep pattern has been maintained. Current recovery is 35 per cent of the oil in place. In this high-pressure gas injection pressure maintenance project, it is believed that vaporization of reservoir oil by dry gas injection has contributed substantially to the total ultimate recovery.

Introduction

The Pickton field history has been sufficiently short so that the predictions obtained by extensive engineering studies have been evaluated. Analysis of the results indicates, that by maximum use of advanced engineering technology and present day conservation measures, the Pickton field operations have been converted from an unprofitable to a profitable enterprise.

In Nov., 1944, with the completion of Humble's C. D. Nichols 1, initial production was obtained from the Pickton field in the East Texas basin, which is situated in the northeast corner of the state as shown at the top of this page. A large scale man of the central area of this basin. Fig. 1, locates the Pickton field in Hopkins and Franklin counties, 28 miles southwest of the Talco field and 28 miles northwest of the Hawkins field. The field is 16 miles southeast of Sulphur Springs, Tex.
Influence of Adjacent Conductive Formations on the Selective Electric Reservoir Heating Process
Authors: Harvey A. Herbert
Published: December 2007

A mathematical model is proposed for approximating the distribution of resistance heating in a process that employs an alternating electric current to heat an oil reservoir. The model assumes radial flow both of fluid and of current.
Comparison of the Inhibitory Action of KCl and Guanidine Hydrochloride Solutions on Montmorillonite Swelling
Authors: Iltis M. , Didier G. , Laréal P.
Published: December 2007

This study compares the effectiveness of potassium chloride with guanidine chlorhydrate in the prevention of clay swelling. The results given on various swelling tests on calcic montmorillonite led to the conclusions that (1) guanidine chlorhydrate is more effective than potassium chloride, especially in low concentrations, and (2) water immersion of samples treated by both solutions shows the permanent feature of the inhibitive action of guanidine chlorhydrate in swelling on one hand and the important increase in swelling of immersed samples treated by potassium chloride on the other. The viscosity measure of montmorillonite suspensions, before and after solution ion elimination by dialysis, confirms these observations.
A Novel Dynamic Measurement of Permeability
Authors: Moran J. H. , Papaconstantinou C. M.
Published: December 2007

A method is proposed for the laboratory determination of permeability; a water-saturated core is shaken and the electrokinetic electromotive forces (cmf's) generated thereby are measured as an indication of water movement within the core. This method also can provide a determination of the zeta potential. It is of special interest because of its possible extension to use as a well logging measurement.
Tubing Movement, Forces, and Stresses in Dual-Flow Assembly Installations
Authors: Durham Kenneth S.
Published: December 2007

Tubing movement, forces, and fiber stresses in single completions have been discussed thoroughly by Lubinski et al.1 Subsequent papers have expanded this discussion to combination tubing strings2 and fixed intermediate packers.3 This paper presents the theory and solution of tubing movement, forces, and fiber stresses for dual-flow assembly installations—that is, situations in which the intermediate packer is free to move within a seal bore.
Decline Curve Analysis Using Type Curves for Two-Porosity Systems
Authors: Prat Giovanni Da , Cinco-Ley Heber , Ramey Henry J.
Published: December 2007

Constant producing pressure solutions that define declining production rates with time for a naturally fractured reservoir are presented. The solutions for the dimensionless flow rate are based on a model presented by Warren and Root.1 The model was extended to include constant producing pressure in both infinite and finite systems. The results obtained for a finite no-flow outer boundary are new and surprising. It was found that the flow rate shows a rapid decline initially, becomes nearly constant for a period, and then a final decline in rate takes place.

A striking result of the present study is that ignoring the presence of a constant flow rate period in a type-curve match can lead to erroneous estimates of the dimensionless outer radius of a reservoir. An example is presented to illustrate the method of type-curve matching for a naturally fractured system.
Influence of Microgels in Polysaccharide Solutions on Their Flow Behavior Through Porous Media
Authors: Chauveteau Guy , Kohler Norbert
Published: December 2007

Microgels existing in xanthan solutions, which are partly responsible for the poor injectability of such solutions, are retained around the injection wells. Therefore, most of the oil is swept by microgel-free solutions. This paper shows that even a few microgels can strongly modify flow behavior in porous media. Consequently, their careful elimination is required in laboratory tests for proper design of a polymer flood.
Block Iterative Methods for Fully Implicit Reservoir Simulation
Authors: Behie A. , Vinsome P. K. W.
Published: December 2007

This paper describes the development of iterative methods suitable for the block-structured Jacobian matrices that occur in multiphase reservoir simulation. Most iterative methods consist of an approximate factorization followed by an acceleration procedure. The acceleration procedure used here is ORTHOMIN.1 Four factorization methods have been investigated that, when coupled with ORTHOMIN, provide four possible iterative algorithms. The first three factorization methods differ only in the number of bands included in the approximate decomposition. The fourth factorization is the most involved and the most powerful of the four methods. It is intended to be used on the equations that occur in thermal simulation, which previously have been considered difficult to solve iteratively. Several examples illustrating the use of the iterative algorithms are described. The algorithms described here are compared with several others on the basis of theoretical work and storage.
Alternatives to the Power-Law Fluid Model for Crosslinked Fluids
Authors: Cloud J. E. , Clark P. E.
Published: December 2007

Measuring the rheological properties of crosslinked fracturing fluids is difficult but important. Fluid properties play a key role in the determination of the final geometry of die created fracture and in the distribution of proppant within the fracture; therefore, an accurate knowledge of these parameters is necessary for optimum treatment design. The first paper1 in this series described a method to measure accurately and reproducibly the rheological properties of crosslinked fracturing fluids. The technique is the first that applies long-accepted mathematical methods to correct the measurements for the deviations in shear rate caused by the non-Newtonian nature of the fluids. This, in turn, allows the rigorous examination of mathematical fluid models to determine which, if any, best describes the flow properties of the fluids.
A Retrospective Look at a Profitable Water Flood
Authors: DeVore S.F. , Wright F.F.
Published: December 2007

The history of Flood 12, a former intensive air-gas repressuring project, is discussed. The sand body is described and core graphs are given showing an upper and lower section of the Bartlesville sand body. The conventional five-spot waterflood development and well completions in these sand sections are outlined. The plant design and distributing systems are reviewed. A comparison is made between intermittent and continuous flowing for producing wells with continuous flowing yielding the better results. The waterflood recovery is determined to be above average for similar nearby projects. Since there seems to be still significant quantities of recoverable oil remaining, especially in the upper sand, plans are proceeding to exploit this reserve.

Introduction

The two leases which make up the area known as Flood 12 are the Riverland and the Scudder, located in the Alluwe pool of Nowata County, Okla. (Fig. 1). Their earlier history has been discussed before. The Riverland is the northernmost 80-acre tract and was formed by unitizing three leases. The Scudder lease, on the south, is also an 80-acre lease. Although the entire 160 acres has been flooded from a single water plant, the oil production of the two tracts has been run from separate tank batteries. Since there has been some difference in the primary history of the two tracts, and also some difference in their development for water flooding, they will be discussed separately.

Both of these tracts were purchased from an independent operator in 1951 as a small part of a larger purchase. Sinclair obtained control of operations Aug. 1, 1951. At that time, the development of the flood was largely completed, the plant was constructed and over 3 million bbl of water had been injected. Except for the change in operating practices instituted by Sinclair and the drilling of additional wells to exploit the sand body more intensively, Flood 12 has been operated from the development program instituted by the former owner. Because it was a part of a large purchase, no actual cash value was assigned to Flood 12 as such. However, the estimated worth attributed to Flood 12 at date of purchase has been more than justified by its performance since then.
Foreign Private Investment- A Boon to Developing Countries
Authors: Just Evan
Published: December 2007

The high standards of living and improved national security which industrialization can bring are so broadly evident that one cannot name a country which does not cherish the hope of industrializing itself. Why, then, with such a universal aim, do many countries which lack either the capital or the skill to develop their own industries, accomplish so little toward attracting the only functionary who can provide the necessary capital and skill, namely, the foreign private investor? Obviously, because they fail to understand what constitutes a favorable climate for investment, because they have false notions about being exploited or dominated by the foreign investor, or because they are so nationalistic that they refuse to permit outside assistance.

The purpose of this paper is to aid the citizens and policy makers of the developing countries in achieving their aims, by defining the conditions which encourage investment and portraying the results of a policy of encouragement. The following is quoted from Eugene R. Black, president of the World Bank:

"The danger today is not that the foreign investor will ask too much of a developing country, but that the developing countries will do too little to attract him. Today the foreign investor cannot go into a country unless he is actually wanted by the people of the country. By indulging the myth that the private investor is trying to force an entry to engage in some sort of evil exploitation, the less developed countries are cutting themselves off from one of the most productive sources of development assistance available to them. The capital and skills which the private investor brings with him may not be available from anyone else. Particularly, he brings with him the skills of industrial management - skills which have to be seen in action to be learned. If a country is bent on industrializing and having the benefits spread broadly among the people, it can do itself no better service than to seek out the private investor abroad who is willing to risk his capital on the chance of a fair return on a successful venture."
An Accurate Slot-Flow Model for Non-Newtonian Fluid Flow Through Eccentric Annuli
Authors: Iyoho Aniekan W. , Azar Jamal J.
Published: December 2007

This paper describes a new model for obtaining analytical solutions to the problem of non-Newtonian fluid flow through eccentric annuli. A discussion on non-Newtonian rheology is presented, followed by the development and solution of applicable differential equations using the Ostwald de Waele power-law model and a nonrectangular slot.

Results indicate that velocity values are reduced greatly in the reduced region of the eccentric annulus. This is important in directional drilling where the drillpipe tends to lie against the hole. Design of mud flow for cuttings transport on the basis of the nominal average velocity could lead to serious problems associated with cuttings buildup in the low-velocity region of the annulus. Other practical ap-plications of this work include the determination of velocity distribution in chemical processes involving fluid flow through eccentric annuli – e.g., heat exchangers and extruders – and more accurate velocity profiles inside journal bearings, particularly for small diameter ratios.

The main advantage in the new approach is that iterative finite difference methods used by previous investigators are avoided. Previous work along present lines used a linearized model and resulted in velocity profiles of unacceptable accuracy. This study improves both the accuracy and the solution technique.
Evaluation of the One-Well Uranium Leaching Test: Restoration
Authors: Kabir Muhammad I. , Lake Larry W. , Schechter Robert S.
Published: December 2007

A one-well test to evaluate reservoir properties that govern the restorability of a zone in an underground aquifer to be solution mined for uranium has been considered. The test involves injection of a relatively small volume of leach solution and subsequent production of a larger volume of fluid. Two important parameters— cation exchange capacity and an equilibrium constant—are determined by history matching the effluent composition.

Two different solution techniques are used. By neglecting dispersion and reservoir heterogeneities, an analytical solution based on the method of coherence provides considerable insight into the pertinent features of the production composition history. To include complexities such as dispersion and layering, a two-dimensional finite difference computer simulation is used.

A number of different approaches have been evaluated. The most reliable approach is to use laboratory tests to determine one parameter with core samples and to use production history to determine the other parameter. Measurements of both anion and cation effluent concentrations are required to implement this procedure.
G-2 and G-3 Reservoirs, Delta South Field, Nigeria: Part 1-An Engineering Study
Authors: Poston S.
Published: December 2007

This paper describes a two-dimensional, three-phase, black-oil simulation of the G-2 and G-3 reservoirs in the Delta South field offshore Nigeria. The purpose of these studies was to investigate, from an engineering standpoint, various operating schemes for optimizing the oil recovery from each of these highly gravity-segregated reservoirs.

Introduction

The G-2 and G-3 sands are two major reservoirs in the Delta South field. The field is offshore Nigeria in approximately 10 to 16 ft of water (Fig. 1). Production from these reservoirs began in March 1968. By the end of March 1978, about 61.3 MMSTB of oil and more than 64 Bscf of gas were produced from the G-2 reservoir, and about 92 MMSTB of oil and more than 75 Bscf of gas were produced from the G-3 reservoir. These productions represent about 2 1% of the original oil in place (OOIP) for G-2 and 29% of OOIP for G-3. During this period, the average reservoir pressures for G-2 and G-3 declined from 3,936 to 2,665 psig and 3,829 to 2,343 psig, respectively.

The G-2 reservoir is at an average depth of 8,920 ft subsea. It is underlain by the G-3 reservoir, but the two are separated by a shale barrier. The two reservoirs are similar in structure and in rock and fluid properties.

The drive mechanism for these reservoirs is primarily gravity segregation. These reservoirs are characterized as massive, clean sands with high porosity (about 28% for G-2 and 26.5% for G-3) and high horizontal and vertical permeabilities (kh=2,000 md and kv=1,000 md).

This paper presents the results of the current G-2 and G-3 reservoir studies, which are extensions of previous work. First, a history match of 10 years of production performance was made. Later, several prediction cases were run under a variety of operating conditions. This study was undertaken to update the previous match, including the past performance data through March 1978. We believe that, by including more history match data, we have obtained a better reservoir characterization. Although about 20 prediction cases were run for each study, only four pertinent cases for G-2 and five for G-3 are included.

Gulf's two-dimensional, black-oil model in an areal mode has been used for this study. The use of this areal model is believed sufficient in describing the reservoir and fluid flow behavior and is justified since the fluids will be segregated because of the high kv/kh ratio (about 0.5:1 were kh=2,000 md). In this cases, gravity/capillary equilibrium exists throughout the thickness. However, there are some limitations in using an areal model for this study:the well coning effects are represented by well pseudo relative permeability curves and not with grid blocks in the vertical direction,the well completions are represented by modifying the well relative permeability curves, andany well coning effect matched using pseudo relative permeability curves may not be strictly valid for future predictions.

These limitations, however, do not seem to be very important for the G-2 and G-3 reservoirs.
Time-Derived Sigma for Pulsed Neutron Capture Logging
Authors: Randall Russel R. , Fertl Walter F. , Hopkinson Eric C.
Published: December 2007

This paper reviews field applications of the Dresser Atlas Neutron Lifetime Log™ (NLL) service and examines recent technical advances in the instrumentation and data-analysis system. The major improvement discussed is a new method for computing S, the thermal neutron capture cross section of an earth formation. In the new method, the time after the neutron burst is measured for each gamma ray pulse detected by the instrumentation system within a gate of fixed width. This "average pulse time" is uniquely related to the thermal neutron decay rate observed in a borehole environment.

The technique discussed is applicable for any condition where the neutron or gamma ray flux is time-dependent. The advantages of this signal-processing method, however, are most apparent for cases of rapid flux change with time, as in an exponential decay. A simple two-gate method of measurement suffers, statistically, from the lower count rate of the second gate. An average-pulse-time measurement over the same range covered by both gates of a two-gate system is less affected by statistical deviations than the ratio normally formed between the two gates.

Some important advantages result from this type of signal processing when applied to the NLL service. First, the statistical accuracy of the log is improved; second, the instrumentation required for implementation of the method is not complicated. Also, the average-pulse-time measurement can be made with either digital or analog equipment, and since it involves only simple arithmetic computations, the method is much simpler to implement than either least-squares or correlation methods.

Introduction

The NLL service1 was introduced in the early 1960's; it was the first measurement through casing that could distinguish and quantitatively evaluate oil and gas in saline formation water environments. More recently, the Dual Detector Neutron Lifetime Log (DNLL) service2 has been used (1) to explore for hydrocarbon resources behind pipe, (2) to monitor the production behavior of wells, (3) to plan workovers properly, (4) to determine residual oil saturation for enhanced-recovery projects, etc.

Although the carbon/oxygen3 (C/O) log provides a reliable cased-hole formation evaluation in fresh and brackish formation water environments, the DNLL service is applicable when logging through casing and/or tubing in saline environments. As discussed in detail in the literature, the basic measurement is the thermal neutron absorption (capture) cross section, S, of a subsurface formation.

Advanced methods of processing the data recorded by such a pulsed neutron capture logging system are presently under development. These improvements include (1) the average-time technique4 and (2) the sigma-dependent positioning of a single gate exhibiting a fixed gate width of 600 µseconds.

The basic theoretical considerations of these improvements are discussed, and supporting field data are presented.
A Simple Technique To Determine the Unknown Constant in y or x for Producing y vs. x as a Straight Line in Reservoir Engineering Problems
Authors: Cheng M.C. Aaron
Published: December 2007

Introduction

It is common practice in some reservoir engineering and well-testing problems to plot a certain function A vs. another function B such that a straight line results. One well-known example is the graphical interpretation of the material-balance equation as a straight line. However, most of the time there is an unknown factor in either A or B. A trial-and-error procedure for estimating this factor until a straight line results is the method usually mentioned in the literature. This paper presents a simple technique for computing, the unknown factor directly.

Technique

Using common algebraic notations, a straight line has the equation y = mx + b.

A plot of y vs. x will give a straight line with slope m and intercept b. Also, if three (or more) pairs of data, (x1, y1),(x2, y2), and (x3, y3), are known,

y2 - y1 y3 - y1 --------- - --------- = m x2 - x1 x3 - x1

or y2 - y1 y3 - y1 --------- - --------- = 0. x2 - x1 x3 - x1

If y is comprised of a certain unknown constant, say c, this equation can be expressed as

f(c) = ----------------- - ---------------- = 0.......(1) x2 - x1 x3 - x1

Similar expression holds for x being a function of c.

Eq. 1 is the formulation of the common root-solving problem, where c is the root to be determined such that problem, where c is the root to be determined such that f(c)=0. Depending on the nature of the equation, the solution of f(c)=0 can be obtained with a closed type formula or, if this is not possible. with an efficient iterative root-solving algorithm such as the Newton's method.

Selection of Data Points

The current technique requires the use of three data points for formulating Eq. 1. If more than three points points for formulating Eq. 1. If more than three points are available, the selection of any three points from the given data would be adequate if all the data points are known to be correct. This is valid because any three correct data points would yield the same root c in Eq. 1. However, if it is not known which data points are correct, which three points to choose is a problem. One logical approach is to choose the two endpoints, (x1, y1) and (xn, yn) and the median or central point from the given set of n data points (x1, y1),(x2, y2),....., (xn, yn) to span the whole data set.

The following examples illustrate the current technique.

Example 1-Determination of Pressure Buildup Correction Factor C

The after flow analysis of Russell for pressure buildup analysis requires the plot of p/(1–1/C t) vs. log t to be a straight line. The correction factor C is usually an unknown. Russell suggested that C be determined by trial and error until the plot is a straight line. The current technique instead solves for C directly. Dake's after flow analysis data are used in this example and there are 15 data points available. Select the two endpoints and the central point (Table 1).

JPT

P. 1140
Generation of Ultralow Tensions Over a Wide EACN Range Using Pennsylvania State U. Surfactants
Authors: Klaus E. E. , Jones J. H. , Nagarajan R. , Ertekin T. , Chung Y. M. , Arf G. , Yarzumbeck A. J. , Dudenas P.
Published: December 2007

Saturated paraffinic and naphthenic hydrocarbons without aromatics have been vapor-phase oxidized to produce cyclic ethers and lesser amounts of olefins. These cyclic ethers appear to be effective cosurfactants for the preparation of slugs containing petroleum sulfonate surfactants. The cyclic-ether/olefin mixture has been reacted with SO3 from oleum or liquid SO3 to form sulfonates comprising a mixture of mono-, di-, and polysulfonates. The reaction products consisting of the sulfonates, unreacted oxidized products, and residual hydrocarbons have been extracted with isopropanol (IPA) to give two sulfonate fractions. The first fraction is predominantly monosulfonate with lesser quantities of disulfonates. The second fraction consists primarily of di-, tri-, and polysulfonates.

The monosulfonate fraction in a low-concentration slug exhibits ultralow interfacial tension (IFT) against hydrocarbons of low equivalent alkane carbon number (EACN). The behavior of this fraction is similar to that of the commercial sulfonates in that its ability to generate low IFT is confined to a narrow range of EACN. To achieve low IFT's at higher EACN in the range of a Pennsylvania crude oil, it is necessary to raise the equivalent weight of the Pennsylvania State U. monosulfonate fraction by blending with a commercial sulfonate of higher equivalent weight.

Recent studies show that by mixing the two IPA fractions of the sulfonation products, a remarkably new surfactant behavior is obtained. In contrast to the behavior of other surfactants that yield ultralow tensions over only a narrow range of values of EACN, this mixture of mono- and polysulfonates generates low IFT's over a wide range of EACN extending from C5 to C12. The salt tolerance of monosulfonates and polysulfonates, either alone or in mixtures, is rather high, and even at about 4 wt% NaCl, the surfactant solutions remain stable and yield low IFT's against crude oil.
Carbon Dioxide Displacement of a West Texas Reservoir Oil
Authors: Yellig William F.
Published: December 2007

This paper presents results of an extensive study to understand CO2 displacement of Levelland (TX) reservoir oil. The work was conducted to support Levelland CO2 pilots currently in progress. Experimental displacement tests were conducted at various pressures, core lengths, and CO2 frontal advance rates. The experimental system included a novel analytical technique to obtain effluent compositional profiles within the oil-moving zone at test conditions.

The results of this study show that at pressures greater than the CO2 minimum miscibility pressure (MMP), a multicontact miscible displacement mechanism predominates. Miscibility is developed in situ by vaporization-or extraction-type mass transfer. The laboratory lengths required for CO2 to develop miscibility and exhibit miscible displacement efficiency were found dependent on the phase equilibria of the CO2/Levelland oil system. Displacements requiring the greatest length to develop miscibility were at pressures where single-contact mixtures of CO2 and Levelland oil form two liquid phases.

A companion paper10 demonstrates the use of the analytical technique developed in this study to obtain process data from a CO2 field pilot test. In addition, the mechanistic information obtained from this study is used to interpret the process data from the pilot test. The results have application to other reservoir oils whose phase equilibria with CO2 are similar to the CO2/ Levelland oil system.
Prospects of Commercialization, Surfactant/Polymer Flooding, North Burbank Unit, Osage County, OK
Authors: Trantham J.C.
Published: December 2007

Introduction

The North Burbank Unit Tract 97 surfactant/polymer pilot (Fig. 1) in Osage County, OK (Fig. 1) is a cooperative project operated by Phillips Petroleum Cofor 17 working-interest owners. During a 51-month period the project was supported by the U.S. DOE. All planned phases of the project have been completed except for conversion from fresh to produced drive water, and tertiary oil recovery is continuing. As of Feb. 27, 1981, 221,700 bbl (35 247 m ) of tertiary oil has been recovered from the 90-acre (364 000-m ) pilot, and it is estimated that tertiary oil production will continue at economical rates for 7 more years. Three annual and a final report on the project have been published by the U.S. DOE.

This reservoir is particularly attractive for tertiary recovery because more than 360 MMbbll (57.2× 10 m ) of sweet, 39 deg. API (0.83-g/cm ) oil will remain unrecovered when waterflooding reaches its economic limit (Fig. 1 2). Unfortunately, the reservoir is highly heterogeneous, both inherently and because of a fracture system that must be considered in orientation of the well pattern. It is also strongly oil-wet, requiring that chemical formulations be carefully tailored to its eccentricities.

Evaluation of the pilot has included a series of studies of prospects for commercial expansion, with economic calculations made periodically as changes in the economic climate have taken place over the past 2 years. The information reported here represents the most recent study, which includes sensitivity of the economics to several important factors.

Pilot Project

The Tract 97 pilot, shown at the bottom of Fig. 3, consists of an array of nine inverted five-spots totaling approximately 90 acres (364 000 m ). Following the drilling of 9 injection wells, 11 producing wells, and 1 saltwater disposal well, the fluid injection sequence shown in Table 1 was started on Dec. 1, 1975. Response to surfactant injection occurred in Nov. 1976, slightly more than 3 months after injection began (Fig. 4). During the early stages of ternary oil production. the response was greater than original predictions. The production peaked at a considerably lower level than anticipated, however, producing a broad, flat production curve rather than a sharply peaked one. Decline-curve analysis led to a forecasted economic limit of about 7 years, with an ultimate tertiary oil recovery of 285,000 bbl(45 300 m ).

As additional production data have been accumulated. the ultimate tertiary oil recovery has been revised upward to 295,000 bbl (46 900 m3). Currently, cumulative tertiary oil is about 225,000 bbl (35 800 m3). A detailed analysis of the pilot performance has been presented and is beyond the scope of this paper. Additional details of all aspects of the pilot project can be found in the annual reports and in several published papers.

JPT

P. 872^
Semiautomated Method for Cation-Exchange-Capacity Determination of Reservoir Rocks
Authors: Gall Bonnie L. , Volk Leonard J. , Raible Clarence J.
Published: December 2007

The presence of significant amounts of clay in tight-gas sand formations makes the determination of cation exchange capacities (CEC) important for electric-log, self-potential (SP), and gamma ray log interpretation.

In the past, CEC measurements have been difficult and time-consuming to obtain. However, an automated method that avoids many difficulties of other techniques while determining the CEC's of many samples at one time has been described by Worthington1. Our work is a modification of the work done by Worthington. Easily assembled commercial equipment instead of specially built equipment is used to agitate rock samples contained in dialysis membrane bags during ion exchange with barium acetate solution and during washing of the samples to remove excess barium ions. Barium acetate is used as the source of barium ions instead of barium chloride, which is used in Worthington's procedure, to avoid corrosion of the stainless steel equipment. The amount of barium ions on the rock samples is then determined by conductometric titration with magnesium sulfate. The titration procedure is not automated.

In addition, the use of the barium ion method was extended to samples with CEC values an order of magnitude lower than those determined by Worthington. Most measured CEC's for the western tight-gas sands ranged from 0.5 to 10 meq/100 g with a few to 19 meq/100 g.

A comparison of barium acetate, adsorbed water, and ammonium acetate methods for determining CEC's is made.