bluuebunny/crossref_metadata_2025 huggingface dataset:
Rheological Monitoring of the Formation of Polyacrylamide/Cr+3 Gels
Authors: Prud'homme Robert K. , Uhl Jonathan T. , Poinsatte John P. , Halverson Frederick
Published: December 2007

The formation of polyacrylamide/chromium-ion gels has been followed rheologically. The time dependence of the storage modulus has been used to analyze the kinetics of the gelation process. The kinetic theory of rubber elasticity has been used to determine the crosslink density in the gel from the measured value of the storage modulus. The effects of changing polymer, chromium ion, and reducing agent concentrations have been studied.
A New Method To Simulate the Effects of Viscous Fingering on Miscible Displacement Processes in Porous Media
Authors: Vossoughi Shapour , Smith James E. , Green Don W. , Willhite G. Paul
Published: December 2007

Dispersion and viscous fingering are important parameters in miscible displacement. Effects of dispersion on concentration profiles in porous media can be simulated when the viscosity ratio is favorable. The capability to simulate viscous fingering is limited.

This paper presents a new method to simulate effects of viscous fingering on miscible displacement processes in porous media. The method is based on the numerical solution of a general form of the convection-dispersion equation. In this equation the convection term is represented by a fractional flow function. The fractional flow function is derived from Darcy’s law by using a concentration-dependent average viscosity and relative flow area to each fluid at any point in the bed.

The method was extended to the description of a polymer flood by including retention and inaccessible PV. A Langmuir-type model for polymer retention in the rock was used. The resulting convection-dispersion equation for displacement by polymer was solved numerically by the use of a finite-element method with linear basis functions and Crank-Nicholson derivative approximation.

History matches were performed on four sets of laboratory data to verify the model: (1) an unfavorable viscosity ratio displacement, (2) stable displacement of glycerol by polymer solution, (3) unstable displacement of brine by a slug of polymer solution, and (4) a favorable viscosity ratio displacement. In general, computed results from the model matched laboratory data closely. Good agreement of the model with experiments over a significant range of variables lends support to the analysis.
A Review of 1960 Domestic Production
Authors: Miller Raymond W.
Published: December 2007

The General Picture

Totaling the score on the oil Industry for 1960 gives a sobering picture. Demands for petroleum products were up 2 per cent for the year. This was on the plus side but was a lot less than industry is accustomed to when contrasted with increases of about 4 per cent for 1959 and 5 per cent per year in the earlier postwar years.

Crude-oil production was about 0.5 per cent below 1959, with an increase of about 7 per cent in the production of natural-gas liquids. Crude-oil stocks were down 9.6 per cent from the previous year, which was the lowest yearend crude-stock figure in more than a decade. On the other hand, gasoline and kerosene stocks were up substantially while distillate and residual fuel oils were a little lower than a year ago.

It is important to note that much of the so-called stocks are actually in pipelines and are working stocks rather than readily available. With the increased use of pipelines for products, a higher per cent of the products are now working stocks. Over-all, at least one-half of the total stocks are not readily available for use.
Gas Injection in Eastern Venezuela Field Increases Oil Recovery
Authors: Vowel W.R.
Published: December 2007

The West Guara field lies in the state of Anzoategui, Venezuela, and is one of a number of fields located in the Eastern Venezuela Sedimentary Basin. The F7 sand, largest producing sand in the field, is of Oligocene age and is found at an average depth of 6,020 ft. The sand itself is clean, very well sorted, medium grained, with permeabilities ranging from 1,000 to 20,000 md and porosities ranging from 25 to 35 per cent. The oil was originally saturated, and a small initial gas cap was found during development. Original stock-tank oil in place was estimated to be 84,710,000 bbl.

Recovery as of Jan. 1, 1958, amounted to 51 million bbl or 60 per cent of the original oil in place. Evidence of gravity segregation was noted early in the life of the field and as a result, recovery under primary depletion, estimated at 59 per cent of the oil in place, would have been very good. However, early initiation of pressure maintenance by gas injection and exercising close control of producing operations will yield an ultimate recovery of approximately 70.5 per cent of the original oil in place. The ideal nature of the reservoir and its very light oil (42 API) are conducive to such control, and accurate prediction of performance using established engineering techniques is facilitated.

Introduction

The field produces from the Oficina formation of Oligocene age which consists of 3,000 ft of interbedded sands and shales. Of the 39 oil productive sands the F7 sand is the largest oil-bearing body in the field. Accumulation is controlled on the south by the West Guara fault, and on the north by an oil-water contact at 5,265 ft. The sand was deposited as a channel trending roughly north and south; thickness in the main channel approaches 100 ft. Thinning occurs to the east and west until on these flanks the thickness is approximately 10 to 20 ft. Fig. 1 shows pertinent structural details.

Table 1 presents pertinent data concerning oil characteristics and other reservoir information used in analyzing the F7 sand reservoir. It became apparent early that reservoir recovery would be high. However, to supplement this recovery and to maintain the wells on a flowing status, it was decided to maintain pressure by gas injection. Methods used in predicting reservoir recovery without pressure maintenance and with pressure maintenance are presented. Also discussed are operating procedures used so that actual recovery will approach as nearly as possible the predicted recovery.
A Novel Pressure Maintenance Operation in a Large Stratigraphic Trap
Authors: Weyler J.R. , Sayre A.T.
Published: December 2007

This paper presents a discussion of a program of pressure maintenance for the Adena sand field, a shallow dipping stratigraphic trap having a large gas cap. It is concluded that a reservoir of this type be successfully water flooded by injection into a row of wells along the gas-oil contact. Reservoir and laboratory studies showed that water channeling in gas saturated streaks existing in the oil zone would not occur, and that an effective water barrier could be formed between the large gas cap and producing area. Studies indicated gas-oil contact water injection far superior to the other programs investigated. One year of field performance indicates that the pressure maintenance program is functioning satisfactorily.

History of Development and Unitization

In May, 1953, Falcon Seaboard Drilling Co. drilled the Snodgrass No. 1 in Sec. 20, T 1 N R 57 W, as a rank wildcat approximately 14 miles south of Fort Morgan. Colo. (Fig. 1). This well encountered gas in the J sand of the Dakota series and was completed for a good gas well in what is now recognized to be the gas cap of the Adena field, the largest oil field in the Denver-Julesburg Basin. This well created only mild interest in this area of the basin and the next few wells drilled were considered to have but slightly more than wildcat prospects. The oil discovery came in Nov., 1953, when an independent operator completed the Cochran No. 1 in Sec. 12, T 1 N, R 58 W, flowing 900 bbl of 42 gravity oil from the J sand.

The Adena J sand field is approximately seven miles long and 3.5 miles wide. The oil zone has an areal extent of approximately 8,425 acres and the gas cap covers approximately 4,650 acres. Basic reservoir data is shown in Table 1. Production is primarily from the Dakota J sand of Cretaceous age, encountered at an average depth of 5,650 ft. The formation dips gently to the west at a rate of only 48 ft per mile, with minor nosing and flattening within the field proper (Fig. 2). Basically, the field is a stratigraphic trap, with local structure playing a very minor role as a trapping component. Oil accumulation is controlled by permeability barriers on the east, north and south sides of the field, and by a shale seal at the base of the first bench. The formation is a light gray, fine-to-medium grained grindstone. To date 170 oil wells and 15 gas wells have been drilled. The gas wells have been shut-in since completion to conserve reservoir energy. Wells were completed by drilling the entire sand section, running 5.5-in. casing and perforating the pay interval. It took only two weeks to drill and complete a well. Approximately 85 per cent of the wells in the field were both cored and logged.
Frictional Heating and Convective Cooling of Polycrystalline Diamond Drag Tools During Rock Cutting
Authors: Ortega Alfonso , Glowka David A.
Published: December 2007

A numerical-analytical model is developed to predict temperatures in stud-mounted polycrystalline diamond compact (PDC) drag tools during rock cutting. Experimental measurements of the convective heat-transfer coefficient for PDC cutters are used in the model to predict temperatures under typical drilling conditions with fluid flow. The analysis compares favorably with measurements of frictional temperatures in controlled cutting tests on Tennessee marble. An equation incorporating several drilling parameters is developed to predict the mean operating temperature across the cutter wearflat, defined as that portion of the cutter surface that wears against the rock formation. It is shown that mean wearflat temperatures can be maintained below a maximum safe value of 750°C [1,382°F] only under conditions of low friction at the cutter/rock interface, regardless of the level of convective cooling. The ability of liquid drilling fluids to reduce interface friction is thus shown to be far more important in preventing excessive temperatures than their ability to provide cutter cooling. Because of the relatively high interface friction developed under typical air drilling conditions, it is doubtful that temperatures can be kept subcritical at high rotary speeds in some formations when air is employed as the drilling fluid.
Equilibrium Calculations for Coexisting Liquid Phases
Authors: Risnes Rasmus , Dalen Vilgeir
Published: December 2007

Modeling of reservoir processes like gas miscible flooding may require consideration of phase equilibrium between multiple liquid phases. Under certain conditions two hydrocarbon liquid phases may form; one may also want to account for mass transfer between the hydrocarbon and the aqueous phases.

This paper describes a refined successive substitution (SS) method for calculating multiphase flash equilibrium. The phase behavior procedure proceeds in a stepwise manner, and additional phases are introduced by a special testing scheme based on phase fugacities. This is to avoid trivial solutions and to ensure continuity across phase boundaries.

The method has been tested on various three- and four-phase systems, and examples of application show that the method performs well.
A Mathematical Model of Thermal Oil Recovery in Linear Systems
Authors: Gottfried B.S.
Published: December 2007

Gottfried, B.S., Junior Member AIME, Gulf Research and Development Co., Pittsburgh, Pa.

Introduction

Thermal oil recovery refers to a class of recovery processes where heat is supplied to a reservoir to provide the necessary expulsive energy. This thermal energy can be supplied externally as steam or hot water, or it can be generated in situ by forward or reverse combustion. In either case, however, thermal recovery processes are characterized by the simultaneous flow of two or three fluid phases in a variable-temperature field, accompanied by possible chemical reaction or phase-change effects. Although a physical understanding of the thermal recovery processes is far from complete, it is possible to construct mathematical models which describe approximately all of the principal physical and chemical phenomena. However, attempts to solve such models, even with high-speed computers, involve formidable mathematical difficulties. Consequently, theoretical solutions have been obtained only for idealized cases in which important physical phenomena are neglected. For example, consider the process of forward in situ combustion. All such theories which have been developed consider only certain aspects of the Process, such as heat transfer, heat transfer with phase change, heat transfer with chemical reaction, or the hydrodynamics of three-phase flow. A general theory including all of the above phenomena has not been developed to date. This paper presents a unified theory of thermal recovery processes in linear systems. A mathematical model is developed which explicitly includes conduction-convection heat transfer with convective external heat loss, chemical reaction between air and oil, aqueous phase change, and the hydrodynamics of three-phase flow. A system of equations is developed which can be solved numerically on a high-speed digital computer, resulting in predicted temperature, pressure, and saturation histories in space and time. The model allows a more detailed simulation of thermal recovery tube experiments than had previously been possible.

THEORETICAL DEVELOPMENT

Consider the linear flow of gas, water and oil in a homogeneous porous medium. Assume that the oil will react with gaseous oxygen, and that mass is transferred between the water and gas phase by evaporation or condensation.

SPEJ

P. 196ˆ
Foamlike Dispersions for Mobility Control in CO2 Floods
Authors: Heller John P. , Lien Cheng Li , Kuntamukkula Murty S.
Published: December 2007

At the reservoir temperature and pressure at which CO2 can displace a crude oil with high microscopic-displacement efficiency, its density and compressibility are close to those of the crude oil—and not greatly different from those of water itself. Because of this, the mechanical and chemical characteristics of a high-pressure, CO2-in-water "foam" cannot be assumed to be the same as those of an air/water foam at near-atmospheric pressure.

This paper reports information on the mobility of foamlike dispersions in reservoir rock. The data come both from the recalculation of selected experimental work reported in the literature and from new experiments. An important criterion for these experiments is to eliminate or greatly reduce the influence of fluid compressibility, so as to approximate field conditions in CO2 floods more closely. The core flow experiments performed for this work meet this condition by use of the nonaqueous phase of either liquid CO2 at high pressure, or a light hydrocarbon to simulate dense CO2 in experiments performed at low pressure.

We postulate that to be effective in retarding the growth of fingers or other instability patterns in CO2 floods while maintaining a high microscopic displacement efficiency, a foamlike dispersion of dense CO2 in surfactant/water should have the following characteristics.

1. Its aqueous-phase content should be as low as possible, to minimize oil trapping and to permit maximum contact between CO2 and the crude oil.

2. Its effective mobility in the reservoir rock should be adjustable, by some parameters accessible during its generation, to about that of the oil bank it is expected to form and to displace.
Experimental Study on the Effect of Axial Tension Load on the Collapse Strength of Oilwell Casing
Authors: Kyogoku T. , Tokimasa K. , Nakanishi H. , Okazawa T.
Published: December 2007

This paper discusses a newly developed collapse testing machine that permits investigation of practical performances of oilwell casings. Although a theoretical analysis has shown that "axial tension stress has no effect on collapse pressure in the elastic case,"1 this theory is not applied to the design of casing string because of lack of useful experimental data or authorized recommendation. To investigate the effect of axial tension load, full-size commercial casings have been tested under combined loading of axial tension load and external pressure. From the experimental results, the theory mentioned was proved in the case of so-called high-collapse casing, which has been used widely in recent years. Also shown is the applicable d/h range, which is wider than API's elastic collapse range. If the results of this experiment were applied to the design of a casing program, an economical and safe one could be obtained.
Performance of Domes Unit Carbonated Waterflood - First Stage
Authors: Scott J.O. , Forrester C.E.
Published: December 2007

Carbonated water has been injected as a slug, followed by non-carbonated water, in the Bartlesville sand formation of the Domes unit in northeastern Oklahoma. Initial results are shown for the first stage of the flood, consisting of nine enclosed five-spots comprising 132 acres. Production history indicates the carbon dioxide have been transferred to the residual oil and has mostly been retained in the reservoir. A large portion of the formation is apparently being bypassed due to stratification and reservoir fracturing. Results of pressure shut-in tests are shown to indicate vertical fractures being opened by injection pressures. The tests have been used to help balance the flood and increase oil recovery from poorly swept areas.

Introduction

The Domes unit is composed of 13 quarter-sections located in Sections 34 and 35 of T-27N, R-10E; and Sections 2 and 3 of T-26N, R-10E in Osage County, Okla., 15 miles west of Bartlesville (Fig. 1).The unit is jointly owned by Cities Service Oil Co. and Oil Recovery Corp. The unit was organized March 1, 1961, with Cities Service as the operator owning a 63.52 per cent working interest, and Oil Recovery Corp. owning 36.48 per cent. Initial operations of the unit have been to conduct a carbonated waterflood of the Bartlesville formation.

Primary Development and Recovery

Development of this area began in 1910 with gas production from the Mississippi Chat at a depth of 1,950 ft. In 1914, development of the Bartlesville sand began and continued through the early 1920's. About 60 wells were drilled during this period but were all plugged when waterflooding was started. Only minor drilling was done for the next 30 years until the advent of hydraulic fracturing. when extensive redrilling of the area occurred. Wells drilled during 1952 and 1953 were completed for potentials of 50 to 100 BOPD after fracturing. This redrilling resulted in an additional 30 wells. Primary oil recovery from the Bartlesville sand in the developed unit area averaged 80 bbl/acre-ft. The NE/4, Section 34 and SW/4, Section 34, due to extensive fracture treatments, have recovered 115 bbl/acre-ft. Primary oil production is estimated to have been 1,255,000 bbl from the total unit area at the start of secondary development. Reservoir properties are shown in Table 1.

Secondary Development-First Stage

Secondary development started in Section 34 in the summer of 1961. Most of the wells used had been drilled in 1952 and 1953. Thirteen producing wells were converted to injection and three additional injection wells were drilled to complete nine five-spot patterns (Fig. 1). The patterns range from 12 to 20 acres, comprising a total of 132 acres. Besides the enclosed producing wells, four outside producing wells existed at the beginning of the flood. Additional producing wells surrounding the enclosed area were added early in 1962.

JPT
Optimal Injection Policies for Enhanced Oil Recovery: Part 1— Theory and Computational Strategies
Authors: Ramirez W. Fred , Fathi Zohreh , Cagnol Jean Luc
Published: December 2007

The theory of optimal control of distributed-parameter systems is presented for determining the best possible injection policies for EOR processes. The optimization criterion is to maximize the amount of oil recovered at minimum injection costs. Necessary conditions for op-timality are obtained through application of the calculus of variations and Pontryagin’s weak minimum principle. A gradient method is proposed for the computation of optimal injection policies.
Linear Oil Displacement by the Emulsion Entrapment Process
Authors: Schmidt D. P. , Soo H. , Radke C. J.
Published: December 2007

Lack of mobility control is a major impediment to successful EOR, especially for high-viscosity oils. This paper presents experimental and theoretical results for continuous, linear, secondary oil displacement using dilute, stable suspensions of oil drops. The major hypothesis is that the oil/water (O/W) emulsion provides microscopic mobility control through entrapment or local permeability reduction not through viscosity-ratio improvement. To describe the displacement process, previous emulsion filtration theory is extended to longer cores and to two-phase flow. Agreement between theory and experiment is satisfactory for continuous secondary oil displacement with 1- to 2-μm [1- to 2-micron] diameter drops of volume concentrations up to 5 % in unconsolidated sandpacks with permeabilities ranging from 1 to 3 μm2 [1 to 3 darcies].

Dilute suspensions of stable oil drops in water also are successful in diverting flow in parallel-coreflooding to the lower-permeability core; therefore, they provide macroscopic mobility control.
An Analysis of Large-Scale Flooding in the Fractured Spraberry Trend Area Reservoir
Authors: Barfield E.C. , Jordan J.K. , Moore W.D.
Published: December 2007

Introduction

The Spraberry Trend oil reservoirs, producing from a very tight fractured sand, have been characterized by a rapid decline in reservoir pressure and oil producing rate and by production of only a small fraction of estimated original oil in place. Almost all original areas of development are now in the stripper stage or have been abandoned. Although it was considered unlikely that this solution gas-drive reservoir would lend itself readily to conventional methods of secondary recovery, a great deal of effort has been devoted to developing techniques which would utilize the unusual characteristics of the reservoir rock and its fracture system to increase ultimate oil recovery. A single five-spot pilot water flood was initiated in the west central portion of the Spraberry Trend Area reservoir during March, 1955. A combination analytical and numerical method employing high-speed computing equipment was utilized to analyze results of this pilot flood. With field behavior as the criterion for the analysis, orientation of the major fracture system, ratio of the permeability parallel and perpendicular to this trend, and relationship of the observed recovery from the center producing well of the pilot flood to that which might be achieved under large-scale flooding operations were determined. Information developed during analysis of the pilot water flood was then used to develop a flooding program for a 40-section area in the western portion of the field. From this work, it was concluded that the analysis procedure has considerable utility in analyzing flooding operations in a fractured reservoir and a relatively high pattern efficiency can be achieved in the area studied if the proper flooding pattern is chosen.

Attempts to Develop Recovery Techniques

The first attempt to develop a new recovery technique was a process designed by The Atlantic Refining Co. to utilize the principle of water imbibition. Laboratory work and the subsequent field trial demonstrated that water injected into the fractures could be imbibed spontaneously into the matrix rock by capillary action with the concurrent expulsion of oil into these same channels from which it could be produced by the surrounding wells. The second example of the research effort to increase oil recovery was work performed by Humble Oil and Refining Co. It was determined that with an intensive and inter-connected system of fractures, water injected into the formation could flood simultaneously a large number of matrix blocks. Water invading the matrix with the concurrent discharge of oil into the fractures would rapidly increase oil content and reduce water content of the effluent in the fractures moving toward the producing wells. To evaluate the potentialities of this type flood, a single five-spot pilot water flood was put into operation March 8, 1955.
Application of Laboratory Data in Calculating the Primary Production History of the Cisco K-1 Reservoir
Authors: Hardy William C. , McArthur B.W.
Published: December 2007

The purpose of this work is to show application of laboratory data in calculating solution gas-drive performance of the Cisco K–1 reservoir. Included herein is a diagram showing the graphical relationship between six variables common to all solution gas-drive mechanisms. With an iterative process one may assume existence of any of these six variables at a particular pressure and calculate the production performance likely to occur in a reservoir produced by solution gas drive.

Four unique pressure values are described at which the material balance equation alone is sufficient to predict the cumulative volumes of gas produced. Information derived from these pressure points establishes a criterion for determining compatibility of the pressure-volume-temperature (PVT) analysis of the produced crude with the gas production history.

Two averaging procedures are used to arrive at a relative permeability-saturation relationship which describes the field-wide performance.

Introduction

The Cisco K–1 reservoir is a lenticular-type sand structure lying at approximately 6,300-ft subsurface. It is located in the H. and T. C. Railroad Co. Block 97, SW 1/4 S 392 and NW 1/4 S 385, Scurry County, Tex. Correlation of data from logs indicated that the Cisco K–1 reservoir occupied approximately 2,390 acre-ft of space with a closure of from 15 to 20 ft.

Analysis of the production data indicates that the initial formation pressure and temperature were 2,450 psig and 121F, respectively. The bubble point occurred at 1,715 psig after production of 12,256 STB oil and 11,520 Mcf gas. Only traces of water have been produced since initiation of production. Successive material balance calculations from June, 1952, to June, 1957, showed that no initial gas cap or water influx has contributed to production of oil and that the Cisco K–1 reservoir originally contained approximately 1.44 X 10(6) STB of oil.
Theory and Application of Imbibition Phenomena in Recovery of Oil
Authors: Graham J.W. , Richardson J.G.
Published: December 2007

The purpose of this paper is to present the results of theoretical and experimental studies of water imbibition. The imbibition processes are involved in recovery of oil from stratified and fractured-matrix formations in natural water drives and water flooding. An understanding of the role of imbibition in implementing the recovery of oil from such formations is deemed essential to proper control of these reservoirs to achieve maximum recovery.

The theoretical studies involved development of the differential equations which describe the spontaneous imbibition of water by an oil-saturated rock. The dependence of the rate of water intake by the rock on the permeability, interfacial tension, contact angles, fluid viscosities and fluid saturations is discussed. A few experiments were performed using core samples to determine the effects of core length and presence of a free gas saturation.

The role of water imbibition in recovery of oil from a fractured-matrix reservoir by water flooding was investigated by use of a laboratory model. This model was scaled to represent one element of a fractured-matrix formation. Water floods were made at various rates with several fracture widths. Interpretations were made of the behavior expected in a system containing many matrix blocks.

The presence of a free gas saturation was found to reduce the rate of water imbibition. In the reservoir prototype of the fractured-matrix model, water imbibition rather than direct displacement by water was the dominant mechanism in the recovery of oil at low rates.

Introduction

Imbibition may be defined as the spontaneous taking up of a liquid by a porous solid. The spontaneous process of imbibition occurs when the fluid-filled solid is immersed or brought in contact with another fluid which preferentially wets the solid. In the process of wetting and flowing into the solid, the imbibing fluid displaces the non-wetting resident fluid. Common examples of this phenomenon are dry bricks soaking up water and expelling air, a blotter soaking up ink and expelling air and reservoir rock soaking up water and expelling oil.
The Effect of Crossflow on Waterflooding of Stratified Reservoirs
Authors: El-Khatib Noaman
Published: December 2007

A mathematical model is developed for waterflooding performance in linear stratified systems for both cases of non-communicating layers with no crossflow and communicating layers with complete crossflow. The model accounts for variation of porosity and saturation in addition to permeability of the different layers. The model predicts the fractional oil recovery, the water cut, the total volume injected, and the change in the total pressure drop, or the change in injection rate at the water breakthrough in the successive layers. A systematic procedure for ordering of layers and performing calculations is outlined. A procedure for combining layers to avoid instability in the case of low mobility ratio is introduced.

The developed model is applied to different examples of stratified reservoirs. The effects of mobility ratio and crossflow between layers are discussed. The effects of variable porosity and fluid saturation are discussed also.

It was found that crossflow between layers enhances the oil recovery for systems with favorable mobility ratios (λw/λo < 1) and retards oil recovery for systems with unfavorable mobility ratios. It was found also that crossflow causes the effect of the mobility ratio on oil recovery to become more pronounced. The variation of porosity and fluid saturation with permeability is found to increase oil recovery over that for the case of uniform porosity and saturation for both favorable and unfavorable mobility ratios.
A Small-Volume Continuous Oil/Water Separator for Laboratory Displacement Experiments
Authors: Bretz R.E. , Pelletier M.T. , Orr F.M.
Published: December 2007

Introduction

An experimental task commonly encountered in laboratory core displacement experiments is the separation of oil and water phases. While such physical separations are not inherently difficult, they can be time-consuming and may lead to material-balance errors if numerous small samples are collected. In this paper, we describe an oil/water separator of low volume that relies on the wetting characteristics of commercially available filter membranes. Because a flowing stream containing oil and water can be separated continuously without a large-volume mixing cell, the separator allows on-line measurement of the compositions of oil and brine streams. It might also prove useful in relative permeability measurements. permeability measurements. Description and Operation

Fig. 1 is a schematic of the device. The two-phase fluid enters the chamber between two porous membranes having different wetting behaviors. Oil, the less-dense phase, rises and contacts the upper, hydrophobic phase, rises and contacts the upper, hydrophobic membrane. Water settles and contacts the lower, water-wet membrane.

Because it is hydrophobic, the upper membrane resists passage of water through its pores but readily admits the passage of water through its pores but readily admits the nonpolar oil. The lower membrane can be wet by either oil or water but, if first wet by water, surface tension effects will prevent oil from entering the pores. Therefore. the first step in operating the separator is to prime it with water to establish a water-wet condition, which must be maintained during operation.

Before the separator is assembled, we saturate the water-wet membrane using a vacuum to eliminate air from the pore spaces. After assembly, we fill the separator with water to the level of the vent of the siphon-breaker.

JPT

P. 487
Field Test Confirms Accuracy of New Bottom-Hole Pressure Gauge
Authors: Lozano G. , Harthorn W.A.
Published: December 2007

Maihak bottom-hole pressure gauges have been field tested in three wells in the San Joaquin Valley, Calif. These are the first known installations of this surface-indicating gauge in the U. S. although it has been used several years in Europe.

The gauge, manufactured by the H. Maihak Co., Hamburg, Germany, consists of a transmitter located at the bottom of the tubing and a receiver at the surface. The signaling circuit consists of a single conductor wire strapped to the outside of the tubing and the tubing itself. Measurements have been made successfully as deep at 6,885 ft. Fig. 1 is a schematic diagram of the system. The gauge appears accurate and reliable and should be a useful addition to the tools of the petroleum engineer.

Introduction

Bottom-hole pressure is one of the most valuable tools of the reservoir engineer. To a lesser degree it is also valued by the production foreman, mechanical engineer and others responsible for efficient production of oil. Existing instruments to measure bottom-hole pressure, although accurate and reliable, have serious limitations. With certain exceptions they are not equipped to telemeter data from the bottom of the well and their utility therefore is limited to occasional measurements. In addition, the high cost of running and retrieving the instruments sometimes discourages their use. This is particularly true in pumping wells where rods or tubing must be pulled to run and retrieve the instruments. A definite need has existed for pressure instruments which will continuously, or on demand, telemeter their data from the well without pulling rods or tubing. The successful development and application of such instruments should open new horizons to reservoir and production engineers and more efficient development and production practices will almost certainly follow. When we learned that the Maihak bottom-hole pressure gauge had been successfully applied in European oil fields, we obtained several for testing. The purpose of this paper is to report on tests made at three wells in the San Joaquin Valley and to make the equipment known to the domestic oil industry.
Accuracy of JBN Estimates of Relative Permeability: Part 1—Error Analysis
Authors: Tao T. M. , Watson A. T.
Published: December 2007

The accuracy of relative permeabilities estimated from displacement experiments by the Johnson, Bossier, and Naumann (JBN) method is considered. A Monte Carlo error analysis is developed to provide quantitative measures of that accuracy. The Monte Carlo error analysis is used to investigate the effect of different experimental operating conditions on the accuracy of relative permeability estimates.
A Numerical Solution of the Linear Displacement Equation with Capillary Pressure
Authors: McEwen C.R.
Published: December 2007

Introduction

The displacement equations of Buckley and Leverett have been successfully applied to the prediction of oil recovery in frontal drives for a number of years. Commonly, the capillary pressure term is omitted from Leverett's fractional flaw formula. The resulting saturation-vs-distance curves became multi-valued, however. Buckley and Leverett, recognizing that the neglect of capillarity was most likely the cause, proposed that this part of the solution be ignored.

An ingenious method of propagating a discontinuity in place of the multi-valued portion of the curve was devised by Cardwell using "non-capillary displacement theory". However, it would seem that a complete description of the displacement process would require the inclusion of capillary forces.

Three publications on displacement theory have appeared in which capillary pressure was included. Terwilliger, et al, calculated saturation profiles which matched those which they observed when gas displaced water vertically downward. Based on their study, Jones-Parra and Calhoun proposed a method of computing saturation distributions sufficiently removed in time from the initial conditions so that all saturations in the flood front region were assumed to move with the same velocity. This latter assumption corresponds to the tangent construction on the flowing fraction-vs-saturation curve proposed by Welge.
The Displacement of Residual Crude Oil by CO2 and Nitrogen in Gravity Stabilized Systems
Authors: Doscher T. M. , Oyekan R. O. , El Arabi M.
Published: December 2007

Physical model studies of the displacement of residual oil by CO2 have led to the conclusion that the driving mechanism for the process is that of a gas drive of the swollen crude. In this final phase of the study, the fluid/fluid displacement process was gravity-stabilized; mixing of the CO2 with the residual crude oil was minimized. As a result, the performance of CO2 was only marginally better than that of relatively insoluble nitrogen.
Analytical Well Models for Reservoir Simulation
Authors: Abou-Kassem Jamal H. , Aziz Khalid
Published: December 2007

The computation of flowing-well bottomhole pressure from the pressure of the block containing the well or of well flow rate when the flowing bottomhole pressure is specified are important considerations in reservoir simulation. While this problem has been addressed by several authors, some important aspects of the problem are not treated adequately in the literature.

We present an analytical method for computing the well-block factors (constants of the PI) for a well located anywhere in a square or rectangular block (aspect ratio between ½ and 2). Equations for well geometric factors and well fraction constants are given for gridblocks of various types, containing a single well, encountered in reservoir simulation studies. The equations given in this paper can be used for both block-centered and point-distributed grids in five- and nine-point two-dimensional (2D), finite-difference formulations. The radial flow assumption used in deriving the equations in this paper is not always strictly valid; however, for most practical situations it provides an adequate approximation for near-well flow.
Gas Phase Appearance and Disappearance in Fully Implicit Black Oil Simulation
Authors: Forsyth P. , Sammon P. H.
Published: December 2007

This paper describes the pseudogas and variable substitution methods for handling gas phase appearance/disappearance in fully implicit black oil simulation. The results of several test runs indicate that there is virtually no difference between these two methods in terms of efficiency. The pseudogas method is easier to program than variable substitution but requires some crucial reallocations of saturations and shows greater material balance errors.
Computer-Assisted Tomography for the Observation of Oil Displacement in Porous Media
Authors: Wang Simon Y. , Ayral Seyda , Gryte Carl C.
Published: December 2007

Computer-assisted tomography (CAT) is used to obtain cross-sectional images of Berea sandstone cores during oil displacement experiments. Local oil saturation averaged over an area of about 0.03 × 0.03 in. [0.8 × 0.8 mm] square is computed as a function of spatial position and time. A series of CAT scan images displaying the time evolution of the fluid distribution at one cross section are shown to illustrate the formation of viscous fingers.
Manual and Automated Turbidimetric Methods for the Determination of Polyacrylamides in the Presence of Sulfonates
Authors: Kuehne D. L. , Shaw D. W.
Published: December 2007

Polymers and sulfonates are often part of the multicomponent chemical systems designed to increase oil recovery from depleted reservoirs. The objective of this work was to develop reliable, analytical methods for measuring Polyacrylamide concentration in the presence of sulfonates. The need for new or improved methods arose because petroleum sulfonates caused interference with the standard turbidimetric method for determining Polyacrylamides. This interference was eliminated by the addition of a butanol-extraction step to remove sulfonates.

Based on the new manual procedure, an automated method was developed for use with a Technicon Auto-Analyzer™ to reduce analysis time. The automated method was designed with four modes of operation to cover high and low polymer concentrations with and without sulfonates present in the samples. Polymer concentrations ranging from 10 to a maximum of 1,200 wt ppm [10 to 1200 mg/kg] can be measured. A unique feature of the automated method is the continuous-flow solvent extraction. Depending on the mode, Auto-Analyzer throughput is 20 or 30 samples per hour. The accuracy of the results is 5% with extraction and 1% without extraction.
The Origin of Reversible Hydroxide Uptake on Reservoir Rock
Authors: Bunge A. L. , Radke C. J.
Published: December 2007

When reservoir solids reversibly consume hydroxide, the impact on alkaline-waterflood performance can be significant. Only recently has this reaction been recognized as a principal factor influencing oil recovery rates and chemical-pulse depletion.

This paper considers the origin of the reversible hydroxide uptake to be ion exchange of sodium for hydrogen ions. Using a simple, mass-action equilibrium model, we describe the alkali exchange isotherm. Because hydronium and hydroxide concentrations in water are never zero, hydroxide uptake must be reported relative to a reference pH and salinity. With the recognition of a reference state and with the mass-action model, we predict qualitatively the effects of pH, salt concentration, and temperature on the measured hydroxide uptake isotherms for the Wilmington, Ranger-zone sand.

Mineral sites that exchange ions of sodium for hydrogen may also exchange calcium for hydrogen or for sodium. Using simple mass-action equilibria again, we demonstrate that reversible hydroxide uptake depends on hardness concentration and that calcium/sodium, exchange is pH dependent.
Semilog Analysis of the Pulse-Decay Technique of Permeability Measurement
Authors: Chen Techien , Stagg P. W.
Published: December 2007

An alternative solution to the system of equations describing the pulse-decay technique of permeability measurement has been obtained. It is a solution in which the sample PV is not neglected. The experimental data are analyzed by using the slope of a semilog plot to evaluate permeability.
Interpretation of Pulse Tests in Reservoirs With Crossflow Between Contiguous Layers
Authors: Prats M.
Published: December 2007

A normally interpreted instantaneous pulse test between two undamaged wells will yield the average transmissivity and storage of two-layer reservoirs with crossflow along their boundary only when the heterogeneity parameter defined in the text is less than approximately unity.
Analytical Model for Vertical Interference Tests Across Low-Permeability Zones
Authors: Bremer R. E. , Winston Hubert , Vela Saul
Published: December 2007

A mathematical model is developed that describes fluid flow and pressure behavior in a reservoir consisting of two permeable zones separated by a zone of low permeability, or a "tight zone." This model can be used to design and to interpret buildup, vertical, interference, and pulse tests conducted in a single well or multiple wells across lithological strata. Dimensionless pressure functions and corresponding parametric type curves are derived to interpret vertical interference test data for tight-zone vertical permeability. Application of these type curves is illustrated using field data from two vertical interference tests. Test results obtained with the tight-zone model are shown to compare favorably with results obtained by using (1) computer simulations and (2) Burns' method based on the uniform anisotropy assumption. Computer simulation using a numerical model also shows that high near-wellbore conductivity from a packer leak or poor cement job could not have adversely affected test results. The model presented and the type-curve interpretation method outlined are accurate for designing and interpreting single-well vertical interference tests across low-permeability zones.
Pressure Transients and Crossflow Caused by Diffusivities in Multilayer Reservoirs
Authors: Gao Cheng-Tai , Deans H. A.
Published: December 2007

This paper considers single-phase unsteady flow in a system of homogeneous layers separated by thin, low-permeability shales, and having interlayer crossflow caused by different diffusivities for different layers. The model considers all layers open to a single well that flows at a constant total rate. Numerical simulations of the problem for the semipermeable-wall model are used to find the structure of the crossflows in typical cases. Analytic solutions for pressure and the n − 1 diffusivity crossflows are developed and compared with the numerical results. These solutions show how the diffusivity crossflows depend on layer properties and ordering. Their behavior and properties are discussed and their effects on pressure distributions are shown.
Flood Water Analyses and Interpretation
Authors: Ellenberger A. Richard , Holben James H.
Published: December 2007

Introduction

With the advent of secondary recovery of oil by water injection, it was some years before much significance was attached to the importance of water analysis or the necessity for water treatment. Filtration of water came into practice when it became apparent that turbid water led to rapid plugging of injection wells. It was soon realized that most waters required more than filtration. Thus, it became evident that water analysis was necessary to determine the causes of corrosion and well plugging, to properly prescribe treatment to correct these ills, and to control and adjust the treatment as necessary after it was instituted.

Initial waterflood developments and the beginning of flood water analysis and treatment were in the Appalachian fields of Bradford, Pa., and Allegany, N. Y. Waterflood activity has moved to Western oil producing fields and is being practiced in most areas. Water analysis and water treatment have kept pace with this expansion.

Several petroleum engineering and oil operator groups have recently requested a discussion from the standpoint of "how to interpret a water analysis". Therefore, this discussion is aimed in that direction. A diagram showing experimental apparatus appears in Fig. 1 and results of filterability tests are shown in Figs. 2 and 3.

Initiating the Water Flood

The first problem to arise in planning a water flood involves what waters to use. More frequently, at least in a project of any size, it is a matter of using whatever water is available in sufficient quantity. If there is a choice of waters, then a survey of each supply is indicated. This should include an analysis of each possible source water with an eye toward the economics of treating each or a possible mixture. Also to be considered will be as complete a study as feasible on quantities available and procurement costs.

Once the water source is established the analysis is used to determine what type of treatment is necessary to provide a satisfactory injection water. The water plant should be designed to provide this treatment or any possible variations which may be encountered. It is rather surprising how often this order of procedure is reversed and the operator acquires a water plant before he learns what he must do to condition the water which is available.