bluuebunny/crossref_metadata_2025 huggingface dataset:
United States Intensifies Quest for Foreign Oil; Russia Expands in World Markets During 1958
Authors: McCobb H.W.
Published: December 2007

Introduction

For foreign oil operations the year 1958 was a year of adjustment and change, rather than a year of crisis or sensational discovery. It marked the establishment of trends that are likely to be of great significance in the years to come:entry of more and more U. S. oil firms into foreign operations,penetration of the Free World oil markets by Russia, anda trend toward more government participation in oil ventures.

1958 was also a year of industry-wide over-capacity. These trends are discussed briefly, including some of the more significantdevelopments in selected countries.

Dynamic Growth of Foreign Market Attracts U. S. Companies

Entry of more U. S. companies into foreign oil operations has resulted largely from the desire by domestic firms to participate in the dynamic growth of foreign markets, along with the feeling that the growth of demand in the U. S. has become relatively slow (see Fig. 1).

Are Foreign Outlets the Key to Growth?

Because of the belief by many that development of market outlets is the key to growth and profits, there has been a desire to obtain outlets in these rapidly growing foreign markets. Also, the growing difficulty and increasing cost of finding oil at home have been factors in causing many domestic firms to search for oil abroad in spite of the great hazards of overseas operations. In 1952, for example, 72 U. S. petroleum companies were engaged in 164 separate exploratory and producing operations in 51 foreign countries. By the end of 1957, the total had more than doubled to 150 companies, representing an estimated 2 million stockholders, with an estimated $8 billion invested overseas. The companies were involved in 398 separate operations and had spread their activities to 73 countries.

As a result of these activities by U. S. and foreign companies, the world supply of crude increased to meet the growing demand as shown in Figs. 2 and 3.

During Sept., 1958, Free World production reached a record level of more than 16 million B/D. The month also was a record for free foreign output, which pushed past 9 million B/D for the first time.
Problems in Characterization of Naturally Fractured Reservoirs From Well Test Data
Authors: Ershaghi I. , Aflaki R.
Published: December 2007

This paper presents a critical analysis of some recently published papers on naturally fractured reservoirs. These publications have pointed out that for a matrix-to-fracture-gradient flow regime, the transition portion of pressure test data on the semilog plot develops a slope one half that of the late-time data. We show that systems under pseudosteady state also may develop a 1:2 slope ratio. Examples from published case studies are included to show the significant errors associated with the characterization of a naturally fractured system by using the 1:2 slope concept for semicomplete well tests.
Exploitation of Oil Shale Deposits by Nuclear Explosives
Authors: Johnson Gerald W.
Published: December 2007

Introduction

During the past two years increasing interest has developed in the possible use of nuclear explosives for mineral development. These projects are still in the discussion and study phases; however, experiments associated with some of them are expected to be executed in the near future regarding exploitation of our huge deposits of oil shale.

All of the experience with the pertinent effects of nuclear explosives has been obtained in conjunction with weapons development and testing. Herein are described results that are presently available and how they might be employed in problems of mineral exploitation.

Use of Nuclear Explosions to Recover Oil from Shale

Consideration is presently being given to the possibility of utilizing nuclear explosions to recover oil from oil shales. This project was discussed in detail at a recent Atomic Energy Commission-Bureau of Mines meeting in Dallas. The concept is to use the explosion to shatter a formation, of shale to permit recovery of oil by retorting in place.

The AEC has announced that the charges for a one million ton explosion would be $1 million, which includes placing, firing and making studies to assure the public health and safety. It has also been stated that the charges may be substantially reduced for multiple firings.

In considering the thick shale in Rio Blanca County, Colo., it was noted that the shale thickness was 1,000 to 2,000 ft (25 gal/ton grade) which would permit detonation at a depth of 2,000 to 3,000 ft. Under these conditions a detonation of a few hundred kilotons could be safely carried out to produce 30 million tons of broken permeable shale. Since the cost of the explosion is $1 million and the placement cost would perhaps be another $1 million, the cost per ton broken would be about 6 cents.

If the technology of retorting in place can be developed economically, for a major portion of the feasibility hinges on the size and distribution of the broken rock, then one sees that the breakage cost would be only a small part of the cost of producing the oil-perhaps 12 cents/bbl of recovered oil. The expected costs of retorting, as estimated roughly by the Bureau of Mines, might be as low as $2/bbl.
Mechanical-Production Aspects of the Rincon Island Development
Authors: Flaherty Robert
Published: December 2007

Since its completion in Sept., 1958, Richfield Rincon island has been the site of intense drilling activity. The score thus far on the 1-acre, rock-base island is three wells completed, a fourth in the process of being drilled, and facilities for the ultimate drilling of 58 more wells.

The lease being developed by the Richfield Rincon island is 1,175 acres in areal extent and lies south and west of Punta Gorda, 10 miles north of the city of Ventura and is in the western portion of the Rincon field (see Fig. 1).

The location of the island was based on geologic information obtained from core holes drilled from the Rincon barge, a converted LSM. The island is located approximately 3,000 ft southwest of Punta Gorda in 45 ft of water.

At the present time there are four types of structures being used to develop California offshore oil leases:template-type platform,permanent platform,floating barge, andartificial island.

There are currently two artificial islands off the California Coast, the Monterey-Texas island at Seal Beach and the Richfield Rincon island. Both of these islands were constructed to develop state leases granted under the California Tidelands Law as it existed prior to Sept., 1955. The law, which has since been modified, at that time called for development from upland sites or from filled lands.

Island Scientifically Designed

The first step in the design of the island was a detailed study of prevailing winds, surface currents and wave heights. The worst weather month was found to be January, at which time the waves are below 5 ft in height 90 per cent of the time and over 16.5 ft 0.1 per cent of the time. However, waves of the order of magnitude of 25 to 30 ft have been observed in this area. The direction of waves is from N 80° W to S 60° W. Prevailing winds are from the northwest at 8 to 12 mph.

Using this weather data, model studies were made of various types of island structures at the Army Corps of Engineers Waterways Experimental Station at Vicksburg, Miss., and from these studies evolved the basic island design. The design can be briefly described as a rock revetment with an internal sand core and with protective armor rock on the outside (see Fig. 2).
Harmattan Elkton Field - A Case for Engineered Conservation and Management
Authors: Donohoe C.W. , Bohannon D.L.
Published: December 2007

The Harmattan-Elkton field, located approximately 50 miles north of Calgary, Alberta, Canada, is a major oil reservoir with a large associated gas cap in the Turner Valley formation, Rundle group of Mississippian Age. The ratio of gas-cap to oil-zone volume is 3.29, and the condensate content of the gas-cap gas was approximately 47 STB/1 million cu ft of gas at original reservoir pressure. The oil zone is partially overlain by gas and partially underlain by a limited water leg. Both gas and water coning have been experienced in the oil rim. The unitization of this field and the application of engineering techniques early in the productive life of the field have resulted in the adoption of a gas conservation program in the oil zone and a gas-cap cycling operation, which should result in the conservation of hydrocarbon products and an enhanced income for the field operators.

Introduction

The Harmattan-Elkton field is located approximately 50 miles northwest of Calgary, Alberta, Canada, as shown on Fig. 1. The field is a stratigraphic trap containing a large gas cap with a relatively thin oil column underlain by a limited aquifer. The oil-zone wells have a tendency to cone both gas and water, depending on structural location of the well and position of the perforations. This coning condition resulted in loss of producing rate under nonunitized operations due to gas-oil ratio and water-oil ratio penalties. Early in the life of the field, an operators' committee was formed to study the problems associated with producing the field, and, in 1960, detailed engineering work was begun to determine the best method of operation considering both conservation and income. The field was unitized in Dec., 1960, at which time the injection of casing-head gas into the gas cap was commenced. Cycling of the gas cap was initiated in March. 1962, at a design rate of approximately 105 MMscf/day. This operating program has performed successfully to date, has increased recoveries of gas-cap liquids due to reduction in retrograde losses, and has permitted the oil zone to produce at full allowable rate. This paper deals with the producing problems of the Harmattan-Elkton field and the ultimate solution of these problems.

Geology

The Harmattan-Elkton field produces from the Turner Valley formation of the Rundle group of Mississippian Age at an average depth of approximately 8,800 ft. The oil and gas accumulation occurs in a monoclinal stratigraphic trap dipping westward at approximately 1 degrees. Loss of permeability occurs along the northern, eastern, and southern flanks due to solution channels which have subsequently been filled with dense limestone. Production down-dip to the west is limited by an oil-water contact at a depth of 5,442 ft subsea. The original gas-oil contact occurred at a depth of 5,360 ft subsea.

JPT

P. 1171ˆ
Some Surprises in the Transport of Miscible Fluids in the Presence of a Second Immiscible Phase
Authors: Jones Stanley C.
Published: December 2007

Displacements were conducted in Berea cores to gain insight into the mechanism of tertiary oil displacement and propagation by a micellar slug. Contrary to expectation, the first oil mobilized by micellar fluid was among the first oil (instead of the last oil) to be produced, giving the appearance of either viscous fingering or of unusually large dispersion. To eliminate the possibility of unfavorable mobility ratios caused by oil/water/surfactant interaction, we conducted several runs in which an injected hydrocarbon displaced another hydrocarbon, initially at residual saturation. In other experiments, water (the wetting phase) at irreducible saturation was displaced by a distinguishable injected aqueous phase.

Injected hydrocarbon appeared in the produced fluids immediately after oil breakthrough, yielding behavior similar to the micellar-slug experiments. Even with a favorable viscosity ratio of less than 0.01, the apparent dispersion was huge. However, mixing zones in the wetting-phase displacements were quite normal and similar to those observed for single-phase flow

Nonwetting-phase fronts (injected hydrocarbon displacing resident hydrocarbon) are smeared much more than wetting-phase fronts because the entrance of hydrocarbon into smaller water-filled pore throats is delayed until the capillary entrance pressure is overcome by differences in the flowing oil and water pressure gradients. Oil might not be displaced from the smaller pores until long after oil breakthrough.

Nonwetting-phase dispersion, which occurs in many EOR processes, can be expected to be one or two orders of magnitude greater than dispersion measured in single-phase-flow experiments. Entrance of the wetting phase, however, is not delayed; hence, wetting-phase mixing zones are short.
Comparison of Magnetic Single-Shot Instruments With a Directional MWD System
Authors: Mltrou T. J. , Stone F. A. , McCarter M. L. , Bill Buss
Published: December 2007

A measurement-while-drilling (MWD) directional survey tool and a set of magnetic single-shot instruments used while drilling a particular, highly deviated well were removed from the field and put in a controlled laboratory environment. Tests were conducted to compare directional-survey azimuth readings obtained with the single-shots against azimuth readings taken with the MWD system. We found both measuring systems were generally accurate and repeatable; but we observed differences in azimuth readings that sometimes exceeded 1° under even ideal test conditions. The MWD tool was more repeatable and, on average, somewhat more accurate.
Characterizing Hydrocarbon Plus Fractions
Authors: Whitson Curtis H.
Published: December 2007

Methods are developed for characterizing the molar distribution (mole fraction/molecular weight relation) and physical properties of petroleum fractions such as heptanes-plus (C7+). These methods should enhance equation-of-state (EOS) predictions when experimental data are lacking.

The three-parameter gamma probability function is used to characterize the molar distribution, as well as to fit experimental weight and molar distributions and to generate synthetic distributions of heptanes-plus fractions.

Equations are provided for calculating physical properties such as critical pressure and temperature of single-carbon-number (SCN) groups. A simple three-parameter equation is also presented for calculating the Watson characterization factor from molecular weight and specific gravity.

Finally, a regrouping scheme is developed to reduce extended analyses to only a few multiple-carbon-number (MCN) groups. Two sets of mixing rules are considered, giving essentially the same results when used with the proposed regrouping procedure.
Beaver Creek Madison, Wyoming's Deepest Water Injection Project
Authors: Pollock C.B.
Published: December 2007

The Madison limestone at 11,000 ft is the deepest of six productive horizons in the Beaver Creek field. Although many Madison reservoirs in the Rocky Mountain region have a very active natural water drive, early performance at Beaver Creek indicated that the natural water drive would be inadequate to maintain producing rates and that costly artificial-lift equipment would be required. Therefore, a supplemental water injection program was chosen as the most logical plan of depletion to maintain reservoir pressure and reduce lifting expense. The performance of the pool and the analysis which dictated the water injection program are discussed.

Introduction

The Beaver Creek field, located in Fremont County, Wyo., approximately 14 miles southeast of Riverton, was discovered in 1938 when Unit Well 1 found gas and condensate in the Cretaceous Frontier, Muddy and Lakota horizons at 8,000 ft. Subsequent development, after a gas market was obtained in 1944, resulted in the discovery of oil in the Cretaceous Mesaverde (3,900 ft) in 1951, the Pennsylvanian Tensleep (10,600 ft) in 1949 and the Mississippian Madison (11,200 ft) in 1953.

The Beaver Creek structure is a dome with a plunging nose to the north. The structure dips quite sharply to the east and south, with gentler dips to the north and west. Some faulting is present along the east flank and has had a major influence upon the accumulation of oil in the deeper Tensleep and Madison reservoirs. Fig. 1 shows the structural features of the field. The Madison reservoir, discovered in Dec., 1953, is at an average depth of 11,200 ft and has a proved productive area of about 1,260 acres. The reservoir is approximately 2-miles long and 1 1/2-miles wide and has a maximum oil-productive closure of 790 ft. There are presently 13 Madison wells drilled on approximately 80-acre spacing. Three of the wells are flowing and the remainder are pumping. The current producing rate is 4,860 BOPD and 300 BWPD. Cumulative production to Jan. 1, 1959 was 5,998,000 bbl of oil And 582,000 bbl of water.
The Interpretation of Screen-Factor Measurements
Authors: Lim Timothy , Uhl Jonathan T. , Prud'homme Robert K.
Published: December 2007

Screen-factor (SF) measurements are widely used in the petroleum industry to characterize polymer solutions. The measurements are easy to perform and provide information that is different from solution-viscosity measurements. However, there has been no quantitative explanation of what solution property is being measured by SF. We show that SF measures the elongational viscosity of a polymer solution. Experiments on a modified commercial screen viscometer show the relationship between SF measurements and elongational-flow measurements performed by Durst and coworkers. Durst has shown that the elongational flow field in a packed bed of spheres triggers a transition in the conformation of a flexible polymer molecule, such as polyacrylamide, from a coiled to a stretched state. This transition in conformation is accompanied by a jump in the resistance to flow by an order of magnitude. We show that conventional screen viscometers operate in the regime where the molecules are in the highly stretched state. On the basis of Durst's work, it is calculated that the SF measurement is sensitive to high-molecular-weight tails in the polymer molecular-weight distribution.
A Generalized Method for Predicting Gas/Oil Miscibility
Authors: Emanuel A. S. , Behrens R. A. , McMillen T. J.
Published: December 2007

An equilibrium-cell simulator provides reliable estimates of gas/oil minimum miscibility pressure (MMP) with a correlation of residual oil against capillary number. The basic flash calculations of the equilibrium cell are supplemented by a number of PVT and fluid-flow modeling techniques that provide a reasonable simulation of slim-tube performance. A PVT stability calculation has been incorporated as an option for systems where flash convergence is difficult. Interfacial tension (IFT) may be calculated either by the method of parachors or by a method based on critical-point scaling theory. An experimental correlation is presented for residual oil reduction with capillary number. The relative permeabilities are varied between the fully immiscible and fully miscible bounds as a function of capillary number.

The slim-tube recovery results have been calibrated against 110 experimental runs for 21 different oils. Recovery by hydrocarbon gas is generally predicted within 10%; recovery by N2 and CO2 is generally predicted to within 15%. The program logic is designed to be most accurate in the miscible region. The simulator will typically give an a priori estimate of MMP within 10% and show the relative effects of changes in injection gas composition and system pressure. The simulator may be calibrated to an experimental recovery point. An oil-specific calibration gives much higher accuracy than the predictions that use the default parameters.
The Technique of Minimum Rate of Flow Tests and the Study of Production Performance
Authors: Cokinos Geneos Pete
Published: December 2007

An exhaustive examination of literature has revealed a lack of any subject material on the technique of minimum rate of flow tests. The minimum rate of flow of a well is that rate of flow of oil or gas production preceding the rate at which the well begins to give definite signs of the flowing pressure establishing a downward trend to zero.

A minimum rate of flow test becomes necessary when a company operating a well seeks evidence that waste will occur to the producing reservoir if the subject well is not given allowable relief. Data frown such a test are presented to the Texas Railroad Commission Oil and Gas Div. for study and engineering recommendations.

In conducting this type test, the well in question undergoes a series of 24-hour tests which subject it to a decreasing rate of flow, through choke changes, until the minimum rate is established.

Twenty-four hour test data, in the form of recorded wellhead flowing pressures, oil production, salt water production, gas production and any other pertinent well information gathered from completion data relative to the producing characteristics of the well, is required. Results and test data are reported in tabular and graphic form with recorded pressure charts. Method of completion, electric log and core analysis, method of operation and other information relative to the producing life of the well is obtained.

Prudency of operation, as demonstrated by manipulation of chokes, will give further evidence. Examples of different minimum rates of flow tests conducted by the author, with results, will be outlined along with concluding information based on results and experiences of well testing.

Introduction

Since the late 1930's, the Texas Railroad Commission has been staunch in insisting that engineering data be presented as evidence in support of any request before Commission hearings. The acceptance of engineering improvements in drilling and production coincides with the Commission's desire to have engineering data from actual field tests presented as exhibits.
Concentric Completions of Oil and Gas Wells
Authors: Harper G.M.
Published: December 2007

Introduction

This paper discusses the use of 1 ¼-in. tubing placed concentrically inside the normal flow string in both oil and gas wells. The use of this extra string provides an annular space which can be employed to perform a number of functions.

The Union Oil Co. of California is probably one of the few companies still completing dual oil and gas wells concentrically, where feasible, rather than using parallel strings of tubing; i.e., Union uses the annulus between tubing and casing to flow the upper zones and the tubing annulus to flow the lower zones.

In view of the economics, further consideration should be given to concentrically completing dual oil wells before deciding to incur the extra expense of larger hole, larger casing sizes and two strings of tubing required for parallel duals. Particularly this is true where past history of the two zones is available.

Application to Oil Wells

Numerous oil wells have been completed in this manner and have produced over a million bbl of oil on the lower zone and three-quarters of a million bbl on the upper zone over the past 17 years. In view of this history, it is hard to justify to management the extra cost of parallel string, dual completions. Of course, it is fully realized that concentric duals have a number of disadvantages. They are impractical where the wells are completed in open water and are subject to marine damage or where there is a need for artificial lifting of both zones. Also, operational problems arise in controlling items such as paraffin accumulation and sand production. However, with the development of new tools, techniques and materials over the past few years, some of the problems which made this type of dual completion so unattractive can now be alleviated.

In one of the old fields, numerous wells were completed dually with 2-in. tubing inside of 5 ½-in. casing, producing from depths of approximately 6,000 ft. Natural water encroachment and declining reservoir pressure began to affect the upper zones in these wells, resulting in a need for artificial lift and higher gross rates in order to maintain the oil allowables. Experience on other wells in this zone also showed that at gross rates above 300 B/D, sand production became a problem. The lower-zone performance history showed that bottom-hole pressure was not declining because of a strong water drive and would not require any artificial lift for a number of years.
A Dedicated Production Support Vessel For Offshore Operations
Authors: Chong Yong Yin , Ibrahim Mohammad Isa bin
Published: December 2007

A dedicated support vessel for production providing facilities for stimulation, nitrogen service, endless coiled tubing and production testing, was used successfully by Brunei Shell to service offshore wells.

Four years of experience showed the tremendous flexibility and versatility of the vessel in an area where wells and fields are scattered. The vessel has shown to be a profitable resource for repairing problem wells to restore production. Indirectly, much rig time has been saved as a result.

Introduction

Brunei Shell has six oil/gas producing fields offshore. Offshore production started in the mid sixties and has been the main activity of production started in the mid sixties and has been the main activity of Brunei Shell's production. The development of offshore fields is very active and has grown into a complex network of structures and pipelines linking the wells to the oil terminal and the Brunei Liquified Natural Gas plant. The Headquarters of Brunei Shell are located in Seria, which is plant. The Headquarters of Brunei Shell are located in Seria, which is also the location of the onshore oil field (Figure 1).

The reservoirs development are all sandstone layers in complexly faulted anticlines. Offshore production at the end of 1982 was about 144,000 b/d of oil and 900 MMscf of gas.

At present, there are 5 tenders, 1 jack-up and 1 semi-sub operating offshore Brunei waters. On average, about 40 new wells per year were completed offshore for the past 3 years and about 15 wells were worked over per year. A production support vessel complements the offshore drilling per year. A production support vessel complements the offshore drilling resources.

TECHNICAL ENVIRONMENT

Brunei Shell has about 500 connected wells offshore scattered in six fields at present. The majority of the wells are drilled from 12-slot platforms. There are a number of satellite wells which are supported by small jackets.

The wells are usually multi-zone completions with dual production tubing (Figure 2). All the oil bearing reservoirs are sandstone formation ranging in depth from 1000 feet to 12000 feet. Gravelpacks are extensively used for sand exclusion. Active wells have specific offtake requirements. In many a case, problems develop (impairment, sand, mechanical etc.) and in order to meet drainage objective, problem wells will have to be serviced.

p. 8–110 p. 8–110
Low-Viscosity Base Fluid for Low-Toxicity Oil-Mud Systems
Authors: Boyd Phil A. , Whitfill Donald L. , Carter T. S. , Allamon J. P.
Published: December 2007

The use of a new low-toxicity oil for drilling-fluid systems is presented. The low-viscosity, low-aromatic oil has undergone extensive laboratory and toxicity testing with favorable results. In addition, a number of field tests have been conducted to evaluate the use of this oil in oil-based muds, water-based muds, and spotting fluids. These tests were very successful and showed excellent performance of the oil for each application. Evidences of improved penetration rates (ROP's), reduced mud-treatment costs, and better borehole stability are all characteristic of this low-viscosity, low-aromatic oil in low-toxicity, oil-based mud systems.
Practical Use of Recent Research in Multiphase Vertical and Horizontal Flow
Authors: Brill J.P. , Doerr T.D. , Hagedorn A.R. , Brown K.E.
Published: December 2007

A recent correlation for multiphase vertical flow by Hagedorn and Brown1has been used to examine the effect of numerous variables such as pipe size, gas-liquid ratio, liquid flow rate, liquid viscosity, liquid surface tension, oil API gravity, water cut, etc., on flowing pressure gradients.

Most previous correlations were derived by using a form of the generalenergy equation which assumed negligible changes in kinetic energy. Undercertain flow conditions this can lead to serious errors in predicting pressuretraverses. Examples of traverses calculated both with and without the kineticenergy term are included here.

The Chew and Connally correlation for calculating change, in viscositywith changing pressure and temperature has been extended so that the effect ofa changing viscosity with depth on pressure gradients can also bepredicted.

Examples illustrating the effect of tubing size show the importance ofthis correlation in determining pipe sizes for initial well completions. Limitations on production rates in small pipe sizes from excessive frictionlosses can be predicted with greater accuracy.

The combined use of a vertical-flow correlation with a horizontal-flowcorrelation provides a method for determining the maximum flow rate possiblefrom both flowing and gas-lift wells.

Examples are included to illustrate application of the combined use ofvertical and horizontal-flow correlations in optimizing production rates andminimizing excessive costs from over injection of gas in gas-liftwells.

INTRODUCTION

The problems of multiphase vertical and horizontal flow are immediatelyencountered in any producing well. Fig. 11 shows three stages ofproduction: flow in porous medium, vertical flow and horizontal flow. All threestages affect the production rate from a well.

If we are confronted with a particular well and consider only the variablesinvolved in the vertical and horizontal stages of Fig. 1, we should be capableof calculating the flowing bottom-hole pressure necessary to produce aparticular flow rate. A change in any of the variables results in a newsolution to the problem.

Recent approaches in developing horizontal and vertical-flow correlationshave improved to the extent that the solution can now be obtained with moreconfidence than previously.
A Note on the Application of the Theory of Coherence to Surfactant Flooding
Authors: Saneie S. , Yortsos Y. C.
Published: December 2007

Previous studies have shown that in the absence of dispersion, a surfactant flooding process is amenable to a simplified solution by the method of coherence. The development of the solution requires the construction of composition paths that are obtained numerically by the integration of ordinary differential equations. In this paper, we show that in the particular case when all tie lines in the triangular phase diagram originate from a single point on the w,o axis, the construction of the composition paths can be considerably facilitated, because the tie lines obey the condition λ1 = constant (contact discontinuity). It is shown that this exceptional case corresponds to a phase equilibrium relationship of the form (CV32CV11- CV12CV31)/CV31-CV32)=K. This relationship was originally proposed to describe the thermodynamics of concentrated solutions. The connection of this relationship to a generalized Hand-plot model is also discussed.
Design of Chemically Balanced Polymer Drilling Fluid Leads to a Reduction in Clay Destabilization
Authors: Griffin J. M. , Hayatdavoudi A. , Ghalambor A.
Published: December 2007

Many water-sensitive shale formations destabilize when contacted by a drilling fluid. This can lead to hole sloughing, stuck pipe, and balled downhole assemblies. If the chemical activity and chemical compounds of the shale are analyzed, then a drilling fluid can be formulated with at least an equivalent chemical activity so that fewer shale cations are removed from the shale by the drilling fluid. Activity of the designed fluid was calculated on the basis of the Debeye-Huckel activity theory. Comparison of the formulated fluid with oil-based muds was conducted with the roller oven and one-dimensional (ID) swelling tests. The formulated fluid produced a combination of electrolytes that yielded more favorable results than did additions of potassium chloride alone.

The procedure for designing a fluid to inhibit swelling for a particular shale is the central focus of this research. The laboratory investigation for developing a stabilizing polymer electrolyte is applied to the Wasatch shale. The technique requires formation samples beforehand and, therefore, has application for both developmental drilling and completion-fluid design.
An Investigation Into Stratified Co- and Countercurrent Two-Phase Flows
Authors: Johnston A. J.
Published: December 2007

This paper investigates theoretically and experimentally certain stratified co- and countercurrent two-phase flows in circular pipes that have not been studied adequately. The theoretical analysis produced semiempirical relationships based on the momentum-balance concept. These relationships were then experimentally evaluated with two fluid systems of significantly different density ratios. It is suggested that the equations that correlated these results can be accepted for general use. An example is presented for a certain natural-gas/condensate application.
Accuracy of JBN Estimates of Relative Permeability: Part 2—Algorithms
Authors: Tao T. M. , Watson A. T.
Published: December 2007

We develop algorithms that can be used for computer implementation of the Johnson, Bossier, and Naumann (JBN) method for estimating relative permeabilities from displacement experiments. The developed algorithms differ in the method used to calculate derivatives of measured data. The Monte Carlo error analysis developed in Part 1 of this paper (Pages 209–14) is used to evaluate the performance of the computer algorithms.
Evaluation of Waterflood Prospects
Authors: Callaway F.H.
Published: December 2007

Introduction

The historical background of water flooding is well known to most engineers associated with the petroleum industry. The earliest water floods were accidental in nature resulting from improperly plugged wells or casing leaks. The obvious benefits of these accidental floods soon encouraged the operators to inject water intentionally. The early waterflooding techniques were thoroughly developed and standardized long before even the most elementary concepts of reservoir mechanics were understood. Under these circumstances, the evaluation of waterflood prospects was strictly a matter of analogy and application of "rules of thumb." If a successful water flood had been conducted in a certain sand in a certain area, operators would presume that a nearby field producing from the same zone could be flooded with similar results.

Use of analogy and rules of thumb had obvious limitations, as is apparent from the rather frequent unsuccessful waterflood attempts. Reliance upon such methods is still surprisingly heavy even today. Modern reservoir engineering enables us to determine the range of reservoir conditions which will result in favorable response to waterflood efforts, and also to delineate the range of conditions under which water flooding will be of doubtful success. By means of relating the various reservoir parameters involved to the results obtained from water floods, a more reliable set of experience factors can be obtained and the uncertainties involved in water flooding greatly reduced.

As is illustrated herein, there are a number of reservoir factors which have a profound influence upon the success of a waterflood project and unfavorable values for any one or two of these factors can result in complete failure of a flood, even though other factors may be quite favorable. It is hoped that this discussion of the effect of various reservoir parameters upon waterflood results will, if nothing else, point out the severe limitations of the rules of thumb by which so many decisions to water flood have been made.

In order to illustrate the manner in which the various reservoir factors operate and their relative importance, it has been necessary to assume a certain set of hypothetical reservoir conditions and investigate the effect of varying one or two of the factors independently. It must be emphasized that the values for waterflood recovery efficiency derived herein are of no real significance except for those specific conditions assumed and must not be used directly for the purpose of evaluating any given waterflood prospect. The term "waterflood recovery" as used herein refers to the increase in recovery over and above that which would be obtained by producing a field to its economic limit by primary means. In the case of a flood initiated before all of the primary oil has been produced, the recovery from the date of inception of a flood is the sum of the remaining primary recovery plus the "waterflood recovery" as defined herein.
A Test for Detecting Rock Property Nonuniformities in Core Samples
Authors: Watson A. T. , Kerig P. D. , Otter R. W.
Published: December 2007

Homogeneous core samples are needed for EOR experiments. We have devised a simple test for detecting the presence of nonuniformities in cores. The test consists of measuring the pressure drop across the core during a two-phase immiscible displacement experiment. We show that for a constant injection rate, the pressure drop will be linear with time provided that the core is homogeneous. In situations for which the initial section of the core is homogeneous, but the properties are not uniform in a latter section of the core, the location of the position where the rock properties first change may be approximately determined. The effect of heterogeneities on the pressure-drop profile is demonstrated with analytical solutions and laboratory experiments.
Heavy-Wall Production Tubing Design for Special-Alloy Steels
Authors: Payne M. L. , Hurst D. M.
Published: December 2007

Critical wells require a comprehensive design philosophy for downhole tubulars. This paper describes novel design techniques used on four key tubing-design tasks on a 23,000-ft [7010-m], high-pressure, offshore gas well: material selection, tubing sizing, threaded-connector qualification, and field installation planning. The in-depth engineering approach combined stringent material and threaded-connector qualifications with new tubing-sizing methods and thorough installation planning. Standard tubing-sizing methods were unacceptable because of conservatism about erosional velocity and stress analysis inaccuracy. Proper stress analysis of the alloy required consideration of triaxial stress states, anisotropy of mechanical properties, and temperature weakening of yield stress.
Kinetic Study of the Decomposition of Surfactants for EOR
Authors: Angstedt H. P. , Tsao H.
Published: December 2007

The effect of temperature, pH, surfactant purity, and air on the decomposition rate of two classes of surfactants typically used in steam EOR processes has been investigated. With synthetic alkylaryl sulfonates, isolation and characterization of the hydrocarbon reaction products established that the principal reaction is desulfonation of the surfactant. The kinetics of the decomposition of certain alkylaryl sulfonates under carefully controlled pH and temperature conditions are discussed and compared with the behavior observed for α-olefin sulfonates (AOS's) under the same conditions. The synthesis and decomposition of key pure isomeric alkylaromatic sulfonates of known structure led to a mechanistic description of the decomposition reaction. An explanation for the differing stability of alkylaromatic sulfonates and AOS's at high temperatures and at differing pH is suggested.
An Evaluation of Lignosulfonate as a Sacrificial Adsorbate in Surfactant Flooding
Authors: Hong S. A. , Bae J. H. , Lewis G. R.
Published: December 2007

A study was conducted to investigate the feasibility of using lignosulfonate as a sacrificial agent in the surfactant flooding process. An analytical technique based on high-performance liquid chromatography (HPLC) analysis was used to determine the concentration of lignosulfonate and petroleum sulfonate. Lignosulfonate and petroleum sulfonate adsorption isotherms were established and used to assess the sacrificial effect of lignosulfonate. A simple model to describe the ion exchange in the presence of lignosulfonate was developed. This model includes the association of cations with lignosulfonate.

The main results of this study are as follows. First, surfactant loss can be reduced significantly (>50% reduction) by pretreatment with a lignosulfonate preflush. However, no significant reduction is obtained when lignosulfonate is incorporated with the surfactant slug. Second, more cations are exchanged from the rock in the presence of lignosulfonate. This enhanced cation exchange is a result of the association of divalent cations with lignosulfonate. Third, lignosulfonate causes dissolution of soluble minerals to a much greater extent than brine or petroleum sulfonate, producing undesirable bivalent cations. Finally, the brine tolerance and optimal salinity of petroleum sulfonate are not greatly affected by lignosulfonate. From these laboratory results, we conclude that lignosulfonate has potential as a sacrificial adsorbate for surfactant flooding.
Interference Between Constant-Rate and Constant-Pressure Reservoirs Sharing a Common Aquifer
Authors: Sageev Abraham , Horne Roland N.
Published: December 2007

A practical pressure transient analysis method is presented for interpreting interference between two oil fields or an oil field and a gas field sharing a common aquifer. One oil field is approximated as a constant-rate line source. The other interfering field is represented by a finite-radius circular source producing at constant rate or constant pressure.

A rigorous application of the superposition principle is discussed, making use of a new model where a constant-rate line source produces exterior to a circular boundary. Both constant pressure and impermeable internal boundaries are considered.

Dimensionless pressure drop curves for both boundary conditions are presented. For the case of a line source producing near a constant-pressure internal boundary, dimensionless curves for the instantaneous rate and the cumulative injection from this internal boundary are given. These curves may be used to forecast the actual injection/production rate and the cumulative injection/production at the interfering reservoir as a function of time.
Computerized Analysis of Thermal Recovery Well Test Data
Authors: Barua Jawahar , Horne Roland N.
Published: December 2007

The thermal recovery of oil requires large investments of time and money. Well tests are a relatively easy way to monitor this expensive process until breakthrough occurs at producers, and they can be used to find the volume (but not the shape) of the swept zone.

This paper discusses the application of automated type-curve match to such well tests. A comparison with the best of present methods, i.e., the pseudosteady-state method, shows that automated type-curve match proves to be better in the determination of swept zone radius when mobility ratio is not high or when multiple flow rates have occurred. The application of automated type-curve match to two field examples is demonstrated.
Comparison of K-Value Calculation Methods in Compositional Steamflood Simulation
Authors: Hong K. C. , Hsueh Liming
Published: December 2007

The speed and accuracy of compositional steamflood simulation were compared for four K-value calculation methods: the Antoine equation, table look-up, the Peng-Robinson equation of state (PR-EOS), and the Hong-Makhlouf modification of Wilson's equation. These methods were used with a compositional steamflood simulator to model light-oil steamfloods in three- and one-dimensional (3D and 1D) reservoir models. The results indicate that the table look-up and the Hong-Makhlouf modification of Wilson's equation are the most preferred methods to use in terms of both speed and accuracy of computation. While the PR-EOS method is the most accurate, it fails to converge for certain problems and takes twice as much computing time to do the same simulation as the other methods. The Antoine equation method is not accurate for high-volatility oils and hence should not be used for those oils.

This paper describes how the four methods are used in compositional steamflood simulation and discusses the advantages and disadvantages of each method.
Solubility of Silica in Alkaline Solutions: Implications for Alkaline Flooding
Authors: Southwick J. G.
Published: December 2007

The expected loss of useful alkalinity caused by the slow dissolution of silica from pure quartz sand is shown for some typical alkaline flooding solutions (about 1 % NaOH or 1.25% sodium orthosilicate) to be only about 10 to 20%. This conclusion is based on the observation that alkaline solutions equilibrate with quartz and on the methodology proposed here for determining the useful alkalinity of a solution. Furthermore, the dissolution of quartz in alkaline flooding can be eliminated by the use of solutions saturated in silica with respect to quartz. Such formulations may be useful in controlling the erosion of the wellbore and gravel pack.
Pressure-Transient Response of an Infinite-Conductivity Vertical Fracture in a Reservoir with Double-Porosity Behavior
Authors: Houzé Oliver P. , Horne Roland N. , Ramey Henry J.
Published: December 2007

This paper describes the behavior of a naturally fractured reservoir when a well is producing through a vertical fracture with uniform flux or infinite conductivity. The reservoir model is a double-porosity medium, and both pseudo-steady-state and transient-interporosity-flow models are studied. The derivative vs. time for each solution is shown, and an analysis method for matching field data to such a model is presented.

This study combines a reservoir and a well model, both of which have been extensively studied separately. Included are a quick review of the main characteristics of these models and the methods used to solve the problems. At the end of the study, a general method is suggested to extend models with constant boundary conditions—e.g., homogeneous and double-porosity cases.
Thermal Visbreaking of Heavy Oil During Steam Recovery Processes
Authors: Shu W. R. , Hartman K. J.
Published: December 2007

This paper describes a simulation study on the effect of visbreaking on heavy oil recovery during steam injection processes. The kinetic rate constant for in-situ visbreaking was derived from in-house kinetic data and then used in conjunction with a thermal compositional simulator to assess the effect of visbreaking on recovery through a series of numerical experiments. Various steam injection strategies were tested and the effect of visbreaking studied. In some cases, physical heating, not thermal visbreaking, was the dominant recovery mechanism. In other cases, visbreaking had a large effect on recovery. The difference was primarily a result of the placement of the visbroken oil with respect to the direction of flow. In cases where the visbroken oil zone was perpendicular to the flow, it formed a mobility transition zone that improved sweep, thus enhancing oil recovery.
A Field Experiment of Improved Steamdrive With In-Situ Foaming
Authors: Brigham W. E. , Marcou J. A. , Sanyal S. K. , Malito O. P. , Castanier L. M.
Published: December 2007

This paper reports on the design and execution of a field experiment on recovery of heavy oils by steamdrive enhanced by additives. The goal of this project was to study the effect of injection of a commercial surfactant (Suntech IV™) and N2 on the behavior of a conventional steamdrive. Because the laboratory studies leading to the design and implementation of this field experiment have been referenced many times, we emphasize here the field data obtained in reservoir definition, monitoring of the experiment's progress, and production evaluation in a heavy-oil reservoir. Several standard and experimental analytical methods were applied, and their validity in the Kern River field test is discussed.

Three slugs of surfactant and N2 were injected at different rates. Analysis of the results shows a considerable improvement in oil recovery by steamdrive caused by the addition of surfactant and N2 to the steam. The changes in production behavior of the reservoir caused by the additives are analyzed and discussed. Although the economics of this project is difficult to determine at this point, it looks promising.