bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.
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

AbstractThis 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

Abstract
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

Abstract
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

Summary
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

Abstract
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

Abstract
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

Summary
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

Summary
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

Abstract
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.