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By S B. Martin, M P. Simpson, J L. Mauk

The Martha deposit in Waihi, New Zealand, is a giant adularia-sericite epithermal gold-silver deposit that formed 6.0 to 6.1 Ma, and has produced over 6.4 Moz gold and 39.9 Moz. Fluid inclusion analyses were undertaken on a limited number of vein samples from Martha. The results from this eight week student project are preliminary but agree with previous studies. There is little variation between primary and secondary inclusions and between different vein types, except that homogenisation temperatures of the inclusions in sphalerite grains are on average 20¦ to 30¦C higher than the average quartz vein values. Overall the temperatures of homogenisation ranged from 182¦ to 258¦C and final ice melting temperatures ranged from 0.0¦ to 2.8¦C. Unusual black inclusions were also found associated only with the ginguro bands. Some of these appear to be solid sulphide inclusions but others are not so clear.

Jan 1, 2007

By M. Feely, W. G. O'Keefe, C. O'Reilly, M. P. Holdstock

A petrographic and microthermometric study of fluid inclusions in the Kentstown Granite, crosscutting quartz (VI) and calcite+quartz (V 2) veins in the granite and calcite+quartz (V 2) veins in the overlying sediments was performed on samples taken from the borehole. Comparisons of the type 1, type 2 and type 3 fluid inclusion populations recorded in the present study with those from other Irish Caledonian granites strongly suggest a similar fluid evolutionary history. Furthermore, the low-temperature CaC12-rich brines (type 5) of this study, which must be syn- to post-Lower Carboniferous in age, have correlatives both in Irish Caledonian granites and in the Lower Carboniferous base-metal deposits of the Irish midlands

Jun 19, 1905

By David L. Rife

Fluid inclusions have been studied since the mid-1800s. In 1858, the famous English geologist H. C. Sorby, stated that ". . . there is no necessary connection between the size of an object and the value of a fact, and that, though the objects [inclusions] ... are minute, the conclusions to be derived from the facts are great."' This statement philosophically emphasizes why fluid inclusions should be studied. Fluid inclusions supply the economic geologist with "hard" data on the chemical environment and mechanisms of transport for ore fluids. Such studies enable geologists to understand more about their complex nature. The information that can be obtained from fluid inclusions is as follows: 1) Fluid inclusion "filling temperatures" measured with the microscope heating stage, reflect the hotness of an ore fluid at the time of its entrapment and are one of the most accurate methods of geologic thermometry. 2) Ore fluid densities indicate the extent to which ground water becomes mixed with ore fluids. Density is determined from the composition of inclusions, the ratios of gas to liquid (at room temperature), and from

Jan 1, 1973

Fluid inclusions and sulfur isotopic compositions were studied in a possible extension of the Toyoha polymetallic vein deposit. The objective of this work was to gain a better understanding of the ore depositional conditions, sources of ore constituents, and distribution of mineralizing fluid in the region. Fluid inclusions in sphalerite and quartz show that most homogenization temperatures range between 190¦ and 290¦C. Most salinities range from 0.0 to 3.4 wt per cent NaCl equiv. Sulfur isotopic compositions of ore minerals (pyrite, sphalerite and galena), determined by a conventional technique, range between 1.3 and 7.7 per mil. The mineralizing fluids were characterized by relatively low and various temperatures and low to moderate salinities compared to those at the southeast region of the main ore bodies (Izumo and Shinano veins) where rare elements such as tin, tungsten and indium occurred. Obtained temperatures and salinities were attributed to the mixing of hydrothermal fluids with groundwater. Sulfur isotopic data suggest sulfide sulfur was of magmatic origin. Isotopic temperatures, estimated from the isotopic fractionation factor between sphalerite and coexisting galena, are between 195¦ and 322¦C. The temperatures are only consistent with fluid inclusion homogenization temperatures in sphalerite or coexisting quartz when sphalerite was a honey-yellow coarse crystal lacking conspicuous colored growth bands. This suggests the detailed classification of mineral pairs growth textures will be necessary for precise in situ measurements to obtain reasonable eothermometric results.

Jan 1, 2002

By R. A. Morse, C. R. Holmgren

The production of oil by water flooding can be substantially increased by the maintenance of free gas saturation in the reservoir during the flooding operation. This effect is accomplished by the alteration of oil relative permeability characteristics and the occupation by gas of pore space that would otherwise be filled with residual oil. The amount of reduction In residual oil can be calculated from appropriate water-oil relative permeability characteristics. This paper presents experimental data in support of the foregoing conclusions and an example of the calculations. The microscopic pore saturation concepts of the mechanism are discussed. A method of practical application to field floods is presented together with discussion of certain limitations. INTRODUCTION The presence of free gas has been reported by a number of investigators to significantly affect the oil recovery which can be obtained from sandstone flow systems by water flooding.1,2,3,4,5 The effect of gas, noted in every instance, has been to cause lower residual oil saturations than could be obtained by water flooding the same systems in the absence of free gas. The degree of improvement in recovery has been observed to vary widely, depending on the systems used and the conditions of the tests. The increased oil recovery obtained because of the presence of gas during a water flood has been variously attributed to changes in physical characteristics of the oil, selective plugging action of the gas, inclusion of oil mist in the free gas phase, and the additional sweeping or driving action of the free gas. All but the first of these suggestions imply changes in the displacement mechanism. The change in viscosity and inter-facial tension of the oil phase, within the pressure range used for all the experimental work, is certainly not sufficient to account for the differences in residual oil saturation noted dess there is a drastic change in the displacement process. One other effect which logically seems capable of causing differences in residual oil saturation of the magnitude noted in the experimental work is that of simple replacement. In a water-wet system containing oil, water, and gas, it is to be expected that the gas will exist inside the oil. This is the position of minimum free surface energy, since the gas-oil interfacial tension will be less than the gas-water interfacial tension. There is no apparent reason to expect that the existence of free gas within the oil phase should alter the saturation at which the non-wetting phase (now oil and gas) should become discontinuous and hence trapped so as to be unrecoverable by direct displacement by water. If this is the situation, then trapping of a certain percentage of gas saturation during water flood should result, at infinite water-oil ratio, in a like reduction of oil saturation below that attainable by flooding in the absence of free gas. It is visualized that the gas will exist as bubbles inside the discontinuous residual oil as illustrated in Fig. 1, with the size of the oil bubbles being substantially unchanged due to the presence of the gas. As a practical matter, it can be anticipated that the presence of a free gas saturation inside the oil phase will reduce the relative permeability to oil which will exist at any particular water saturation. This reduction will be caused by two factors — -the addition of the gas-oil interface, and the reduction of area available for oil flow in the pores containing gas. This reduction in oil permeability at any particular water saturation will result in water breakthrough at a lower water satu-

Jan 1, 1951

By R. A. Morse, C. R. Holmgren

The production of oil by water flooding can be substantially increased by the maintenance of free gas saturation in the reservoir during the flooding operation. This effect is accomplished by the alteration of oil relative permeability characteristics and the occupation by gas of pore space that would otherwise be filled with residual oil. The amount of reduction In residual oil can be calculated from appropriate water-oil relative permeability characteristics. This paper presents experimental data in support of the foregoing conclusions and an example of the calculations. The microscopic pore saturation concepts of the mechanism are discussed. A method of practical application to field floods is presented together with discussion of certain limitations. INTRODUCTION The presence of free gas has been reported by a number of investigators to significantly affect the oil recovery which can be obtained from sandstone flow systems by water flooding.1,2,3,4,5 The effect of gas, noted in every instance, has been to cause lower residual oil saturations than could be obtained by water flooding the same systems in the absence of free gas. The degree of improvement in recovery has been observed to vary widely, depending on the systems used and the conditions of the tests. The increased oil recovery obtained because of the presence of gas during a water flood has been variously attributed to changes in physical characteristics of the oil, selective plugging action of the gas, inclusion of oil mist in the free gas phase, and the additional sweeping or driving action of the free gas. All but the first of these suggestions imply changes in the displacement mechanism. The change in viscosity and inter-facial tension of the oil phase, within the pressure range used for all the experimental work, is certainly not sufficient to account for the differences in residual oil saturation noted dess there is a drastic change in the displacement process. One other effect which logically seems capable of causing differences in residual oil saturation of the magnitude noted in the experimental work is that of simple replacement. In a water-wet system containing oil, water, and gas, it is to be expected that the gas will exist inside the oil. This is the position of minimum free surface energy, since the gas-oil interfacial tension will be less than the gas-water interfacial tension. There is no apparent reason to expect that the existence of free gas within the oil phase should alter the saturation at which the non-wetting phase (now oil and gas) should become discontinuous and hence trapped so as to be unrecoverable by direct displacement by water. If this is the situation, then trapping of a certain percentage of gas saturation during water flood should result, at infinite water-oil ratio, in a like reduction of oil saturation below that attainable by flooding in the absence of free gas. It is visualized that the gas will exist as bubbles inside the discontinuous residual oil as illustrated in Fig. 1, with the size of the oil bubbles being substantially unchanged due to the presence of the gas. As a practical matter, it can be anticipated that the presence of a free gas saturation inside the oil phase will reduce the relative permeability to oil which will exist at any particular water saturation. This reduction will be caused by two factors — -the addition of the gas-oil interface, and the reduction of area available for oil flow in the pores containing gas. This reduction in oil permeability at any particular water saturation will result in water breakthrough at a lower water satu-

Jan 1, 1951

By D. W. Akins

The case history of a combination gas and water flood instituted early in the life of a field is described. It was recognized from the beginning that recovery would be low, under normal production methods, from the several separate, thin beds of porous limestone which had such poor native permeability that the wells would not produce without acidizing. It is thought that the combination flood gives excellent recovery efficiencies for this type of reservoir. The chief function of the gas flood now is to maintain bottom hole pressure in that part of the reservoir which will not be affected by the water injection program until later. Present estimates are that ultimate recovery will be approximately double the recovery expected under the original solution gas drive mechanism. Wide (80-acre) spacing has enhanced the economics of the over-all field program by the elimination of more than $5,000,000 worth of unnecessary wells. INTRODUCTION The Haynesville Pettit Field was discovered in November, 1941, with the completion of T. L. James Co.'s Callie Akin No. 1, located in the W 1/2 of the NE 1/4 Section 27-23N-8W, Claiborne Parish, La., at an approximate depth of 5,300 ft. The center of the field is about two miles north and a mile west of the town of Haynesville, La. A total of 189 producing wells have been drilled on 14,500 acres. An additional nine dry holes were drilled. The Louisiana-Arkansas state line divides the field so that 34 wells are in Arkansas and 155 are in Louisiana. Governmental sections are divided equally to contain eight production units making 80-acre spacing where the sections are regular. Along the state line in Louisiana there is an irregular tier of sections, each of which contains approximately 456 acres. When divided equally into eight production units the spacing is 57 acres per well for these three and a fraction productive sections. All Haynesville Pettit wells are identified by their section number followed by their position in the section as determined by numbering the production units counterclockwise beginning in the upper right corner of the section. All of the producing wells in the field except two are unit-ized and operated by the Haynesville Operators Committee. These two wells are located in the extreme northern part of the field in Arkansas. Efforts to bring them into the Unit are being continued. The Pettit operators organized the Haynesville Operators Committee and the field became a unit operation May 1: 1944. GEOLOGY The Pettit is Lower Cretaceous in age and is defined as the uppermost porosity in the Sligo formation. The unitized area known as the Haynesville Pettit Field is composed of two separate zones of porosity approximately 40 ft apart and without connection between the two, except in wells. These zones are known as the Upper Pettit and the Lower Pettit. The Upper Pettit is separated into two sections throughout most of its area by a relatively thin but quite impervious shale streak. These are called the "A" and "B" sections of the Upper Pettit. All of these lenticular zones are composed of coquina limestone and a small percentage of normal oolites. The large

Jan 1, 1951

By D. W. Akins

The case history of a combination gas and water flood instituted early in the life of a field is described. It was recognized from the beginning that recovery would be low, under normal production methods, from the several separate, thin beds of porous limestone which had such poor native permeability that the wells would not produce without acidizing. It is thought that the combination flood gives excellent recovery efficiencies for this type of reservoir. The chief function of the gas flood now is to maintain bottom hole pressure in that part of the reservoir which will not be affected by the water injection program until later. Present estimates are that ultimate recovery will be approximately double the recovery expected under the original solution gas drive mechanism. Wide (80-acre) spacing has enhanced the economics of the over-all field program by the elimination of more than $5,000,000 worth of unnecessary wells. INTRODUCTION The Haynesville Pettit Field was discovered in November, 1941, with the completion of T. L. James Co.'s Callie Akin No. 1, located in the W 1/2 of the NE 1/4 Section 27-23N-8W, Claiborne Parish, La., at an approximate depth of 5,300 ft. The center of the field is about two miles north and a mile west of the town of Haynesville, La. A total of 189 producing wells have been drilled on 14,500 acres. An additional nine dry holes were drilled. The Louisiana-Arkansas state line divides the field so that 34 wells are in Arkansas and 155 are in Louisiana. Governmental sections are divided equally to contain eight production units making 80-acre spacing where the sections are regular. Along the state line in Louisiana there is an irregular tier of sections, each of which contains approximately 456 acres. When divided equally into eight production units the spacing is 57 acres per well for these three and a fraction productive sections. All Haynesville Pettit wells are identified by their section number followed by their position in the section as determined by numbering the production units counterclockwise beginning in the upper right corner of the section. All of the producing wells in the field except two are unit-ized and operated by the Haynesville Operators Committee. These two wells are located in the extreme northern part of the field in Arkansas. Efforts to bring them into the Unit are being continued. The Pettit operators organized the Haynesville Operators Committee and the field became a unit operation May 1: 1944. GEOLOGY The Pettit is Lower Cretaceous in age and is defined as the uppermost porosity in the Sligo formation. The unitized area known as the Haynesville Pettit Field is composed of two separate zones of porosity approximately 40 ft apart and without connection between the two, except in wells. These zones are known as the Upper Pettit and the Lower Pettit. The Upper Pettit is separated into two sections throughout most of its area by a relatively thin but quite impervious shale streak. These are called the "A" and "B" sections of the Upper Pettit. All of these lenticular zones are composed of coquina limestone and a small percentage of normal oolites. The large

Jan 1, 1951

By L. A. Rapoport, W. J. Leas

The original Burkley-Leverett theory has been extended and a more detailed formulation of the waterflood behavior in linear horizontal systems is presented. Particular consideration has been given to the evaluation of capillary pressure effects and differential equations permitting an explicit evaluation of these effects have been derived. On the basis of the developed theory it is recognized that the flooding behavior is dependent upon the length of the system and the rate of injection. At the same time it has been determined that systems of different lengths yield the same flooding behavior if the injection rates and or the fluid viscosities are properly adjrrsted or "scaled." It has also been found that the sensitivity of the flooding behavior with respect to rate and length decreases as any one of these {actors increases in value and that for sufficiently long systems and high rate.; of water injection the flooding behavior becomes independent of rate and length. or "stabilized." To such stabilized conditions the theory formulated by Buckley and Leverett is applicable. A number of laboratory flooding tests have been made and good agreement Iraq been found between theory and experimental observations. The experimental results are discussed and it is shown that under field conditions the flooding behavior is usually stabilized. As a result of these finding; a procedure is indicated for evaluating field performances either on the basis of tests performed with commonly available core samples or by means of calculations using relative permeability data INTRODUCTION In recent years the development of methods for evaluating oil recovery by waterflooding has been the object of considerable research. A theoretical analysis of the mechanisms involved in the displacement of immiscible fluids was originally established by Buckle!- and Leverettl and experimental investipatio~~s have been made by numerons workers." Many of the experimental results are in mutual agreement and bear out several significant features of the flooding mechanism as predicted by theory. Thus it lias been generally recognized that a flood corresponds to the movement of a steep saturation hank or "front" (primary phase), followed by additional gradual oil displacement (subordinate phase). It has also been found that for any porous medium the flooding behavior is largely dependent upon the oil-water viscosity ratio and that for increasing values of this ratio the relative importance of the primary displacement phase decreases while that of the subordinate phase becomes more pronounced. Although the studies to date have clarified certain aspects of the flooding process. they have given rise to observations of a somewhat contradictory nature that cannot he explained in terms of the original theory. These observations pertain mainly to the effect of injection rate or pressure gradient upon recovery. Some investigators report laboratory tests that indicate incresing oil recoverieq with increasing rates of water injectill, others find the flooding behavior to be independent of and other. mention lower oil recoveries with increased injection rates.3 The conflicting evidence indicated above creates considerable uncertainty with respect to laboratory testing procedures and the utilization of the resulting data for field evaluations. The principal purpose of this paper, then, is to resolve these Uncertainties by means of a comprehensive theoretical and experimental investigation of the flooding meanism. THEORETICAL DEVELOPMENT Derivation of Flooding Equations The mathematical description of transient flow phenomena is based upon the consideration of the various processes occurring during an infinitesimal time interval in an infinitesimal volume element and upon the correlation of these processes with those occurring in the adjacent elements. The volume elements are defined as being infinitesimal in comparison to the overall dimensions of the porous system, yet each sufficiently large so aS to encompass the full range of pore openings encountered throughout the system. If a porous system can arbitrarily be subdivided into an infinite number of volume elements all possessing the same distribution of pore openings and if this distribution is unformly continuous. the system may be said to be homogeneous. Such a homogeneous porous medium is considered in the present studivs. It is furthermore postulatecl that only oil and water are present in the pornu wediu. that they act a- totally incompressible and immiscible fluids. and that gravity effects are negligible. In n linear flow system of unit cross sertional area. as treated here. the infinitesimal volume element.; to he considered are cylindrical ".slices" of thickness dx. oriented perpendicularly to the direction of flow. The equations applicable to any such volume element. at my time. describe the movement. of oil and water across the element:

Jan 1, 1953

By N. Van Wingen, Norris Johnston

Laboratory flood pot testing of California sands has progressed to a considerable extent in the past 18 months. Flood evaluations have been carried out on over 200 large core samples. Many of these were heavy oil sands of high permeability and completely unconsolidated in nature. The oil frequently formed a bank, though some of the oil was recovered in the subordinate phase of the flood, by viscous drag. Flood pot recoveries as high as 1400 bbl/acre ft have been recorded. Reservoir analysis suggests a conformance factor of 0.4 to reduce laboratory recovery to probable field practice. Oils with viscosities up to 1800 cp have been successfully handled in flood pot evaluations. The shallow, loose sands are not well adapted to the application of- high pressures to offset the high viscosities. INTRODUCTION Secondary recovery may be said to have started 60 years ago when accidental floods occurred in the Bradford sand in Pennsylvania. About 1921 artificially conducted water drives came into extensive use and since that time the great Bradford field has been almost completely subjected to water flooding. During the last 30 years, most of the known medium and deeper production in California has been discovered and is being exploited by primary recovery methods supplemented in some instances by high pressure gas injection. The California area is just beginning to feel the need for secondary recovery in view of an unprecedented market demand and the rapidly rising cost of new pool discoveries. With the presently recognized desirability of secondary recovery in California, there must also be appreciated a number of serious differences between the water flooding problems here as compared to the territory east of the Rockies. California sands are generally thicker, and are frequently soft and argillaceous. The oils are often heavier and asphaltic. Much of the oil is below 15°API, occurs at shallow depth, is cool and free from appreciable dissolved gas, which results in relatively high reservoir oil viscosity. Secondary recovery is particularly beneficial where primary recovery has been poor and where no natural water drive exists. These conditions apply particularly to the heavy, shallow, clean production from soft, often argillaceous California sands so abundantly found at depths less than 1500 feet. Often, too, there is a totally insufficient supply of water of satisfactory quality to inject at a reasonable cost. Also, the crude oils are priced far below the premium Bradford crude. Although these and a number of minor problems beset the operator desirous of starting secondary recovery, great progress has been made in the past few years in finding how to adapt previous Mid-Continent and Eastern experience to water flooding in California. There are about nine projects for subsurface injection of water which can be said to classify as secondary recovery operations. Subsurface water disposal would so classify when the sand receiving the water is a nearby oil producer, as is often the case. When water is injected subsurface into a barren sand, the operation does not classify as secondary recovery. Several of the most active operators avail themselves extensively of preliminary engineering and laboratory work to guide their decisions, while others enter small scale flooding operations directly in the field. It is the laboratory work pertinent to several of the California secondary recovery projects that this paper discusses. PURPOSES OF LABORATORY FLOODING TESTS Experience in areas where water flood operations have been carried out has indicated that careful engineering planning is an important requisite for subsequent economically successful field operation. Floods that fail are more frequently those where operations were instigated without a prior engineering investigation to determine the effectiveness of the injection fluid as an oil displacing medium. Laboratory data are essential in the evaluation of an oil property for secondary recovery possibilities. Success or failure of secondary operations can under certain special circumstances be determined directly by cores and their subsequent routine analysis. This is particularly the case where flushing of the cores in the course of coring is negligible and where the results of the analysis can be compared with existing secondary recovery operations. Where these conditions cannot be' fulfilled, the application of core analysis is more limited. In such event, the results obtained by water flooding core samples in the laboratory have been found to be of prime importance. Cores may be flooded "raw" as taken from the well or in the event flushing and depletion of the cores in the process of drilling are major factors the fluid content may be artificially restored prior to the flooding. Laboratory studies should also be made to determine the suitability of the water selected for injection. Thus interaction between injected and formation water may cause precipitates to be formed which may plug the sand. Even more important, especially to California operations, is the possibility of the hydration of formation clays by the injection water. The aims of flood pot and associated tests are basically to determine the residual oil saturation after flood, the water-oil throughput ratio and to establish whether an oil bank is formed. Additional information which can be obtained from flood pot tests pertains to the pressure differential required to effect displacement, the relative permeability to oil in the oil bank and the relative permeability to water in the watered out region behind the bank.

Jan 1, 1953

By James R. I. Henagan, William O. Crego

The Mamou Field, located in Evangeline Parish, La., is an elongated anticlinal structure on the downthrown side of a major east-west fault with oil and gas production from the upper part of the Wilcox formation. Two main producing horizons occur at an approximate depth of 11,500 ft and have been designated the Morein sand and the Deshotels sand. The upper sand (Morein) had an original bottom-hole pressure of 6,788 psig, which is some 1,500 psi above the normal pressure for that depth. Oil production with high gas/oil ratios and fluid analyses giving high shrinkage factors prompted a study of the reservoir in its early stages. The results indicated a closed reservoir producing under solution gas drive with low expected ultimate oil recovery. The early study of the Wilcox formation and its contained hydrocarbons resulted in the presentation of the data to the Department of Conservation of the State of Louisiana. with suggestions for field rules and a request for permission to inject extraneous water into the Morein sand. The water injection plans eventually led to complete unitization of working and royalty interests, to the construction of a gasoline plant, and to a central tank battery installation for the field. Deshotels sand wells were reworked to the Morein sand, and the water injection system was installed and ready for continuous operation in the early part of 1949. The injection of water was started in time to arrest the bottom-hole pressure decline at or near the bubble-point pressure. This injection was calculated to increase the ultimate recovery and to conserve natural resources. Pressure maintenance, the extraction of LPG products, and the sale of residue gas (early 1950) represent an attempt to produce an oil field with utmost efficiency. INTRODUCTION The two principal Wilcox oil horizons in the Mamou Field are the Morein sand and the Deshotels sand, occurring at 11,500 ft and 11,700 ft subsea, respectively. Minor oil production has been encountered in Morein stringer sands. (Fig. 1.) This paper deals only with the Morein sand, which is blanket over the Mamou Field. It is, however, segmented by the northwest-southeast "E" fault as shown in Fig. 2. The west segment is the area involved in the water injection pressure maintenance program. To date the east segment has operated largely under the influence of a strong water drive. The paper presents (1) a brief history of field development, (2) a resumé of reservoir conditions which led to the decision to inject extraneous salt water into the principal producing horizon, and (3) a summary of reservoir analysis and performance. FIELD DEVELOPMENT The Mamou Field is located in Evangeline Parish, La. The discovery well (J. B. Morein No. 1, now Unit No. 5) was completed in December, 1945, after penetrating 200 ft into the Wilcox formation. Initial production from the Morein

Jan 1, 1951

By James R. I. Henagan, William O. Crego

The Mamou Field, located in Evangeline Parish, La., is an elongated anticlinal structure on the downthrown side of a major east-west fault with oil and gas production from the upper part of the Wilcox formation. Two main producing horizons occur at an approximate depth of 11,500 ft and have been designated the Morein sand and the Deshotels sand. The upper sand (Morein) had an original bottom-hole pressure of 6,788 psig, which is some 1,500 psi above the normal pressure for that depth. Oil production with high gas/oil ratios and fluid analyses giving high shrinkage factors prompted a study of the reservoir in its early stages. The results indicated a closed reservoir producing under solution gas drive with low expected ultimate oil recovery. The early study of the Wilcox formation and its contained hydrocarbons resulted in the presentation of the data to the Department of Conservation of the State of Louisiana. with suggestions for field rules and a request for permission to inject extraneous water into the Morein sand. The water injection plans eventually led to complete unitization of working and royalty interests, to the construction of a gasoline plant, and to a central tank battery installation for the field. Deshotels sand wells were reworked to the Morein sand, and the water injection system was installed and ready for continuous operation in the early part of 1949. The injection of water was started in time to arrest the bottom-hole pressure decline at or near the bubble-point pressure. This injection was calculated to increase the ultimate recovery and to conserve natural resources. Pressure maintenance, the extraction of LPG products, and the sale of residue gas (early 1950) represent an attempt to produce an oil field with utmost efficiency. INTRODUCTION The two principal Wilcox oil horizons in the Mamou Field are the Morein sand and the Deshotels sand, occurring at 11,500 ft and 11,700 ft subsea, respectively. Minor oil production has been encountered in Morein stringer sands. (Fig. 1.) This paper deals only with the Morein sand, which is blanket over the Mamou Field. It is, however, segmented by the northwest-southeast "E" fault as shown in Fig. 2. The west segment is the area involved in the water injection pressure maintenance program. To date the east segment has operated largely under the influence of a strong water drive. The paper presents (1) a brief history of field development, (2) a resumé of reservoir conditions which led to the decision to inject extraneous salt water into the principal producing horizon, and (3) a summary of reservoir analysis and performance. FIELD DEVELOPMENT The Mamou Field is located in Evangeline Parish, La. The discovery well (J. B. Morein No. 1, now Unit No. 5) was completed in December, 1945, after penetrating 200 ft into the Wilcox formation. Initial production from the Morein

Jan 1, 1951

By R. M. Leibrock, J. E. Huzarevich, R. G. Hiltz

The various factors considered in recommending the initiation of a gas injection project in the southern portion of the Cedar Lake Field are discussed. Performance history under gas injection operations is reviewed and these data are analyzed, utilizing both the material balance method and the fractional flow and frontal advance expressions. Results of the analysis of the performance data indicate that the injected gas has contacted and affected at least 60 per cent of the reservoir and a substantial increase in ultimate recovery can reasonably be expected. By holding the reservoir pressure appreciably above the bubble point, the well productive capacities have been maintained substantially above the level predicted for primary operations. The analysis of the Cedar Lake project suggests that in certain limestone reservoirs, at least, the probable success of gas injection cannot be predicted simply from ohservation of permeability distribution throughout the pay section, as indicated by core analysis data, on either one or a number of wells. Further, the performance of this particular project fails to indicate any basis for classifying carbonate reservoirs in general as being inherently unsuited to a dispersed type gas injection program, thus indicating that each reservoir should be considered on its own merits, regardless of the composition of the reservoir rock. INTRODUCTION Early in the life of the Cedar Lake Field, an extensive data gathering program was initiated to provide an accurate record of reservoir performance characteristics. From the study of these data it was apparent that there was a critical need for supplementing the natural reservoir energy in order to maintain well productivities and obtain the maximum ultimate oil recovery. Accordingly, detailed engineering studies were made of the various methods of secondary recovery which might be applicable. As a result of these investigations, the decision was made to initiate a gas injection program of sufficient intensity to maintain reservoir pressure at approximately 600 psia, or some 274 lb above the bubble point pressure of 326 psia. A full scale dispersed type gas injection program has been in operation on leases of the Stanolind Oil and Gas Co. in the southern portion of the field for nearly five years, and sufficient performance data are now available to evaluate the benefits which have been derived from this project. It is the primary purpose of this paper to analyze the performance data for the Cedar Lake gas injection project and to point out the significance of the ohserved behavior with respect to certain hypotheses which have been advanced in recent years concerning the probable success of gas injection projects in limestone reservoirs. This paper properly should be regarded more on the order of a progress report, inasmuch as some revision in interpretation will undoubtedly be required from time to time as additional performance data are obtained, although the satisfactory performance of the project to date leaves little doubt as to the ultimate success of gas injection in the Cedar Lake Field. As a result of the success of the project to date, a unit was formed in the southern part of the field, effective March 1, 1951, for the purpose of continuation of the gas injection program. Participants in this unit are the Mid-Continent Petroleum Co. and Stanolind Oil and Gas Co. GEOLOGY AND STRATIGRAPHY The Cedar Lake Field is located in the northern portion of the Midland Basin area as shown in Fig. 1. The southwest portion of the field lies within a playa, or dry salt lake, which covers an area of approximately eight square miles. As might be expected, it was this lake which furnished the inspiration for the name of the field. Except for its value as a salt water disposal pit, this lake has succeeded only in magnifying the difficulties in developing this portion of the field. Typical of this section of West Texas, the area in general is relatively flat and has a semi-arid climate. The localized structure which favored the accumulation of oil is an anticline with approximately 100 ft of closure. The major axis of the structure extends in a general southeast-northwest direction. Originally this structure was defined by seismograph data, which have been subsequently confirmed by development. In general, the geologic column is typical of that found throughout the basin. From the surface to depth of approximately 1,800 ft, surface sands and undifferentiated red beds. probably Triassic. are encountered. Below this point to the producing horizon, all formations are of the Permian age.

Jan 1, 1951

By J. E. Huzarevich, R. M. Leibrock, R. G. Hiltz

The various factors considered in recommending the initiation of a gas injection project in the southern portion of the Cedar Lake Field are discussed. Performance history under gas injection operations is reviewed and these data are analyzed, utilizing both the material balance method and the fractional flow and frontal advance expressions. Results of the analysis of the performance data indicate that the injected gas has contacted and affected at least 60 per cent of the reservoir and a substantial increase in ultimate recovery can reasonably be expected. By holding the reservoir pressure appreciably above the bubble point, the well productive capacities have been maintained substantially above the level predicted for primary operations. The analysis of the Cedar Lake project suggests that in certain limestone reservoirs, at least, the probable success of gas injection cannot be predicted simply from ohservation of permeability distribution throughout the pay section, as indicated by core analysis data, on either one or a number of wells. Further, the performance of this particular project fails to indicate any basis for classifying carbonate reservoirs in general as being inherently unsuited to a dispersed type gas injection program, thus indicating that each reservoir should be considered on its own merits, regardless of the composition of the reservoir rock. INTRODUCTION Early in the life of the Cedar Lake Field, an extensive data gathering program was initiated to provide an accurate record of reservoir performance characteristics. From the study of these data it was apparent that there was a critical need for supplementing the natural reservoir energy in order to maintain well productivities and obtain the maximum ultimate oil recovery. Accordingly, detailed engineering studies were made of the various methods of secondary recovery which might be applicable. As a result of these investigations, the decision was made to initiate a gas injection program of sufficient intensity to maintain reservoir pressure at approximately 600 psia, or some 274 lb above the bubble point pressure of 326 psia. A full scale dispersed type gas injection program has been in operation on leases of the Stanolind Oil and Gas Co. in the southern portion of the field for nearly five years, and sufficient performance data are now available to evaluate the benefits which have been derived from this project. It is the primary purpose of this paper to analyze the performance data for the Cedar Lake gas injection project and to point out the significance of the ohserved behavior with respect to certain hypotheses which have been advanced in recent years concerning the probable success of gas injection projects in limestone reservoirs. This paper properly should be regarded more on the order of a progress report, inasmuch as some revision in interpretation will undoubtedly be required from time to time as additional performance data are obtained, although the satisfactory performance of the project to date leaves little doubt as to the ultimate success of gas injection in the Cedar Lake Field. As a result of the success of the project to date, a unit was formed in the southern part of the field, effective March 1, 1951, for the purpose of continuation of the gas injection program. Participants in this unit are the Mid-Continent Petroleum Co. and Stanolind Oil and Gas Co. GEOLOGY AND STRATIGRAPHY The Cedar Lake Field is located in the northern portion of the Midland Basin area as shown in Fig. 1. The southwest portion of the field lies within a playa, or dry salt lake, which covers an area of approximately eight square miles. As might be expected, it was this lake which furnished the inspiration for the name of the field. Except for its value as a salt water disposal pit, this lake has succeeded only in magnifying the difficulties in developing this portion of the field. Typical of this section of West Texas, the area in general is relatively flat and has a semi-arid climate. The localized structure which favored the accumulation of oil is an anticline with approximately 100 ft of closure. The major axis of the structure extends in a general southeast-northwest direction. Originally this structure was defined by seismograph data, which have been subsequently confirmed by development. In general, the geologic column is typical of that found throughout the basin. From the surface to depth of approximately 1,800 ft, surface sands and undifferentiated red beds. probably Triassic. are encountered. Below this point to the producing horizon, all formations are of the Permian age.

Jan 1, 1951

By T. J. Nowak

The heat flow processes determining the injection and shut-in temperature logs in a water injection well have been analyzed and the theoretical basis for determining the water injectivity profiles from the temperature logs has been presented. Both the injection and the subsequent shut-in logs are necessary to resolve the injection interval into relative water intake strata; the former, to provide an accurate estimation of the thicknesses of the strata, and the latter to indicate the major and minor intake rates into the strata. A procedure is described for estimating the injectivity profile from the temperature logs and is applied to several temperature logs. For a water injection well, a comparison is made of the injectivity profiles obtained from the core analysis, the spinner survey, and the temperature logs. INTRODUCTION In secondary recovery of oil by water flooding, the injectivity profile is needed to obtain diagnostic evaluation of water intake distribution over the injection interval. If the distribution is unfavorable among the various strata, corrective measures can be taken to provide better control. Numerous methods have been developed for determining the injectivity profile from water velocity measurements in well bores. Often, dependence is placed upon core analyses and/or electric logs for estimating the relative water intakes over the injection interval. In many cases, the temperature log method described herein will give results more diagnostic than those obtained through use of the other available methods inasmuch as it is based upon the study of temperature disturbances in and around the well bore as a function of water flow in the well bore and in the formation. This method is the result of analyses of a number of temperature surveys made in water injection wells to determine the point of entry of the water into the formation. The material in this paper is presented in two sections: the first deals with the theoretical study of temperature survey data, and the second deals with the field application. PART I — THEORETICAL TREATMENT OF TEMPERATURE LOG DATA Before discussing the various aspects of heat flow relative to temperature log data, the phenomena that give rise to well bore temperatures — namely, the indigenous formation temperature and the associated rates of heat flow — will be considered. Geothermal Gradient The geothermal gradient is defined as the increment of depth at which the indigenous subsurface temperature increases by l°. It is caused by the continuous flow of heat outward from the interior of the earth. The flow of heat is an equilibrium process between the heat sources, the thermal conductivities of the formations, and the mean surface temperature. Therefore, there is no accumulation of heat energy in the path of heat transmission, and the geothermal gradient for a given formation will depend upon its thermal conductivity.

Jan 1, 1953

By H. H. Kaveler, W. R. Evans, Jack Tarner

The geological features, development history and engineering detail of the Shuler Field and the results of approximately two years of unitized operation of the Shuler Jones Sand Pool, were discussed in a prior publication.' The purpose of this paper is to present the results of pressure maintenance in the Shuler Jones Sand Pool after nine years of unit operation. GENERAL INFORMATION The Shuler Jones Sand Pool is located in and about Section 18, Township 18 South, Range 17 West, Union County, Ark. The pool was discovered .in September, 1937, unitized in February, 1941, and subjected to gas injection operations in July, 1941. Water was first returned to the reservoir in July, 1944. The reservoir is an anticlinal trap covering about 4,000 acres. The 154,000 acre-ft of sandstone initially consisted of approximately 150,000 acre-ft of productive oil zone and 4,000 acre-ft of gas-cap. The average depth of production is 7,400 ft. Maximum closure of the reservoir is 135 ft and the oil column lies between a gas-oil contact at -7,270 ft and a water-oil contact at -7,370 to -7,380 ft. The field is approximately four miles long. east and .west, and one and one-half miles wide. The sand grains are angular and vary from fine to medium size. The porosity of the sandstone averages 20.2 per cent. The specific permeability averages 400 md. Some zones have as high as 30 per cent porosity and specific permeability of 4,000 md. The reservoir rock is not uniform in character but consists of sandstone zones interspersed with shale. The variation in rock characteristics is evident in the electric log and core analyses presented in the original publication. Asphalt present in the pore space of the sandstone limited the reservoir to the southeast and apparently blocked any encroachment of water from that direction. The initial reservoir pressure at a subsea depth of 7,300 ft was 3,520 psi. The reservoir temperature was 198ºF. Initially, the solution gas volume was 765 cu ft per bbl and the reservoir volume factor was 1.45. The gas solubility and formation-volume-factors of the reservoir liquid are related with reservoir pressures above 300 psi as follows: Solution gas, cu ft per cu ft, S = 0.0334 P + 18.65 Formation volume factor of reservoir oil, FVF = 8.0 x 10 -5 P + 1.168 Gas volume factor, standard cu ft of gas equivalent to one cu ft of gas at reservoir conditions of temperature and pressure, F = .062 P - 4 Pressure (P) measured in psia. The equation for the gas volume factor presented above is based on a direct measurement of a sample of the gas and is a correction of that used in the original paper. The gravity of the oil produced is from 32 to 34" API. CALCULATION OF INITIAL OIL IN PLACE The Jones Sand production history is interesting because it lends itself to analysis by material balance. Production statistics from discovery of the Jones Sand through 1949 and material balance calculations of the initial stock tank oil in place are shown in Table I. The usual procedure in testing the application of material balance calculations is to compute the apparent initial volume of oil in place, using production and pressure information obtained at different time periods. If the apparent oil in place volumes computed increase with successive time periods, water encroachment is indicated and approximations must be mads to correct for its influence. The first requirement in utilizing such calculations is reliable reservoir pressure, accumulated gas, oil and water production, and PVT data. Calculations of apparent oil in place in the Jones Pool, based on field data

Jan 1, 1951

By W. R. Evans, H. H. Kaveler, Jack Tarner

The geological features, development history and engineering detail of the Shuler Field and the results of approximately two years of unitized operation of the Shuler Jones Sand Pool, were discussed in a prior publication.' The purpose of this paper is to present the results of pressure maintenance in the Shuler Jones Sand Pool after nine years of unit operation. GENERAL INFORMATION The Shuler Jones Sand Pool is located in and about Section 18, Township 18 South, Range 17 West, Union County, Ark. The pool was discovered .in September, 1937, unitized in February, 1941, and subjected to gas injection operations in July, 1941. Water was first returned to the reservoir in July, 1944. The reservoir is an anticlinal trap covering about 4,000 acres. The 154,000 acre-ft of sandstone initially consisted of approximately 150,000 acre-ft of productive oil zone and 4,000 acre-ft of gas-cap. The average depth of production is 7,400 ft. Maximum closure of the reservoir is 135 ft and the oil column lies between a gas-oil contact at -7,270 ft and a water-oil contact at -7,370 to -7,380 ft. The field is approximately four miles long. east and .west, and one and one-half miles wide. The sand grains are angular and vary from fine to medium size. The porosity of the sandstone averages 20.2 per cent. The specific permeability averages 400 md. Some zones have as high as 30 per cent porosity and specific permeability of 4,000 md. The reservoir rock is not uniform in character but consists of sandstone zones interspersed with shale. The variation in rock characteristics is evident in the electric log and core analyses presented in the original publication. Asphalt present in the pore space of the sandstone limited the reservoir to the southeast and apparently blocked any encroachment of water from that direction. The initial reservoir pressure at a subsea depth of 7,300 ft was 3,520 psi. The reservoir temperature was 198ºF. Initially, the solution gas volume was 765 cu ft per bbl and the reservoir volume factor was 1.45. The gas solubility and formation-volume-factors of the reservoir liquid are related with reservoir pressures above 300 psi as follows: Solution gas, cu ft per cu ft, S = 0.0334 P + 18.65 Formation volume factor of reservoir oil, FVF = 8.0 x 10 -5 P + 1.168 Gas volume factor, standard cu ft of gas equivalent to one cu ft of gas at reservoir conditions of temperature and pressure, F = .062 P - 4 Pressure (P) measured in psia. The equation for the gas volume factor presented above is based on a direct measurement of a sample of the gas and is a correction of that used in the original paper. The gravity of the oil produced is from 32 to 34" API. CALCULATION OF INITIAL OIL IN PLACE The Jones Sand production history is interesting because it lends itself to analysis by material balance. Production statistics from discovery of the Jones Sand through 1949 and material balance calculations of the initial stock tank oil in place are shown in Table I. The usual procedure in testing the application of material balance calculations is to compute the apparent initial volume of oil in place, using production and pressure information obtained at different time periods. If the apparent oil in place volumes computed increase with successive time periods, water encroachment is indicated and approximations must be mads to correct for its influence. The first requirement in utilizing such calculations is reliable reservoir pressure, accumulated gas, oil and water production, and PVT data. Calculations of apparent oil in place in the Jones Pool, based on field data

Jan 1, 1951

By R. J. Bethancourt, D. M. Collingwood

The use: of a pilot waterflood is very desirable where all of the pertinent data necessary to initiate a full scale waterflood are not. available. This paper attempts to take a specific case and .show the step by step process of starting with a pilot waterflood and progressing to a full wale flood as results are obtained. INTRODUCTION Many of the older fields of Soutlwest Texas are approaching depletion by primary produrtion methods. As primary protlllc:inp operations on individual properties approach their economic limit. conflicting considerations face management: cm the one hand. plugging and abandonment of wells for equipment salvage; on the other hand, further investment in secondary recovery installtions, equilent, and well workovers in the interests of conservation anal additional oil reserves. In main instances, where primary production by pressure depletion and gas solution drive has been comparatively good, there still exists the possibility of an economic secondary recovery by waterflood. This is not necessarily true to the same degrre of all such fields. nor all portions of large fields. To properly evaluate the economics of a prospective water-11ot1cI requires a considerable amount of precise geological. statitical. and physical data Such information on the older field.; is often very limited. and in the case of the property discussed in this paper was considered inadequate to justify investment in an overall waterflood. Primary production was estimated at :39 per cent of the original oil in place, yet sand conditions of permeability and homogeneity, and position in the field appeared to be favorable for a limited margin of profit from a carefully controlled waterflood. Thus a pilot waterflood, with its minimum initial financial risk, followed by extension as favorable results were obtained, seemed to be the answer for the Sun Oil Co L. Wiederkehr lease in the Nortl Government Wells Field, Duval County. Texas DESCRIPTION OF RESERVOIR Approxinately 8,200 wells have been drilled in Duval County. As of March 1, 1952, there were 3,350 producing oil wells in 92 different fields, with very few flowing wells (Fig. 1.) Sun Oil Co. operates the I.. Wiederkehr lease located in the North Government Wells Field in Duval Countv. 85 mile. west of Corpus Chriti and 100 miles south of San Antonio. The lease has been subjected in part to a controlled five spot waterflood. The North Government Wells Field is roughly 7 miles long and 3 miles wide, with numerous overlapping producing zones. The L. Wiederkehr lease of 3.085 acres. Has seven producing zones from 700 to 7.500 ft. The lease is in the northern section of the field where it is widest, and has 710 acres productive from the North Government Wells .and. (Fig. 2.) The North Government Wells sand, Jackson group. Eocene age, at an average depth of 2.250 ft (minus 1.750 subsea). has a thickness range of 25 ft on the east side of the L. Wiederkehr lease to 4 ft on the west side. It has a slight overall dip to the North and East of some 33 ft to the mile.

Jan 1, 1953

By Raj K. Rajamani, Poly K. Songfack

The slurry transport within the ball mill greatly influences the mill holdup, residence time, breakage rate, and hence the power draw and the particle size distribution of the mill product. However, residence-time distribution and holdup in industrial mills could not be predicted a priori. Indeed, it is impossible to determine the slurry loading in continuously operating mills by direct measurement, especially in industrial mills. In this paper, the slurry transport problem is solved using the principles of fluid mechanics. First, the motion of the ball charge and its expansion are predicted by a technique called discrete element method. Then the slurry flow through the porous ball charge is tackled with a fluid-flow technique called the marker and cell method. This may be the only numerical technique capable of tracking the slurry- free surface as it fluctuates with the motion of the ball charge. The result is a prediction of the slurry profile in both the radial and axial directions. Hence, it leads to the detailed description of slurry mass and ball charge within the mill. The model predictions are verified with pilot-scale experimental work. This novel approach based on the physics of fluid flow is devoid of any empiricism. It is shown that the holdup of industrial mills at a given feed percent solids can be predicted successfully.

Jan 1, 1995

By Deyou Yin, Kongfang Feng, Bo Wang, Jieyu Zhang, Xin Hong, Shaobo Zheng, Jinyin Xie

"The flow patterns and mixing characteristics in a water model of C-H2 smelting reduction furnace are experimentally studied in this paper. Water modeling is employed to investigate the features of gas jet stirring and the fluid flow patterns in the bath of a smelting reduction furnace during the top, bottom, and side combined blowing process. The influence of the gas flow rate for top, bottom and side nozzles, angle, submerged depth of each side nozzles and the height of the top nozzle has been examined. It showed that the gas flow rate of side nozzles and bottom nozzle had a key role on the fluid flow and mixing characteristics. The gas jet from the top nozzle could change the agitation and fluid flow pattern caused by the gas jets from the side nozzles in the bath.IntroductionFacing the current natural resources decrease and the environmental degradation, smelting reduction iron-making technique is believed to be the most representative at present. Mid last century, the concept of producing liquid iron or semi-steel directly from ore fines and inexpensive fuel was the subject of considerable pilot plant development activity. Among these projects, the direct smelting process, which is the reduction and melting of iron-bearing materials by carbon and other hydrocarbons in the vessel containing a molten bath, is the most popular one. A number of direct smelting processes have been developed around the world, e.g. COREX, DIOS, HIsmelt, AISI, ROMELT, etc.These studies put forward a new technology, which through bottom nozzle blowing rich hydrogen, top nozzle blowing rich oxygen and provide preheating ore and solvent, side nozzles blowing oxygen-coal to realize smelting reduction iron-making process. Owing to the metallurgy reactions always in high temperature, which is above 1600 °C, it is difficult to visualize the mixing behavior and measure the desired phenomena in the reduction vessel. With water modeling, the primary advantages are that it is relatively easy to observe and measure the flow phenomena in the bath."

Jan 1, 2011