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By Yanlong Li, Lifeng Zhang, Ying Ren

In this work, a multiphase mathematical model for the fluid flow in argon-stirred steel ladles was established and validated by experimental measurement of wood's metal. Alloy dispersion in the molten steel was calculated. The melting and mixing of alloy was faster with smaller size of the alloy particles, larger superheat and bigger slip velocity. The current mixing time is approximately 300 s with 30 mm alloy diameter and 91.5 K superheat.

Jan 1, 2014

By Hebi Yin

A two-dimensional finite element solidification model was developed to simulate the transport phenomena occurring during laser deposition of AISI 410 stainless steel during the Laser Engineered Net Shaping (LENS®) process. The molten pool geometry and the distribution of temperature, solute concentration and velocity were calculated during deposition of a thin wall plate. An analysis of the simulations results revealed the importance of heat transfer by both conduction and convection as well as the roles of the driving forces for convection in the molten pool. The heat transfer and the flow pattern in the molten pool are considerably dependent on the travel speed of the laser beam. For the alloy and process parameters in the simulations, no significant macrosegregation was observed. The temperature-dependent properties and thermodynamic variables involved in solidification modeling were calculated using Thermo-Calc software. The results of this work contribute to the current understanding of transport phenomena in the molten pool of laser deposition processes.

Jan 1, 2008

By Kent D. Peaslee, Lifeng Zhang, Edith Martinez, Yufeng Wang

The current study investigated the multiphase fluid flow, heat transfer, solidification of the steel, and the motion and entrapment of inclusions during the centrifugal casting process using FLUENT software. User-defined functions (UDFs) were developed to add velocity with a value related to the rotation speed and radial distance to the solidified steel, to exert a centrifugal force to the motion of inclusions, and to add the entrapment condition of inclusions at the solidifying shell and export the entrapment locations of the inclusion. The calculation shows that there are two peaks of inclusions along the thickness of the produced tube: one at close to outer surface and another one close to the inner surface of the tube. With a larger rotation speed, inclusions tend to be entrapped more towards the inner surface. The calculation agrees well with the industrial measurements.

Jan 1, 2012

By J-S Han, J-M Yao

"An EXTENDED ABSTRACT is available for download. A full-length paper was not prepared for this presentation. The Shagou deposit is located along NE-trending faults within the high-grade metamorphic basement of the Xiong’er Terrane in the Qinling orogenic belt. It is a large Ag-Pb-Zn deposit hosted in the Taihua Supergroup and has proven reserves of 1.54 Mt of ore with grades of 767 g/t Ag, 13.24 per cent Pb and 4.31 per cent Zn. The hydrothermal ore-forming process can be divided into early quartz-pyrite, middle quartz-polymetallic sulfides and late quartz-carbonate stages. Four types of fluid inclusions (ie pure carbonic, carbonic, pure aqueous and aqueous) can be distinguished in quartz. Fluid inclusion, hydrogen, oxygen and sulfur isotope systematics indicate that the ore-forming fluids are initially deeply sourced metamorphic water with meteoric water gradually mixed in the later stages. Sulfur isotope data show that the ore-forming fluids originated from both the Taihua Supergroup and the sedimentary successions of the Guandaokou and Luanchuan Groups (CSC) located to the south of the Machaoying Fault. A genetic model of the Shagou deposit is proposed as follows: CSC subducted northward along the Machaoying Fault beneath the Xiong’er Terrane during the Mesozoic collision between the North China Craton and South China Block. Subsequent dehydration resulted in the devolatilisation of fluids rich in CO2. These fluids migrated upwards, reacted with the Taihua Supergroup and formed the Shagou deposit.CITATION:Han, J-S, Yao, J-M and Chen, H, 2015. Fluid inclusion and isotopic constraints on the mineralisation of the Shagou Ag-Pb-Zn deposit, Henan Province, China , in Proceedings PACRIM 2015 Congress, pp 615–618 (The Australasian Institute of Mining and Metallurgy: Melbourne)."

Mar 18, 2015

By G. Chi, A. Solomon, J. Lai

"The Buffalo gold deposit is a small deposit consisting of auriferous quartz-tourmaline veins within a granodiorite stock in the Red Lake greenstone belt. This study aims to characterize the mineralizing fluids through fluid inclusion and stable isotope analyses and to compare them with those of the world-class Campbell- Red Lake deposit. Four types of fluid inclusions were recognized, including carbonic, aqueous-carbonic, aqueous, and halite-bearing aqueous, with the carbonic type being the most abundant. Raman analyses indicate that the carbonic phase mainly consists of CO2, with minor amounts of N2 and CH4, and rarely detectable H2S. The homogenization temperatures of the carbonic inclusions range from -41.7° to 30.9°C. The homogenization temperatures and salinities of the aqueous, halite-bearing aqueous, and aqueous-carbonic inclusions are 130° to 276°C and 9.7 to 23.6 wt.% NaCl equiv., 155° to 207°C and 32.9 to 42.3 wt.% NaCl equiv., and 215° to 357°C and 8.3 to 19.7 wt.% NaCl equiv., respectively. The d18OVSMOW values of tourmaline range from 8.2‰ to 9.0‰, and those of quartz from 11.4‰ to 11.9‰, with estimated fluid temperatures from 323° to 399°C based on the quartz-tourmaline isotopic geothermometer. It is postulated that separate CO2-dominated and aqueous fluids intermittently invaded the fracture/vein system in response to fluid pressure fluctuations, with limited mixing. The CO2-dominated fluid, previously recognized in Campbell-Red Lake as the main mineralizing fluid, is inferred to have been derived from deeper parts of the crust. This deep CO2-dominated fluid reservoir might have been a common source for gold mineralization in the Red Lake greenstone belt. Le gîte aurifère Buffalo est un petit dépôt composée de veines de quartz-tourmaline à l’intérieur d’un stock de granodiorite dans la ceinture de roches vertes de Red Lake. Cette étude vise à caractériser les fluides impliqués dans la minéralisation par les inclusions fluides et par les isotopes stables ainsi que de les comparer avec ceux du gîte de classe mondiale de Campbell-Red Lake. Quatre types d’inclusions ont été notes, incluant des inclusions carboniques, aqueuses-carboniques, aqueuses et aqueuses avec halite, les inclusions carboniques étant la variété la plus abondante. Les analyses par spectroscopie Raman indiquent que la phase carbonique consiste principalement en CO2, avec des quantités mineures de N2 et de CH4, et rarement avec des quantités mesurables de H2S. Les températures d’homogénéisation des inclusions carboniques vont de -41.7° to 30.9°C. Les températures d’homogénéisation et les salinités des inclusions aqueuses, aqueuses avec halite et aqueuses-carboniques sont varient de 130° à 276°C et de 9.7 à 23.6 poids.% NaCl équiv., 155° à 207°C et 32.9 à 42.3 poids.% NaCl équiv., et de 215° à 357°C et 8.3 à 19.7 poids.% NaCl équiv., respectivement. Les valeurs de d18OVSMOW pour la tourmaline vont de 8.2 à 9.0‰, et celles du quartz de 11.4 à 11.9‰, avec une température estimée du fluide entre 323° et 399°C sur la base du géothermomètre isotopique quartz-tourmaline. Il est postulé qu’un fluide riche en CO2 et un fluide aqueux distinct ont envahi le système de fractures/veines par intermittence en réponse à des variations dans la pression des fluides, et qu’il y a eu peu de mélange. Le fluide riche en CO2 est également observé à Campbell-Red Lake ou il est le fluide minéralisant principal, il est présumé être dérivé de portions plus profondes de la croûte. Ce réservoir profond de fluides riches en CO2 pourrait être la source commune des minéralisations aurifères de la ceinture de roches vertes de Red Lake."

Jan 1, 2009

By K. Shen, A. J. Sinclair, N. Champigny

"Fluid inclusion studies from the Cinola deposit indicate low salinities and low C01 contents of the ore fluid. This supports a suggestion that the mineralizing fluids originated from pore water in the fluviatile host rock (mid-Miocene Skonun Formation). Bimodal distribution of filling temperatures suggests the existence of at least two temperature regimes centred on 160°C and 270°C during mineral deposition. Independent age and stratigraphic evidence indicates that depth of mineralization is between 1.1 and 1. 8 km, corresponding to a hydrostatic load of between 110 and 170 bars.RESUMELes donnees sur les inclusions fluides du gisement Cinola indiquent de basses salinites et basses teneurs en C01 . Ceci confirme que les fluides mineralisants ont ete derives de l'eau interstitielle prise dans les sedimentsfluviatiles hates. La distribution bimodale des temperatures d'homogenisation implique !'existence de deux regimes de temperature concentrees vers 160°C et 270°C pendant Ia mineralisation. La profondeur alaquelle le gisement s'est forme est evaluee d'etre entre 1.1 et 1.8 km a partir d'informations stratigraphiques independantes: ceci correspond a des pressions hydrostatiques de 110 a 170 bars."

Jan 1, 1982

By Smith J. W, Wilkins R. W T

This paper is a preliminary report of research on the Mount Morgan gold-copper deposit being done at the Division of Mineralogy, CSIRO. Fluid inclusion and sulphur isotope measurements were made on a suite of 11 samples collected by the staff of Geopeko Ltd. This suite contained representatives of the main ore and rock types of the deposit. Homogenization temperatures of fluid inclusions measured on quartz from 8 of the 11 samples, ranged from 172¦C to 276¦C and to this must be added a pressure correction (in this case, up to 50¦C) to obtain the formation temperature of the mineral. Sulphur isotope measurements were made on 34 sulphides from 8 of the 11 samples. The 6S values form a well defined group ranging from -0.5%oto +3.6%owith a mean of +2.4%c. Although the preliminary data do not indicate unequivocally the origin of the deposit they do impose restraints on the wide ranging suggestions that have been put forward. This work is complementary to the paper of Dr G. Gibbons who has described other mineralogical aspects of the Mount Morgan deposit, based on a more extensive suite of Samples.

Jan 1, 1974

By A H. Hofstra, G P. Landis, P Emsbo, A G. Hunt

Models of the evolution of the hydrothermal systems that form porphyry Cu (Mo-Au) deposits are compromised because aqueous magma-derived fluids in the ore zones of most deposits have changed from their original magmatic compositions as a result of cooling, depressurising, mineral precipitation, brine-vapour unmixing and fluid-rock reactions. However, in deep quartz-rich, sulfide-poor veins from numerous porphyry type deposits, we have identified parental fluids trapped in inclusions at near magmatic temperatures and pressures above the brine-vapour unmixing solvus. We have analysed these inclusions for bulk salinity, density, solute chemistry, helium isotopic ratios and elemental composition. These parental inclusions contain 35 - 70 volume per cent bubble, are low to moderate salinity, contain up to ten mol per cent CO2, and commonly contain a chalcopyrite daughter crystal. Our results indicate that these Cu-rich fluids transport Cu from a plutonic complex below upward into a hydrothermal system, where decompression, cooling, unmixing and water-rock reaction drive ore-mineral precipitation. Na/Cl ratios greater than one indicate that in addition to chlorine, sulfur and/or carbonate must play a key role in Cu transportation. Helium isotope ratios indicate that between ~15 and 100 per cent of helium in these fluids is mantle-derived. We suggest that in addition to He, volatiles from mafic magmas in the mantle are also likely to supply CO2, Cu and S to the fluids that form porphyry copper deposits. An EXTENDED ABSTRACT is available for download. A full-length paper was not prepared for this presentation.

Jan 1, 2008

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