Search Documents

By T GRAHAM-TAYLOR

A trend towards mining more complex and economically marginal orebodies, often combined with increasingly tight product specifications, increases the number of variables which need to be considered in production scheduling. Linear programming incorporating integer constraints can be used to create production schedules which are practical as well as mathematically optimum. Factors which can be taken into account include variability in product stockpiles, targets for head or product grades, production of different material types, production from different areas, production targets for loaders, and dependencies between mining blocks. For each schedule an appropriate objective for optimisation must be chosen. Examples of objectives are: to minimise or maximise grade variation; to minimise waste movement; and to minimise movement by front end loaders. A staged approach to the implementation of computer systems based on linear programming optimisation is Proposed.

Jan 1, 1992

By Scott Hopkins

Simulation tools are preferred for evaluating complex systems due to its ability to mimic reality and quickly evaluate many different what-if scenarios and find global solutions. A simulation model is capable of representing variable and dynamic disturbances that are typically encountered in day-to-day operations; this is where spreadsheet models or linear programs fall short because they cannot account for the dynamic behavior and relationships. The simulation model used for this work was developed by Xstrata-Nickel (previously Falconbridge). The simulation tool is very flexible and can be used to simulate different mining and development methods. The scope of the modeling included production mining, geology, equipment fleets, equipment maintenance and random failures, manpower, shift schedules, and cycle activity times. A case overview of the 170 Orebody will be presented along with the challenges associated with data collection for the model inputs. Results and lessons learned will also be discussed.

May 1, 2008

By Lyon F. Terry

SPEED-UP of production of crude oil and its products, accompanied by rising prices and the organization of the industry on a war basis, featured the economic aspects of petroleum in 1941. Early in the year American tankers were urgently requested by the British to replace losses and offset slower transit under convoy. Some forty American owned tankers were first assigned to Britain and an additional forty-odd ships were transferred during the summer. This threatened to reduce our transportation facilities from Gulf ports to the Eastern seaboard below requirements, especially should sinkings have increased and the British needed more ships. Co-ordinator Ickes began preparations for restricting gasoline consumption in the Eastern district and plans were formulated for the construction of an emergency trunk pipe line from Texas to New York and Philadelphia refining centers, and for a gigantic tanker-building program. Sales of new oil-heating units in the East practically ceased. The companies were urged to transport as much oil as possible by tank car and by October 140,000 barrels of oil per day were reaching the East Coast district by rail, sufficient to meet 8 per cent of total requirements. But British sinkings from July through October decreased 63 per cent compared with the four months ended June 30, Britain began the return of tankers, the construction plans were dropped, and the threatened shortage was thus averted.

Jan 1, 1942

By AIME AIME

THE fall meeting of the Petroleum Division, held at Tulsa, Okla., on Oct. 11 to 14, devoted two days to technical sessions and two to field excursions. A representative attendance of 250 to 300 engineers and operating officials engaged in oil production marked the sessions and paid close attention throughout to a notable series of highly technical papers. Restricted as the program was to consideration of production problems only, the time proved too short for discussion or even the presentation of the 20 papers submitted. Much informing and pertinent discussion none the less took place, and the sentiment was general to the effect that the meeting was one of the best ever held by the Division. The meetings were held in the auditorium of the Municipal building and local arrangements were well looked after by the Mid-Continent Section of the Institute and the Oil and Gas Association. The combination of the three organizations served to bring together engineers and operators most usefully. F. Julius Fohs, chairman of the Division, presided at the sessions on Monday. Tuesday morning John M. Lovejoy of the local section took over this responsibility in the absence of T. E. Swigart, who was detained in California. The afternoon session was presided over by A. G. Heggam of the Oil and Gas Association and the Tuesday evening banquet by W. C. Franklin of the same organization.

Jan 1, 1926

By Thomas V. Falkie

4.3-1. Introduction. DEFINITION OF PRODUCTION SYSTEMS ENGINEERING. Surface mines, like most other mining and manufacturing operations, are usually organized along functional departmental lines. Frequently a mine manager will have his responsibilities divided among production, maintenance, administrative, and engineering functions. Often these are separate departments, but various combinations and variations of these functions can be found in mining companies throughout the world. The production function is responsible for physically removing the ore from the ground, processing it, and shipping the product to its market. The production manager supervises and is responsible for all man-machine systems necessary to extract and process the ore. The maintenance function, which is sometimes included within the framework of production, has the task of insuring the maximum availability and longevity of equipment needed to produce the ore. The administrative function is responsible for accounting, personnel, industrial relations, purchasing, public relations, property, and other related staff functions. For purposes of this chapter, engineering can be described as the function which plans, designs, and supervises construction of physical plant and equipment. In this context engineering includes mechanical, civil, chemical, electrical, and mining engineering. However, another phase of engineering is to prepare plans to insure that the various man-machine components function in an optimum way towards the single most important goal of any enterprise-the maximization of return on the investors' money. Along with the planning, another duty of engineering is to audit all phases of the operation for the purpose of recommending improvements toward this same general goal. These latter two ideas form the basis for a discussion of production engineering and systems engineering. Production engineering is a catchall, problem-oriented function whose duties can include: 1) solution of day-to-day production problems, 2) short-

Jan 1, 1968

By Howard E. McKinney

A high-pressure wellhead lubricator has been developed to facilitate telemetering electrical measurements from subsurface reservoirs to the surface with the well under normal flowing conditions. The field unit in use at the present time employs a 5/16-in diameter, single-conductor armored cable and is to be used in wells with surface pressures up to 5,000 psi. It has a pressure sealing element that maintains a continuous and absolute seal around the cable as it enters or leaves the tubing at speeds up to 175 ft per minute. A cable injecting device is used which obviates sinker bars or weight sections on the instrument. INTRODUCTION The development of instruments for securing physical measurements in pressure wells has been confined in the past to those instrument which would operate on a wire line and record the necessary measurements in the downhole instrument itself, or those which would operate on an electric cable in a well with the surface pressure killed by the use of weighted fluids or by the use of tubing plugs. In one case the accuracy of the measurements is questionable, and in the other the range of application is very limited. Considerable work has been done by other interests to provide effective means to accomplish the necessary telemetering. The U. S. Bureau of Mines developed a wellhead lubricator prior to 1947 which permitted a 5/16-in diameter single-conductor cable to be lowered into a well with a surface pressure of approximately 500 psi. This unit was used successfully in a number of tests in Oklahoma. A company which tests wells has recently offered on a service basis a wellhead lubricator with a 3/16-in diameter cable that reportedly operates up to 2,500 psi surface pressures. Each of the above operates on a staging principle to effect a seal. In both of these units some leakage of well fluid occurs when the cable is moved. SPECIFICATIONS FOR DESIGN In order to provide the maximum flexibility in its use, the following parameters were established for the design of our high-pressure wellhead lubricator: L An absolute well fluid seal up to 5,000 psi surface pressures. 2. Means for raising and lowering the instrument at speeds of at least 100 ft per minute. 3. Provision for the instrument to enter and leave the well without disturbing the well flow or the reservoir conditions. 4. A cable large enough to provide suitable electrical characteristics and suitable mechanical properties. 5. A method of operation that will not damage the well in any way. The present high-pressure wellhead lubricator field unit fulfills the above requirements. DESCRIPTION OF THE UNIT AND ITS OPERATION The cable selected for this use is the standard Amergraph 1H2 as manufactured by the American Steel and Wire Co. This particular cable is normally used by the Halliburton Oil Well Cementing Co. in their conventional well logging operations. Although the cable presents a noncircular cross-section (Fig. l), its diameter is very consistent; lor example, maximum diameter is 0.325 in., minimum diameter 0.314 in. This [actor permits the use of the sealing element, as later described. Early in the development of the high-pressure wellhead lubricator it was apparent that we could not effect a direct gas seal around a moving 1H2 cable. This becomes evident when an examination of the cable cross-section is made. The voids between the strands of the outer armor provide natural channels lor the flow and escape in large quantities of a low-viscosity fluid such as gas. However, it is relatively simple to

Jan 1, 1952

By Henry A. Stiff, and Lawrence E. Davis

The authors previously presented a method for predicting the tendency of oil field waters to deposit calcium sulfate. The present paper gives a similar method for calcium carbonate. Methods for predicting calcium carbonate scaling tendencies in fresh waters have been available for some time, but these could not be used for brines. By experimentally deriving the value of the K term in the Langelier equation, a method has been developed which applies to waters of high salt content. A statistical study is included which shows that the experimentally derived values of K are in good agreement with actual conditions. Several applications of the final equation to production practice are given. INTRODUCTION The authors previously presented a method for predicting the formation of calcium sulfate scale in oil field waters.' Although calcium sulfate deposition is important in production operations, the majority of scale problems involve calcium carbonate. The present communication discusses a method by which the formation of this type of scale in oil field waters can be predicted. Calcium carbonate precipitation is caused by a shift toward carbonate in the carbonate-bicarbonate-carbon dioxide equilibrium. When equilibrium shifts in the other direction, the precipitate goes back into solution. Since there is usually considerable delay between the establishment of an equilibrium and the precipitation or solution of calcium carbonate, unstable conditions exist in which a water will precipitate or dissolve calcium carbonate on standing. Tillmans? who did a major part of the early work on carbonate scaling, pointed out that the condition of equilibrium not only indicates the tendency of a water to scale but also is an indication of its corrosive properties. Previously precipitated calcium carbonate combines with iron to form a dense crust which inhibits corrosion. If the water tends to dissolve carbonate, the scale becomes porous, and electrolytic corrosion takes place. Tillmans1 work was extended by several investigators until in 1934 Langeliers developed an equation setting forth the conditions of carbonate equilibrium. By the use of this equation the pH of a water at equilibrium can be calculated. If the actual pH is higher than the calculated pH, the water has a tendency to form scale. If it is lower. the water has a tendency to be corrosive. Langelier's equation can be expressed in a simple form as follows: SI = pH-pCa-pA lk-K where: SI is the stability index. A positive index indicates scale formation. A negative index indicates corrosion. pH is the pH of the water sample, as actually determined. pCa is the negative logarithm of the calcium concentration. pAlk is the negative logarithm of the total alkalinity. K is a constant, the value of which depends on the total salt concentration and the temperature. This equation has been shown to apply to waters with totaI solid concentrations as high as 4.000 ppm. In fact, control of fresh water treatment by means of this equation has been standard text-book practice for a number of years. Nomographs have been worked out so that the stability index of a fresh water sample can be determined in a matter of minutes. Most oil field waters, however, contain well over 4,000 ppm of salts and for this reason the usual application of Langelier's equation can not be made. By an empirical method we have extended the application of the Langelier equation to waters of high salt concentration. By the use of this equation the tendency of oil field waters to deposit calcium carbonate can be predicted.

Jan 1, 1952

By Henry A. Stiff, Lawrence E. Davis

A graphic method was developed which can be used to predict the tendency of oil field waters to precipitate calcium Sulfate under a variety of conditions. Application of this method is made to the prediction of sulfate scale formation in heater treaters. boilers. oil wells. cooling systems and water injection wells. INTRODUCTION A solution may be said to be in equilibrium with respect to a given salt when the concentration of that silt in equal to its solubility. If for any reason the concentration of the salt is increased or its solubility decreased. the equilibrium is upset and precipitation of the salt takes place. Thus, if the concentration of a salt in a particular solution is known and its solubility can be calculated for a given set of conditions, the tendency of this salt to form a precipitate under these conditions can be predicted. Based on these principles a method has been developed for determining the tendency of oil field waters to form calcium Sulfate precipitates under various conditions. THE SOLUBILITY DIAGRAM Calcium sulfate precipitation most frequently occurs when two waters are mixed: one containing calcium ions. and the other sulfate ions. As one of these waters is added to the other a point may be reached where the concentration of calcium Sulfate is greater than its solubility. thus causing the formation of a precipitate. The solubility diagram is a graphic device for determining the location of such points, thereby making possible a prediction of the tendency of such a system to deposit sulfate scale. A similar diagram can be used to solve many other problems involving the precipitation of calcium sulfate. Fig. 1 shows a solubility diagram representing the mixing of two waters. Water "A" contains a high concentration of odium, magnesium, and sulfate ions together with a small amount of calcium. Water "B" contains a high concentration of calcium ions together with sodium, magnesium and a small amount of sulfate ions. The percentage mixture of these waters is plotted along the abscissa of a system of rectangular coordi-

Jan 1, 1952

By Henry J. Welge

The approximate methods which are now in use for calculating oil displacement from reservoirs by gas-cycling or gravity-drainage at constant gas pressure, or by water flooding, make use of fundamental relationships derived by Leverett' and Buckley and Leverett.2 The mathematical equations needed are derived by applying Darcy's law to the flowing phases, and by material balance considerations. ln general, any treatment of this type gives. for any particular exploitation time considered, a plot of oil saturation against distance in the reser-voir. The oil recovery must then be obtained by integrating in some manner the area under the plot. A useful analytical method has been derived for computing the average saturation, and hence the oil recovery. Use of this method simplifies the calculations because it makes unnecessary any numerical integrations. and even the saturation distribution plots are not needed. A further advantage of the method is that knowledge of the relative permeabilities is required only for a limited and intermediate saturation range. In both the Buckley and Leverett method and the method discussed here, a linear sand section is assumed, and in the case of gas drive the gas pressure is assumed sufficiently constant both with respect to reservoir position and time so that changes in gas density. solubility, or reservoir volume factor are negligiklle. Thus, the exploitation contemplates oil displacement as by an immiscible phase. Examples are given to illustrate how the new method can be used. INTRODUCTION AND THEORETICAL BACKGROUND This paper treats a simplified method for computing oil recovery when the oil is displaced, from the reservoir sand by a fluid which, within the limits of accuracy desired, can be assumed to be incompressible and immiscible with the oil. The method makes use of two basic relations originally developed for the case of water displacing oil. However, the case of gas displacing oil saturated with gas at a constant (or nearly constant) pressure may also be considered a displacement by an immiscible fluid. This is possible for the reason that the concentration of the gas in the oil never changes if tile pressure is fixed. consequently, any additional free gas must remain undissolved in the oil, and so must act essentially as an immiscible phase. For convenience, the cape of gas drive will be considered first. Both of the two basic relations needed refer to a linear reservoir, or one which may be somewhat idealized so that a constant cross-section is exposed to fluid flow. Further, the displacing phase is injected at one end, or face; of the reservoir, while the produced fluids are understood to emerge at one point only. which is the opposite face of the reservoir. As indicated in Fig. 1, the reservoir may he inclined by some angle 8. The first of the required equations may be derived by applying Darcy's law to both displacing and displaced phases, and subtracting the two equations. The result for water drive has been given previously, as Equation (13) of the reference by

Jan 1, 1952

By Glenn A. Marsh, George Bernard

It is often assumed that aerated oil field brines which are to be injected underground contain dissolved oxygen in amounts which will cause appreciable corrosion. Through the use of a new portable dissolved oxygen meter, accurate determinations were made at three brine conditioning plants. At two older plants, dissolved oxygen concentration in the final treated brine was found to he almost zero In spite of aeration during the conditioning process. At a new plant, dissolved oxygen was initially present but disappeared soon after the brine was "inoculated" with oxygen-free brine from one of the other plants. Corrosion tests at the two older plants have substantiated predictions that the brines would lint be corrosive. These results show that mechanical deaeration may not always be required in brine treating plants. INTRODUCTION The present work was undertaken to add to our knowledge of aeration and deaeration of oil field brines in brine conditioning plants. It is commonly assumed that brines which are exposed to the air soon become more or less saturated with dissolved oxygen. Since oxygen-containing brines are known to be corrosive, precautions are often taken to keep air out of brine through the use of closed systems or mechanical deaeration. The study of oxygen in brine has been seriously hampered in the past because of the lack of a suitable analytical tool. The standard Winkler method for the determination of dis-solved oxygen is satisfactory for use in fresh water, but not in many oil field brines. Corrections have to be made for a number of reducing substances such as ferrous iron and hydrogen sulfide which are commonly present in natural brines. Very often the correction factors are much greater in magnitude than the amounts of oxygen which are to be determined, and consequently erroneous results are obtained. Also. erratic Winkler data are obtained when appreciable concentrations of calcium and magnesium salts are present. The first step in carrying out a systematic study involved designing a portable dissolved oxygen apparatus which would operate in natural brines. Subsequently, this apparatus was used in three brine conditioning plants. Dissolved oxygen data obtained here, and certain corrosion rate data, illustrate the interesting behavior of oxygen in these oil field brines. APPARATUS A portable dissolved oxygen meter described in detail elsewhere,' was developed specifically for use with oil field brines. It is a polarographic apparatus employing a small rotating platinum electrode (cathode) and calomel reference electrode (anode). A potential of 0.7 volts is applied across the electrodes while they are immersed in the brine to be tested. 4References given at end of paper.

Jan 1, 1952

By Harvey T. Kennedy, Charles R. Olson

In many investigations of the performance of petroleum reservoirs the assumption is made that the liquid, if below its bubble-point pressure, is at all times in equilibrium with gas. On the other hand, observations by numerous investigators have indicated that gas-liquid systems including hydrocarbon systems, may exhibit supersaturation to the extent of many hundred psi in the laboratory. Up to the present, there has been no reliable data on which ti judge the actual extent of supersaturation under conditions approaching those existing in petroleum reservoirs. The work reported here deals with observations and measurements on mixtures of methane and kerosene in the presence of silica and calcite crystals. Bubbles were observed to form on crystal-hydrocarbon surfaces in preference to the glass-hydrocarbon interface or to the body of the liquid. Statistically, it was found that the number of bubbles formed per second per square centimeter of crystal surface was a function of the supersaturation only. and the function was evaluated graphically. Supersaturations were observed up to 770 psi, under which condition bubbles formed quickly and with considerable violence. With decreasing degrees of supersaturation, the frequency of bubble formation became less, until at 30 psi supersaturation and lower, no bubbles were observed to form, even though the observation at 30 psi was continued for 138 hours. It was found that silica and calcite crystals had identical effects, within experimental error, in accelerating the formation of bubbles, and that small amounts of water and crude oil had no effect on the results. It is shown that the maximum supersaturation that can exist in a reservoir may be calculated from the data presented and from the area of the rock surface. It is also shown that the number of bubbles formed in the reservoir, in order of magni- tude, may be calculated for any rate of pressure decline imposed on the reservoir by production. The bearing of the number and distribution of bubbles on reservoir performance is discussed. INTRODUCTION A liquid system is supersaturated with gas when the amount of gas dissolved exceeds that corresponding to equilibrium at the existing pressure and temperature. The degree of super-saturation may be conveniently expressed as the difference between the bubble-point of the mixture and the prevailing pressure. Thus, if a mixture having a bubble-point of 1,000 psi at a given temperature exists in single liquid phase at 700 psi at the same temperature. it is supersaturated to the extent of 300 psi. There are many examples of high supersaturations, mostly in aqueous solutions, reported in the literature. Thus, Kenrick, Wismer and Wyatt1 showed that water may be saturated with oxygen, nitrogen or carbon dioxide at 100 atmospheres, and the pressure reduced to one atmosphere without producing bubbles immediately. When liquids are in a state of tension, they may be considered as supersaturated at least to the extent of the tension. The tensile strength of water has been reported as 30 atmospheres by Meyer,1 60 atmospheres bv Budgett. 30 to 50 atmospheres by Temperley and Chambers,4,5 200 atmospheres by Dixon6. and 223 atmospheres by Briggs.7 Vincent8,9 determined the tensile strength of a mineral oil as 45 psi. Gardescu1 maintained pressures for short times in a model reservoir at 115 psi below the bubble-point. It should be noted that the high supersaturations observed were obtained on systems carefully purified to remove particles or surfaces which might promote the formation of bubble; These "nuclei" were considered as contaminants which interfered with the determination of a property of the liquid. In

Jan 1, 1952

By John V. Morgan

Although the Lansing-Kansas City groups One one of the more important producing horizons of Central Kansas, exploitation has been hindered by inability to consistently identify and correlate the various productive intervals. A study of gamma ray-neutron logs and core data indicates that definite zones exist which are related to production and which may be generally correlated over an appreciable portion of Central Kansas. A suggested system of zoning and nomenclature is developed and illustrated, along with examples of its specific application in overall evaluation and in development of zonal production characteristics. General adoption of the suggested system should aid appreciably in the future development of commercial Lansing-Kansas City production in Central Kansas. It is probable that similar systems might be developed for other regions where production is obtained from various uncorrelated and unnamed zones in thick pay intervals. GENERALIZED GEOLOGY OF CENTRAL KANSAS The most important large subsurface feature in Central Kansas regarding oil production is the Barton Arch, which is part of the Central Kansas uplift. The Barton Arch is a buried ridge of Pre-Cambrian granite running northwest-southeast, near which the majority of Central Kansas oil fields have been found. To the northeast of this arch, the granite dips sharply into the Salina Basin and similar basin areas to the west and south are termed the Hugoton Embayment and Anadarko Basin, respectively. This report deals Primarily with the region of the Central Kansas Uplift and its southwestern flank. Fig. 1 indicates the general location of subsurface structural features along with the oil and gas fields of central Kansas. Above basal granite lies the Cambro-Ordovician Arbuckle Dolomite which is the principal oil producing zone in Central Kansas. This formation, as well as those higher in the section, reflects the general underlying granite structure; however, the Arbuckle top is an erosional surface and most oil producing structures are probably topographic hills. Formations above the Arbuckle in ascending order may include those of the Ordovician, Silurian, Devonian, Mississippian, Pennsylvanian, and Permian periods as well as certain recent sediments. As the Barton Arch is approached, those formations below the Pennsylvanian and above the Arbuckle tend to pinch out until Pennsylvanian rocks, which include the Lansing-Kansas City groups, rest directly upon the Arbuckle. The Arbuckle itself is also completely eroded away at points on the Arch, but is up to 600 ft thick only 20 to 30 miles down dip. Formations of the Pennsylvanian system vary considerably in thickness but probably average about 1,000 ft as an overall total. The more commonly known oil productive zones are the Tarkio, Topeka, Toronto (Dodge), Lansing-Kansas City and Marmaton. Of these, the Lansing-Kansas City, which varies from about 200 ft to 400 ft in thickness, is the most important, since its areal frequency of oil production is exceeded only by that of the Arbuckle. Most Pennsylvanian rocks in Central Kansas were deposited in shallow seas which alternately covered, then retreated from the land. This resulted in recurring cycles of thin beds which cover relatively large areas. Small surface deformations during the period of deposition also caused variations in the type material deposited and its thickness. The local structures of Pennsylvanian time probahlv influenced the accumulation of

Jan 1, 1952

By Loyd R. Kern

A procedure for determining the behavior of a reservoir under a gas or water injection program was reported by Buckley and Levertt in 1942.1 This method, which allowed the calculation of the phase saturation distribution behind the front of a displacing fluid, has been extended to apply to a more general situation. The reservoir may initially contain flowing quantities of the displacing fluid, or the fluid in the reservoir may be above saturation pressure SO that solution effects are present. Production may occur behind the front as in the case of a well which is produced after breakthrough of the displacing fluid. The calculating procedure is simplified in that the graphical integration necessary to determine breakthrough saturation is eliminated by performing a direct integration and the graphical differentiation necessary to determine saturation distribution is eliminated by representing the displacing phase fraction of the flowing stream by an empirical equation. This representation results in simple expressions for the producing gas or water/oil ratio and cumulative production. INTRODUCTION A method for the calculation of the saturation distribution behind the front (interface between the displaced and displacing phases in a gas injection or water flooding operation) was reported by Buckley and Leverett in 1942. The method leads to a curve for the saturation distribution which is double-valued; consequently, part of' the curve was interpreted to be physically meaningless. That part of the curve which has physical significance was determined by a graphical integra-tion (material balance). In this paper it is shown that the integration may be performed analytically with a resulting equation for the saturation of the displacing phase at the front. The case in which the displacing fluid is initially flowing and the case in which the reservoir is initially above the saturation pressure so that some injected gas goes into solution are included in the integration. The calculations are considerably simplified by representing the fraction of the flowing stream which is oil by an exponential function of saturation. The methods is extended to apply approximately to reservoirs in which wells located between the injection well and the front are produced. An illustrative example utilizing the methods presented is included. RESERVOIR BELOW SATURATION PRESSURE In the case of a water flooding operation or in the case of a gas injection operation in which no gas goes into solution in the displaced oil, the equation for saturation in a linear flow system as a function of time and position as given by Buckley and Leverett is where* q = total reservoir volume flow rate, rvb/day A = cross sectional area of system, sq ft / = porosity of formation x = distance from injection point, ft t = time, days Pj = saturation of the displacing phase /dx velocity of planes of constant saturation, ft/day *The nomenclature used here is not the same as that used by Buckley and Leverett A complete nomenclature is given in Appendix A.

Jan 1, 1952

By C. F. Rust

Experimental evidence is presented showing that reproducible formation resistivity factor measurements and resistivity index determinations on reservoir core samples map be made utilizing either the two- or four-electrode methods. Equipment is described which permits the application of either technique to the core specimen without loss of time and with a minimum amount of effort. Since electrical resistivity measurements on reservoir rocks are important not only in electric log interpretations, but also in the study of fundamental rock parameters, it was considered desirable to compare the applicability of both techniques of resistivity measurement. INTRODUCTION The techniques employed in the measurement of electrical resistivity on reservoir rocks, as practiced in the petroleum industry, may be reduced to two fundamental methods: one utilizing two electrodes only, usually referred to as the two-electrode method; the other using two additional electrodes and commonly known as the four-electrode method. In the former, the core sample whose resistivity is to be measured is mounted between two electrodes, usually metal discs, which serve to pass a current of known magnitude through the saniple. The potential drop across the sample, measured between these same two electrodes, and the core dimensions furnish the necessary data to compute he resistivity of the sample. In the four-electrode technique the end plates, again usually ol metal, still serve as current electrodes. Additional probes or electrodes dispersed along the sample are utilized to measure the potential drop. Both methods are used in practice1,2 and it is the purpose of this paper to compare the two techniques as applied to the determination of formation reiistivity factors and the resistivity index exponent n, in Archie's empirical equation I = p/po = Sw 11. To evaluate the two techniques it is desirable to point out the experimental precautions which must be taken to insure reliable results. It is evident from the electrode arrangements of the two- and the four-electrode methods that, for a given sample, the volume of sample included by the four-electrode method is less than the volume included by the two-electrode method. One of the prime difficulties associated with the two-electrode method is the possible occurrence of an abnormally high resistance between the electrodes and the brine-saturated sample, which results in erroneous resistivity values for the core sample itself. Attempts to alleviate this difficulty meet varying degrees of success. Methods used in the past employ such absorbent materials as brine-saturated Kleenex: chamois, or felt. A technique described by Morgan, Wyllie, and Fulton,1 appears to be more satisfactory. Their method consists of spraying or painting the end areas of a core sample with conductive silver paint. This technique reduces contact resistances between the porous medium and the electrodes to a value which is generally negligible as compared to the resistance of the sample itself. In the four-electrode method these requirements are not as stringent since separate probes are used to measure the potential difference acrozs a portion of the sample. In this case, contact resistance occurring at the current electrode; are of no consequence. and those appearing at the potential

Jan 1, 1952

By Wallace W. Wilson

The Cook Ranch Field produces from a very permeable lens of Cook Sand of lower Permian or upper Pennsylvanian age, occurring at an average depth of 1.300 ft. The field was discovered in 1926, and has been operated with low pressure gas injection since July, 1927, one of the first such projects in Texas. Cumulative recovery to Dec. 31. 1950, was 14,701,131 bbl of crude oil, an average of 1,013 bbl per acre-ft of oil rection. and 72.5 per cent of the oil originally in place. Analysis of the reservoir performance indicates that grav-ity drainage has been an important factor in the producing mechanism. The high permeability and uniformity of the reservoir were extremely Favorable tor this type of operation. INTRODUCTION The Cook Ranch Field is the largest of a number of relatively small, shallow producing areas near .Albany, in Shackelford County, Texas. This field is one of the first to be operated by gas injection in Texas, and probably is the most successful low pressure gas injection project ever attempted. The field is owned entirely by Koeser and Pendleton, Inc., and Continental Oil Co., and has been operated by Roeser and Pendleton, Inc., since it was discovered. This study has been made possible through the cooperation of Roeser and Pendleton, Inc.. in making availahle a remarkably complete set of records covering all phases of their operations. The purpose of this paper is to present a summary of the history of the operations through Dec. 31, 1950, and to analyze some of the factors which appear to be responsible for the success of the project. Information concerning the physical plant and the early gas injection history has been presented in an earlier paper.' RESERVOIR CHARACTERISTICS production in the Cook Ranch Field is from a large lens of Cook Sand. of lower Permian or upper Pennsylvanian age, occurring at an average depth of 1.300 ft. The average dip of the sand body, as shown in Fig. 1. is only about 50 ft per mile to the northwest. The reservoir has an area of 930 acres and contains 15,512 acre-ft of Sand, consisting of about 14.512 acre-ft of produc-tive oil zone. and an estimated 1.000 acre-ft of primary gas-cap. The iso-pachous map (Fig. 2) was prepared from drillers' logs. Recent coring in the field has proven these logs to be quite accurate. The productive limits of the field are defined by shale on all sides but the southwest where a small zone of edgewater was encountered. This water does not appear to have encroached into the reservoir, and water production has been small. A smaller producing area to the south of the Cook Ranch Field also produces from the Cook Sand. but is separated from the reservoir under consideration by a band of shale. The sand consists of well sorted, coarse grained. rounded and subangu-lar quartz fragments. very poorly cemented. The analysis of 46 chip-core samples from two recently completed test wells indicates a range of porosity values between 12.5 and 28.2 per cent. wit11 an arithmetic average of 24.0 per cent. Air permeability values range between 50 and 2,300 md, with an arithmetic average of 1.200 md. The reservoir where cored is a Solid sand body. with no discernible major shale breaks or impermeable streaks. Vertical permeability appears to be of the same magnitude as the horizontal permeability. A core of the Cook Sand was cut ill the smaller field to the south, using lubricating oil as drilling fluid. The connate water content of the sand in this core was found to average about ten per cent, and the porosity and permeability were comparable with the values reported above. No analysis was made of subsurface or recombined hydrocarbon samples,

Jan 1, 1952

By R. H. Jacoby, M. J. Rzasa

Experimental equilibrium vaporization ratios (K values) were obtained for nitrogen, methane, carbon dioxide, ethane and hydrogen sulfide in two natural gas-absorber oil mixtures and in two natural gas-Elk Basin crude oil mixtures. For each mixture of constant over-all composition, data were obtained at 100°, 150° and 200°F and at various pressures in the range 200 to 5,000 psia. Some effects of composition on the K values were obtained to serve as a guide in choosing K's for engineering calculations on other mixtures. The pressure cell used to obtain the data is a new type and is described here for the first time. INTRODUCTION The phase equilibria of complex hydrocarbon mixtures such as natural gases, crude oils and their mixtures have been studied previously for the purpose of finding equilibrium vaporization ratios for the hydrocarbon constitutents. In a few cases, such non-hydrocarbon.: as nitrogen, carbon dioxide, and hydrogen sulfide were included in the mixture. studied because they occur. in the fluids obtained from petroleum reservoirs. The increasing occurrerce. of these non-liydrocarbon.; antl their growing economic importance. make it necessary to account for them more accurately in engineering calculation.: than is now possible using the meager published data. The available data for non-hydrocarbons may he classified into two groups: namely, binary mixtures of a hydrocarbon and a non-hydrocarbon. and mixtures containing three or more components, only one of which is a non-hydrocarbon. Amon: the former. phase analyses are available for two nitrogen-HC mixtures, tve carbon dioxide-HC mixtures and three hydrogen sulfide-HC mixtures. Data for more complex mixtures are available as follows: Nitrogen-Methane-Pentane'; Nitrogen-Methane-Hexane,'; Nitrogen-Methane-Heptane'; Carbon dioxide-Natural Gas-Natural Gasorline": Carbon dioxide-Natural Gas-Crude Oil". These data have been used generally lor engineering calculations, often with little regard for their precise applicability because data for the non-hydrocarbons in the complex mixtures being dealt with were not available. The use of K values from binary data for calculation:; involving complex mixtures is open to criticism because such K's are not a function of composition and very often show large differences from the K's for the same components in a complex mixture. Thus the effects of composition must be evaluated when obtaining K's for components in complex mixtures. Poettmann and Katz " varied the carbon dioxide content of their mixture.; from about five to ten mol per cent and found substantially no effect on the K values due to this change. This was not surprising since one might expect that changing a minor com-ponent by * three mol per cent would have little effect. It is more important to find the composition change which have the largest effect on the K values. For example. varying the methane or heptanes — plus compositions over a wide rangr may have a large effect on the K'. of all components in the mixture. Interesting data to this effect were obtained by Eilerts and Smith." It was toward these problems that the experimental data presented here were directed. EQUIPMENT The pressure cell used to obtain the data i:. somewhat dif-ferent from those which have been described in the past. Photographs of the equipment are shown in Figs. 1 and 2. Fig. 1 Shows. the front panel: from a .rated position at the right the

Jan 1, 1952

By V. A. Josendal, J. W. Wilson, B. B. Sandiford

Two radioactive tracers have been tested as a means of determining core saturation in multiphase flow studies. Cesium chloride was tried as a water-phase tracer, but complications in its use in low permeability cores resulted from sorption of cesium by the core or water-wet pads. IodoI3'ben-zene proved very satisfactory as an oil-phase tracer. The synthesis of iodobenzene from the sodium iodide as received from Oak Ridge is simple and direct. The tracer is insoluble in water and there was no evidence of sorption by any of the core materials used. use of the method to determine saturation profiles during capillary and dynamic desaturations and relative permeability measurements on oil-water and oil-gas systems is described. Comparisons of the dynamic and capillary methods of relative permeability determination were made using the tracer to check core saturation and saturation distribution. Other experiments are also described in which mobility of the oil phase at various saturations was measured by displacing labeled oil by flowing inactive oil. Similar experiments were made using water labeled with cesium 134. INTRODUCTION To be fundamentally sound. any laboratory method of determining relative permeability must meet, among others, the following requirements: (1) the core saturation between the pressure taps must be uniform, and (2) there must be uniform pressure difference between the phases in the region between the pressure taps. In practice it may eventually be shown that appreciable departure from either or both of these conditions may be permitted without introducing sensible error. but the magnitude of such error remains to be established. There is need then for methods of saturation determina- tion which will determine the saturation profile in a core as well as the overall average saturation given by the gravimetric or material balance methods usually employed. Methods which have received consideration include resistivity, X-ray absorption, gamma ray absorption, neutron diffraction, and radioactive tracers. The resistivity method has use in the determination of profile, but needs checking by independent means.' The X-ray method has been used successfully, but requires elaborate equipment and calibration.23 4 At present gamma ray absorption is practical only for very large cores. The neutron methodo does not appear adaptable to measurement of saturation variations in short cores since it is a scattering method. Russell, Morgan and Muskat' employed radiovanadium in a study of the mobility of interstitial water. Coomber and Tiratsook used radioiodine as an oil-phase tracer and measured profiles in unconsolidated sand packs. ADVANTAGES OF RADIOACTIVITY METHOD A thorough discussion of the theory of radioactive tracers and the technique of using them to study the movement of fluids in sands is given by Coomber and Tiratsoos and need not be detailed here. The method requires less equipment than the X-ray method; the counting problem is similar, but the generation and regulation of the radiation, which is a major problem in the X-ray method, is not required in the radioactivity method. In the X-ray method it is customary to add up to 20 per cent of absorber, usually an iodine compound, to the phase to be labeled. while in the radioactivity method a mere trace is sufficient. A possible disadvantage of the radioactivity method is that a disproportionate amount of the activity comes from the portion of the core nearest the counter, whereas the X-ray gives a true average saturation in the region traversed by the beam. 011 the other hand, this characteristic of the radioactivity method renders it peculiarly adaptable to study of certain types of radial variations in saturation. As with the X-ray method, a tracer may be added to either the oil or water-phase. An oil-phase tracer is more generally useful. however. since it permits work on oil and gas in the

Jan 1, 1952

By J. K. Kerver, J. S. Osoba, J. G. Richardson, J. A. Hafford

A detailed study of a number of methods of relative permea-abilitv measurement has been made in a search for the tech-niqrle most suited to routine analysis of cores taken from reservoir rock. It has been found from tests run on the same samples of core material by a number of techniques that the Penn State, Hassler, Hafford, and dispersed feed techniques all yield results which are felt to be reliable. Conditions under which the faster single core dynamic technique may be used are described. Further work on the calculation of relative permeabilities to oil from data obtained by the gas drive method is needed before this latter rapid method can be utilized. Correlations between theoretical studies and experimental results have been obtained in studies of the boundary effect. pressure distribution in two-phase flow, and gas expansion effects. Previous conclusions that the effects of the outflow boundary could be made negligibly small have been substantiated. Results of experimentally determined oil and gas pressure distributions along a core sample during flow are presented. Further studies of the effects of rate of flow in the measurement of relative permeability-saturation relations have shown that results are independent of the rate of flow as long as the flow rate is below the point where inertial effects commence. An analysis of the effects of a severalfold expansion of gas along the flow path indicates that while saturation gradients are induced in the test sample, the errors caused by this phenomenon in relative permeability measurements are small. INTRODUCTION Many pages of literature have been devoted to pointing out the need for relative permeability-saturation relations in reservoir engineering. One of the most attractive ways of obtaining this information is by the analysis of samples of core material taken from the formation in question, and again literature has described man); methods for obtaining these data. It is the purpose of this paper to present the work that has been done in the study of some of these published methods together with some other methods that have been recently developed in this laboratory. Also, a study of some of the factors that influence the laburatory determination of relative permeability-saturation relations is presented. FACTORS WHICH AFFECT LABORATORY STUDY OF FLUID FLOW THROUGH RESERVOIR ROCK To determine relative permeability-saturation relations of samples of reservoir rock in the laboratory, it is important to know what factors affect these measurements in order that the magnitude of these effects can be ascertained and steps then can be taken to eliminate or, in some cases, to minimize them. The factors that have been investigated are the boundary effect, the effect of gas expansion. and the rate effect. Boundary Effect In laboratory experiments in which two immiscible fluids are flowed through a porous medium, there exists a discontinuity of capillary properties at the outflow face. This discontinuity exists became the fluids pass from a region of finite capillary pressure in the sample to a region of zero capillary pressure in an open receiving vessel. The capillary forces existing in the core caupe the rock to tend to retain

Jan 1, 1952

By R. L. Slobod, H. A. Blum

A semiquantitative method for measuring the wettability of reservoir rocks has been developed. These data are needed for reservoir analysis and for interpretation of laboratory displacement studies. The wettability of a core sample is measured by the contact angle for the system oil-water-solid. These contact angles are calculated from the displacement pressure (threshold pressure) obtained by use of the centrifuge, using first oil-water and second air-oil in the same core sample. This method is based on the assumption that the air-oil and oil-water interfaces occupy similar positions in the porous medium when desaturation of the wetting phase is initiated. The assumption is also made that the Contact angle for the air-oil-solid system which is close to zero in value does not change appreciably even when the contact angle for the oil-water-solid system experiences marked changes. "Apparent contact angles'' for five different solids ranging from 31" to 82" have been determined, and changes irr the "apparent contact angle" of a given sample with laboratory use from 33" to 53' {lave been observed. INTRODUCTION Reservoir rocks vary in their wettability, 1,2,3,4 some being preferentially water wet while other are apparently preferentially oil wet. The degree of wettability, in theory, is measured quantitatively by the contact angle for the system solid-oil-water, hut in 1)practice this quantity is extremely difficult to determine." The need for obtaining some measure of this quantity has become obvious in recent years as a result of both laboratory. and field observations. Several reservoir.: such as the Bradford Sand in Pennsylvania and the Wilcox' at Oklahoma City are reported to be oil wet. If these report:: correctly reflect the true nature of the surface of the rock in the ground, then these reservoirs probably will not perform as predicted on the basis of a water wet rock. In the laboratory many core samples have been Observed to be oil wet. These samples, while perhaps not correctly representing the reservoir, have markedly different properties from water wet rock. The location of the phases is different (oil is in contact with rock instead of water), and other quantities such as the connate water, the capillary pressure curve; residual oil. relative permeabilities. and the recovery of oil by water flooding are markedly affected by the value of the contact -4 A further complication observed in the laboratory is the chang-ing of the wettability of a rock specimen with use. such changes mean that repeat runs on the same core are not the duplicate tests desired, but represent new experiments on a more oil wet material. The changes in surface characteristics are sometimes so rapid that by the time an experiment requiring several days is completed, the results may not be representative of the core as originally described, The, rock material itself (Silica. carbonates. etc.), whell Clean and uncontaminated, is water wet. There seems b( : little evidence of the presence of oil wet minerals such as heavy metal sulfides. The oil wetness of reservoir samples, therefore, is believed to be caused by the accumulation of an adsorbed film in which the polar group of a large organic. molecule is adsorbed on the surface leaving the organic or hydrocarbon part of the molecule projecting out from the solid. Such a surface is much more readily wet 17" oil than by water. These considerations indicate the need for a method which will provide some measure of tile wettalbility (Contact(angle if possible) for reservoir rock ..samples) The method should be capable of (1.1 distinguishing between tile wettalility of dif. ferent formation,.. (2) detecting (change. ill wettalbility of a core with use. and (3) measuring the changes in Wettability which may be accomplished with cleaning operations. such as the use of sodium silicate for increasing water wrettalbility." A preliminary report on such a method is preseted below. not with the idea that this procedure alone will Solve the wettabil-ity problem. but rather that it may provide encouragement to

Jan 1, 1952

By J. S. Aronofsky

The results of polentiometric model studies and numerical computations are described. The purpose of these studies was to determine the influence of the mobility ratio on flooding efficiencies during water encroachment in petroleum reservoirs, in systems of regular well geometry. The direct line drive well pattern having relative spacing distances of one and one-half to one was investigated for water to oil mobility ratios of 10. 1. and 0.1. The results of these studies indicate that the pattern Sweep efficiency i.; very dependent upon the mobility ratio. INTRODUCTION The almost universal occurrence of water in the immediate neighborhood of oil-hearing sands lends considerable emphasis to the desirability of having a rational analysis of water encroachment into petroleum reservoirs. This problem has 1)become increasingly important with the accelerated use of water injection for secondary recovery operations. The water encroachment problem has been studied from both the theoretical and experimental viewpoints by Muskat.' He has formulated, in a precise manner, differential equations to express flow in a water encroachment system, and rigorous analytical solutions have been developed for the linear, radial, and spherical cases.' However, it becomes exceedingly difficult to solve the encroachment problem rigorously for any general two-dimensional system in which the shape of the two-fluid interface is not immediately evident from the geometry of the system. The difficulty lies in the fart that a rigorous analytical solution requires that the shape of the two-fluid interface be known simultaneously with its instantaneous posititon and with the pressure distribution on both sides of the interface. Although this paper concerns the study of the two-fluid system of oil and water. the methods described in the paper are generally applicable to other systems of incompressible and immiscible fluids in which the displacing fluid sweep-the displaced fluid down to a residual value. In each region it is assumed there is only one mobile fluid and its mobility is constant throughout the region. The Same procedure. with minor alteration, is applicable for gas injection systems provided the assumption can be made that both the displaced and displacing gases can be described by steady state formulas. For the particular two-fluid problem considered in this paper, there is a relative permeability. K, and a viscosity. p. associated with the water zone, and a different permeability and viscosity associated with the oil zone. The K/p (mobility value associated with a particular volume element of the porous medium. at any instant of time. will depend upon whether the element is ahead of. or behind the advancing interface. It is assumed that all volume elements ahead of the interface are characterized by the K/p value for oil, while all the elements behind the interface are characterized by the K/p value for water. That is. the K/p value in the oil zone is constant throughout the oil zone. and the K/p value in the water zone is also constant but different from the value in the oil zone. The symbols are defined at the end of the paper. The well pattern chosen for initial study is the direct line drive; the swept-out area at breakthrough was determined by two different methods which are described in the section on theory. These are: 1. Potentiometric analyzer 2. Numerical computation The use of the potentiometric analyzer for studying water flooding problems is adequately described in the literature, particularly for cases where the mobility in the water zone is assumed equal to the mobility in the oil zone." ' 5

Jan 1, 1952