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By K. J. Kutz, F. A. Nice

Drilling of the second shaft at Texas Gulf Sulphur Co.'s Cane Creek potash operation southwest of Moab, Utah, is perhaps the largest undertaking ever made by private industry in the field of rotary shaft drilling. The new shaft, known as No. 2, is located within the plant area, about 400 ft northeast of the No. 1 shaft. This location within the pillar of the first shaft allowed utilization of a great deal of in- formation gained prior to and during sinking of the original No. 1 shaft, a conventionally sunk 22-ft diam shaft 2789 ft deep. The No. 2 shaft will be used for auxiliary transportation of men and supplies, and is steel lined with a 48-in. ID casing. The top 825 ft of the shaft is in predominantly red sandstone with interbedded shales. From 825 ft to 2800 ft, which is the top of the salt beds, the rock is mostly limestone with interbeds of anhydrite and shale.

Jan 9, 1968

By J. Fred Johnson

COROMANT is the trade name of the alloy-steel drill rod tipped with a chisel-type tungsten-carbide bit manufactured by Sandvik Steel Works Co., Ltd. Other names, such as Swedish or air-leg method of drilling, are used in various localities. Coromant drilling in Sweden was the natural sequence of the adaptation of tungsten-carbide inserts to the already established routine of drilling. By the middle thirties the percussion drill had reached practically its highest attainable efficiency as a drilling machine. Since then improvement has been in metallurgy of component parts to increase life or lessen weight, in the development of pneumatic and automatic feeds, in the use of jumbos to more quickly and easily handle machines, and in changes in drill rods and bits. By 1937, drilling in the United States and Canada was done by relatively heavy mounted drifters with positive hand or automatic feeds. In Sweden, on the other hand, emphasis had been placed on light equipment and drifting was done with pneumatic bars and reverse-feed stopers. In 1938, one of the most prominent American drill manufacturers developed an air-leg for successfully drilling the extremely variable but relatively soft iron ores of some of the northern Michigan mines. Also in 1938, a comparative Swedish test, also in soft iron ore, of a 50-lb jackhammer mounted on an air-leg, against a 100-lb reverse-feed drifter on a pneumatic bar, showed the net drilling time was increased by the air-leg set-up from 51 to 71 pct, in drilling 6-ft rounds in a 6 1/2x6 1/2 ft drift. Miners were becoming scarce in Sweden even at that time and, since the lighter equipment made the work easier and more attractive, the airleg was then made use of in some types of soft rock. In 1940, for instance, a large tunnel for a hydroelectric plant was driven with this equipment. By 1943, when tungsten-carbide inserts came into the picture in Sweden, a great many of the kinks in percussion drilling with this hard-metal had been worked out in Germany under the stress of war conditions. However, only 10 pct of the drilling machines manufactured in Sweden were jackhammers for use on air-legs and only the one manufacturer made air-legs in the United States. American practice had largely supplanted integral forging of drill bits by the detachable steel bit. Canada and South Africa were using the one-pass throwaway bit but Sweden was still using the same old integral forged bit. After a long study of the trend toward simplicity

Jan 1, 1952

By William B. Hughes

The rubber-sleeve core barrel was developed to improve core recovery from unconsolidated sands, where it is most difficult to obtain cores with conventional barrels. The use of a rubber-sleeve core retainer, together with other departures from clsual design, has required a considerable amount of testing to prove its op-erability. Tests run in shallow experimental holes and in drilling wells in the U. S. and Vemzuela have, to a large extent, proved the operation of the barrel. Internal mechanism troubles, such as sandbinding of the sleeve, have been largely overcome. Cores have been recovered from completely unconsolidated sands where conventional coring has almost been abandoned because of poor recovery. In addition to retaining the core until brought to the surface, the barrel gives a "packaged-ar-cut" core, which is coilverzient for handling and transportatiorz. In the initial work, drag blade cutters, roller cutters, and tungsten carbide insert cutters were usrd for cutting unconsolidated sands. Further bit head development is presently being conducted using diamond heads in unconsolidated sands where shaler, hard sands, and limestones are encountered in adjacent formations. Thir work should render the barrel capable of cratting and recovering most types of formations, possibly including broken and frac- tured fornlations. This development is being carried on in cooperation with a diamond bit manufacturer. INTRODUCTIO N For many years the oil industry has needed greater recovery of cores from unconsolidated formations. Conventional equipment has been used to core unconsolidated sands with little success. Specifically, a core barrel was needed which would recover unconsolidated sands in a condition that would give useful reservoir information. DEVELOPMENT OF 'THE RUBBER-SLEEVE CORE BARREL Basic Requirements of Unconsolidated Sand Corino The basic need was defined as a core barrel that would obtain a continuous unconsolidated core with sand grains in place as deposited in the formation. A preliminary survey of coring equipment and search of the literature pointed out the weaknesses of conventional core barrels. Laboratory tests using unconsolidated sand in a metal tube simulated actual sand movement into the core barrel during conventional coring. In conventional barrels the core sometimes crumbles and bridges, or fails under compressive column action, becomes oversize, and wedges against the walls of the inner barrel. The core barrel requirements established by the surveys and preliminary tests are as follows. 1. The core should be held to- gether as it is cut so it cannot crumble and bridge against the walls of the coring tool, care being taken not to permit damage from fluid circulation. 2. The core should be continuously supported as it is cut so it will not have to support itself in compression. 3. The core should be packaged in the barrel to retain an undisturbed condition during the trip out of the well. The packaging should be such that the core can be removed from the barrel and shipped to the core analysis laboratory without physical disturbance or alteration of fluid content by exposure to the atmosphere. Operation of the Rubber-Sleeve Core Barrel The rubber-sleeve core barrel (Fig. 1) meets the basic requirements for the recovery of unconsolidated sands.

By B. E. Eakin, R. T. Ellington

An apparatus and a procedure for determining the viscosity behavior of hydrocarbons at pressures up to 10,000 psia and temperatures between 77 and 400° F are described. The equipment is suitable for measuring viscosity of either the liquid or vapor phases or the fluid above the two-phase envelope for systems exhihiting retrograde phenomena, according no the phase state of the system within these ranges of temperature and pressure. Equations are developed for calculation of viscosity from the experimental measurements, and new data for the viscosities of ethane and propane at 77° F are reported. INTRODUCTION With the advent of higher pressures and temperatures in industrial processes and deep petroleum and natural gas reservoirs, demand has increased for accurate values of physical properties of hydrocarbons under these conditions. Proportionately, more frequent occurrence of natural gas and condensate-type fluids is encountered as fluid hydrocarbons are discovered at greater depths. This increases the importance, to the reservoir engineer, of being able to predict accurately the physical properties of light hydrocarbon systems in the dense-gas and light-liquid phase states. Reliable gas viscosity data are limited primarily to measurements made on pure components near ambient temperature and at low pressures. Few investigations have been reported for high pressures, and except for methane, data on light hydrocarbons are subject to question. This is demonstrated by the large discrepancy between sets of data on the same component reported by different investigators. For mixtures in the dense gas and light liquid regions and for fluids exhibiting retrograde behavior there are very few published experimental data. Viscosity data for methane have been reported by Bicher and Katz,1 Sage and Lacey,12 Comings, et al,3 Golubev,3 and Carr,3 with good agreement among the last three sets of data. Comings, Golubev and Carr utilized capillary tube instruments for which the theory of fluid flow is well established. The theory permits calculation of the viscosity directly from the experi- mental data and dimensions of the instrument alone. Sage and Lacey, and Bicher and Katz used rolling-ball viscometers. The theory of the rolling-ball viscometer has not been completely established, and these instruments presently require calibration by use of fluids of known viscosity behavior before viscosities of test fluids can be measured. To obtain accurate data it is necessary that the rolling-ball viscometers be calibrated by use of fluids of density and viscosity similar to the test fluids, a difficult selection for the gas phase. From the methane data and experimental tests on various natural gases, Carr developed a correlation for predicting the PVT behavior of light natural gases.2,3,4 This correlation was based on data for a very limited composition range; its application to rich gases and condensate fluids is questionable. The object of this investigation is to develop an instrument which can be used to obtain viscosity data at reservoir temperatures and pressures, for rich gases, condensate-type systems above the two-phase envelope and light liquid mixtures. These data will be used in an effort to develop correlations to represent the viscosity behavior of these fluids. APPARATUS In a previous viscosity study Carr2 utilized a modified Rankine capillary viscometer configuration," Fig. 1. In this instrument the gas to be tested is forced through the capillary tube in laminar flow by motion of a mercury pellet in the fall tube, the measured displacement time being that required for the mercury slug to move between the brass timer rings. The viscometer is constructed of glass and mounted in a steel pressure vessel. The test gas pressure in the viscometer is balanced by an inert gas (usually nitrogen) in the vessel. Excellent results have been obtained with instruments of this type, with Carr2 and Comings5 reporting repro-ducibilities of 99.5 to 99.3 per cent and an estimated absolute accuracy of 99 per cent. However, these instruments have limitations which have precluded their use for liquids. The need for maintaining a balance between pressures of the test fluid and inert gas in the viscometer vessel presents operating problems, and requires charging the test fluid to the viscometer very slowly. The principle drawback to the Rankine unit is behavior of the mercury slug which provides the pressure differential across the capillary. When even trace quantities of propane or heavier hydrocarbons are present in the test gas, the mercury tends to subdivide

By E. Amott

A test is described in which the wellubility of porous rock is measured as a function of the displacement properties of the rock-water-oil system. Four displacemet operations are carried out: (I) sponlaneous displaceti?ent of water by oil, (2) forced displacement of water by oil oil in the same system using a centrifuging procetllrre, (3) spontaneous displacement of oil by water. and (4) forced displacment of oil by water. Ratios of the spontaneous displacement volumes to the total displucenlent volumes are used as wettability indicates. Cores having clean mineral surfaces (strongly preferentially water-wet) show displacement-by-waler ratios approaching 1.00 and displacement-by-oil ratios of zero. Cores which ([re. strongly preferentinlly oil-wet give the reverse resu1ts. Neutral wellability cores show zero values for both ratios Fresh cores from different oil reservoirs have shown wettabiltties in tlris te.st covering rrlti~ost 111e conlplrtt, range of thr: te.st. Notvever, nlo.s/ of tlle fresh California cores tested were slightly prcfere111icrlly wclter-\vet. The chrrnge.~ in coro u ('liabilities, as indicated hy this te.st, r~.sril/ing from various CO~P hanrlling procedures tt,ere oh.served. In sonie ca.sc,s /Ire ~,cttahilitio.c. of fresh cores were changell by drxi:~g or 11y e.x/rclct ing with iolcreiii~ or. dioxunc~; in o/h~r cases they were 1101 changed. Co~ltrrc/ of cort,.s ~.ith filtrc~t~c. from water-base rlrilling rilrrrls crlrc.sed littlc change in we/ /ahility ivhile contnct with filtrates frorii oil-hus~ ri1rlcl.s tlecrrascrl the prefcrerlcc, of the, cores for )I.NI Usitig thi,s test to ri.crl~lute n~r~ttubili~y, N .vt~ldy was iilarle of /lie correlmtio~i of wettability with wa/erfloocl nil recovery for orttcrop Ohio sand.stone and for Al~ln-tlunl. Resul/.v indicate thml no single correlatioti between these factors applies to different porous rock syste~n. It is thought that diflerences in pore gen~netry resrrlt in diflrrerrce.~ in this correlurio~z. INTRODUCTTON Most investigators who have reported on the wettahility of porous rock have described such rock as prcferentially water-wet or preferentially oil-wet. In some cases a third classification, neutral wettability. has been used. The efficiency of water floods in each of these wettability groups has been described in numerous publications. Several methods for characterizing porous rock wet tability more precisely have been reported,' " but it appears that because of one weakness or another. none of these has been generally accepted. Early in our studies in this field, it was found that the displacement efficiency of oil by water in a particular porous rock having a strong preference for water was quite different from that in a similar rock having only a moderate preference for water. Thus, there appeared to be a need for a practical, reasonably precise wet tability test. one which could classify porous rocks into 10 to 20 different groups rather than the two or three broad groups listed above. The test developed to meet this need is described in this paper. Also, changes in wettability, as indicated hy this test, resulting from various core handling procedures are discussed. Finally, data showing the corrclation of wettability with waterflood oil recovery for two different types of cores are presented and discussed. Some confusion has resulted from the failure of certain writers to define clearly some of the wettability terms they have used. Accordingly, the following commcnts concerning definitions are offered. The wc t ta-hility of a solid surface is the relative preference of that surface to be covered by one of the fluids under consideration. It is felt that this is the generally accepted definition. The fluids being considered must bc specified (or understood) before the term wettability has any significance. In the work reported here these fluids are water (3 per cent brine) and oil (kerosene). The term preferential wettability is sometimes used, but we think that the word preferential is redundant here and should not be used. Tn line with the definitions of Jennings', a preferentially oil-wet solid surface is regarded as a surface which will show an oil advancing contact angle less than 90" (measured through the oil) in the water-oil-solid system. Oil will spontaneously displace water, if both are at the same pressure, from such a surface. A preferentially water-wet surface is analogous. This is consistent with the wettability definition above. As Jennings has said, frequently the term oil-wet is used to mean the same thing as preferentially oil-wet. However, oil-wet also has been used occasionally referring to an oil-covered surface when the availability of water was limited. To avoid confusion from this source, we do not use the terms oil-wet and water-wet. DESCRIPTION OF WETTABTLITY TEST The following points were considered desirable in a wettability test for our purpose. 1. The test should be a displacement test resembling

By A. B. Hildebrandt

P. B. Baxendell is to be complimented for an exccllent piece of work. To our knowledge there has been no previous publication of field data on the flow of oil and gas through the annulus of a well. It is certainly gratifying to see this work on annular flow confirm the previous published correlation procedure on tubing flow. It extends considerably the range under which reliable gas-lift calculations can be made. Baxendell discussed this work with us about a year ago and was kind enough to send a large scale plot of his correlation. We had been designing gas-lift installations on flow through the annulus, assuming that the original correlation of the f factor based on tubing flow' was valid as long as we stayed within the same mass velocity range on which the correlation was based. Doing this work necessitated the use of an equivalent diameter for the annular flow. The equivalent diameter is defined as area' of stream cross section wetted perimeter and for the case of an annulus is D, — D,. Substituting this in the basic equation correlating energy loss along with the area to flow required to convert the velocity, to volumetric flow rate, D (Baxendell's Eq. 7) becomes dell's expression, D,). Similarly, the D in 1.4737 X 10 (M&/D) becomes (D, + D;) for annular flow. On receipt of Baxendell's data, we. of course, recalculated it to put it into the form we were using, and to see how well it agreed with the correlation based on tubing flow. Fig. 1 shows the results, which were certainly gratifying. For low values of (D, - D,) pv, the data coincide with the data on flow through tubing, whereas at high values the data on flow through the annuli appear to be leveling off to a constant value. For very high rates of flow where the turbulence is very high, one might expect the value f to level out and become constant. A bulletin published in 1914 by the U. of Wisconsin presented results of a large number of laboratory teats in air lifting water through short lengths of 1.25-in. tubing. It was possible to correlate a random sampling of

By E. Topanelian

In recent years considerable progress has been made in the development and application of mathematical techniques for the solution of certain problems involving economic "strategies". Such a problem might involve, for example, the scheduling of shipments of a commodity from a number of sources to a number of destinations. The object would be to schedule the shipments in a manner so as to satisfy the destination requirements and at the same time minimize the transportation costs. The solution to such a problem is not necessarily intuitively obvious. The "obvious" solution is frequently far from optimum. If the shipments are to be made from, for example, only two sources to four destinations, the optimum schedule is readily found. However, if shipments are to be made from, say, 10 sources to several hundred destinations, even a competent and experienced scheduler may spend considerable time in finding a reasonable answer. Even then he is not sure that he has the optimum solution. Furthermore, he has no way of knowing how far from optimum the answer is. Consequently, he does not know whether he should accept this solution or seek a better one. Prior to the advent of large high-speed digital computers, little more could be done with such problems because of their great size and multiplicity of possible solutions. A problem involving 20 sources and 50 destinations would require choosing, from a very large number of possible combinations, the optimum combination of 1,000 variables. The best one could do was to utilize intuition, extrapolation from past experience, and other non-exact approaches. With a high-speed computer, however, such problems can be solved providing a reasonable computational procedure (or algorithm) can be utilized. The purpose of this paper is to describe such a procedure (linear programming) and to apply this procedure to a production scheduling problem. THE RESERVOIR PROBLEM A simple reservoir model is used throughout this analysis to illustrate the use of linear programming. Even the simplest reservoir behavior problem is nonlinear in both space and time, but if the geometry is fixed for a particular study and the time variable is quantized, the resultant system may be described by linear constraints on the variable production rates. Crude oil is available from five separate sources and is delivered to a pipeline. Sources 1, 2, 3 and 4 are ideal reservoirs and therefore are subjected to reservoir flow restrictions. Source 5 is labeled "Outside Source" and crude oil from this source is assumed to be available in unlimited quantities without considering reservoir conditions. The general problem is to determine the schedule of crude oil production from five sources which, over an eight-year period and subject to certain restrictions, will result in maximum profit. "Profit" is defined to encompass all economic factors and expenses involved in producing and selling crude oil to a pipeline facility. Such economic factors are lumped to the extent that the term represents the dollars profit from one barrel of crude oil from any of the five sources entering the pipeline system. Table 1 presents the assumed profit per barrel for oil from any of the five sources over each of the four time periods. In this chart the eight years is broken into four equal intervals of two years. The selection of four time periods of two years each and the values representing the potential profit are completely arbitrary selections for the purpose of illustrating this idealized reservoir problem. In any practical application of this work a careful economic study would have to be made in order to estimate potential unit profits for time periods as far in the future as eight years. In this particular study it is assumed that all of the potential unit profits (C) are known and fixed before the production schedule is attempted. For each reservoir arbitrary values are assigned for

By John R. Eckel

A Iaboratory drilling rig has been devised and placed in operation which permits the application of hydrostatic, terrastatic, and formation pore pressures to a rock sample for drilling under controlled conditions. Calibrated rests of this equipment in-dicate qualitative agreerment with field results on the effect of weight on bit, rotary speed, and rate of circ~~lation on drilling rate. Tests under pressure, using water and air as the drilling fluids, indicate that when drilling saturated limestone samples, a pressure differential between hydrostatic and formation pressure is the only pressure which affects drilling rate. A differential in either direction causes a reduction in rate, but the same diflerential from the wellbore into the formation causes the greater reduction. Also, in lime.stone, air favorably affected drilling rote only when compared to water at high hydrostatic pressurre, all other conditions remaining constant. Large increases in drilling rate with air could be obtained in the laboratory only while drilling a shale, which offered a limited permeability to nitrogen and which could be drilled with a differential from the formation into the wellbore. In general, the magnitude of the changes due to the pressure effect were small compared to changes in drilling rate obtainable by changing either bit weight or rotary speed. INTRODUCTION In the course of Humble's drilling research program, the desirability of investigating several factors which lend themselves to laboratory rather than field study became obvious. Principal reasons for this are the expense involved in field studies and the difficulty of exercising the required degree of control. Of primary importance are investigations of the effect of fluid pressure on rock rate, the effect of pressure on rock drillability, and a study of the fundamental mechanics of rock failure and chip generation. Several years ago some work in the laboratory on the effect of mud properties on drilling rate was re- ported to the API', but the completion of this work and the investigation of the other variables affecting drilling rate required equipment somewhat more elaborate than that used on these earlier tests. This equipment has been assembled to form Humble's Drilling Engineering laboratory. To date only the effect of pressure on rock drillability while using water and air has been investigated, and this work is not yet complete. Facilities are available to investigate the effect of fluid properties on rate of penetration, and information is being assembled on a current basis on the mechanics of drilling. The sequence of presentation in this progress report is somewhat different from that in which the data were obtained since the order of ex-

By C. van der Poel, R. L. Chuoke P. van Meurs

When an initially planar interface between two im-ttitcihle liquids is displaced at constant rate, U, nor-mat to the front, instability will occur for all rates greater than a critical rate. U, given by provided the Fourier decomposition of the spatial pertmrbcrtiott or deformation of the moving displacetment front contains modes with wavelengths. A, greater than a critical wavelength, given by tit there expressions, p, p and k, with the subscripts I and 2 distinguishing the two 1iquids under consideration, are density, viscosity and effective pemeability coefficients respectively; g is the absolute value of the acceleration due to gravity; and cos (zz') is the direction cosit7e between the vertical carlesian coordinate z' (positive upward) and the z coordinate norma1 to the initially plane macroscopic interface taken positive in the direction from Liquid I to Liquid 2. U is the average volumetric velocity (injected volume of liquid pet. unit time per unit of area normal to Z) and is positive for Liquid I displacing Liquid 2, negative for the reversc displacement and r2 is an effective inter-fucial tension (for displacements between parrallel plates, t0= s the ordinary bulk interfacial tension). further, there is a wavelength of maximum instability given by For natural perturbations, this wavelength will preclotninate and characterize the form of the instability as a quasi-sinusoidal deformation, i.e., viscous fitzgers of peak-to-peak separatiotr, A,,. Comparison of experitient with theory rei'eals tltat these considerations are recsonably valid for displacements in hoth parallel plate chantzels and nnconsoli-clutt'd glass ptnvder packs. These results are. tij particular interest for interpretation of data from laboratory experiments with regard to fielil applica/iotz.s. It is quite possible for A,, although st7zall relative to the large lateral dimension of the reservoir, to rxceed the greatr.st lateral extent of the lahoratory sample or model. If it does, frontal displace- ment occurs in the laboratory experiments, and oil INTRODUCTION Thc puposes of this paper are to present theoretical and experimental evidence for occurrence of macroscopic instabilities in displacement of one viscous fluid by another immiscible with it through a uniform porous medium and to compare available experimental data with some predictions of a theory of instability developed by the first author. The instabilities are referred to as macroscopic in the sense that spatially quasi-sinusoidal, growing fingers of the displacing liquid are formed, the width and peak-to-peak separation (wavelength) of which is large relative to a characteristic length of the particular permeable medium such as grain size. Visual models of two kinds have been used to obtain observations: displacement of oil by water-glycerine solutions through the flow channel formed by closely spaced parallel plates and displacement of oil by water with and without initial interstitial water through unconsolidated glass powder packs, employing the technique of matching indices of refraction. In all cases we have observed macroscopic instabilities or fingers under conditions predicted by the theory to be favorable for their occurrence. The phenomenon discussed here is not the production of streamers due to gross inhomogeneities such as permeability stratification of the porous medium. It is our object to show, on the contrary, that a quantitative prediction of finger spacing is possible in a porous medium known to be macroscopically homogeneous and isotropic throughout. The importance of the phenomenon in its influence on the configuration of oil and water with respect to oil production behavior was noted earlier by Engel-berts and Klinkenberg' who coined the term "viscous fingering". THEORY Necessary and Sufficient Conditions ior Instability anc Initial Kinematics There are several levels of increasing complexity in the theoretical description of instabiIity of fluid displacements in permeable media. Of these, the simplest description, ;tdapted to low permeability systems, is selected for presentation.' More inclusivc tlescriptions are reserved for separate publication.

By A. E. Anderson, H. J. Hilll

Laboratory data for 155 field muds and 77 .shales have been used to develop correlations to estimate the net streaming potential component of the SP. Analysis of these data and comparison with field tests show that streaming potential corrections must be made to obtain an accurate estimate of the electrochemical potential for use in the determinntion of formation water resi-iiviy. The self-potential curve is related to formation water resistivity, and considerable effort within the oil industry has been directed toward clarifying this relationship. The Schlumbergers and Leonardon1,2 recognized that two types of potentials, electrochemical and electro-kinetic, resulted in the net potential variation in the borehole. Most of the later papers have dealt with the electrochemical component and its controlling parameters. The investigations of Wyllie,2" Salisch' and Moore5 provide the most extensive sources of data on streaming potentials across mud cakes. These authors observed streaming potentials of sufficient magnitude to be of critical importance in SP interpretation, if it is assumed that streaming potentials develop only opposite permeable beds. Streaming potentials across shales have been reported by Schenck and by Gondouin, et al.7 Since SP magnitude is the difference in potential opposite shale and sand beds, these authors suggested that the net streaming potential component may be negligible. The present investigation was initiated to evaluate empirically some of the parameters controlling the magnitude of the net borehole streaming potential and to determine whether useful relations between mud properties and net streaming potential could be established. Field muds were used in this investigation. These muds were characterized by the amount and type of chemical treatment utilized for five days before Sampling. Filter loss, mud resistivity, mud density and filtrate resistivity were determined for each mud with conventional methods and apparatus. Mud filtrate pH was estimated with Hydrion pH paper for the appropriate range. Streaming PotentIals Across MuD Cakes Commercial calomel-saturated KC1 electrodes are subject to potential changes attributed to contamination of the very small fiber-tip bridge by particles of clay from the drilling mud.3 To minimize this difficulty, a large diameter bridge (Fig. 1) was constructed with saturated KC1-agar gel and a filter disc of microporous porcelain. Experiments showed that streaming potentials across this bridge are less than 0.2 mv at pressure dif-

By R. J. Blackwell, J. R. Rayne, W. M. Terry

This paper presents results of an experimental investigation of factors that control the efficiency with which oil is displaced from porous media by a miscible fluid. The study was made to elucidate the relevant processes both on microscopic level (within individual or between neighboring pore spaces) and on macroscopic level (within a large sand body). Mixing of miscible fluids on the microscopic level was studied in sand-packed tubes. It was found that molecular diffusion is the dominant dispersion mechanism for reservoir conditions of rate, length and pore sizes. Macroscopic channeling was studied for various mobility ratios in reservoir mode1s scaled to relate viscous, gravitational, and diffusional forces. The formation of channels was due to viscous firzgering, gravity segregation and variations in permeability. With adverse mobility ratios, it was found for reservoirs of realistic widths that diffusion will not be effective in preventing the formation and growth of fingers, even in homogeneous sands. At sufficiently low rates channeling was eliminated by gravity segregation in tilted reservoirs. The dependence of recovery on mobility ratio, length-to-width ratio, flow rate and angle of dip is presented. INTRODUCTION Oil recovery by solvent flooding is finding increasing application in the field. While the process promises high recoveries from the region swept by solvent, under adverse conditions only a small fraction of the reservoir volume may be swept at the time solvent breaks through to the producing well. Further, the high cost of the solvent encourages its use only as a bank whose size must be kept at a minimum. Thus, two important questions arise: (1) what fraction of the reservoir can be swept, practically, by solvent? and (2) what is the minimum size solvent bank that can be used to carry out the displacement? The answers to these questions require knowledge of both macroscopic channeling processes and microscopic mixing processes. The studies described here were carried out to gain this knowledge. Microscopic mechanisms which cause mixing will be discussed first, because an understanding of these mechanisms is necessary for proper interpretation of the experimental work on channeling described later. INVESTIGATION OF MICROSCOPIC DISPLACEMENT PHENOMENA FOR MISCIBLE FLUIDS The questions to be resolved concerning microscopic displacement behavior are: (1) how much mixing occurs between oil and solvent in the direction of flow? and (2) does the solvent completely flush the oil from the pore spaces in the region invaded by solvent? The classic work of Sir Geoffrey Taylor' and its extension by Aris2 have shown that it is possible from theory to describe the amount of mixing in single straight capillaries when solvent displaces a fluid of equal viscosity and equal density. Aris showed that the lengths of the mixing zones, 81, corresponding to the 10 per cent and 90 per cent concentration levels of the solvent can be calculated from the formula, 81 = 3.62 \/Kt, .........(1) where 8l is the length of the mixing zone, cm; t is the time, sec; and K is the effective dispersion coefficient, cm2/sec, given by K/D = 1 + (1/48) (au/D)2......(2) where a is the radius of the capillary, cm; D is the molecular diffusivity, cm2/sec; u is the average velocity

By H. D. Outmans

A method has been developed for determining the relative water wet-tability (fraction of the surface wet by water) of porous media. This method involves the adsorption of methylene blue dye from an aqueous solution onto the solid surfaces of rock contacted by the injected dye solution. Experiments on Berea snndstone cores have shown that water-wet cores adsorb a large amount of dye from solution. In oil-wet cores, however, the injected aqueous dye solution is prevented from contacting the adsorptive surfuces by a film of oil and virtually no dye is adsorbed. This method was tested by experiments on mixtures of water-wet and oil-wet sand. Using the dye adsorption method, it was possible to determine quantitatively the fraction of water-wet and oil-wet sarzd in such mixtures. The dye adsorption test is readily applied to determinitrg the relative water wettability of fresh oilfield cores. The cores are not extracted before testing. Observed values of the wettability of field cores tested to date have varied from 100 to 6 per cent water wet. INTR OD UCTIO N Recent articles1 ' have emphasized the important role that wettability plays in almost all phases of reservoir rock behavior. It has been shown that wettability has a profound effect on the interstitial water saturation, residual oil saturation, capillary pressure, relative permeability, waterflood behavior, and resistivity index of oilfield cores. A quantitative investiga- tion of the effect of wettability on these core properties is severely handicapped by the lack of a simple technique for measuring the wettability of a porous medium. If such a technique were available, it would provide investigators with a means of gaining insight into the distribution of phases within a core. A number of qualitative methods of estimating wettability are known. These include contact angle measurements, flotation tests and studies of displacement pressure: imbibition7 and relative permeability data.' Using these tests, it is usually possible to classify a core as water-wet, oil-wet, or some intermediate degree of wettability. One recently proposed method involving measurement of nuclear magnetic relaxatione offers promise of determining quantitatively the fractional wettability of cores. The equipment is rather elaborate and necessary treatment of the cores before testing probably alters the natural wettability. This latter point also applies to most of the cited qualitative methods. This paper presents a new technique for determining water wettability of cores; it is based on measurements of the dye adsorption capacity of the core. This method has the advantage of requiring relatively simple equipment and involves minimum handling of the core before testing. It is important to distinguish between the various concepts of wettability referred to in the literature. The term "wetting" is defined by Bartell as that phenomenon which occurs when a solid and liquid phase come in contact in any manner so as to form a solid-liquid interface. A preferentially water-wet solid is defined by Jennings in terms of the advancing contact angle in the solid water-oil systems. Brown and Fatt regard fractional wettability as the fraction of the total surface area that is preferentially oil-wet or water-wet. However, none of these definitions adequately describes the type wettability measured by the dye test. This calls for the introduction of a new term, "relative water wettability", which we define as the fraction of the total surface area of a core contacted by injected water. DESCRIPTION OF METHOD The ability of a porous medium (especially the clays) to adsorb large quantities of surfactants, dyes, etc., is well known. It is reasonable to assume that a substance can be adsorbed from solution onto a solid surface only if the solution contacts the surface. In this connection Shapiro" has shown by experiments on silica gel that completely dry gel will adsorb methyl red dye from a benzene solution. On the other hand, if a film of water more than several molecules thick is present on the silica gel, the adsorption capacity of the gel for the dye is drastically reduced. Thus, a study of the dye adsorption capacity of cores should give some clue as to the fluid distribution on the surface of the core. TEST OF METHOD As a qualitative check on this theory, dye adsorption tests were run on similar Berea sandstone cores (Table 1, Cores 1-5). Cores saturated initially with water and flooded with 0.01 per cent aqueous methylene blue adsorbed 0.58 mg dye/gm of core. Similar cores saturated initially with water, driven to irreducible water with oil, and then flooded with the same dye solution also adsorbed 0.58 mg dye/gm of core. Another core, treated with a 5 per cent Dri-Film solution, dried and saturated with oil (Soltrol) adsorbed no dye when the dye solution was injected. These tests confirm

By L. W. Holm

Laboratory flooding experiments on linear flow systerns indicated that high oil displacement, approaching that obtained from completely miscible solvents, can be attained by injecting a small slug of carbon dioxide into a reservoir and driving it with plain or carbonated water. Data are presented in this paper which show the results of laboratory work designed to evaluate this oil recovery process, particularly at reservoir temperatures above 100°F and in the pressure range of 600 to 2,600 psi. Under these conditions CO2 exists as a dense single-phase fluid. It was found that a bank, rich in light hydrocarbons, was formed at the leading edge of the CO? slug during floods on long cores. Formation of this bank is probably due to a selective extraction by the C02 and, it is believed, partially accounts for the attractively high oil recoveries. In crddition to the efficient displacernerlt of oil from the pores of the rock by this process, the favorable rnobility ratio related to a C0 2-water flood also contributes to high oil recovery. A further advantage of this process is noted on limestone and dolomite rock, in that the CO1 reacts with the porous medium increasing its permeability. Flooding experiments were conducted on sandstone and vugular dolomite models. The results of this experimental work show the effect on oil recovery of type of porous medium, pore geometry, flooding length, and flooding pressure. The porosity of the cores and rilodels varied from 16 to 21 per cent and their pern~eabilities ranged from 100 to 200 md. A reconstituted West Texas reservoir oil, a West Texas stock tank oil, an East Texas stock tank oil and Soltrol were used to represent reservoir oils in this study. Oil recoveries ranging from 60 to 80 per cent of the original oil in place in these cores were obtained by CO2,-carbonated water floods at pressures between 900 and 1,800 psi, compared with conventional solution gas drive and water-flood recoveries of 30 to 45 per cent on the same cores. Oil recoveries greater than 80 per cent resulted frorn f1oods at pressures above about 1.800 psi. There high recoveries were noted from both the sandstone and the irregular Porosity carbonate cores. In all floods, additional oil was recovered by a solutiorr gas drive resulting from blowdown following the flood. Oil recoveries of 6 to 15 per cent of the original oil in place were obtained during this blowdown period. This additional recovery was found to be a function of oil remaining after the flood, decreasing with decreasing oil saturation. It was also noted that highest oil recoveries by blowdown were obtained when carborlated water rather than plain water followed the CO, slug. INTRODUCTION Miscible phase or solvent flooding processes, which are designed to increase oil recovery -from petroleum reservoirs, involve the injection of small quantities of a petroleum solvent into the reservoir, followed by an inexpensive scavenging fluid which is miscible with the solvent. Essentially complete displacement of oil from the pores of reservoir rock has been obtained by this technique. CO,, although not completely miscible with most reservoir oils at moderate pressures, is highly soluble in these oils at pressures above about 700 psi; there is appreciable swelling and reduction in the viscosity of oil when CO, is dissolved in it. Therefore, CO, could be expected to perform similarly to other oil solvents as a displacing agent. CO, is also highly soluble in water at elevated pressures, so water should be a satisfactory material to drive a slug of CO, through an oil-bearing reservoir. A favorable mobility ratio would be obtained through the reduction in viscosity of the oil and the use of water as a final displacing agent. A number of investigations of the use of CO, to improve oil recovery have been reported in the literature.2,3,4,5,6 These studies, however, have been conducted on uniform porosity sandstone at relatively low temperatures and pressures. The behavior of CO1 as a flooding agent at temperatures above its critical temperature could not be predicted adequately from these studies, particularly for the case of non-homogeneous rock. The purpose of this work was to evaluate the oil recovery efficiency of a process involving the injection of a CO2 slug followed by carbonated water, at reservoir temperatures above 100°F and in the pressure range of 600 to 2,600 psi, and to compare this process with conventional water flooding. The investigations were primarily designed to provide information on the efficiency of the process in irregular porosity carbonate rock. The effects of flooding path length, the presence of free gas, the type of oil to be recovered, and the amount of solvent required were also determined. The essential results of static phase behavior studies and experimen-

By Dwight K. Smith, Greg Carter

Studies have been conducted on The properties of many deep well cementing compositions to determine their Strength behavior over curing periods to 180 days at elevated tem-peratures and 3,000 psi pressure. This pressure results in essentially the .vat, compressive strength as that obtained with much higher pressures in ac-cordance with the findings of an API subcommittee ' These different compositions include API C1asses A, E, and F cements containig additives such as retarders, berrtorlite, heavy weight materials and pozzolans. All compositions except mixtures of Poz-zolrrrts and hydrated lime show from mild to severe degrees of strength lass over a temperature rang from -730 to 320" F after setting. Pozzolatl-time compositions actually gain in strength with time at these high temperatures. Other chemical find physical properties evaluated to observe their inter-relation.ship with Strength loss show very little correlation except in per-meability. As retrogression in strength increases, the permeability of set cement increases. X-ray difraction patterns on the set products indicate the formation of certain compounds having little or no strength value in those cementing compositions where strength loss was more severe. INTRODUCTION As a result of the growing trend toward deep well completions, a study has been made on the properties of the various cementing slurries presently in use at elevated temperatures and pressure. The strength of these compositions is of prime importance in selecting the most suitable material for use at high temperatures, to determine WOC time and the proper time to perforate with a minimum of shattering. Of primary interest in this investigation was the strength behavior of various compositions currently in use, and the effect of additives on cement after long periods of curing under severe conditions. Earlier investigators have pointed out that the strength of some cements will increase with increasing curing temperature to about 220 to 340" F, but at higher temperatures a loss in strength occurs at extended time intervals. Studies by the API Mid-Continent District Study Committee on Oil Well Cements' outlined a testing procedure whereby field conditions of temperature and pressure could be simulated in the laboratory.' It was observed that retarded cements undergo changes at elevated temperatures and some lose as much as 50 per cent of their early strength when cured at high temperatures. The scope of these tests was limited to curing periods of 1 to 28 days; additives were not covered in this study. Saunders and Walker' found that the use of additives influenced the strength behavior of cements at high temperatures, but studies were conducted only to a seven-day curing period. Ludwig and Pence' conducted an investigation of two types of cements under elevated pressures and temperatures in an effort to explain the causes of this loss in strength phenomenon. It was observed that with retrogression in strength there were other physical and chemical changes which took place as the cement aged. Today there are a number of cementing compositions available for use at well depths below 10,000 ft. Since all these earlier investigations were limited in curing time as well as the number and type of compositions studied, it was believed that a more extensive study should be conducted on the properties of cements at elevated temperatures, and this work should include those compositions actually in general field use at this time.

By Kenneth E. Gray

The turbulent flow drag coefficients, or friction factors, have been experimentally determined for the cut-tings normally encountered in drilling operations. The gas law and average drag coefficients for characteristically flat particles (limestones and Shales) and for angular to sub-rounded particles (sandstones) were used to extend Newton's equation to a more useful form. The resulting equations are expressions for the slip velocity of a particle as a function of the particle size and shape, the bottom-hole injection Pressure, and the Bottom-hole temperature. The velocities necessary to lift actual rock cuttings as observed in the laboratory were compared with velocities predicted from the derived equations. Results indicate that there is no single correct circulating velocity and that the commonly used 3,000 ft/min linear velocity may he sufficient to lift only very mall particles. The advantage, in terms of horsepower requirements, of cycling high pressure air to obtain lower compression ratios was shown. INTRODUCTION A promising departure from standard rotary hydraulic drilling is air or gas drilling. In many instances the rate of penetration and bit life increases resulting from this method have been very substantial. Further the application of air drilling in areas of lost circulation or water sensitive pay zones has been highly successful. Purpose For the drilling contractor, the practical question remains, "How much air pressure and volume should I have?' lt is necessary to have a reasonable knowledge of the air velocities and pressures required in air drilling operations for the proper design and most advantageous use of surface equipment and for adequate removal of cuttings from the borehole. Eased on experience, most operators agree that at least 3,000 ft/min linear velocity is necessary for satisfactory hole cleaning.' It was the purpose of this investigation to evaluate the drag coefficients, or friction factors, for the cuttings normally encountered in drilling operations, i.e., sandstones, limestones and shales, and to utilize the values obtained to develop an expression for the minimum velocities and pressures (hence the volumes) necessary to lift these cuttings. THEORY Several investigators have done extensive work on the ability of drilling mud to lift bit cuttings. They conclude that the ability of a drilling mud to lift cuttings is dependent on the density difference between the rock being drilled and the drilling mud, the cutting size and shape, the mud flow constants, and the flow state (laminar, transitional or turbulent) of the mud. However, drilling muds are not true fluids but have a variation of viscosity with velocity in laminar flow and a constant apparent viscosity in turbulent flow. A survey of the literature revealed that no experimental work had been done to determine the velocities necessary to lift actual rock cuttings using a compressible fluid such as air or gas. In 1953, Nicolson6 stated that in air drilling fluid mechanics the particles could be assumed spherical in shape and that ; constant drag coefficient of 0.5 could be used due to the highly turbulent flow of the circulating air. By equating the turbulent resistance on the particle to the gravitational force on the particle, he obtained the expression, ^ = 2.67^y ,.......(1) where V, is slip velocity of spherical particle, ft/sec; D is particle diameter, in.; p, is particle density, 1b/ft8; and p, is fluid density, lb/ft3. However, as stated earlier, most operators seem to agree that adequate hole cleaning can be obtained by circulating a sufficient volume of air to give a linear velocity of 3,000 ft/rnin in the annular space. Basic Equation The velocity with which a solid particle freely falls through a fluid will increase until the accelerating force, gravity, is equal to the resisting forces, buoyancy due to the fluid displaced by the particle and friction due to the relative motion of the particle through the fluid. When the accelerating and resisting forces become equal,

By I. Fatt

Study of a model which contains "dead-end" pore volume indicates that pressure transients are influenced by the amount of dead-end pore volume and by the resistance of the flow path between the dead-end pore volume and the main flow channels. A semi-empirical method is demonstrated that makes possible measurenment of the volume in the dead-end pores and the total pore volume. The difference between these two volumes is the volume of the flow channels. An indication of the flow resistance between the dead-end pore space and the lain flow channels is also obtained. INTRODUCTION In some engineering calculations the distribution of pore volume in a petroleum reservoir need not be known. For example, a material balance calculation treats a reservoir as an oil-filled tank. In other calculations the distribution of pore volume appears implicitly through use of the porosity and the relative permeability and capillary pressure characteristics. It is the purpose of this paper to point out that under certain conditions the exact distribution of pore volume must be known in order to interpret correctly transient flow behavior. Pressure transients during single-phase flow in porous media are usually said to obey differential equations of the form

By Carl Gatlin, S. Srini-Vasan

It is shown thar k k ratios cornputed on the as.sutnption that the average sandstone reservoir has a pore-size distribution characrerized by a linear 1/P saturatioN plo are in good agreewient with correspotlding k,,/k,, ratios obfairzed by Wahl, Mul-/ins and Elfrink by correlatiotz of field measurements. Methods of calculating relative permeability data have recently been reviewed and extended.' It was shown that for sandstone reservoirs where ' is approximately a linear function of effective saturation (as suggested first by Corey') it is possible to express relative permeabilities in very simple terms. For systems wetted by connate water and producing oil and gas (gas saturation growing at the expense of oil) the expression for the The accuracy of Eq. I has been frequently confirmed in our laboratories; because of its simplicity we make routine use of it in the analytical solution of proble~ns in reservoir engineering. Nevertheless, comparisons of the k,,,/k,, ratios yielded by Eq. 1 with appropriate reservoir data have been few. The publica- tion by Wahl, Mullins and ElfrinkV of an empirical equation for k,,/k,, ratios is thus of interest since this equation is specificalljl stated to be Vased on the correlation of field measurements made on sandstone reservoirs. Not surprisingly these authors found that it was necessary to

By J. E. Fox Jr., J. L. Lummus, J. P. Gallus

Fresh water or brine drilling fluids may be kept free of suspended drilled solids by the addition of a water soluble acrylamide-carboxylic acid copolymer at the flowline. Addition of from .01 to 0.2 lblbbl of the polymer solution to drilling fluids containing less than 5 per cent clay solids by weight causes the solids to flocculate and settle rapidly to the bottom of the pits. Solutions of the polymer injected at the pump suction reduce the loss of water to permeable formations without impairing the permeability to oil. The use of drill-itlg fluids clarified with the polymer has resulted in increased drilling rates, extended bit life, and lower drilling fluid costs. INTRODUCTION Field experience and the results of a number of investigations have established that the accumulation of solids in drilling fluid reduces drilling rate.'-' Drilling with water makes possible higher drilling rates than can be achieved with mud but in many areas drilling with water may not be feasible because of the possibility of encountering high formation pressures or by-dratable formations. To combat these conditions, the drilling fluid must possess certain physical properties such as viscosity, density, fluid loss, etc., which require the presence of solids. The current trend in drilling fluid treatment is to maintain as low a percentage of solids as is possible without harmfully affecting the mud properties needed for drilling. Mechanical separating devices such as wet cyclones and decanting-type centrifuges are proving to be an economical means of controlling the percentage of solids and thereby maintaining low solids muds. Also: special muds have been developed for the purpose of retarding the hydration of drilled solids so that they may be more easily removed by shale shakers or settling pits. In some areas, such as West Texas, the characteristics of some formations will permit drilling with water. However, because of the dispersion of drilled solids, it is usually not possible to maintain clear water even with the aid of mechanical separators, or by utilizing large settling pits. For this reason the commonly used term "water drilling" is a misnomer since the water usually contains some solids. Because of the improved drilling rates and other benefits which might be effected, a laboratory and field study was made of the use of flocculating agents for maintaining clear water for drilling. PROCEDURE Laboratory—Solids Settling Two techniques were employed to determine the effectiveness of flocculating agents in settling solids from drilling mud. First, the rate of fall of solids was measured in graduated beakers containing mud treated with various flocculating agents. Natural gum, oil-in-water emulsions prepared with ethoxylated nonyl phenols and diesel oil. and a powdered synthetic acrylamide-carboxylic acid copolymer* (hereinafter referred to as "polymer") were tested as flocculating agents in both fresh water and salt saturated muds containing 4 per cent solids. The polymer was not added in the powder form directly to the muds but was first dissolved in water in a concentration of 3.5 lb/bbl. The polymer solution was then added directly to the mud. The concentration of the flocculating agents, including the polymer, was varied. High rates of fall of the solids indicated high flocculating efficiency. A second technique consisted of measuring the time in minutes required to obtain clear water at the pump suction after addition of the various flocculating agents at the flowline. These tests were made using a model mud circulating system having a total volume of approximately 10 gal. The natural fresh water and brine muds used contained 4 per cent solids. A sketch of the circulating system appears in Fig. 1. The circulating rate

By M. R. Tek, K. H. Coats, D. L. Katz

The performance of a gas reservoir su,bject to water drive is often affected by interference due to gas procluction or injection in neighboring reservoirs adjacent to a common aquifer. Field data available on production-pressure behavior of several reservoirs indicate that prediction of reservoir performence must include the effects due to mutual interference. A method developed to predict the performance of two or more interfering gas reservoirs, subject to specified production-iniection .rchedule.s, is presented. The method involves the comhinatiorz of the theory of unsteady-state water movernent with appropriate meterial balance consideration.s. The procedure which extends M. Mortada's treatment for interfering oil reservoirs makes use of his dimen-.sionless pressure drop quantities. prevented graphically in the literature. In order to evaluale the predictive accuracy and practical field applicability of the theory, the method has been applied to analyze the performance of two actual gas reservoirs in mutual interference. The calculations were performed on an IBA4 704 computer. The predicted performances were alro calcltlated with the interference effects ignored. The results show that considerably better agreement between calculated and observed behavior ic. obtained when the interference effects are included. INTRODUCTION Fluid communication between any number of oil or gas reservoirs adjacent to a common aquifer results in mutual interference effects on their production-pressure behavior. The theory, application and interpretation of pressure build-up behavior of oil wells, drawdown tests on oil or gas-producing formations and behavior of several storage reservoirs indicate ample experimental evidence of mutual interference. A method developed to compute the behavior of interfering oil reservoirs was published several years ago by Mortada.4 Studies conducted during the recent years on underground storage of natural gas clearly indicated the need for extending Mortada's work to the case of interfering gas reservoirs. The adoption of appropriate material balance equations in conjunction with the unsteady-state pressure interference theory yields pressure-explicit equations. Their solution, their application to a specific case history and an over-all evaluation of the developed method through the comparison of predicted and observed field performances were the main objectives of this study. DEVELOPMENT OF MATHEMATICAL RELATIONS The diffusivity Eq. 1 governs planar, radial, unsteady-state compressible liquid flow through a porous medium. ?p/?r2+1/r ?p/?r=µFc/k ?p/?t (1) The 1iterature1,2,3 contains derivations and solutions of

Drilling, Blasting, and Ore winning A General Meeting and Colloquium on the above subject was held on November 13th, 1974, at Kelvin House, Johannesburg. Professor R. P. Plewman (President) was in the Chair. The Colloquium was attended by 235 delegates and was opened by the President at 09h30.

Jan 1, 1975