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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 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 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 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

By Robert S. Mayo

My subject today is "Drilling-and-Blasting of Small Rock Tunnels". I am sure that there will be some people, primarily college students but perhaps Consulting Engineers, who will say: "Drilling-and-Blasting? I thought that went out with the invention of the Tunnel Boring Machine". A few years ago I talked to Dick Robbins and he told me that they did not try to sell a "Robbin's Mole" unless the tunnel was two miles long. For easy calculations I use 10,000-ft. (3km) A Mole today costs about $2 million which works out to $200 per lineal foot. This is "front money". You cannot place the order unless you are the uncontested low-bidder and then you must wait at least six months for delivery. Of course you can use that time to square up your portals, ready to turn-the-eye, or maybe you have shafts to sink to reach the tunnel grade. But this is "dead-time" and it is a heck of a feeling to have a job and cannot get started on it until you get the Mole. I do not have the American figures on lengths of tunnels but there was an article a few years ago in a British magazine: NEW CIVIL ENGINEER, on this subject. This stated that 75% of the jobs in Britain which were bid were for small tunnels, 10-ft x 10-ft (3m x 3m) or smaller, and that they were less than 5,000-ft (1.5km) in length. This does not mean that 75% of the footage in Britain was less than 10-ft in diameter. It means that 75% of the jobs being bid were less than a mile in length. From my experience in the U.S. I believe that we have substantially the same ratio: so many of the jobs with which I was associated were short, 1,000-ft, 2,000-ft and sometimes 3,000-ft and the bores

Jan 1, 1981

By R. F. Burdyn

The inadequate use of centrifugation to economically recover solids from weighted drilling fluids reflects the need for better equipment and techniques for this putpose. Laboratory studies in the development of an improved separator are described in which an operating equation is derived and tested. Results show that the concentric cylinder geometry employed effectively separates bnrite from a suspension and that the operating equation provides a good approxinmtion for scale-up. INTRODUCTION Our current drilling technology frequently requires a high-density drilling fluid obtained by addition of barite. In the course of drilling, formation solids which are too fine to be removed either by screening or settling become suspended in the drilling fluid and gradually the volume of solids in the mud increases. The volume fraction of solids must be limited (if a satisfactory set of rheological parameters are to be maintained). A centrifugal separatorprovidesan economical way of accomplishing this. The barite recovery process can be considered as a separation of two solids. One, the light solids, composed of formation and added solids, has a specific gravity of 2.6 to 2.7; the other, barite, has a specific gravity of 4.2 to 4.3. This density difference, plus the fact that the average light-solids particle size is much smaller than the average barite particle size, permits separation by a centrifuge. In drilling fluids some of the coarse particles of the light-solids-range will settle faster than fine particles of the barite-particle range. As a result a complete separation of the two species is not possible. since the object of the process is not merely recovering the maximum amount of barite but includes as well removing the maximum amount of light solids, an optimum barite recovery efficiency exists. From a practical standpoint this optimum cannot be determined in the field for each drilling fluid system, and in practice the separation is less than optimum, with some sacrifice of barite. Drilling technology has included centrifugal separators for barite recovery for more than a decade. Results have been reported by a number of investigators indicating that the process is practical and economica1. l-4 The decision to use a centrifuge is based on economics in which direct cost savings and the indirect benefits in rig time derived from improvement of the drilling fluid are important factors. One would expect that centrifugal separation of barite from drilling fluids would significantly affect barite consumption; however, this is not the case. The Minerals Yearbook shows an annual domestic barite consumption in the drilling industry of nearly 1 million tons.5 By rough estimate there are perhaps 80 separators presently in field use. Assuming half of these in use at any one time, operating an average of four hours per day, at recovery rates averaging 3,000 Ib of barite per hour, total annual recovery is about 90,000 tons. This is less than 10 per cent of he total barite used. I conservatively estimate that barite consumption in drilling operations can be reduced by 30 per cent through greater utilization of centrifugal separators. To encourage more widespread acceptance of centrifugal separators in the drilling industry, improved equipment and techniques would be very desirable. The present paper, covering theory and results obtained from a laboratory model, is the first in a series on he development of an improved mud separator for field use. THE CONCENTRIC CYLINDER GEOMETRY AS A SEPARATING DEVICE Consider the geometry shown in Fig. 1, consisting of two concentric cylinders separated by an annular space. These are arranged so that the outer cylinder is fixed and the inner one can be rotated about its axis on shafts sealed against the ends of the outer cylinder. If the outer cylinder is fitted with openings at either end, the inner

Jan 1, 1966

By D. E. Hawk, R. F. Burdyn, F. D. Patchen

Earlier work on a mud separator for barite recovery is extended to the design and construct ion of a rugged field unit. Problems associated with scale-up for field use include the me of dilution water and its effect on capacity, power requirements and pressures developed. Equations for these quantities are derived and applied in maximizing the beneficial effects of dilution and minimizing the power required. Tests on the full-size rotor show that its performance can be predicted by theory. The completed unit is compact and lighter than current decanting types. Its capacity is from 10 to 22 gal/min with corresponding barite recovery efficiencies of 92 to 86 per cent. INTRODUC'TION In an earlier publication a new type of centrifugal device was described for solid-liquid separations.l In that paper an operating equation was derived, and its validity demonstrated in laboratory scale experimentation. Some of the features apparent in this new device seem particularly well suited to the conservation of barite in field drilling-mud systems, hence the development was extended to the design and construction of a field unit. In the present paper the design problems associated with scale-up are considered. A full-scale, rugged self-contained field unit is described, and test results discussed which verify that the performance of the large field unit can be described by a simple operating equation. PRINCIPLE OF OPERATION OF SEPARATOR In principle, the new device is simply a perforated cylinder rotating within a body of fluid which is contained within a stationary case, as in Fig. 1. The frictional drag generated by the rotating cylinder causes part of the fluid to rotate. At the surface of the cylinder, assuming no slip occurs, the angular velocity of fluid and of the cylinder are identical. If there are suspended particles present of greater density than the fluid, the centrifugal force acting on these particles causes them to move radially away from the cylinder at some velocity vp . Where the Stokes settling equation holds, this velocity may be expressed as:2 d2 ?p rw2 If the case is provided with openings at both ends, a suspension can be pumped in at one end at a fixed rate. Part of the suspension can then be removed at a fixed rate at the other end of the case as underflow, and the remainder forced through the perforations and hollow shaft of the rotor to appear as effluent, also at a fixed rate. The radial component of the flow velocity of this stream as it reaches the rotor surface, is simply effluent flow rate divided by cylindrical surface area: Because up is a function of particle size, for some particular particle size, the velocities vp and v, will be equal in magnitude. This is defined as the critical particle size and represents the size above which all particles appear in the underflow and below which all particles appear in the effluent. For this equilibrium condition at the rotor surface, Eqs. 1 and 2 combined give

Jan 1, 1966

By W. C. Maurer

A study of bit-tooth penetration, or crater forniation. under simulated borehole condirions has been made. Pressure conditions existing when drilling with air, water and mud have been sirnulated for depths of 0 to 20.000 ft. These crater tests showed that a threshold bit-tooth force must he exceeded before a crater is .formed. This thresh old force increased with both tooth dullness and diflerenrial pressure between the borehole and formalion fluids. At low differential pressures, the craters formed in a brittle manner and the cuttings were easily removed. At high differenlial pressures, the cunings were firmly held in the craters and the craters were formed by a pseudoplas-tic mechanism. With constant farce of 6,500 16 applied to the bit reeth, an increase in differential pressure (sitnulated mud drilling) from 0 to 5,000 psi reduced the crater volumes by 90 per cent. A comparable increase in hydrostatic fluid pressure (simulated water drilling) produced only a 50 per cent decrease in volutne while changes in overburden pressure (simulated air drilling) had no detectable effect on crater volume. Crater tests in unconsolidated sand subjected to differential pressure showed that high friction was present in the sand at high pressures. Similar friction belween the cuttings in craters produces the transition from brittle to pseudo plastic craters. INTRODUCTION The number of wells drilled below 15,000 ft increased from 5 in 1950 to 308 in 1964. Associated with these deep wells are low drilling rates and high costs. High bottom-hole pressures produce low drilling rates by increasing rock strength and by creating bottom-hole cleaning problems. This paper describes an experimental investigation of crater formation under bottom-hole conditions simulating air, water and mud drilling. Although numerous investigators have studied bit-tooth penetration (cratering) at atmospheric pressure conditions, only limited work has been done on cratering in rocks subjected to pressures existing in oil wells. Payne and Chippendale2 have studied cratering in rocks subjected to hydrostatic pressure using spherical penetrators. Garner et aLJ conducted crater tests in dry limestone by varying overburden pressure and borehole fluid pressure independently and using atmospheric formation-fluid pressure Gnirk and Cheathem4,5 have studied crater formation in several dry rocks subjected to equal overburden and borehole pressure and atmospheric formotion pressure. Podio and Gray studied the effect of pore fluid viscosity on crater formation using atmospheric borehole and formation-fluid pressurc and varying overburden pressure. Although these studies have provided useful information on crater formation under pressure, they were limited in that the three bottom-hole pressures could not be varied independently and, therefore, that many drilling conditions could not be simulated. The prersure chamber used in this study allowed visual observation of the cratering mechanism and independent control of the borehole, formation and confining pressures. By using different fluids in the chamber, pressure conditions existing in air, water and mud drilling to depths of 20,000 ft were simulated. The mechanisms involved in cratering at these different pressure conditions were studied for teeth of varying dullness and at different loadins rates. High-speed movies (8,000 frames/sec) and closed-circuit television were used to visually study the crater mechanism under pressure. EXPERIMENTAT PROCEDURE PRESSURE CHAMBER The Pressure chamber in Fig. I was used to simulate bottom-hole pressure conditions. This chamber has been pressure-tested to 22,500 psi and is normally operated at pressures up to 15,000 psi. The chamber contains four lucite windows' used for illuminating and observing the crater mechanism under pressurc. A closed-circuit television and a Fastax camera (8,000 frames/sec) have been used in these studies. Cylindrical rock specimens (8-in. diameter X 6-in. long) were subjected to three independently controlled pressures simulating overburden, borehole fluid and formation-fluid pressures. Overburden pressure, which corresponds to the stress induced by the overlying earth mass, was applied by exerting fluid pressure against a rubber sleeve surrounding the rock. Borehole pressure, which is the pressure exerted by the column of mud in the wellbore, was simulated by applying pressure to the fluid overlying the rock in the chamber. Formation pressure was simulated by applying pressure to the water saturating the rock. The borehole and formation pressures were equal except when mud was used in the chamber, in which case the differential pressure between these fluids acted across the mud filter cake.

Jan 1, 1966

By H. A. Kendall, W. C. Goins

Several investigations in recent years have shown that drilling rates are increased significantly with increased hydraulic horsepower. But, there has been no over-all method of designing jet-bit programs that efficiently uses the surface power. A study of present practices indicates that frequently as little as 50 per cent of the possible effects at the bit are used. Some observers have indicated that the best utilization of hydraulic horsepower (maximum effect on drilling rate) occurs when the bit hydraulic horsepower is maximum; others have stated that jet impact force is more important, and others have believed that maximum jet velocity is required. Limited efforts to date have shown some optimum conditions for bit hydraulic horsepower and impact, but these conditions cannot exist during drilling of a large part of the hole and do not provide a basis for designing a complete jet-bit program. This paper shows the maximum obtainable bit horsepower, impact force and jet velocity at all depths, taking into account the limitations of the pump, piping, hole and minimum circulating rate for adequate cuttings removal. Ranges of operation are developed; and flow rates, surface pressure and bit pressures are specified for each range to provide a maximum of any one of the desired effects. It also is shown that, by proper selection of nozzle sizes and by following the rules presented, the maximum obtainable quantities can be effectively utilized from surface to total depth. Finally, a simple graphical method of selecting nozzle sizes and flow rates is presented which can be used with familiar bit-company hydraulic tables and calculators to design jet-bit programs for maximum bit hydraulic horsepower, impact or jet velocity, as desired. These programs make most effective use of the pumps. Heretofore, there was no method available for designing field tests which adequately separated the effects of bit horsepower, impact and jet velocity. The programs and procedures developed in the paper are dissimilar and, when used in future field testing, should demonstrate which program is the most important in obtaining the fastest drilling rate. INTRODUCTION During the past decade, rig hydraulics has come into increasing prominence. There has been a definite trend toward providing higher horsepower pumps, jet-type bits have had increased use, numerous investigators"" have reported increased drilling rates as a result of increased hydraulics, and bit manufacturers have provided tablesa-" and calculators that are now commonly used 10 design jet-bit programs. Opinion has varied as to the hydraulic quantity which has the great- est effect on drilling rate. Papers and data have been presented that show pump horsepower,'9 it hydraulic horsepower and jet impact force,' each to be the most significant factor affecting drilling rate. Examinatibn of jet-bit programs of the bit companies indicates emphasis on jet velocity. Only pump horsepower can be eliminated because it can be used to produce any one of the bit effects which, a priori, must be more relevant factors. This contradictory state of opinion and practice regarding the bit effects is unfortunate, but several published references have been concerned with making one or another of the factors maximum; and, because these in each case have given results applicable to only intervals of the hole drilled, there seems to be ample reason to complete the previous efforts. It also is believed that the differences in programs for each effect, where they exist, should be delineated so that future use may determine which hydraulic effect is the more relevant. It is the purpose of this paper to: (1) show the theoretical maximum bit hydraulic horsepower, jet impact force and jet velocity available at all depths, taking into consideration all necessary restrictions on operating conditions; (2) illustrate procedures by which the maximum available horsepower, impact force or veIocity may be obtained; and (3) present a graphical method for rapid selection of jet-nozzle sizes and flow rates to be used with conventional procedures to design jet-bit programs for maximum bit horsepower, impact force or velocity as desired.

By E. I. Radzinovsky, D. W. Dareing

This paper presents theory which is used to predict rock-bit bearing life reduction due to simple harmonic variations in bit forces. The theory is based on the premise that if a constant load acts for a certain fraction of the life which the bearing would have if that constant load were applied for its entire life, then the same fraction of thelife of the bearing is consumed. Total bearing life is related to simple harmonic variations in bearing life associated with instantaneous bearing loads. The results show that rock bit bearing life is not affected appreciably by forces commonly impressed upon a bit, but it is affecied appreciably by relatively large dynamic bit forces occasionally encountered during drilling. In addition, the results show that the life of sealed bearings is more sensitive to bit force variations than is the life of unsealed bearings. INTRODUCTION Roller bearings are important components in roller cone rock bits because they transmit a large portion of the drill collar weight to the formation being drilled. Unfortunately, they have a relatively short life under down-hole drilling conditions. Roller bearings are usually the first bit components to fail, and their failure leads immediately to failure of the entire bit. Short roller bearing life, and thus short bit life, is due mainly to high unit loads transmitted by the bit and to the adverse environment in which the bearings operate. The results of the study discussed in this report show how dynamic bit forces also affect roller bearing life. The purpose of this paper is to discuss theory developed to predict the effect of different magnitudes of periodic bit forces on roller bearing life. Theoretical results are used to compare the life of rock bit roller bearings subjected to steady forces to the life of rock bit roller bearings subjected to unsteady forces similar to the type of unsteady forces measured at the bit with a special downhole recording instrument. BACKGROUND AIanufacturers of bearings have conducted laboratory tests which show how bearing life is affected by steady bearing load. 1 The well-known empirical equation which defines bearing life follows from bearing test data. It is: where L = bearing life, hr P = bearing load, Ib C = constant q = exponent (constant). The effect of environment on bearing performance is manifested through the exponent q and the constant, C. King,2 in similar tests conducted on roller bearings used in rock bits, showed that, in addition to the load, the environment (abrasive materials, chemical components, etc.) greatly affects bearing life. His data, which show how the life of roller bearings in a 7-7/8-in. W7R bit rotating at 60 rpm is affected by bit weight and fluid environment, are displayed on a log-log plot by broken lines made up of straight line segments. Each broken line corresponds to a given environment. One segment (q = 1.4) of the broken line corresponding to a fluid environment of barite mud is shown in Fig. 1 along

Jan 1, 1966

By L. W. Legerwood

During the past three decades, the oil industry has expended increasing eflorts seeking improved drilling tools or systems to reduce drilling costs. The total cost of these efforts is unknown, but it certainly amounts 10 tens of millions of dollars. Most of the "new" system that past and present investigators have sought to develop actually are old public information. In seeking to implement new-systern concepts, investigators have tested the following: impact at frequencies ranging from 6 to 300 cycles per second; electrical, mechanical and hydraulic meam of actuating percussors; bit rotary speeds up to 2,000 rpm; electric and hydraulic bottom-hole means of rotating bits; bottom-hole machines with power outputs up to 400 hp; shock waves; explosives; high-velocity pellets; flame; arc; grinding wheels; abrasive jets; erosion by high-velocity gases; chemical attack; electric current; magnetic waves; retractable rock bits; reelable drill pipe; continuous coring with reverse circulation; and automation of drilling rigs. Table I shows how these investigations are grouped for discussion purposes in this paper. In spite of these efforts to discover new and improved systems, rotary drilling main;aim its economic leadership. Undoubtedly, rotary drilling costs will continue to be reduced by rigid application of the best available technology and by development of new rotary technology. In view of the extensive past development programs, however, significant long-range improvement appears to be a research, not a development problem. Research must postulate and prove theories and principles governing variour subsurface rock-failure processes pertinent to both rotary and new systems. Ah, research must produce physical and engineering data relative to these processes. When such information is available, earth boring will graduate from an art to a science. Major improvements in rotary drilling can then be expected, and the systematic evolution of an improved drilling method can be initiated—with a strong probability for success. Development of drilling methods other than rotary drilling has been one approach investigated by the industry as a means for reducing drilling costs. Major cost-reduction efforts, however, have been centered on engineering development work aimed at incremental improvements in rotary drilling. A relatively minor effort has been expended to establish basic physical principles and engineering data pertaining to the earth-boring process which can serve as a foundation for the development of cost-cutting drilling hardware. Current oil-industry economic trends have added impetus to the need for effective programs to reduce drilling costs. However, areas for expanded future efforts should be selected only after careful study of past investigations. It is the purpose of this paper to review past and Dresent industry efforts to develop new drilling tools or systems and to suggest areas where additional science is needed. Past reviews of drilling methods have been limited to a few processes prominent at the time the reviews were made. This paper seeks to present a concise, well organized review of all methods that have received actual development or test work. The preparation of a paper seeking to review all past developments is fraught with many difficulties, not the least of which are errors in or obsolesence of printed matter used as source material and the lack of data on industry developments which have not been published. Since de-

By R. Simon

The sources of energy dissipation for concentrated loadings on rock are considered in an attempt to account for the experimentally measured magnitude of the work required to break out a unit volume of rock from the free surface of an essentially semi-infinite medium. It is concluded that most of this work probably represents the elastic strain energy developed by the loading in a much larger volume of rock beneath the loaded region than the volume of the rock fragment broken out to the side of the loaded region. This strain energy is largely dissipated in the form of stress waves generated by the high rate of unloading produced by the propagating cracks. The energies associated with the formation of the new surfaces of the cracks and with the stress waves generated directly by the loading process are computed to be negligibly small. Possibilities for improving the utilization of energy to drill rod. subject to the geometrical limitations imposed by down-hole operation, are discussed. It is pointed out that any such possible improvements would probably have to be differential ones, since each rock configuration of more favorabIe loading geometry that can be created down the hole is accompanied by a complementary configuration of less favorable loading geometry. INTRODUCTION Dislodging each cubic inch of rock from the bottom of the hole by the action of a bit requires the expenditure of an amount of energy that varies from approximately 5,000 in.-lb to approximately 100,000 in.-lb, depending on the hardness of the rock, or, more technically, upon its fragmentation strength.1 In this paper we will discuss (I) why the energy expended in drilling is so large, (2) what happens to this energy upon completion of the drilling process, and (3) what are the possibilities for reducing the magnitude of the energy required to drill rock. DETERMINATION OF ROCK DRILLING ENERGY The volume of rock removed per unit time from the bottom of a hole of diameter D is evidently (7/4)D2R, where R is the rate of penetration of the bit. If P is the rate at which work is done by the bit on the rock at the bottom of the hole, the energy required to break out a unit volume of rock is given by: Ev =(4/p) P/D2R............(i) For rotary drilling, of either the rolling-cone or drag-bit varicty, P = 2pLN, where L is the torque resistance to rotation at the bottom of the hole and N is the rate of rotation of the bit. L is essentially the same as the torque measured at the rotary table only when drilling in shallow holes. The energies expended in rotating the drill string against the frictional resistance of the walls of the hole and and against the viscous drag of the drilling fluid are extraneous to the subject under consideration, although these may be much greater in magnitude than E, when drilling in a deep hole. For percussion drilling, P = fE where f is the percussion frequency and E is the work done on the rock per impact. The latter quantity can be both computed and measured for a percussion drilling machine. 2 (Under satisfactory drilling conditions, defined in terms of ranges of numerical values of certain dimensionless parameters, E is only 30 to 50 per cent less than the impact energy of the striker.2) Alternatively, E, may be measured directly by dropping chisels shaped like bit edges, backed by rigid weights, onto the surfaces of laboratory rock samples of effectively semi-infinite extent. Under these circumstances, essentially all of the impact energy is converted to work done on the rock, and the relationships among volume of rock broken out, chisel shape, impact energy and indexing distances can be obtained.3 The values of the energy required to break out a unit volume of rock under favorable circumstances are substantially in agreement for rotary drilling, percussion drilling and drop testing at atmospheric pressure. The energy per unit volume is a quantity of the order of magnitude of roughly twice the com-pressive strength of the rock as measured by a uniaxial loading test. The phrase "order of magnitude" in this paper means from about 1/3 as much to 3 times as much; i.e., the energy per unit volume may range from roughly the same up to several times

By L. H. Robinson

A proposed method of drilling utilizes sequential detonation of two types of explosive charges delivered to the hole by a conventional drilling fluid through pipe. A shaped charge first produces a long thin hole. A second charge, called a gauging charge, is pumped into the thin hole, explodes, and enlarges it to full gauge. In one suggested configuration, the explosives are contained in cylindrical capsules 4- to 5-ft long. A drilling head is positioned 2- to 3-ft off bottom. When a capsule is pumped to the bottom of the hole and stops, pressure inside the drill pipe increases and differential pressure detonates the explosive. Primacord along the length of the capsule disintegrates the capsule. The debris circulates out of the hole with the drilling fluid. The gauging-charge action was examined using 2-ft cubes of Berea sandstone. The sandstone (18 per cent porosity) was vacuum-saturated with water and surrounded by concrete. To prevent reflected tensile pulses, the acoustical impedance of the concrete matched that of the sandstone. A 750-psig pressure was applied to a drilling fluid within a shaped-charge-formed hole before detonating the gauging charge. In these tests, 190 gm of rock were removed for each gram of explosive detonated. A similar series of experiments on low-porosity (0.40 per cent) metamorphic limestone provided a more rigorous test. Extensive fracturing from the gauging-charge action prevented an estimate of the volume of the expanded hole. The diameter of the hole was irregular, ranging from about 2 to 4 in, or about fivefold larger than the hole created by the shaped charge. INTRODUCTION In the past, explosives have found a varied but somewhat limited use in the oil field. An early well stimulation technique, still in use today, in vo lves shooting ni troglycerin to en large the borehole and to increase matrix permeability near the wellbore. Bullets and jets are now the conventional method of perforating casing and tubing. Detonations are frequently used to "back off" or "shoot off" stuck pipe and, of course, seismo-graphic work has long depended on explosive-generated pulses to find attractive earth structures. Efforts to use explosives in drilling operations have received limited examinations1-3 which, in one respect, is surprising because explosives offer one way to transmit large amounts of energy directly to the bottom of the hole. Recently, Ostrovskii l described a Russian method of drilling with explosives that utilizes small capsules containing explosives which are pumped into the mud stream to the bottom of a borehole. As the capsules leave the end of the drill pipe, a detonation mechanism is armed. Impact detonates the explosive. In another configuration, two liquids (an oxidizing agent and fuel) in the capsule are separated by a frangible membrane. Separately, the liquids are nonexplosive. Near the bottom of the drill pipe, the capsule passes through a narrow constriction which ruptures the membrane. The mixing of the liquids produces an explosive. Impact is again used to detonate the explosive. About the time Ostrovskii was developing his method, Humble Oil & Refining Co. was independently doing research on another explosive drilling concept based on the sequential detonation of two types -of explosive charges. The proposed technique consisted of alternately pumping a shaped charge and then a "gauging charge" down a well. The shaped charge should drill a long, tapered hole, and the gauging charge should expand it to full gauge. This paper presents the visualized drilling concept and gives results of laboratory work which showed that sequential firing of charges can form hole at an attractive charge-to-rock removal ratio. An important finding was that increased environmental pressure, which is to be expected in wells, increases rock removal efficiency of the gauging charge.

Jan 1, 1966

By D. J. Weintritt, R. G. Hughes

Statistics show arz increase in the average depth of wells drilled in recent years. As a corollary to this trend, drilling fluids have been improved in an effort to meet the problems inherent at temperatures approaching 500°F. Of importance are (1) deterioration of mud components and (2) the effect of solids on filtration and rheological properties. High-temperature, stable water-base and oil-bare muds are discussed. Those areas in which differences exist are pointed out. Results are based on data taken from the Fann consistotneter, rheometer and shear-strength measurements, static and dynamic filtration tests, methy-lene blue test for bentonite solids and specific heat measLrrenlents of muds. INTRODUCTION Higher well temperatures go along with the fact that the average depth of wells continues to increase. Recent data by Gardner' lists 137 completions deeper than 15,000 ft for the first half of 1964 with a record second-half total of 167 wells drilling or proposed. In addition, there has been an increase in drilling for steam for power production or mineral recovery. In this application the depths are modest, but the mud may approach the critical pressure and temperature of water. Scearce and Magnon' report drilling mud used at temperatures of about 700°F in the Salton Sea area of California. Most deep wells have been drilled with water-base muds. In recent years, however, there has been a substantial increase in the use of oil-base muds because of technological advances in effective additives. The significance of this development was dealt with in considerable detail by Simpson and his co-workers.3 Additiona1 field data have now been obtained to indicate that oil muds are competitive in control, performance and cost with the best types of water muds for use at high temperaturc. This parallel offer of two very different fluid systems, each offering a similar variability in performance, cost and convenience, has created the need to evaluate the merits of these fluids under specified conditions so that the advantages and disadvantages of each can be weighed in relation to the over-all drilling program. This paper is not intended as a review of all the factors. Rather, it attempts to emphasize: (1) important condltions and facts peculiar to high-temperature drilling muds, (2) that more than one imposed test condition or testing method is necessary to describe the quality of a mud at high temperature and (3) that elaborate experimental precautions are necessary whenever laboratory data are used in selection of a mud for field use. WHAT IS A HIGH-TEMPERATURE DRILLING FLUID? For the purpose of this discussion, a high-temperature drilling fluid is any system so formulated or treated to economically minimize the effects of temperature on the properties of the fluid. Our experience in drilling fluids suggests that these effects become obvious for many mud materials at temperatures of 300F or higher. It is understood that hydrolysis of starches, depoly-merization of certain organic thinners, or irreversible chemical reactions (such as that of clay and lime) can affect filtration, viscosity and shear strength at less than 300F. However, the temperature level is not a serious point and in no way affects the precautions and techniques used in this study. An up-to-date review of the literature on high-temperature drilling fluids and the many variations was treated by Rogers'in 1963. EXPERIMENTAL REQUIREMENTS TESTING EQUIPMENT AND PROCEDURES With the advent of deeper drilling and increased demand for temperature-stable drilling fluids, new testing equipment and laboratory techniques were devised for the evaluation of drilling fluids subjected to elevated temperature and pressure. While the equipment has not been standardized, it is in widespread use. Milligan et al. Qescribe a filtration cell for determining the filtration properties of drilling fluids at temperatures in excess of 300F. They showed the effect of variations in temperature and pressure on oil and water muds filtered in the 300 to 400F range. The dynamic filtration apparatus described by Simpson6 permits the study of the filtration properties to temperatures of 350F for drilling fluids circulated over sandstone cores. Watkins et al.' describe the use of pressure bombs for studying the effect of prolonged periods of elevated temperature upon the gelation or solidification of drilling fluids. Chisholm et a1.' describe the use of a modified cement consistometer adapted for use in drilling fluid evaluations. A similar consistometer is used in this study, although the application and data-recording method have been changed. The consistency of a mud sample is measured by timing the movement of a soft iron bob which is magnetically moved up and down in the sample container.* Changer in the time of travel and the temperature of the mud at that moment are plotted with a two-point Brown Elec-tronik Recorder. A 10-in. chart with a speed of 4-in./hr is used. Fia.- 1 is a generalized internretation of the data ob-

Jan 1, 1966