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Publication numberUS3349845 A
Publication typeGrant
Publication dateOct 31, 1967
Filing dateOct 22, 1965
Priority dateOct 22, 1965
Publication numberUS 3349845 A, US 3349845A, US-A-3349845, US3349845 A, US3349845A
InventorsGrant Bruce F, Holbert Don R
Original AssigneeSinclair Oil & Gas Company
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method of establishing communication between wells
US 3349845 A
Abstract  available in
Images(3)
Previous page
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Claims  available in
Description  (OCR text may contain errors)

Oct. 31, 1967 D. R. HOLBERT ETAL 3,349,845

METHOD OF ESTABLISHING COMMUNICATION BETWEEN WELLS Filed Oct. 22, 1965 5 Sheets-Sheet 1 P m a .l'

I INVENTORS B w/vnaflam' Oct. 31, 1967 o. R. HOLBERT ETAL 3,349,345

METHOD OF ESTABL ISHING COMMUNICATION BETWEEN WELLS Filed Oct. 22, 1965 5 Sheets-S em 2 I N VENTOR BRUCE x l' 6P9:

1967 D. R. HOLBERT ETAL 3,

METHOD OF ESTABLISHING COMMUNICATION BETWEEN WELLS Filed Oct. 22, 1965 I5 Sheets-$heet 5 I N VENTORS United States Patent 3,349,845 METHOD OF ESTABLISHING COMMUNTCATKON BETWEEN WELLS Don R. Holbert, Huntington Beach, Calif-Z, and Bruce F. Grant, Tulsa, Okla., assignors to Sinclair Oil & Gas Company Filed Oct. 22, 1965, Ser. No. 501,894 5 Claims. (Cl. 166-4) This invention relates to a method for recovering hydrocarbons from an underground petroliferous formation. Such hydrocarbons are solids or viscous liquids, generally unflowable at ordinary formation temperatures, and are often characterized by having an API gravity less than about 25. Such a viscosity characterization applies to solid hydrocarbons as well. The method is, furthermore, concerned with formations which are essentially impermeable to flow of their native fluid and, generally, the applicable formations have essentially no gas permeability or an effective gas permeability of less than about millidarcies.

The recovery of viscous crude hydrocarbon material from formations of this type is important in those areas where such hydrocarbons are, or may soon be, the principal indigenous source of petroleum liquid hydrocarbons or where the cost of finding and producing crude petroleum has risen so that the viscous oils and other non-flowable hydrocarbons can be recovered and refined on an economically competitive basis. The formations which contain the non-flowable hydrocarbons may be one of a number of types including tar sands, oil shale, etc. Oil shale, for example, is a fine-grained, compact sedimentary rock having splintery uneven laminae having essentially no gas permeability which may contain about 10 to 65, or more, gallons of oil per ton in the form of a solidified, resinous organic material which clings to the siliceous shale particles. Hereinafter the invention will be described with reference to oil shales although it is not so limited.

Although quarrying and surface retorting of shale is practiced in some places to recover hydrocarbons, removal of the overburden or mining in many areas is generally impractical. Also, the use of secondary recovery methods such as heat in situ to fluidify, that is, to melt, distill or decompose the non-flowable hydrocarbons is not always a panacea. In such secondary recovery methods, the entire formation may be heated at least to the fluidifying temperature of the hydrocarbons which then drain out to the production well or wells. However, such a conduction process is expensive since the whole formation must be kept heated, usually by burning saleable fuel, and a good deal of heat is wasted to the overburden and the substrata. Further, these heating methods generally require the output well to be rather close to the input well and a distance of less than about fifty feet between input and output Wells is undesirable from an economic standpoint. Another type of secondary recovery process involves forcing a hot gas through the formation to heat the formation largely by convection and to both fluidity and clean out the hydrocarbons. However, the formations frequently have essentially no natural gas permeability or a permeability less than about 10 millidarcies or even less than about 5 md., for example, less than about 1 Ind. In many of these formations, therefore, secondary recovery methods which involve gas circulation are not feasible.

The process of this invention avoids the above-mentioned difiiculties by providing a corridor of reduced resistance to gas flow in the formation between an input well and an output well which corridor can be converted into a hot passageway and can be maintained while hydrocarbons are recovered by thermal means. The corridor of reduced resistance in this invention is produced by first fracturing the petroliferous formation at one of the wells to produce a vertical fracture system generated outwardly from this well and thereafter drilling at least one communicating, essentially horizontally extending bore from the other well which intersects the fracture system to establish communication between the two wells. In other words the corridor is a part of the formation stretching continuously from the input well to the output well through which gases from the input well can pass to the output well in preference to passing through the formation in general. Once the corridor is established, the hydrocarbons are recovered by igniting and maintaining a fire in the bottom of the input well to heat the bore hole and corridor and liquefy and/0r vaporize hydrocarbons which are gradually removed from the formation to the output well and recovered.

The first step, i.e., fracturing, when applied to a relatively imperable formation, results in the opening of at least one substantially continuous fracture or corridor extending outwardly from the first well. This corridor, which is later converted to the hot passageway, serves as the core or axis for the hot passageway. It has been recognized in this invention that fracturing in formations such as oil shale results in a vertical fracture system rather than the more conventional horizontal fracture systems. These vertical fractures will be from one or two, e.g., several, feet up to 40, or even 50, feet in height and will, in general, run for long distances outward from the well at which fracturing is accomplished. The width of the fractures is small, e.g., from about hi to inch, and varies along the length of the fracture. If desired, the fractures can be propped open with sand or other granular solids which do not prevent fluid flow to the output well. It is to be understood that the corridor is suflicient to provide only a small fraction of the fluid-carrying capacity of the entire stratum.

Fracturing is accomplished by pumping quantities of gases, heated if desired, or liquids into the input well, and/or output wells, and increasing the pressure until seams or fissures of the desired fluid flow capacity have been opened in the stratum. The location of the fracture can be controlled by notching the bore prior to pumping of the fluid and straddling this notch with packers to leave an area of open formation.

Following fracturing of the formation, e.g., at the input well, the orientation of the fracture system is determined using conventional techniques, for example, by impression packers, and a second well is drilled. The location at Which this second well is drilled is determined by the orientation of the vertical fracture system. and is, preferably, within about feet of the projected location of the vertical fracture. The distance between the two wells is determined by economic considerations, but, in general, will not be in excess of about 1000 feet, preferably 500 feet. A horizontal bore is then drilled from this second well to intersect the vertical fracture system and establish communication between the two Wells.

In general, horizontal drilling is accomplished using the apparatus described in copending Holbert application Serial No. 493,970, filed concurrently herewith. A deflecting tool is positioned in the main bore of the well adjacent the desired formation at which the horizontal bore is desired, i.e., at which the bore wi-ll intersect the vertical fracture. The drilling apparatus used in combination with the deflecting tool to actually effect horizontal drilling of the horizontal bore comprises several structures all of which are attached to the lower end of the usual drill pipe and includes a flexible shaft, a universal or knuckle, joint, a reamer and a drill bit which are connected together. The flexible shaft may be or any suitable construction which will permit the shaft to follow a drill bit into a horizontal hole which is being drilled 01f outwardly from the main bore, and yet, be capable of transmitting torque to the drill bit.

It has been found that in order to be able to drill a horizontal bore in a desired direction and maintain this direction, as desired in the instant invention that the bit-reamerknuckle joint configuration must meet specific design requirements. The hole drilled in producing the horizontal bore, i.e., in going from vertical to horizontal, is slightly elliptical in cross-section and is actually curved. The angle building capacity of the tool described the radius of curvature of this hole, i.e., 5 per foot of angle build gives a radius of curvature of about 11.5 feet or, in other words, with a 5 per foot of angle build the bore will go from vertical to horizontal through a curve having a radius of curvature of 11.5 feet. For a given radius of curvature RC, to provide accurate horizontal drilling in a desired direction without substantial deviation from this direction, the knuckle joint to reamer spacing L and drilled hole centerline to knuckle joint centerline spacing a must be in accordance with the equation: R=L /2a. L is measured from the centerline of the knuckle joint to the centerline of the reamer, both in the plane of contact to the drilled bore hole, and a is the distance between the centerline of the reamed hole to the centerline of the knuckle joint. Also, the reamer must cut in order for the designed angle building capability to be developed.

In general, the size of the reamer used will vary from a size suflicient to cut or ream the bore and prevent stabilization of the bit to the size at which the reamer requires so much force to cut that the axial applied load on the drilling apparatus is insufficient to drill the bore. A /8 inch cut by the reamer is preferred. If the reamer does not cut, the reamer becomes a stabilizer, lifting the knuckle joint toward the centerline of the hole, reducing dimension a in the above equation and increasing dimension L. Furthermore, since the axial applied load used in drilling the bore provides the moment causing the reamer to dig down and the bit to dig up, if the axial load is diminished from friction or less applied drill collar weight, the force against the reamer may fall below a threshold Value causing it to stabilize and not cut. Accordingly, the applied drilling weight has a critical lower limit. For the bit-reamerknuckle joint configuration, the force against the reamer is about 50 percent of the axial load.

A blade reamer is preferred in the present invention although a spiral or other type can be used. The type of bit used is determined by the rock being drilled in accordance with standard considerations. The applied drilling weight required in accordance with this invention is a function of the rock being drilled, i.e., is that amount sufficient to make the reamer cut in the particular rock being drilled. In general, the applied weight is in excess of about 7,000 lbs. for oil shale.

The direction and radius of curvature RC will be chosen as desired in order to drill toward the fracture produced at the output well and the chosen radius of curvature put into the formula described above to define the size of the equipment to be used. In general, a small radius of curvature is preferred because the directional characteristics are better achieved with a small radius of curvature. The radius of curvature is generally spoken of in terms of the desired angle of build which is generally from about 2 per foot to about 6 per foot with approximately 5 per foot being a preferred angle of build. The upper limit for the angle of build is determined by the flexibility and strength of the flexible shaft being used. Too high an angle of build will generate torque in such an amount as to tear up, i.e., shear, the pipe. With a 5 per foot angle of build the radius of curvature is approximately 11.5 feet and with a 2 angle of build the radius of curvature is approximately 28 feet. A further important consideration in the present invention is the drilling fluid used in the drilling operation. The drilling fluid is preferably close in consistency and composition to water and contains an extreme pressure agent in an amount suflicient to coat the pipe.

With the horizontal drilling apparatus of the present invention, it is possible to drill accurately in a desired direction horizontal bores from a main bore to distances in excess of about 100 feet horizontally outward from the main bore with the limit being that defined by the amount of torque required to be applied to the pipe. If the torque exceeds the load limit of the pipe, the pipe will shear.

The deflecting tool used in combination with the drilling apparatus of this invention is commonly called a whipstock and ideally should have the same radius of curvature RC along its length as defined above which is the radius of curvature of the curve through which it is desired for the flexible pipe to pass in going from a vertical to a horizontal bore. The whipstock in general should have a radius of curvature or an angle with respect to the vertical of at least 5, and up to about 20, preferably at least 10 to 12 up to about 15 to 18 depending upon the length of the whipstock. It is preferably, if the radius of curvature is not the same as RC described above, to have the whipstock angle slightly higher than the desired angle of build which determines the radius of curvature RC.

Other objects of this invention will become apparent from the following description taken in connection with the accompanying drawings in which:

FIGURE 1 is a longitudinal cross-sectional view of drilling apparatus embodying this invention, the horizontal drilling apparatus being shown associated with a de fleeting tool and conditioned for placing in a main well bore prior to the beginning of drilling operations to make a horizontal bore;

FIGURE 2 illustrates the bit-reamer-knuckle joint configuration of this invention;

FIGURE 3 illustrates in plan view a plot of an example of this invention wherein a vertical fracture system from one well is intersected by horizontal bores from a second well; and

FIGURES 4 and 5 are side elevation plots of the horizontal bores illustrated in FIGURE 3.

Referring to the drawings in detail and first to FIGURE 1, there is shown a drilling structure for drilling horizontal bores from a main well bore. These horizontal bores are drilled after the main bore is drilled into the oilbearing strata and can be drilled from the main bore at or near any depth of the main bore and the direction thereof can be at any point of the compass. In some cases the angle of the horizontal bore with respect to the axis of the main bore will be in excess of The horizontal bores reach points a considerable distance, e.g., on the order of feet or more, in a generally horizontal direction from the main bore.

As shown in FIGURE 1, there is provided a deflecting tool, generally designated as D, which has a tubular upper end 10 and a window 11 at its lower end. Mounted in the lower end of the tubular member opposite the window is a plug portion 12 provided with a surface 13 angularly positioned with respect to the longitudinal axis of the defleeting tool, which surface is ordinarily called the deflecting surface. Surface 13 is opposite the window 11 so that the drilling bit can be deflected toward a direction which is at an angle to the axis of the tubular part of the deflecting tool. A tail pipe 14 is secured at the lower end of the deflecting tool. Tail pipe 14 has an anchor 15 at its lower end, the purpose of which is to anchor the deflecting tool D in the main bore and at the desired distance above the bottom of the main bore. The length of the tail pipe 14 will be selected so that when the anchor member 15 is on the bottom of the main bore, the deflecting surface 13 will be at the point in the main bore where it is desired to begin drilling of the lateral bore.

. The horizontal drilling apparatus which embodies this invention comprises in combination with the deflecting tool D several structures which are attached to the lower end of the usual drill pipe P including a flexible shaft or pipe S, a knuckle or universal joint I, a reamer R. and a drill bit B, connected together as shown. The flexible shaft S may be of any suitable construction which will permit the shaft to follow a drill bit into a horizontal hole which is being drilled laterally from the main bore and yet' be capable of transmitting torque to the drill bit. The particular shaft shown comprises a number of tubular sections 16 joined together by means of interengaging lobes 17 and sockets 18.

The universal or knuckle joint J is mounted in the drilling structure at the lower end of the flexible shaft S and forms a connecting joint between this shafting and the drill bit B together with the reamer R which is attached at the rear of the drill bit. The joint] provides a universal connection and is so constructed that drilling torque can be transferred from the flexible shafting to the drilling bit to accomplish drilling operations. Such universal joints are well known in the art and further description is believed unnecessary. To attach the upper end of the joint structure I to the lower end of the flexible shafting S there is provided a tapered sub 19, see FIGURE 2. The drill bit B, already referred to, may be of any suitable construction such as the rock type having rotary cutting members as shown. The reamer R which is located directly behind the drilling bit B follows the drilling bit as it cuts the lateral or horizontal bore and reams out the cut bore.

Before inserting the horizontal drilling apparatus just described into the well bore to perform the drilling of the lateral bore, the deflecting tool will be connected to the drilling bit and flexible shafting so that the relationship thereof will be known. This is accomplished by means of a frangible pin 20 arranged between the tubular part of the deflecting tool and the sub 19 above the joint I. The position of the pin will be such as to hold the bit B slightly above the deflecting surface of the deflecting tool, as shown in FIGURE 1. With this connection, the whole drilling structure shown in FIGURE 1 will then be lowered into the main bore. It will be noted that the structure will be arranged so that the anchor will rest on and press into the bottom of the main bore. The distance that the deflecting tool is above this bottom will depend upon the length of the tail pipe 14. Before placing the anchor 15 on the bottom of the main bore, the deflecting surface 13 of the deflecting tool D will be oriented, that is, placed in the desired compass direction and at the desired depth to drill off from the main bore to produce the horizontal bore. The orienting of the deflecting surface on the deflecting tool is accomplished by conventional methods well known to one skilled in the art and when such is done the anchor will then be placed on the bottom of the main bore where the teeth thereof will dig into the bottom surface and prevent rotation of the deflecting tool relative to the bore.

Drilling operations can now be commenced and these are begun by first applying a downward pressure on the drill pipe P, which will result in severing the frangible pin and disconnection of the drilling structure from the deflection tool. As the drill pipe P is rotated, the drill bit B will also be rotated, and upon continued lowering of the drill pipe, the drill bit will be deflected by the deflecting surface 13 through the window 11 of the deflecting tool and the drilling bit will then begin to cut a hole off from the side of the main bore and in a direction as determined by the angle of the deflecting surface. Due to the fact that the diameter of the members of the joint I is less than the drill bit B, the joint, when acted upon by downward forces present during drilling, will be pushed over toward the deflecting surface 13 of the deflecting tool D. Consequently, this tendency of the joint tomove toward the deflecting surface will result in the placing of the axis of the drilling bit B and also the coinciding axis of the reamer R to be at a slight angle to the deflecting surface. Thus, as soon as drilling bit B reaches a point where it is passing off from the deflecting surface, the bit will tend to dig toward the top side of the bore being drilled and, as a result, the bore will be drilled in a curve, i.e., at an angle to the vertical, and not in a straight or substantially straight line. This is referred to as building angle. If there were no tendency for the drilling bit to build angle as a result of the structure employed, the bore would be drilled in a straight direction substantially the same as that of the deflecting surface as extended, and the axis ofthe lateral here would always maintain an angular relation with the main bore which would be substantially the same as the deflection surface. However, with the improved drilling construction of this invention embodying the universal joint J having a particular relationship with the reamer R, both as to diameter and spacing, the axis of the drilling bit will be at a slight angle to a line tangent to the lateral bore at a point where th drilling bit is cutting, and this angle will be such as to direct the drilling bit toward the high side of the lateral bore as drilling continues. As the drilling bit is rotated and the angle continues to build," the bore cut will have a curvature which will have a substantially uniform radius of curvature. If the lateral bore is continued to be drilled outwardly, it will reach a horizontal direction with respect to the main bore which is assumed to be vertical. During all the drilling, fluid is circulated through the flexible shafting S, joint I and reamer R to the drill bit B. If necessary, the flexible shafting can be lined with a suitable rubber tubing to prevent leakage at the joints.

After the desired length of lateral hole is drilled and the fracture has been intersected, the flexible shafting and other drilling structure can be pulled back into the deflecting tool and then the whole structure removed from the bottom of the main bore, or if it is desired to drill additional drain holes 011 from the main bore, the deflecting tool can be raised off the bottom of the main bore and after turning the drill pipe to a new oriented position it can be again lowered and a lateral bore drilled off in another direction, which will be determined by the direction of the deflecting surface of the deflecting tool.

FIGURE 2 illustrates the required relationship between the reamer R and the joint J. This specific relationship is one of the distance L between the pivotal axis of the joint I, represented by line 34, and the centerline 36 of the reamer R and of the difference a between the radius of the joint and the radius of the reamed hole H, i.e., the distance between the centerline 30 of the reamed hole H and the centerline 32 of the shaft S. This specific relationship of dimension is critical to accomplish the desired drilling of the horizontal bore through buildin of angle and to accomplish control, i.e., maintenance in the direction of horizontal drilling. The radius of curvature RC of the bore drilled is given by the equation L /2a and will be uniform once drilling is begun. If the curvature of the bore is allowed to get off course, i.e., if the bore is drilled in the wrong direction, the curvature is irreversible. In general, an angle of build, i.e., a radius of curvature, is chosen for the drilling apparatus and from this the desired dimensions are chosen. Since the knuckle joint must be smaller than the drill bit and in general has a diameter equal to the flexible shaft S, the dimension a is also relatively set such that in constructing the apparatus in accordance with this invention the dimension L is of primary importance. The reamer R must not only ream out the bore H, but must cut to.

develop the designed and required angle building capability of the drilling apparatus. This cut is preferably approximately A3 inch, although in general the amount may be only that sufiicient to prevent the reamer from acting as a stabilizer and straightening out the flexible shafting S. The upper limit of cut is determined by the amount of cutting which would apply too great torque load to the shafting S and tear the shafting apart.

communication test with a packer set between the two laterals resulted in a strong, turbulent flow of mud through the tubing when the first well was air pressured. The data for the second lateral No. 5 are shown in Table II and FIGURES 3 and 5.

TABLE IL-SECOND LATERAL-WHIPSTOCK ORIENTATION S47E Drilling Drilling Penetration Survey Deviation, Direction, Vertical Depth, Weight, Rate, Depth, deg. deg. Angle Build, ft lbs. ftJmin. it. deg/ft.

2, 293. 8 7, 000 No survey 2, 317. 8 7, 000 No survey 2, 318. 8 7, 000 No survey 2,330.8 7, 000 16 No survey in this well at 2,262 ft. depth using a four jet to-Ol with the hold-down device set at 2,202 ft. The fluid used Was 3,000 gal. of water containing one lb. per gal. of sand concentration. The fluid was pumped for minutes at a 4 b.p.m. rate while rotating the drill pipe at 6 r.p.n1. Lynes straddle packers were set at 2,230 ft. and 2,271.4 ft., top and bottom centers, respectively, and a breakdown with barrels of water was made. A sand-gelled water fracture treatment was then made through 2 drill pipe with a packer set at 2,230 ft. using 30,000 lbs. of 20/40 mesh sand in 15,000 gal. of gelled water.

Packer and pumping tests indicated vertical communication between the 2,246 and the 2,293 ft. zone. A nonoriented impression packer was run to 2,265.4 ft. and an impression of a vertical fracture was obtained. Five irnression packers were run to map the fracture, see FIGURE 3.

A second well was drilled. The second well was located in the direction of the fracture planes with a surface location approximately fifty feet from the first well. The second well was plugged for a whip-stock setting at a depth (2,264 ft.) selected for drilling into the vertical fracture system and a whipstock was set in the direction of the fracture system.

The first three feet of a first lateral were drilled with the bit and stabilizer at the lowest possible weight. The bit and stabilizer assembly were then pulled and the bit, reamer and 5 per foot knuckle joint assembly run. With 8,000 lbs. drilling weight, the direction still shifted 48 in only eight survey feet. The drilling weight was further decreased to 7,000 lbs. for drilling the next 9 ft. and the survey showed no change in direction. A stabilizer was run after drilling almost 22 ft. and the hole was drifted to a total depth of 42% ft. (34% ft. of horizontal distance). At this depth pressured air from the first well blew out in the second well indicating that the drill had cut through the fracture. The data for this lateral are shown in Table I and the lateral is plotted in FIGURES 3 and 4.

The mud system used in drilling the laterals was a salt water emulsion containing 90 pds./bbl. salt, 2.8 pds./bbl. diesel oil, 2.8 pds./bbl. D.M.E. and 9.5 pds./ bbl. EP mudlube. The characteristics of the mud system were:

Characteristics:

Weight pds./gal 9.6-9.7 Viscosity sec 31-33 Chloride ion p.p.m. 247,255,000 Oil percent 3 Water do 87 -89 Solids do 8-10 Lubrication properties Yes EP Lub. properties Yes 1 Diluted down to 190,000 p.p.m.

The output of the compressor used for testing was 66 M c.f.d. during the test for communication of the first lateral. After allowing the second well to blow overnight, an air flow of 64 M c.f.d. was measured with the orifice well tester, indicating 97% communication. The injection pressure was dropping at 1,150 p.s.i. from 1,550 p.s.i. when the test Was ended.

The same basic procedure was used to test the second lateral. A ballon packer was run to 2,268 ft. The blowout preventers were closed and air injection was started into the first well. The pressure stabilized at 1,250 p.s.i. with an injection rate of 64 M c.f.d. After seven hours the second well was still making a strong flow of water and mud up the drill pipe. The test was discontinued since this, plus the water fiow while drilling, was considered ample evidence of good communication.

Hydrocarbons are recovered from an oil shale formation in accordance with this invention by developing a corridor between a first and a second well, now referred to as the input and output wells, as described above. In a preferred embodiment of this invention a fire is maintained in the bore hole of the input well by burning a TABL E I.FIRST LATERAL-WHIPSTOCK ORIENTATION S3E Drilling Drilling Penetration Survey Deviation, Direction, Vertical Angle Horizontal Angle Depth, it. Weight, lbs. Rate, fin/nun. Depth, it. deg. deg. Build, deg/ft. Build, deg/it.

2, 263. 9 Start 2, 266. 9 1, 000-2, 000 A v 2, 273. 9 8,000 14 271. 9 36 845W 4. 5 6 2, 282. 7 7, 000 14 2, 280. 7 75 S45W 4. 4 2,285. 7 7,000 .08 2,283.7 89 848W 4. 7 1 2, 293. 7 7, 000-9, 000 14 2, 291- 7 96 849W 1 2, 306. 7 8, 000 16 2, 304. 7 98% 549W 2 fuel gas therein after the corridor is formed, i.e., communication is established, between the input and output wells. The ignition and maintenance of the fire may be performed by conventional burner means and the temperature of the fire is allowed to increase to at least about 700 F. The bore hole temperature can be maintained at this minimum level by regulating the proportions of fuel gas and combustion supporting gas sent through the bore hole. The heat in the bore hole may exceed 700 F., i.e., up to a temperature where the casing or bore hole wall of the input well will be damaged, but the temperature of the formation adjacent the input bore hole will usually not be greater than about 1,500 F, frequently not greater than about 1,000 F. Since the work required in pumping a gas is proportional to the difference in the squares of the initial and final absolute pressures, less work is generally required to bring about a given pressure difference when a higher initial pressure brings this difference closer to 0. For this reason, the pressure in the output well is preferably maintained above atmospheric pressure and usually at a minimum of about 200 p.s.i.g., with the maximum being somewhat below that pressure which would lift the overburden. The pressure in the input well during the creation of the hot passageway need only exceed the pressure in the output well by just sufficient pressure to bring the fuel and combustion supporting gases from the input well through the corridor. This difference in pressure of input well gases over output well gases is insufiicient to cause significant gas flow through portions of the stratum other than the corridor. In travelling through the passageway the gases may pick up additional fuel components from the adjacent formation and so may be recycled back to the input well to exploit this fuel value and the heat of the exhaust gas. Alternatively the exhaust gases may be passed in a direct or indirect heat exchange relationship with the input gases to conserve heat.

The fire in the bottom hole of the input well heats the walls of the input well and the walls of the corridor become heated by the moving gases. Heat is transmitted primarily by conduction from these heated walls into the formation, and gradually a zone in the formation adjacent the walls of the corridor will become heated. The gases moving through the corridor are, of course, cooled by contacting the walls of the formation, so that it takes some time for the heated zone or hot passageway to reach a temperature of at least 700 F. all the way from the input well to the output well. The conduction of heat into the stratum which takes place from the walls of the bottom hole of the input well and the walls of the corridor heats up a passageway having a smaller transverse cross-section as it approaches the bottom hole of the output well.

Heating under mild gas pressure is continued until a heated zone, i.e., a mass of formation having a tempera ture of atleast about 700 F. is created which extends for at least about 40 or 50 feet along the vertical wall of the bottom hole of the input well and this 700 F. isotherm can even extend the complete height of the hydrocarbon-containing stratum. The heating can also raise the temperature of the entire stratum between the input and output wells, and it can be continued until essentially all of the stratum between the input and output wells is heated to the required minimum temperature, but this is usually neither necessary nor desirable. The approximate 700 F. minimum temperature is sufiicient to fiuidify, that is, to liquefy and/ or vaporize hydrocarbons in or recoverable from the formation. As the heat of the walls of the bore hole and the walls of the corridor including the frac ture and horizontal bore is transmitted to the surrounding formation, the kerogen or other petroliferous material contained in the heated zone is affected and the heat thus serves gradually to remove a certain amount of hydrocarbons from the zone, which are conducted by the corridor to the output well for recovery. Since the creation of the hot passageway is carried out under the minimum gas pressure and since the corridor provides much lower resistance to the passage of gas than the body of the formation, there is little penetration of heated hydrocarbons into cold portions of the formation during heating. As hydrocarbons are removed from adjacent the corridor to the output or production well, the permeability of the heated zone is increased creating a larger passageway for gases. When a later gas sweep or burning wave treatment, conducted under substantially increased gas pressures, is applied to this formation, the hydrocarbon materials which are taken from the formation can travel to the output well without being exposed to congelation temperatures and, therefore, without clogging all passageways and requiring uneconomically high pressures for the creation and maintenance of gas circulation.

The shape of the heated zone is determined by the characteristics of the formation, for example, the specific heat of the formation material and the convective ability of the corridor. The same factors, as well as the ignition temperature of the fuel, will also determine how high a temperature above about 700 F. may be reached in the heated zone. The time required to heat the formation to create a base for the passageway at the wall of the input well bottom hole having the desired 700 F. temperature and least about 40 or 50 feet in diameter also depends upon how much heat is consumed in fluidifying the hydrocarbons of the formation. The rate of gas injection and the composition of the injected gases govern to a large extent the amount of time taken for the complete length of the fracture to reach the desired temperature.

The heated passageway is maintained at a temperature of at least about 700 F. during a subsequent hydrocarbon recovery procedure which employs passage of gas from the input well, through the preheated formation or passageway, and to the output well at a pressure higher than employed in creation of the heated passageway. In order to insure flow of the gas through the formation itself, rather than through the generally more permeable, original corridor, the end of this corridor adjacent the input well may be plugged, to a greater or less extent, depending on the relative permeability of the corridor and the adjacent heated zone of the formation.

A simple way to recover hydrocarbons from the formation is the injection of a gas into the formation from the input well to fiuidify hydrocarbons in the formation. This sweep gas, preferably at a temperature of at least about 700 F. and, of course at a pressure sufiicient to penetrate the formation itself, travels through the hot passageway and maintains the passageway at this temperature. The passage of the gas may also serve gradually to heat zones in the formation surrounding the hot passageway to the approximate 700 F. mark causing fluidification of the supporting gas such as flue gas or steam.

Alternatively, after the hot passageway and heated formation are established and the corridor plugged, if necessary, a moving burning wave can be generated in the previously heated formation, for instance, according to the process of the aforementioned U.S. Patent No. 2,780,449. As an example, the proportions of fuel gas and combustion supporting gas sent to the fire in the bottom hole of the input well are adjusted, if necessary, to give a temperature level in a portion. of the formation of at least about 700 or 1000 F. or higher depending on the combustion temperature of the carbonaceous residue in the siliceous material in the vicinity of the input well bore hole. The pressure is increased to a value sufficient for the combustion gases to penetrate at least the portions of the formation which have been heated by conduction. The gas flow rate should be as high as is practical at a pressure sufiicient to maintain passage through heated portions of the formation from the input well to the output wells or output zone. When the heated zone, that is, a zone having a temperature of at least about 700 F has been established at the wall of the input well, burning in the input well is discontinued and the heated zone is moved as a thermal front or wave radially outward into the formation through the area preheated by conduction and in the direction of the output well. This can be performed by substituting an unheated substantially noncombustible oxygen-containing gas stream for the fuel-gas-air mixture at the input well so that the region of peak temperature is moved gradually outward into the formation from the input well. In this manner the injected gas stream is an effective heat transfer medium absorbing heat as it approaches the peak temperature region of, for example 700 to 1000 or 2000 F., and transferring heat absorbed in the process to the regions of the formation beyond the hot zone. Gases, both those injected and those produced by heating, and fluidified hydrocarbons flow through the heated passageway to the output well. The pressure on the input gases may force some of the heated gases into unheated zones within the formation to secure recovery of hydrocarbons from these zones or these zones may be heated by conduction in advance of the burning wave. Thus, the hot zone is moved as a front or thermal wave from the input well region through the preheated formation toward the output well. During the operation, or as part of a coordinated cycle, the temperature level is maintained in the frontal zone by controlling the oxygen content of the input gas with water, recycle flue gas or other substantially inert diluents.

A principle behind the moving thermal front formation is the reduction of the fuel content of the input gas stream to a proportion below the explosive limit so that the mixture cannot ignite until it is in the formation where unburned carbonaceous matter is available to enrich the fuel-oxygen ratio to within combustible limits and where a high enough temperature for spontaneous combustion exists. As injection of the cool oxygen-containing gas proceeds, regions in the stratum closer to the input well are cooled while regions remote from the heated passageway may be successively heated to 700 F., a temperature suflicient to fluidify and remove a quantity of the hydrocarbons present therein and to increase the crosssectional area of the portions of the heated passageway remote from the input well. A carbonaceous residue is left in the passageway as fuel for combustion when the residue is contacted with the oxygen-containing gas.

In order to accomplish continuous forward movement of the heated zone as a wave of relatively narrow profile and high peak temperature, it is advantageous to move the zone into the formation by use of a relatively cool gas drive system. Alternate cycles may be operated in which an inert gas mixture, for example, recycled flue gas substantially free of oxygen, may be employed as a cold gas drive to keep the burning zone confined to the moving front and to heat the formation in front of the burning Wave. Usually the combustion supporting gas will contain about 1-25 by volume of free oxygen, preferably about 520%.

In certain circumstances, depending on the character of the crude hydrocarbons and the well spacing, a reverse burning wave procedure may be advisible. For example, where the input well is rather distant from the output Well and where heating of portions of the formation results in the movement of great amounts of viscous crude to the hot passageway at a temperature below about 700 F. thus tending to cool and clog the passageway, it is feasible to conduct the burning wave in reverse, that is, to have it pass from the producing well back to the input well, as disclosed in the aforementioned US. Patent No. 2,793,696. This reverse-traveling wave front may be accomplished by heating the walls of the output well, after the creation of the hot passageway, to combustion temperature and passing combustion-supporting gas into the output well until combustion is established in the formation adjacent the output well. When combustion is thus established in the formation itself, injection of combustion supporting gas to the output well is discontinued while injection of this gas into the input well at a relatively high pressure and exhaustion of the waste and hydrocarbon-containing gases from the output well is established. The creation of the hot passageway can overcome some of the difficulties encountered with reverse-burning waves described in the above-mentioned patent. During the burning wave, the hot passageway will offer less resistance to the flow of combustion-supporting or waste gases and also will, partially at least, provide for hydrocarbon recovery in the part of the stratum near the input well which may be beyond the economic recovery limit of the reverse-wave treatment.

As mentioned previously, the greater proportion of gases pass through the previously heated passageway which is maintained at a temperature above the congealing temperature of the fluidified hydrocarbons. The gases carry with them the vaporized hydrocarbons to the production well. Liquid hydrocarbons also flow to this well and recovery from the well may be accomplished by any suitable means.

Sometimes it may be desirable to introduce cool combustion supporting gas and perhaps some fuel gas as well to the output well when a burning wave breaks through to the production well. Such a procedure serves to cool the production well and also perhaps to prevent combustion of liquid hydrocarbons which have drained to the production well bottom hole. The cooling of the production well is desirable to prevent destruction of equipment in the production well and the plugging of the bore hole or equipment by coke and soot accumulation. Water may also be injected into the output well to control combustion and also, by partially filling the bottom hole, to prevent pressure escape to other parts of the field.

It is thus seen that the initial heating method of this invention removes hydrocarbons from an underground deposit containing hydrocarbons in a substantially nonflowable condition while minimizing heat losses and gas pressure requirements. For example, when applied to shale or a Kansas field containing a crude oil of about 23 API and exhibiting an effective gas permeability of 3 md., the method of this invention gives better results than other secondary recovery methods. The process prepares the formation for treatment by subsequent gas sweep thermal recovery procedures. The latter procedures include more gas sweeping the preheated formation or sending a burning wave through the stratum.

It is claimed:

1. A method for establishing communication between two wells in an oil shale formation comprising fracturing in said formation at a first well to produce a vertical fracture system generating outwardly from the well, determining the orientation of said fracture system, and drilling a lateral bore from the main bore of the second well to intersect said fracture and establish communication between said first and second wells.

2. The method of claim 1 wherein said drilling of the lateral bore comprises drilling a lateral curved bore having a predetermined uniform radius of curvature from the main bore of the second well in a direction to intersect said fracture system until an approximately horizontal plane is reached utilizing a drilling structure including a flexible drill shaft, a drill bit, a reamer attached behind said bit and a universal joint connecting said shaft and drill bit, said reamer cutting the lateral curved bore a sufficient amount to prevent stabilization of said drill bit, said joint structure having an overall diameter less than the drill bit and being positioned closely adjacent to the drill bit in accordance with the equation RC:L /2a wherein RC is said predetermined radius of curvature, L is the distance measured from the centerline of said joint structure to the centerline of said reamer both in the plane of contact to the drilled lateral curved bore and a is the distance between the centerline of the reamed lateral curved bore and the centerline of the joint structure, said flexible drill pipe also being of a diameter less than the drill bit whereby during drilling the drill bit can first be deflected in the desired direction from the main bore by the deflecting tool to start the lateral bore and thereafter the joint will be permitted by the dimensional relationship thereof to the reamer, the cutting of the reamer bit, and the size of the flexible drill pipe to be forced to the low side of the lateral bore being drilled and the bit will be directed continuously in said desired direction without substantial deviation and toward the high side of the bore bottom to thereby build angle and produce the curved bore, and after said plane is reached replacing said reamer with a stabilizer and drilling a horizontal bore until said fracture system is intersected.

3. The method of claim 2 wherein a drilling fluid containing an extreme pressure lubricant is circulated through said flexible shaft and around said drill bit during said drilling.

4. The method of claim 2 wherein an axial load in excess of 7,000 pounds is applied on said drilling structure.

5. A method for establishing communication between two wells in an underground petroliferous formation having an effective permeability less than about 10 millidarcies comprising fracturing in said formation at a first well to produce a vertical fracture system generating outwardly from the well, determining the orientation of said fracture system, and drilling a lateral bore from the main bore of the second well to intersect said fracture and establish communication between said first and second Wells.

References Cited UNITED STATES PATENTS 2,796,129 6/ 1957 Brandon 166-42 2,966,346 12/1960 Huitt et al 16642 3,003,557 10/1961 Huitt et al 166-42 3,199,586 8/1965 Henderson et a1 166-9 3,270,816 9/1966 Staadt 166--42 3,285,335 11/1966 Reistle 166-42 CHARLES E. OCONNELL, Primary Examiner. JAMES A. LEPPINK, Examiner.

UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION Patent No. 3,349,845 October 31, 1967 Don R. Holbert et al.

It is hereby certified that error appears in the above numbered pa ent requiring correction and that the said Letters Patent should read a corrected below.

In the heading to the printed specification, lines 5 and 6, cancel "assignors to Sinclair Oil 6 Gas Company" and insert assignors, by mesne assignments, to Sinclair Research, Inc., New York, N. Y., a corporation of Delaware Column 2, line 17, "imperable" should read impermeable line 70 "or" should read of Column 3 line 10 I "described" should read describes Column 4, line 20, "preferably" should read preferable Column 6, line 47, after "joint" insert J Column 10, line 18, before "least" insert at Signed and sealed this 23rd day of September 1969.

(SEAL) Attest:

EDWARD M.FLETCHER,JR. WILLIAM E. SCHUYLER, JR. Attesting Officer Commissioner of Patents

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Classifications
U.S. Classification166/251.1, 166/259, 166/271, 166/252.1, 166/255.3, 166/272.7, 166/250.1
International ClassificationE21B17/20, E21B43/17, E21B7/04, E21B17/00, E21B7/08, E21B7/06, E21B43/16
Cooperative ClassificationE21B7/061, E21B43/17, E21B17/20, E21B17/00
European ClassificationE21B7/06B, E21B43/17, E21B17/00, E21B17/20