# Patent

## Title
Diamond drill bit with varied cutting elements

## Abstract

This is a Continuation-In-Part of Ser. No. 215,209, filed Dec. 11, 1980, now U.S. Pat. No. 4,427,080; the entirety of which is incorporated by reference.

## Background
This invention relates to preventing downhole equipment from sticking in well boreholes. The invention comtemplates the use of improved drill collars and other well implements having a porous coating placed on at least a portion of those implements.

In the drilling of oil wells, gas wells, lixiviant injection wells, and other boreholes, various strata are bypassed in achieving the desired depth. Each of these sub-surface strata has associated with it physical parameters, e.g., porosity, liquid content, hardness, pressure, etc., which make the drilling art an ongoing challenge. Drilling through a stratum produces an amount of rubble and frictional heat; each of which must be removed if efficient drilling is to be maintained. In rotary drilling operations, heat and rock chips are removed by the use of a liquid known as drilling fluid or mud. Most rotary drilling apparatus use a hollow drill string made up of a number of drill pipe sections and, of course, a drill bit at the bottom. Drilling fluid is circulated down through the drill string, out through orifices in the drill bit where it picks up rock chips and heat and returns up the annular space between the drill string and the borehole wall to the surface. There it is sieved, reconstituted and directed back down into the drill string.

Drilling fluid may be as simple in composition as clear water or it may be a complicated mixture of clays, thickeners, dissolved inorganic components, and weighting agents.

The charactertistics of the drilled geologic strata and, to some extent, the drilling apparatus determine the physical parameters of the drilling fluid. For instance, while drilling through a high pressure layer, e.g., a gas formation, the density of the drilling fluid must be increased to the point that the hydraulic or hydrostatic head of the fluid is greater than the downhole pressure of the stratum to prevent gas leakage into the annular space surrounding the drill pipe and lower chances for a blowout.

In strata which are porous in nature and additionally have a low formation pressure, another problem occurs. Some of the drilling fluid, because of its hydrostatic head, migrates out into the porous layer rather than completing its circuit to the surface. One common solution of this problem is to use a drilling fluid which contains bentonite clay or other filtration control additives. The porous formation tends to filter the filtration control additive from the drilling fluid and form a filter cake on the borehole wall thereby preventing the outflow of drilling fluid. As long as this filter cake is intact, very little fluid is lost to the formation.

During drilling, the rotating drill string is closely adjacent or in contact with the filter cake. If the filter cake is soft, thick, or of poor quality or if the drill string thins the filter cake, then the higher hydrostatic head of the drilling fluid will tend to push the drill string into the filter cake. In some cases the drill string will stick to the borehole wall. This phenomenon is known as differential pressure or hydrostatic sticking. In severe cases, it will be impossible to either turn the drill string or even move it up and down the borehole. It is this problem for which the apparatus of the invention is a solution.

The two widely used methods of alleviating hydrostatic or differential pressure sticking attack the problem from different flanks; one is remedial and the other preventative.

Once a drill string is stuck against a filter cake adjacent a porous formation, the remedy of a chemical spotting agent is used. It is first necessary to determine where on the drill string the stickage has occurred. One such method involves stretching the drill string by pulling it at the surface. Charts are available correlating the resulting stretch (per amount of applied stress) with feet of drill pipe. Once this information is known, the injection of water-based drilling fluid is interrupted and the spotting agent substituted. The spotting agents are often oleophilic compositions and may be oil-based drilling fluids, invert emulsions of water in oil, or a material as readily available as diesel oil. After the slug of, typically, 10-50 barrels of spotting agent is introduced, addition of drilling fluid is re-commenced. The slug of spotting agent continues its trip down through the drill string, out the drill bit, and up the wellbore annulus until it reaches the site of the stickage. Upon arrival of the spotting agent at the stickage location, circulation is temporarily ceased. Those  skillful in this art speculate that oil-based spotting agents tend to dehydrate the filter cake on the borehole wall and cause it to break up, thereby allowing the drill string to come free. In any event, once movement of the drill string is detected, circulation of the drilling fluid is restored. It should be observed that the cost of this process is high and the success rate only moderate.

A preventative method of allaying drill string stickage in porous formations entails the use of drill collars having flutes, spirals, or slots machined in the outer surfaces. This method is used to a lesser extent than the spotting agent method since it involves a higher capital expense, and results in lighter drill collars. Drill collars are, of course, used for the specific purpose of adding weight to the lower end of a drill string. Consequently, light drill collars are not viewed with much enthusiasm. Although these collars are somewhat more effective in preventing stickage, they are not immune to the problem since the exterior grooves can be plugged, inter alia, with soft clay.

The purpose of this invention is to provide downhole well implements with reduced susceptibility to differential pressure sticking. In particular, it involves providing such implements with a wear-resistant porous layer or coating. This coating may be permeated with a chemical spotting agent. This coating may also be either permanent or detachable.

The implements typically requiring such a coating would be either drill collars or logging tools. Drill collars are essentially heavy drill pipe sections and are placed between the drill bit and the upper section of drill pipe. They are used to stabilize the drill string and weight the drill bit during drilling operations. Logging tools are instruments lowered into an open borehole on a wire-line or cable to measure various formation parameters, e.g., resistivity, sonic velocity, etc. These measurements are then transformed into usable information regarding, for instance, natural gas or oil content.

The applied porous coating of the present invention is one that does not present a large unbroken surface area to the filter cake but does allow liquid migration within the coating from the open borehole area to an area of contact with the filter cake. It should be apparent that the well implements, whether permanently coated with a porous coating or merely covered with a detachable porous coating, present a substantially nonporous or continuing surface below the innermost level of the coating. It is theorized that the porous coating's capability of allowing liquid to flow toward the area of the drill string's contact with the thinned filter cake is the physical characteristic which prevents substantial differential pressure sticking.

It is further contemplated that the pores of the coating may be impregnated with an oleophilic composition having a viscosity between that of a light oil and a grease and having the capability of acting as a localized spotting agent.

FIG. 1 is a schematicized depiction of a typical drilling rig.

FIG. 2 is a cross-sectional view of a drill collar in a borehole having a permanent single layer of porous material attached thereto.

FIG. 3 is a cross-sectional view of a drill collar in a borehole having multiple layers of porous material attached thereto.

FIG. 4A is a side view of a well implement having mottled layers of porous material attached thereto.

FIG. 4B is a side view of a well implement having bands of permanent layers of porous material attached thereto.

FIG. 5A is a side view of a detachable porous covering suitable for use on a well implement.

FIG. 5B is a variation of the detachable porous covering shown in FIG. 5A.

A conventional rotary drilling rig is shown in FIG. 1. The portion below ground consists of a drill string and is made up of upper drill pipe sections 103, drill collars 104, and drill bit 105. Pipe sections 103 and drill collars 104 are little more than threaded hollow pipe which are rotated by equipment on the surface. Drill collars 104 are significantly heavier than are the sections of drill pipe 103 because they are intended to weight drill bit 105, to steady the drill string and to keep it in tension.

The drill string is turned by use of kelly 102, a flat-sided hollow pipe often square in cross section, which is screwed into the uppermost section of drill pipe 103. The kelly is turned by a powered rotary table 107 through a kelly bushing 108. The drill string and kelly 102 are supported by rig hoisting equipment on derrick 106.

While the drill string is turning, a drilling fluid or mud is pumped into the swivel 101 from a hose attached to connection 110. The drilling fluid proceeds down through kelly 102, upper drill pipes 103, and drill collars 104. The drilling fluid exits through orifices in drill bit 105 and flows upwardly through the annulus between the borehole wall 109 and either the drill collars 104 or the drill pipe sections 103. Drilling fluid leaves the well through pipe 111 for subsequent recovery, reconstitution and recycling.

For purposes of illustration, the depicted well has a porous stratum or layer 114. The well has been treated with a drilling fluid which left a filter cake 115. The well has, as most oil wells have, a partial casing 112 terminated by a casing shoe 113. Well casings are cemented in place and serve to isolate the various pressured formations and to prevent contamination of water-bearing strata with drilling fluid and petroleum.

Problems with differential pressure sticking in such a well normally would occur at the interface between filter cake 115 and drill collar 104.

FIG. 2 depicts, in horizontal cross-section, a situation in which a drill collar 104 made in accordance with the present invention is in contact with a low pressure formation 114 having a filter cake 115 deposited thereon. The drill collar 104 has the inventive porous coating 150 disposed about it. The drill collar 104, in this example, squeezed in or abraded away a portion of filter cake 115 and formed a thin area 155. Since the hydrostatic pressure of the drilling fluid in wellbore annulus 154 is higher than the pressure in formation 114, a potential differential pressure sticking situation is present.

The wellbore implements of the instant invention, such as the drill collars depicted in FIGS. 1 and 2, or various logging tools, have thereon a porous coating. Desirable coating compositions comprise those metals which adhere to the steels used in most drilling implements after proper treatment. They are corrosion and wear resistant in the borehole environment. The coating may also have dispersed within it a number of abrasive or wear resistant particles. These abrasives are used to prolong the life of the coating and may be materials such as SiC, WC, corundum, etc.

The use of porous ceramic, glass materials or plastics which are sufficiently tough to undertake the rigors of rig handling and borehole environment without substantial degradation are within the scope of this invention.

In theory, the coating prevents differential pressure sticking for two reasons. First, the rough outer surface of the coating does not readily provide a seal between the implement and the filter cake. Secondly, the network of small tunnels within coating 150 allows the higher pressure fluid in borehole annulus 154 to flow via a path 153 to the vicinity of highest differential pressure to lower the pressure differential at the interface between the drill collars and the filter cake and enable movement of the drill string.

Another desirable configuration is depicted in FIG. 3 and entails multiple layers of coatings of different permeabilities, e.g., an inner layer 156 or layers produced with large particles and thereby having a higher permeability, covered by an outer layer 150 produced from smaller particles having lower permeability. This allows the liquid to flow quickly through the inner layer to the contact area while the outer layer would be less susceptible to plugging.

The coating need not completely cover the outside area of the implement. It must, however, mask a sufficient proportion of the implement's outer surface to prevent differential pressure sticking. The coating as shown in FIG. 4A, may be mottled 157 in its coverage of the implement. The most desirable configuration entails bands 158 of coating as shown in FIG. 4B. The coating need not be uniform in thickness in either case although such is desirable from the viewpoint of lessened solids buildup on the drill collar 104.

Production of the coating may take place any well-known prior art method. The often corrosive environment presented by drilling fluids somewhat limits the choice of materials which are suitable as coatings for the drill implements. However, application of powdered iron alloys with or without additional abrasive material such as silica or alundum to steel and iron substrates is shown in U.S. Pat. No. 2,350,179 (issued on May 30, 1944 to Marvin). The process taught therein partially presinters the powders to create a pre-form corresponding in shape to the desired backing. The pre-sintered form is placed on its backing material and both are raised to a temperature suitable for sintering the particles and bonding them to the support. A reducing atmosphere is used in the latter sintering step. The sintered layer is then rolled either while still in the sintering oven or shortly after its exit to enhance the adhesion between the layers.

Another suitable method for producing a porous coating on a drill implement is disclosed in U.S. Pat. No. 3,753,757 (issued on Aug. 31, 1973 to Rodgers et al). This process entails first applying a diluted polyisobutylene polymer to the implement. The polymer forms a tacky base to which metal powders will adhere. An appropriate metal powder of iron, steel, or stainless steel is then applied to the tacky surface preferably by electrostatic spraying. The implement is heated to a first temperature sufficient to volatilize the isobutylene polymer and a second temperature sufficient to bond the powder to itself and the implement.

The optional abrasive powders are mixed with the metal powders at or before the time of application. The sintering temperature of most abrasives is significantly higher than that of any metal or alloy realistically useful on a drill implement. For instance, the sintering temperatures of tungsten carbide is 2650.degree.-2700.degree. F. The usual sintering temperatures for AISI C1020 carbon steel is generally about 2000.degree. F. A tungsten carbide particle therefore comes through the powder sintering process largely unaffected.

When ferrous powders are used to coat the implement, treating in superheated steam (1000.degree.-1100.degree. F. ) for a short length of time after sintering is desirable. Such treatment causes an increase in the wear and corrosion resistance of the coating by producing a thin layer of black iron oxide on the exterior of the particles.

Another method of placing a porous coating on well implements entails use of removable devices such as those shown in FIGS. 5A and 5B. FIG. 5A shows a removable coating assembly in which a thin nonporous layer 160 is coated by a permeable layer 162 made in the manner discussed above. The two or more parts are hinged together at hinge 164. The two halves are swung together over a well implement and bolted together using bolts 165 through recessed boltholes 166 connecting with nuts 167 in and nutholes 168. Holes 181 may be cut through layer 160 to expose both sides of permeable layer 162. In this way, the permeability of layer 162 may be monitored during the lifetime of the assembly.

FIG. 5B shows another embodiment of a removable coating assembly. This embodiment uses two similar halves; one of which is shown 170. Each half has fingers 172 along the mating edge which fit into matching depressions on the other half. When assembled around a well implement, a pin 174 is inserted through a series of holes which line up through the meshing fingers 172. Two pins 174 hold the assembly together. Alternately, a hinge, as shown in FIG. 5A, may be substituted for a set of meshing fingers. The assembly half 170 is made up of a nonporous backing 178, to add strength to the assembly, and the porous coating 180. Holes 181 may also be integrated in this design.

The length of the remarkable coating assembly shown in FIGS. 5A and 5B is not particularly critical. Its area must be sufficient to cover the well implement to prevent sticking. Sizing depends on the particulars of the involved well. The removable coating assembly should fit snug against the well implement around which it is installed. Several may be placed on a single well implement and form a complete covering or a number of bands.

The porous coating on the removable coating assemblies shown in FIGS. 5A and 5B may be mottled, banded, or be made up of multiple layers having varying porosities as discussed above. The coatings may also contain the abrasion-resistant materials mentioned supra.

The removable assembly shown in FIGS. 5A and 5B are especially suitable for lighter well implements such as logging tools. These may be fabricated from the noted plastic, metal, glass, ceramic, or wear resistant composite materials.

In any event, once the implements are provided with a porous coating, they are used as any uncoated implement would be. However, if so desired, the porous openings in the outer layer may be impregnated with an oleophilic composition having a viscosity between about that of diesel oil and about that of grease. Greases may be applied by a number of methods. For instance, the greases may be diluted in a volatile hydrocarbon solvent and sprayed on the implement. Once the solvent evaporates, the grease will remain both on the surface of the implement and in the outer pores of the applied coating. The greases obviously may also be applied by rolling or brushing. The lighter hydrocarbons may be sprayed or brushed or the implement may be dipped into the hydrocarbon prior to use.

The added oleophilic composition has dual functions. It primarily serves as a localized spotting agent. However, some lubricity is also present especially when heavier hydrocarbons are applied.

In sum, the instant invention is readily applicable to either new or existing well implements. It uses only well known materials and methods of application and yet solves a heretofore serious problem.

However, it should be understood that the foregoing disclosure and description are only illustrative and explanatory of the invention. Various changes in size, shape, materials of construction, and configuration as well as in the details of the illustrated construction may be made within the scope of the appended claims without departing from the spirit of the invention.

## Claims

1. Apparatus adapted for removably attaching to implements used in a well comprising an inner substantially continuous backing layer, an outer porous coating with porosity sufficient substantially to prevent downhole differential pressure sticking, and means for removably attaching said apparatus to said implement, wherein said means comprise bolts or comprise interlocking fingers and pins.

2. The apparatus of claim 1 wherein the outer coating is multi-layered.

3. The apparatus of claim 2 wherein the outermost layer is less permeable than at least one inner layer.

4. The apparatus of claim 1 wherein the outer coating is configured in the shape of bands around the apparatus.

5. The apparatus of claim 1 wherein the outer coating is in a mottled configuration.

6. The apparatus of claim 1 wherein at least a portion of the outer coating is impregnated with a spotting agent.

7. The apparatus of claim 6 wherein the spotting agent is an oleophilic composition having a viscosity between about that of diesel oil and about that of grease.

8. The apparatus of claim 7 wherein the spotting agent is diesel oil.

9. The apparatus of claim 1 wherein the outer coating additionally contains a dispersed abrasive composition.

10. The apparatus of claim 9 wherein the abrasive composition is tungsten carbide.

11. The apparatus of claim 1 wherein said substantially continuous backing layer has holes therethrough.

12. Apparatus suitable for use in a well comprising in combination a well implement and a removable porous coating assembly attached to the exterior of said implement, said assembly comprising an inner substantially continuous backing layer, an outer porous coating with porosity sufficient substantially to prevent downhole differential pressure sticking, and means for removably attaching said assembly to said implement, wherein the means for removably attaching said assembly comprises bolts or comprise interlocking fingers and pins.

13. The apparatus of claim 12 wherein the outer coating is multi-layered.

14. The apparatus of claim 13 wherein the outermost layer is less permeable than at least one inner layer.

15. The apparatus of claim 12 wherein the outer coating is configured in the shape of bands around the apparatus.

16. The apparatus of claim 12 wherein the outer coating is in a mottled configuration.

17. The apparatus of claim 12 wherein at least a portion of the outer coating is impregnated with a spotting agent.

18. The apparatus of claim 17 wherein the spotting agent is an oleophilic composition having a viscosity between about that of diesel oil and about that of grease.

19. The apparatus of claim 18 wherein the spotting agent is diesel oil.

20. The apparatus of claim 12 wherein the outer coating additionally contains a dispersed abrasive composition.

21. The apparatus of claim 20 wherein the abrasive composition is tungsten carbide.

22. The apparatus of claim 12 wherein the well implement is a drill collar.

23. The apparatus of claim 12 wherein the well implement is a logging tool.

24. The apparatus of claim 12 wherein said substantially continuous backing layer has holes therethrough.