CA1173350A - Apparatus for preventing differential sticking in wells - Google Patents
Apparatus for preventing differential sticking in wellsInfo
- Publication number
- CA1173350A CA1173350A CA000410618A CA410618A CA1173350A CA 1173350 A CA1173350 A CA 1173350A CA 000410618 A CA000410618 A CA 000410618A CA 410618 A CA410618 A CA 410618A CA 1173350 A CA1173350 A CA 1173350A
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- Canada
- Prior art keywords
- outer coating
- comprised
- iron alloy
- abrasive composition
- additionally contains
- Prior art date
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Abstract
APPARATUS FOR PREVENTING
DIFFERENTIAL PRESSURE STICKING IN WELLS
ABSTRACT OF THE INVENTION
A porous layer is placed on the outside of various well implements.
The layer allows movement of liquid toward sites of localized low pressure and therefore prevents differential pressure stickage of the well implements on the borehole wall.
DIFFERENTIAL PRESSURE STICKING IN WELLS
ABSTRACT OF THE INVENTION
A porous layer is placed on the outside of various well implements.
The layer allows movement of liquid toward sites of localized low pressure and therefore prevents differential pressure stickage of the well implements on the borehole wall.
Description
1 3 3 5 ~
2DIFFERENTIAL PRESSURE STIC~ING IN WEL~S
4This invention relates to preventing downhole equipment from sticking in well boreholes. The invention contemplates the use of improved 6 drill collars and other well implements having a porous coating placed on 7 at least a portion of those implements.
8 In the drilling of oil wells, gas wells, lixiviant injection 9 wells, and other boreholes, various strata are bypassed in achieving the desired depth. Each of these subsurface strata has associated with it 11 physical parameters, e.g.~ porosity, liquid content, hardness, pressure, 12 etc., which make the drilling art an ongoing challenge. Drilling through a13 stratum produces an amount of rubble and frictional heat; each of which 14 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 16 known as drilling fluid or mud. Most rotary drilling apparatus use a 17 hollow dril:L string made up of a number of drill pipe sections and, of 18 course, a drill bit at the bottom. Drilling fluid is circulated down 19 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 21 drill string and the borehole wall to the surface. There it is sieved, 22 reconstituted and directed back down into the drill string.
23 Drilling fluid may be as simple in composition as clear water or 24 it may be a complicated mixture of clays, thickeners, dissolved inorganic components, and weighting agents. The charactertistics of the drilled 26 geologic strata and, to some extent, the drilling apparatus determine the 27 physical parameters of the drilling fluid. For instance, while drilling ,.
~ 1~335~
1 through a high pressure layer, e.g., a gas formation, the densi~y of the
2DIFFERENTIAL PRESSURE STIC~ING IN WEL~S
4This invention relates to preventing downhole equipment from sticking in well boreholes. The invention contemplates the use of improved 6 drill collars and other well implements having a porous coating placed on 7 at least a portion of those implements.
8 In the drilling of oil wells, gas wells, lixiviant injection 9 wells, and other boreholes, various strata are bypassed in achieving the desired depth. Each of these subsurface strata has associated with it 11 physical parameters, e.g.~ porosity, liquid content, hardness, pressure, 12 etc., which make the drilling art an ongoing challenge. Drilling through a13 stratum produces an amount of rubble and frictional heat; each of which 14 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 16 known as drilling fluid or mud. Most rotary drilling apparatus use a 17 hollow dril:L string made up of a number of drill pipe sections and, of 18 course, a drill bit at the bottom. Drilling fluid is circulated down 19 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 21 drill string and the borehole wall to the surface. There it is sieved, 22 reconstituted and directed back down into the drill string.
23 Drilling fluid may be as simple in composition as clear water or 24 it may be a complicated mixture of clays, thickeners, dissolved inorganic components, and weighting agents. The charactertistics of the drilled 26 geologic strata and, to some extent, the drilling apparatus determine the 27 physical parameters of the drilling fluid. For instance, while drilling ,.
~ 1~335~
1 through a high pressure layer, e.g., a gas formation, the densi~y of the
2 drilling fluid must be increased to the point that the hydraulic or hydro-
3 static head of the fluid is greater than the downhole pressure of the
4 stratum to prevent gas leakage into the annular space surrounding the drill pipe and lower chances for a blowout.
6 In strata which are porous in nature and additionally have a low 7 formation pressure, another problem occurs. Some of the drilling fluid, 8 because of its hydrostatic head, migrates out into the porous layer rather 9 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 ll filtration control additives. The porous formation tends to filter the 12 filtration control additive from the drilling fluid and forms a filter cake13 on the borehole wall thereby preventing the outflow of drilling fluid. As 14 long as this filter cake is intact, very little fluid is lost to the forma- tion.
16 During drilling, the rotating drillstring is closely adjacent or 17 in contact with the filter cake. If the filter cake is soft, thick, or of 1~ poor quality or if the drill string thins the filter cake~ then the higher 19 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 21 borehole wall. This phenomenon is known as differential pressure or hydro-22 static sticking. In severe cases, it will ~e impossible to either turn the23 drill string or even move it up and down the borehole. It is this problem 24 for which the apparatus of ~he invention is a solution.
The two widely used methods o~ alleviating hydrostatic or differ-26 ential pressure sticking attack the problem from different flanks; one is 27 remedial and the other preventative.
3 3 5 ~
1 Once a drill string is stuck against a filter cake adjacent a 2 porous formation, the remedy of a chemical spotting agent is used. It is 3 firs~ necessary to determine where on the dril]. string the stickage has 4 occurred. One such method involves stretching the drill string by pulling it at the surface. Charts are available correlating the resulting stretch 6 (per amount of applied stress) with feet of drill pipe. Once this informa-7 tion is known, the injection of water-based drilling fluid is interrupted 8 and the spotting agent substituted. The spotting agents are often oleophilic 9 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 11 slug of, typically, 10-50 barrels of spotting agent is introduced, addition12 of drilling fluid is re-commenced. The slug of spotting agent continues 13 its trip down through the drill string, out the drill bit, and up the 14 wellbore annulus until it reaches the si~e of the stickage. Upon arrival of the spotting agent at the stickage location, circulation is temporarily 16 ceased. Those skillful in this art speculate that oil-based spotting 17 agents tend to dehydrate the filter cake on the borehole wall and cause it 18 to break up, thereby allowing the drill string to come free. In any event,19 once movement of ~he drill string is detected, circulation of the drilling fluid is restored. It should be observed that the cost of this process is 21 high and the success rate only moderate.
22 A preventative method of allaying drill string stickage in porous23 formations entails the use of drill collars having flutes, spirals, or 24 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 26 expense, and results in lighter drill collars. Drill collars are, of 27 conrse, used for the specific purpose of adding weight to the lower end of 28 a drill string. Consequently light drill collars are not viewed with much 29 enthusiasm. Although these collars are somewhat more effective in preventing stickage, they are not immune to the problem since the exterior grooves can 31 be plugged, inter alia, with soft clay.
2 The purpose of this invention is to provide downhole well imple-3 ments with reduced susceptibility to differential pressure sticking. In 4 particular it involves providing such implements with a wear-resistant porous layer or coating. This coating may be permeated with a chemical 6 spotting agent.
7 The implements typically requiring such a coating would be either 8 drill collars or logging tools. Drill collars are essentially heavy drill 9 pipe sections and are placed between the drill bit and the upper section of drill pipe. ~hey are used to stabilize the drill string and weight the 11 dxill bit during drilling operations. Logging tools are instruments lowered 12 into an open borehole on a wire-line or cable to measure various formation 13 parameters, e.g., resistivity, sonic velocity, etc. These measurements are14 then transformed into usable information regarding, for instance, natural gas or oil content.
16 The applied porous coating is one that does not present a large 17 unbroken surface area to the filter cake but does allow liquid migration 18 within the coating from the open borehole area to an area of contact with 19 the filter cake. It is theorized that the porous coating's capability of allowing liquid to flow toward the area of the drill string's contact with 21 the thinned filter cake is the physical characteristic which prevents 22 substantial differential pressure sticking.
23 It is further contemplated that the pores of the coating may be 24 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 loca-2~ lized spotting agent.
33~
1 ~RIEF DESCRIPTION OF THE D~AWINGS
2 ~I~URE 1 is a schematicized depiction of a typical drilling rig.
3 FIGURE 2 is a cross-sectional view of a drill collar in a borehole.
4 DESCRIPTION OF THE PRE~ERRED EMBODIMENTS
A conventional rotary drilling rig is shown in FIGURE 1. The 6 portion below ground consists of a drill string and is made up of upper 7 drill pipe sections 103, drill collars 104, and drill bit 105. Pipe 8 sections 103 and drill collars 104 are little more than threaded hollow Y 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 11 are intended to weight drill bit 105, steady the drill string and keep it 12 in tension.
13 The drill string is turned by use of kelly 102, a flat-sided 14 hollow pipe often square in cross section, which is screwed into the upper-~ost section of drill pipe 103. The kelly is turned by a powered rotary 16 table 107 through a kelly bushing 108. The drill string and kelly 102 are 17 supported by rig hoisting equipment on derrick 106.
18 While the drill string is turning, a drilling fluid or mud is 19 pumped into the swivel 101 from a hose attached to connection 110. The drilling fluid proceeds down through kelly 1~2, upper drill pipes 103, and 21 drill collars 104. The drilling fluid exits through orîfices in drill bit 22 105 and flows upwardly through the annulus between the borehole wall 109 23 and either the drill collars 104 or the drill pipe sections 103. Drilling 24 fluid leaves the well through pipe 111 for subsequent recovery, reconsti-tution and recycling.
26 ~or purposes of illustration, the depicted well has a porous 27 stratum or layer 114. The well has been treated with a drilling fluid 28 which left a fi.lter cake 115. The well has, as most oil wells have, a 29 partial casing 112 terminated by a casing shoe 113. Well casings are , . .
;:
., .
., ,, , , ~
335~
1 cemen~ed in place and serve to isolate the various pressured formations and 2 to prevent contamination of water-bearing strata with drilling fluid and 3 petroleum.
4 Problems with differential pressure sticking in such a well ; 5 normally would occur at the interface between filter cake 115 and drill 6 collar 104.
: 7 FIGURE 2 depicts, in horizontal cross-section, a situation in 8 which a drill collar 104 made in accordance with the present invention is 9 in contac~ with a low pressure formation 114 having a filter cake 115 deposited thereon. The drill collar 10~ has the inventive porous coating 11 150 disposed about it. The drill collar 104, in ~his example, squeezed in 12 or abraded away a portion of filter cake 115 and formed a thin area 155.
13 Since the hydrostatic pressure of the drilling fluid in wellbore annulus 14 154 is hi8her than the pressure in formation 114, a poten~ial differential pressure sticking situation is present.
16 The wellbore implements of the instant invention, such as the 17 drill collars depicted in FIGURES 1 and 2, or various logging tools, have 18 thereon a porous coating. Although the composition of the coating is not a19 critical feature of the invention, the most desirable compositions are comprised of those metals which adhere to the steels used in most drilling 21 implements after proper treatment and are corrosion and wear resistant in ; 22 the borehole environment. The coating may also have dispersed within it a 23 number of abrasive particles. These abrasives are used to prolong the life24 of the coating and may be materials such as SiC, WC, corundum, etc.
The use of porous ceramic and glass materials which are sufficiently 26 tough to undertake the impactive rigors of rig handling and borehole environ-27 ment without substantial degradation are certainly within the scope of this28 invention.
'' :
:-:
, .
~ 1 ~ 33~
1 In theory, the coating prevents differential pressure sticking 2 for two reasons. First, the rough outer surface of the coating does not 3 readily provide a seal between the implement and the filter cake. ~econdly,4 the network of small tunnels within coa~ing 150 allows the higher pressure fluid in borehole annulus 154 to flow via a path 153 to the vicinity of 6 highest differential pressure to lower the pressure differential at the 7 interface between the drill collars and the filter cake and enable movement 8 of the drill string.
9 The coating need not completely cover the outside area of the implement. It must, however, mask a sufficient proportion of the implement's 11 outer surface to prevent differential pressure sticking. The coating may 12 be mottled in its coverage of the implement. The most desirable configura-t'~ 6 \ttl 6 R. ~ ~ 6 ~T ~
13 tion entails bands of coating. The coating need not be unlfor~ in thickness~
14 although such is desirable from the viewpoint of lessened solids buildup on the drill collar.
~6 Another desirable configuration entails multiple layers of coatings 17 of different permeabilities, e.g., an inner layer or layers produced with 18 large particles and thereby having a higher permeability, covered by an 19 outer layer produced from smaller particles having lower permeability.
This allows the liquid to flow quickly through the inner layer to the 21 contact area while the outer layer would be less susceptible to plugging.
22 Production of the coating may take place by resort to any well-23 known prior art method. The often corrosive environment presented by 24 drilling fluids somewhat limits the choice of materials which are suitable as coatings for the drill implements. However, application of powdered 26 iron alloys with or without additional abrasive material such as silica or 27 alundum to steel and iron substrates is shown in U.S. Patent No. 2,350,179 28 (issued on May 30, 1944 to Marvin). The process taught therein partially 29 presinters the powders to create a preform corresponding in shape to the `1 `~733~
1 desired backing. The presintered form is placed on its backing material 2 and both are raised to a temperature suitable for sintering the particles :3 and bonding them to the support. A reducing atmosphere is used in the 4 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 6 between the layers.
7 Another suitable method for producing a porous coating on a drill 8 implement is disclosed in U.S. patent ~o. 3,753,757 (issued on August 31, 9 1973 to Rodgers et al). This process entails first applying a diluted polyisobutylene polymer to the implement. The polymer forms a tacky base - 11 to which metal powders will adhere. An appropriate metal powder of iron, 12 steel, or stainless steel is then applied to the tacky surface preferably 13 by electrostatic spraying. The implement is heated to a first temperature 14 sufficient to volatilize the isobutylene polymer and a second temperature sufficient to bond the powder to itself and the implement.
16 The optional abrasive powders are mixed with the metal powders at17 or before the time of application. The sintering temperature of most 18 abrasives is significantly higher than that of any metal or alloy realis-19 tically useful on a drill implement. For instance, the sintering tempera-tures of tungsten carbide is 2650-2700F. The usual sintering temperature 21 for AISI C1020 carbon steel is generally about 2000F. A tungsten carbide 22 particle therefore comes through the powder sintering process largely 23 unaffected.
24 When ferrous powders are used to coat the implement, treating in superheated steam (1000-1100F) for a short length of time after sintering is 26 desirable. Such treatment causes an increase in the wear and corrosion 27 resistance of the coating by producing a thin layer of black iron oxide on i28 the exterior of the particles.
: 29 In any event, once the implements are provided with a porous coating, they are used as any uncoated implement would be. However, if so '.'~
~ :~ 7 33!j~
1 desired, the porous openings in the outer layer may be impregnated with an 2 oleophilic composition having a viscosity between about that of diesel oil 3 and about that of grease. Greases may be applied by a number of methods.
4 ~or instance, the greases may be diluted in a volatile hydrocarbon solvent and sprayed on the implement. Once the solvent evaporates, the grease will 6 remain both on the surface of the implement and in the outer pores of the 7 applied coating. The greases obviously may also be applied by rolling or 8 brushing. The lighter hydrocarbons may be sprayed or brushed or the imple-9 ment may be dipped into the hydrocarbon prior to use.
The added oleophilic composition has dual functions. It primarily 11 serves as a localized spotting agent. However, some lubricity is also 12 present especially when heavier hydrocarbons are applied.
13 In sum, the instant invention is readily applicable to either new14 or existing well implements. It uses only well known materials and methods of application and yet solves a heretofore serious problem.
16 However, it should be understood that the foregoing disclosure 17 and description are only illustrative and explanatory of the invention.
1~ Various changes in size, shape, materials of construction, and configuration 1~ 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 21 of the invention.
6 In strata which are porous in nature and additionally have a low 7 formation pressure, another problem occurs. Some of the drilling fluid, 8 because of its hydrostatic head, migrates out into the porous layer rather 9 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 ll filtration control additives. The porous formation tends to filter the 12 filtration control additive from the drilling fluid and forms a filter cake13 on the borehole wall thereby preventing the outflow of drilling fluid. As 14 long as this filter cake is intact, very little fluid is lost to the forma- tion.
16 During drilling, the rotating drillstring is closely adjacent or 17 in contact with the filter cake. If the filter cake is soft, thick, or of 1~ poor quality or if the drill string thins the filter cake~ then the higher 19 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 21 borehole wall. This phenomenon is known as differential pressure or hydro-22 static sticking. In severe cases, it will ~e impossible to either turn the23 drill string or even move it up and down the borehole. It is this problem 24 for which the apparatus of ~he invention is a solution.
The two widely used methods o~ alleviating hydrostatic or differ-26 ential pressure sticking attack the problem from different flanks; one is 27 remedial and the other preventative.
3 3 5 ~
1 Once a drill string is stuck against a filter cake adjacent a 2 porous formation, the remedy of a chemical spotting agent is used. It is 3 firs~ necessary to determine where on the dril]. string the stickage has 4 occurred. One such method involves stretching the drill string by pulling it at the surface. Charts are available correlating the resulting stretch 6 (per amount of applied stress) with feet of drill pipe. Once this informa-7 tion is known, the injection of water-based drilling fluid is interrupted 8 and the spotting agent substituted. The spotting agents are often oleophilic 9 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 11 slug of, typically, 10-50 barrels of spotting agent is introduced, addition12 of drilling fluid is re-commenced. The slug of spotting agent continues 13 its trip down through the drill string, out the drill bit, and up the 14 wellbore annulus until it reaches the si~e of the stickage. Upon arrival of the spotting agent at the stickage location, circulation is temporarily 16 ceased. Those skillful in this art speculate that oil-based spotting 17 agents tend to dehydrate the filter cake on the borehole wall and cause it 18 to break up, thereby allowing the drill string to come free. In any event,19 once movement of ~he drill string is detected, circulation of the drilling fluid is restored. It should be observed that the cost of this process is 21 high and the success rate only moderate.
22 A preventative method of allaying drill string stickage in porous23 formations entails the use of drill collars having flutes, spirals, or 24 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 26 expense, and results in lighter drill collars. Drill collars are, of 27 conrse, used for the specific purpose of adding weight to the lower end of 28 a drill string. Consequently light drill collars are not viewed with much 29 enthusiasm. Although these collars are somewhat more effective in preventing stickage, they are not immune to the problem since the exterior grooves can 31 be plugged, inter alia, with soft clay.
2 The purpose of this invention is to provide downhole well imple-3 ments with reduced susceptibility to differential pressure sticking. In 4 particular it involves providing such implements with a wear-resistant porous layer or coating. This coating may be permeated with a chemical 6 spotting agent.
7 The implements typically requiring such a coating would be either 8 drill collars or logging tools. Drill collars are essentially heavy drill 9 pipe sections and are placed between the drill bit and the upper section of drill pipe. ~hey are used to stabilize the drill string and weight the 11 dxill bit during drilling operations. Logging tools are instruments lowered 12 into an open borehole on a wire-line or cable to measure various formation 13 parameters, e.g., resistivity, sonic velocity, etc. These measurements are14 then transformed into usable information regarding, for instance, natural gas or oil content.
16 The applied porous coating is one that does not present a large 17 unbroken surface area to the filter cake but does allow liquid migration 18 within the coating from the open borehole area to an area of contact with 19 the filter cake. It is theorized that the porous coating's capability of allowing liquid to flow toward the area of the drill string's contact with 21 the thinned filter cake is the physical characteristic which prevents 22 substantial differential pressure sticking.
23 It is further contemplated that the pores of the coating may be 24 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 loca-2~ lized spotting agent.
33~
1 ~RIEF DESCRIPTION OF THE D~AWINGS
2 ~I~URE 1 is a schematicized depiction of a typical drilling rig.
3 FIGURE 2 is a cross-sectional view of a drill collar in a borehole.
4 DESCRIPTION OF THE PRE~ERRED EMBODIMENTS
A conventional rotary drilling rig is shown in FIGURE 1. The 6 portion below ground consists of a drill string and is made up of upper 7 drill pipe sections 103, drill collars 104, and drill bit 105. Pipe 8 sections 103 and drill collars 104 are little more than threaded hollow Y 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 11 are intended to weight drill bit 105, steady the drill string and keep it 12 in tension.
13 The drill string is turned by use of kelly 102, a flat-sided 14 hollow pipe often square in cross section, which is screwed into the upper-~ost section of drill pipe 103. The kelly is turned by a powered rotary 16 table 107 through a kelly bushing 108. The drill string and kelly 102 are 17 supported by rig hoisting equipment on derrick 106.
18 While the drill string is turning, a drilling fluid or mud is 19 pumped into the swivel 101 from a hose attached to connection 110. The drilling fluid proceeds down through kelly 1~2, upper drill pipes 103, and 21 drill collars 104. The drilling fluid exits through orîfices in drill bit 22 105 and flows upwardly through the annulus between the borehole wall 109 23 and either the drill collars 104 or the drill pipe sections 103. Drilling 24 fluid leaves the well through pipe 111 for subsequent recovery, reconsti-tution and recycling.
26 ~or purposes of illustration, the depicted well has a porous 27 stratum or layer 114. The well has been treated with a drilling fluid 28 which left a fi.lter cake 115. The well has, as most oil wells have, a 29 partial casing 112 terminated by a casing shoe 113. Well casings are , . .
;:
., .
., ,, , , ~
335~
1 cemen~ed in place and serve to isolate the various pressured formations and 2 to prevent contamination of water-bearing strata with drilling fluid and 3 petroleum.
4 Problems with differential pressure sticking in such a well ; 5 normally would occur at the interface between filter cake 115 and drill 6 collar 104.
: 7 FIGURE 2 depicts, in horizontal cross-section, a situation in 8 which a drill collar 104 made in accordance with the present invention is 9 in contac~ with a low pressure formation 114 having a filter cake 115 deposited thereon. The drill collar 10~ has the inventive porous coating 11 150 disposed about it. The drill collar 104, in ~his example, squeezed in 12 or abraded away a portion of filter cake 115 and formed a thin area 155.
13 Since the hydrostatic pressure of the drilling fluid in wellbore annulus 14 154 is hi8her than the pressure in formation 114, a poten~ial differential pressure sticking situation is present.
16 The wellbore implements of the instant invention, such as the 17 drill collars depicted in FIGURES 1 and 2, or various logging tools, have 18 thereon a porous coating. Although the composition of the coating is not a19 critical feature of the invention, the most desirable compositions are comprised of those metals which adhere to the steels used in most drilling 21 implements after proper treatment and are corrosion and wear resistant in ; 22 the borehole environment. The coating may also have dispersed within it a 23 number of abrasive particles. These abrasives are used to prolong the life24 of the coating and may be materials such as SiC, WC, corundum, etc.
The use of porous ceramic and glass materials which are sufficiently 26 tough to undertake the impactive rigors of rig handling and borehole environ-27 ment without substantial degradation are certainly within the scope of this28 invention.
'' :
:-:
, .
~ 1 ~ 33~
1 In theory, the coating prevents differential pressure sticking 2 for two reasons. First, the rough outer surface of the coating does not 3 readily provide a seal between the implement and the filter cake. ~econdly,4 the network of small tunnels within coa~ing 150 allows the higher pressure fluid in borehole annulus 154 to flow via a path 153 to the vicinity of 6 highest differential pressure to lower the pressure differential at the 7 interface between the drill collars and the filter cake and enable movement 8 of the drill string.
9 The coating need not completely cover the outside area of the implement. It must, however, mask a sufficient proportion of the implement's 11 outer surface to prevent differential pressure sticking. The coating may 12 be mottled in its coverage of the implement. The most desirable configura-t'~ 6 \ttl 6 R. ~ ~ 6 ~T ~
13 tion entails bands of coating. The coating need not be unlfor~ in thickness~
14 although such is desirable from the viewpoint of lessened solids buildup on the drill collar.
~6 Another desirable configuration entails multiple layers of coatings 17 of different permeabilities, e.g., an inner layer or layers produced with 18 large particles and thereby having a higher permeability, covered by an 19 outer layer produced from smaller particles having lower permeability.
This allows the liquid to flow quickly through the inner layer to the 21 contact area while the outer layer would be less susceptible to plugging.
22 Production of the coating may take place by resort to any well-23 known prior art method. The often corrosive environment presented by 24 drilling fluids somewhat limits the choice of materials which are suitable as coatings for the drill implements. However, application of powdered 26 iron alloys with or without additional abrasive material such as silica or 27 alundum to steel and iron substrates is shown in U.S. Patent No. 2,350,179 28 (issued on May 30, 1944 to Marvin). The process taught therein partially 29 presinters the powders to create a preform corresponding in shape to the `1 `~733~
1 desired backing. The presintered form is placed on its backing material 2 and both are raised to a temperature suitable for sintering the particles :3 and bonding them to the support. A reducing atmosphere is used in the 4 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 6 between the layers.
7 Another suitable method for producing a porous coating on a drill 8 implement is disclosed in U.S. patent ~o. 3,753,757 (issued on August 31, 9 1973 to Rodgers et al). This process entails first applying a diluted polyisobutylene polymer to the implement. The polymer forms a tacky base - 11 to which metal powders will adhere. An appropriate metal powder of iron, 12 steel, or stainless steel is then applied to the tacky surface preferably 13 by electrostatic spraying. The implement is heated to a first temperature 14 sufficient to volatilize the isobutylene polymer and a second temperature sufficient to bond the powder to itself and the implement.
16 The optional abrasive powders are mixed with the metal powders at17 or before the time of application. The sintering temperature of most 18 abrasives is significantly higher than that of any metal or alloy realis-19 tically useful on a drill implement. For instance, the sintering tempera-tures of tungsten carbide is 2650-2700F. The usual sintering temperature 21 for AISI C1020 carbon steel is generally about 2000F. A tungsten carbide 22 particle therefore comes through the powder sintering process largely 23 unaffected.
24 When ferrous powders are used to coat the implement, treating in superheated steam (1000-1100F) for a short length of time after sintering is 26 desirable. Such treatment causes an increase in the wear and corrosion 27 resistance of the coating by producing a thin layer of black iron oxide on i28 the exterior of the particles.
: 29 In any event, once the implements are provided with a porous coating, they are used as any uncoated implement would be. However, if so '.'~
~ :~ 7 33!j~
1 desired, the porous openings in the outer layer may be impregnated with an 2 oleophilic composition having a viscosity between about that of diesel oil 3 and about that of grease. Greases may be applied by a number of methods.
4 ~or instance, the greases may be diluted in a volatile hydrocarbon solvent and sprayed on the implement. Once the solvent evaporates, the grease will 6 remain both on the surface of the implement and in the outer pores of the 7 applied coating. The greases obviously may also be applied by rolling or 8 brushing. The lighter hydrocarbons may be sprayed or brushed or the imple-9 ment may be dipped into the hydrocarbon prior to use.
The added oleophilic composition has dual functions. It primarily 11 serves as a localized spotting agent. However, some lubricity is also 12 present especially when heavier hydrocarbons are applied.
13 In sum, the instant invention is readily applicable to either new14 or existing well implements. It uses only well known materials and methods of application and yet solves a heretofore serious problem.
16 However, it should be understood that the foregoing disclosure 17 and description are only illustrative and explanatory of the invention.
1~ Various changes in size, shape, materials of construction, and configuration 1~ 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 21 of the invention.
Claims (42)
PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. Apparatus suitable for use in a well comprising a substantially imperforate inner section and having an adherent outer porous coating with porosity sufficient to substantially prevent downhole differential pressure sticking.
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, 2 or 3 wherein the outer coating is comprised of an iron alloy.
10. The apparatus of claim 1, 2 or 3 wherein the outer coating is comprised of an iron alloy and additionally contains a dispersed abrasive composition.
11. The apparatus of claim 1, 2 or 3 wherein the outer coating is comprised of an iron alloy and additionally contains a dispersed tungsten carbide abrasive composition.
12. The apparatus of claim 4, 5 or 6 wherein the outer coating is comprised of an iron alloy.
13. The apparatus of claim 4, 5 or 6 wherein the outer coating is comprised of an iron alloy and additionally contains a dispersed abrasive composition.
14. The apparatus of claim 4, 5 or 6 wherein the outer coating is comprised of an iron alloy and additionally contains a dispersed tungsten carbide abrasive composition.
15. A drill collar having an adherent outer porous coating with sufficient porosity to substantially prevent downhole differential pressure sticking.
16. The apparatus of claim 15 wherein the outer coating is multi-layered.
17. The apparatus of claim 16 wherein the outermost layer is less permeable than at least one inner layer.
18. The drill collar of claim 15 wherein the outer coating is configured in the shape of bands around the apparatus.
19. The drill collar of claim 15 wherein the outer coating is in a mottled configuration.
20. The drill collar of claim 15 wherein at least a portion of the outer coating is impregnated with a spotting agent.
21. The drill collar of claim 20 wherein the spotting agent is an oleophilic composition having a viscosity between about that of diesel oil and about that of grease.
22. The drill collar of claim 19 wherein the spotting agent is diesel oil.
23. The drill collar of claim 15, 16 or 17 wherein the outer coating is comprised of an iron alloy.
24. The drill collar of claim 15, 16 or 17 wherein the outer coating is comprised of an iron alloy and additionally contains a dispersed abrasive composition.
25. The drill collar of claim 15, 16 or 17 wherein the abrasive composition is comprised of an iron alloy and additionally contains a dispersed tungsten carbide abrasive composition.
26. The drill collar of claim 18, 19 or 20 wherein the outer coating is comprised of an iron alloy.
27. The drill collar of claim 18, 19 or 20 wherein the outer coating is comprised of an iron alloy and additionally contains a dispersed abrasive composition.
28. The drill collar of claim 18, 19 or 20 wherein the abrasive composition is comprised of an iron alloy and additionally contains a dispersed tungsten carbide abrasive composition.
29. Apparatus suitable for use in a well comprising a substantially imperforate logging tool having an adherent outer porous coating with sufficient porosity to substantially prevent downhold differential pressure sticking.
30. The apparatus of claim 29 wherein the outer coating is multi-layered.
31. The apparatus of claim 30 wherein the outermost layer is less permeable than at least one inner layer.
32. The apparatus of claim 29 wherein the outer coating is configured in the shape of bands around the apparatus.
33. The apparatus of claim 29 wherein the outer coating is in a mottled configuration.
34. The apparatus of claim 29 wherein at least a portion of the outer coating is impregnated with a spotting agent.
35. The apparatus of claim 34 wherein the spotting agent is an oleophilic composition having a viscosity between about that of diesel oil and about that of grease.
36. The apparatus of claim 35 wherein the spotting agent is diesel oil.
37. The apparatus of claim 29, 30 or 31 wherein the outer coating is comprised of an iron alloy.
38. The apparatus of claim 29, 30 or 31 wherein the outer coating is comprised of an iron alloy and additionally contains a dispersed abrasive composition.
39. The apparatus of claim 29, 30 or 31 wherein the abrasive composition is comprised of an iron alloy and additionally contains a dispersed tungsten carbide abrasive composition.
40. The apparatus of claim 32, 33 or 34 wherein the outer coating is comprised of an iron alloy.
41. The apparatus of claim 32, 33 or 34 wherein the outer coating is comprised of an iron alloy and additionally contains a dispersed abrasive composition.
42. The apparatus of claim 32, 33 or 34 wherein the abrasive composition is comprised of an iron alloy and additionally contains a dispersed tungsten carbide abrasive composition.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA000410618A CA1173350A (en) | 1982-09-01 | 1982-09-01 | Apparatus for preventing differential sticking in wells |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA000410618A CA1173350A (en) | 1982-09-01 | 1982-09-01 | Apparatus for preventing differential sticking in wells |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1173350A true CA1173350A (en) | 1984-08-28 |
Family
ID=4123516
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000410618A Expired CA1173350A (en) | 1982-09-01 | 1982-09-01 | Apparatus for preventing differential sticking in wells |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA1173350A (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN112761525A (en) * | 2021-02-05 | 2021-05-07 | 西南石油大学 | Horizontal annular self-oscillation pulse detritus bed clearing device structure and clearing method |
-
1982
- 1982-09-01 CA CA000410618A patent/CA1173350A/en not_active Expired
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN112761525A (en) * | 2021-02-05 | 2021-05-07 | 西南石油大学 | Horizontal annular self-oscillation pulse detritus bed clearing device structure and clearing method |
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