Patent Application
20120024604
1. Field of the Invention
The invention relates to fixed cutter drill bits designed for abrasive applications, and more particularly to fixed cutter bits designed for high rate of penetration drilling in unconsolidated ultra abrasive formations.
2. Background Art
Different types of drill bits have been developed and found useful in different drilling environments. Bits typically used for drilling boreholes in the oil and gas industry include roller cone bits and fixed cutter. Cutting structures on bits vary depending on the type of bit and the type of formation being cut. Roller cone cutting structures typically include milled steel teeth, tungsten carbide inserts (“TCIs”), or diamond enhanced inserts (DEIs). Cutting structures for fixed cutter bits typically include polycrystalline diamond compacts (“PDCs”), diamond grit impregnated inserts (“grit hot-pressed inserts” (GHIs)), or natural diamond. The selection of a bit type and cutting structure for a given drilling application depends upon many factors including the formation type to be drilled, rig equipment capabilities, and the time and cost associated with drilling.
In drilling unconsolidated, ultra abrasive formations, bit life is limited due to excessive wear; therefore, bit cost has become a significant factor in the selection of bits for this environment. One example of an unconsolidated, ultra abrasive drilling application includes drilling of the pay zone of heavy oil reservoirs. Heavy oil reservoirs typically comprise unconsolidated to low compressive strength, yet highly abrasive sands that are permeated with thick, dense heavy oil. These dense, high viscosity liquid hydrocarbons are also sometimes referred to as bitumen.
Heavy oil production typically requires special oil recovery techniques, such as the injection of heat and/or pressure into the reservoir to reduce the viscosity of the oil and enhance its flow. One commonly used recovery technique is known as steam-assisted gravity drainage (SAGD), which involves drilling a pair of horizontal wells, typically one above the other, through the reservoir as shown in
Horizontal wellbores drilled through heavy oil reservoirs often extend 1000 meters or more through the reservoir. To maximize oil recovery in a larger reservoir, multiple directional wells may be drilled from a common wellbore to reduce the distance the oil has to travel through rock to reach a wellbore.
Drill bits used in unconsolidated, ultra abrasive applications are typically damaged beyond repair after a first run due to the extreme abrasion and erosion encountered during drilling. Milled tooth roller cone bits have been considered the most economically feasible bit for these applications because they cost significantly less than other bits and offer more aggressive cutting structures for higher ROP. Fixed cutter bits are generally not used in these applications because they cost 5 to 10 times more than a comparable roller cone bit and typically become damaged beyond repair after a first run, such that their higher cost can not be justified.
Although roller cone bits have been found to be most economically feasible for unconsolidated, ultra abrasive applications, the useful life of these bits is limited. As a result, several bits are typically required to complete a wellbore and the trips back to surface to replace the bits and the number of bits required to complete a well have a significant economic impact on a drilling program. However, up to now, milled tooth bits have still been found to be more economically feasible when compared to the significant cost of using a conventional fixed cutter PDC bit.
What is desired is a fixed cutter drill bit that offers increased useful life in high ROP, unconsolidated, ultra abrasive applications. In particular, such bits may be useful in reducing the number of trips required to complete wellbores in heavy oil drilling applications, or similar applications. Additionally, a drill bit capable of maintaining gage over an extended drilling operation in any highly abrasive environment is desired. Also desired is a more abrasive resistant drill bit that may be used to achieve higher rates of penetration (ROP) to provide a positive economic impact in a drilling program for a heavy oil drilling application.
In one aspect, the present invention provides a fixed cutter drill bit providing improved performance in a high rate of penetration unconsolidated abrasive drilling operation.
In one embodiment, the bit includes a bit body having a cutting face and a side portion. The bit body is formed of carbide matrix material. A plurality of blades azimuthally spaced about the cutting face and a plurality of cutters disposed along the blades. At least one gage pad is disposed along a side of the bit body and comprising wear resistant gage elements formed of a material more wear resistant than the matrix material forming a portion of the gage pad. The wear resistant elements include a rounded surface and are embedded in gage pad material proximal a leading edge of the gage pad to provide a rounded wear-resistant edge or surface proximal the leading edge.
In another embodiment, the drill bit includes a bit body, a plurality of blades, and a plurality of cutters is disposed along the blades and arranged to have an extent from a corresponding blade front face of 0.10 inches or less for a majority of the cutters. A majority of the adjacent cutters are also positioned to have spaces there between that are less than 0.25 inches. At least one gage pad is disposed along a side of the bit body. The at least one gage pad has a circumferential width that is at least about 2 inches or results in a total gage pad width equal to 30% or more of the circumference of the bit. At least one wear resistant element is disposed on the gage pad near a leading edge of the gage pad to provide wear resistant protection near the leading edge. Additionally, the bit includes at least one back reaming element positioned on the bit to back ream formation in a path of the bit as the bit is pulled from a wellbore.
Various other aspects and advantages of the invention will be apparent from the following description and the appended claims.
Reference will now be made to the figures in which various embodiments of the present invention will be given numerical designations and in which aspects of the invention will be discussed so as to enable one skilled in the art to make and use embodiments of the invention.
In one aspect, the present invention provides a fixed cutter drill bit for drilling earth formations, which may be particularly useful in drilling formations comprising unconsolidated to low compressive strength, yet highly abrasive sands, such as those encountered in heavy oil reservoirs. These types of formations will be generally referred to as “unconsolidated and ultra abrasive” for simplicity. In another aspect, the present invention provides novel gage pad configurations for drill bits, which may be particularly useful on bits designed for any abrasive drilling environment. In another aspect, the invention provides methods for manufacturing or rebuilding fixed cutter bits.
Fixed cutter drill bits (also referred to as fixed head bits or drag bits) are significantly more expensive than mill tooth roller cone drill bits and are considered to offer less aggressive cutting structures than roller cone drill bits. However in several applications fixed cutter bits can be used to drill longer well segments in a single run and can be rebuilt and reused multiple times to provide an overall economic benefit that outweighs their higher cost.
Fixed cuter bits which include polycrystalline diamond compact (PDC) cutters are typically referred to as PDC bits. PDC bits can be rebuilt after being used by heating the entire bit to a predefined high temperature and then adding material to areas of the bit where material has been worn away due to erosion or abrasion. Material is typically added by torch welding or the like. Additional heat may also be applied to the cutting structure to melt brazed material around the cutters so that cutters can be rotated to expose an unworn portion of the cutting edge for drilling. When cutters cannot be rotated and reused due to excessive damage or wear, cutters are removed and replaced with new cutters using additional braze material. Bit rebuilding operations are typically carried out as quickly and carefully as possible out to avoid thermal stress cracks in the bit body material. Extensive rebuild operations require repeated thermal cycling of the bit which leads to a higher chance of forming thermal stress cracks. If thermal cracks are found to have developed during a rebuild operation, the bit must be scrapped and a new bit used. Bits can only undergo a limited amount of thermal cycling before developing thermal cracks. Therefore, thermal cycling during a rebuild operation should be limited when possible to extend the useful life of a drill bit.
When considering high rate of penetration (ROP), unconsolidated, ultra abrasive drilling applications, many PDC bits are not designed to provide the ROPs demanded in these applications. PDC bits have also been found to suffer severe material loss in these unique drilling environments where unconsolidated ultra abrasive cuttings mix with drilling fluid, often pumped at high flow rates, to Create a highly abrasive/erosive slurry that flows around surfaces of the bit during drilling. The bit tends to ride on the abrasive slurry pumped between surfaces of the bit and the bottomhole, which results in excessive wear on the bit such that bits cannot be rebuilt or reused a sufficient number of times to justify their cost.
In particular, severe erosion has been found to occur between cutters, on cutter substrates, and on the blade faces around the cutters. Severe abrasion has also been found to occur across blade tops, cutter substrates, gage pad surfaces, and blade heel surfaces of the bit. For example, a conventional 12¼ matrix body bit may loose as much as 10 to 12 pounds of material in a single run when used in an unconsolidated, ultra abrasive application. These bits typically cannot be rebuilt or rerun and must be scrapped. In a case where a bit may be rebuilt to attempt a second nm, the rebuild operations required are extensive and often result in thermal stress cracks. Also, wear and damage sustained by the cutters are usually such that the cutters cannot be rotated or reused for a second run.
In horizontal drilling applications, the gage pads suffer excessive wear due to constant rubbing action against the formation and the sharp sands in the abrasive slurry flowing past gage pad surfaces. This can cause a bit to go under gage prematurely. Conventional PDC bits also are often less directionally responsive than roller cone drill bits in these applications and have greater tendency to drill out of a desired zone and into bounding formation without any indication at the surface. PDC bits also have gage surfaces that create multiple points of constant hole wall contact which results in bits going undergage prematurely in these environments. Conventional PDC bits have also been found to be more difficult to trip out of horizontal holes after completing their drilling requirement in these environments. This is because cuttings that fail to reach the surface during the drilling tend to fall to the low side of the hole, effectively creating a restricted passage back to the surface. Additionally, conventional PDC bits have been found to be more susceptible to cutter damage when used to drill out cementing shoes and when engaging more competent formations above or below the reservoir pay zone. Damage sustained by conventional PDC bits in these applications leads to costly rebuild operations or the inability to reuse the bit. Thus, conventional PDC bits have not been economically feasible unconsolidated, ultra abrasive drilling applications and are generally not used.
The inventors have studied problems associated with the use of fixed cutter bits in unconsolidated, ultra abrasive drilling applications and have discovered several design features that can be used to significantly extend the life of a fixed cutter drill bit in these applications to provide a positive economic impact on a drilling program.
Examples of the basic features on a PDC bit will now be generally described with reference to the bit shown in
A gage region is also formed along an outer side surface 125 of the bit body 102 and includes one or more gage pads 124 having surfaces that extend proximal the gage diameter of the bit 100. One or more gage inserts 127 are embedded in material forming the gage pad 124 to contact the side wall of the wellbore and help maintain the gage diameter being drilled. Gage pads 124 also help to stabilize the drill bit 100 against vibration. In the example shown, a plurality of gage pads 124 are formed at the ends of blades 108 and are spaced apart around the periphery of the bit body 102 with junk slots 126 defined there between. Gage pads which extend around the entire periphery of the body are also known in the art and may be used.
A central longitudinal bore (not shown) which extends into the bit 100 permits drilling fluid to flow from a drill string into the bit 100. A plurality of openings or flow passages 118 are positioned in the cutting face 103 of the bit 100 and in fluid communication with central bore. The flow passages 118 are configured for mounting nozzles 120 therein which serve to distribute drilling fluid around the cutters 110 and cutting face 103 of the bit body 102. The nozzles direct fluid to flush formation cuttings away from the cutting structure and borehole bottom during drilling. Grooves or channels 122 between the blades 108 serve as drilling fluid flow courses for directing drilling fluid and cuttings radially outward away from the cutting face 103. The junk slots 126 between the gage pads 124 of the bit 100 are in fluid communication with the channels 122 and permit drilling fluid and formation cuttings to flow away from the cutting face 103 and up an annulus formed between the drill string and the wall of the borehole during drilling.
In this example, small hard elements 128 are also provided along on a heel surface 129 of the bit 100 to help “back ream” or remove formation in the path of the bit as the bit 100 is pulled from the borehole.
Features of embodiments of the invention will now be described with reference to
Any cutters suitable for abrasive drilling applications may be used in accordance with embodiments of the present invention. In the embodiment shown in
PDC cutters can be formed by placing a cemented carbide substrate or components for forming a carbide substrate into a press container. A mixture of diamond grains or diamond grains and catalyst binder is then placed on top the substrate and the container assembly is subjected to high pressure, high temperature conditions such that the metal binder migrates from the substrate and through the diamond grains to promote bonding of the diamond grains to each other to form the diamond layer, subsequently bonding the diamond layer to the substrate. The catalyst or binder material commonly used includes cobalt. The catalyst material may later be removed or depleted from the working surface of the cutter for enhanced abrasion resistance. One or more intermediate layers of material may also be disposed between the diamond layer and the substrate, as is known in the art. Additionally, the cutter may include a non-planar interface between the diamond layer and substrate.
In one or more embodiments of the present invention, larger cutters are used on the bit to allow for higher rates of penetration. In one or more embodiments, cutters having a diameter of 16 mm or larger are disposed along the blades of the bit. For the example embodiment shown in
Many PDC bit designs have cutters spaced apart along the blades and positioned to extend from a front of the blade front face. However, these cutter arrangements can lead to increased recirculation of abrasive slurry around the cutters and blades and excessive abrasive and erosive wear on the cutters, blades, and braze material. Therefore, as shown in
Therefore, cutters 210 are preferably arranged on the blades 208 such that adjacent cutters on a blade 208 have a spacing there between of 0.25 inches or less. In selected embodiments, this spacing may be closer to around 0.040 inches or less and may be applied to a majority of adjacent cutters 210 on the blades 208 where possible. Arranging cutters 210 closer together along the blades 208 also provides greater ultrahard coverage along the leading edge of the blades 208 which leads to an overall reduction of wear on cutters. Reducing the spacing between cutters to 0.25 inches or less, and more preferably to 0.10 inches or less, can help reduce wear on the blade s 208 and the cutters 210, such that less material is lost from the bit during drilling. This can help a bit effectively handle longer drilling runs and extend the useful life of the bit. In particular, this can reduce the time and number of thermal cycles required for a rebuild operation.
In one or more embodiments, blades 208 of the bit 200 are also preferably formed to have a limited helix from cutter to cutter. Referring to
Referring again to
Examples of test bits used for a drilling run in an unconsolidated, ultra abrasive formation are shown in
In one or more embodiments, the bit also includes thicker blades and gage pads which may also help to increase the useful life of the drill bit in ultra abrasive applications. For example, referring to
Space available for blade thickness is limited near the crown of the bit 200. However, in one or more embodiments, the blades 208 may be configured to increase in thickness in a direction away from the center of the bit 200 toward the gage pads 224. The blade thickness will generally depend on the diameter of the bit 200 and the number of blades 208 in the bit design. Therefore, in one or more embodiments, the number of blades on the bit maybe limited to eight blades or less, and in many cases six blades or less to allow for thicker blades as well as higher ROPs. However, for the six bladed, 12¼ A inch bit described above, the blades 208 can be generally configured to increase in thickness along their length toward the gage region to a width close to the selected width of the gage pad.
In the embodiments shown in
The inventors have determined that providing increased blade thickness can increase the number of rebuild operations a bit can undergo before developing thermal stress cracks. Thicker blades and gage pads have been found to retain heat better during rebuild operations such that more rebuild work can be done in a single heat cycle and the number of thermal cycles required during a rebuild operation can be reduced. Additionally, blades and gage pads that are initially thicker than structurally required increase the chances of the bit being structurally sound for a second run before needing to be rebuilt. This can also reduce the time required for a rebuild operation because less material will need to be added to the bit to place it into a structurally sound rerunable condition. As a result, both the rerunability (ability to rerun the bit) and the repairability (ability to repair the bit multiple times) can be increased to enhance the economic feasibility of fixed cutter bits in unconsolidated, ultra abrasive drilling applications.
Referring now to
As shown in
Additionally, in one or more embodiments, matrix materials used to form outer surfaces of the bit body, blades, and/or gage pads may be selected to provide increased wear resistance over other matrix materials commonly used for PDC bits in applications, such as high impact applications. For example, matrix materials having a higher hardness or higher carbide content may be used to provide increased wear resistance. Alternatively, the wear resistance of matrix material can be increased by using more fine grain carbide powder to form the matrix. This can also result in a higher carbide content and lower binder content when the matrix body is formed. For example, a tungsten carbide matrix powder used to form portions of the bit body, blades, and/or gage pads may include a higher percentage of fine tungsten carbide particles to achieve an average tungsten carbide grain size of 60 μm or less, and in some cases 50 μm or less. Alternatively, the matrix powder used may include at least about 30% by weight tungsten carbide with an average particle size between about 0.2 μm and 30 μm to provide a higher packing density to achieve increased wear resistance and strength. In selected embodiments, this amount is at least about 40% by weight, and in some cases, at least about 50% by weight.
The wear resistance of matrix material can also be increased by using a greater amount of particular types of tungsten carbides to form the matrix powder. Types of tungsten carbides generally include macro-crystalline tungsten carbide, cast tungsten carbide, carburized tungsten carbide and sintered tungsten carbide. Matrix powders typically include two or more of the aforementioned types of tungsten carbide combined in various weight proportions. Matrix powders may also include other metal additives, such as nickel (Ni), iron (Fe), cobalt (Co) or other transition metals. The wear resistance of matrix material can be increased by using a greater amount of a harder tungsten carbide in the matrix powder. For example, more cast carbide may be used in the matrix powder. In selected embodiments, cast carbides in amounts of around 40% or more by weight, and in some cases 45% or more, have be used to provide increased wear resistance over conventional matrix materials.
Additionally, in one or more embodiments, cutters used on the bit may be selected to have more wear resistant substrates. Wear resistance of substrate material also increases with hardness or carbide content, or by decreasing the binder contents or tungsten carbide grain size. Therefore, in one embodiment, cutters with substrates having hardness of 88 Ra or more may used Alternatively, cutters having substrates with a binder content of around 13% or less by weight may be used. Also, in one embodiment, substrates may be formed using tungsten carbide particles with an average grain size of around 3 microns or less to provide increased wear resistance. Alternatively, cutters 210 may be treated or a coating applied to exposed surfaces of cutter substrates to reduce wear in selected embodiments.
To provide increased wear resistance along surfaces of the bit subjected to the greatest amount of wear, selected portions on the bit, such as the bit body 202, blades 208, or gage pads 224, may be formed using different matrix materials to obtain the increased wear resistance desired without sacrificing impact toughness or crack resistance of the bit body. Examples of this are described in U.S. patent application Ser. No. 10/454,924 to Kembaiyan, titled “Bit Body Formed of Multiple Matrix Materials and Method for Making the Same,” which is assigned to the assignee of the present invention and incorporated herein by reference. Referring to
Additionally, ultrahard material can be deposited along surfaces of the bit body to reduce wear of matrix material in selected regions. For example, a coating comprising ultrahard material, such as a plated diamond coating, may be applied to surfaces of the bit, such as along the blades 208, gage pads 224, or cutter substrates 212 to increase the wear resistance along those surfaces. Such coatings may be used to help reduce wear on bit body surfaces and to allow for longer bit runs.
Alternatively, ultrahard particles or elements may be embedded in outer surfaces of the bit to increase the abrasion and erosion resistance of these surfaces. For example, ultrahard material can be embedded in blade tops and cutter substrates to further reduce wear during drilling. Test bits run in a high flow rate unconsolidated, ultra abrasive application both with and without ultrahard material embedded in blade tops and cutter substrates are shown in
The bit shown in
The blade tops 532 and cutter substrates 512 with the embedded ultrahard material (542, 544, 546) were found to be in better condition than the bit run without embedded ultrahard material (shown in
In other embodiments where ultrahard particles or elements are embedded or infiltrated into the matrix material forming surfaces of a bit, the ultrahard material may be natural or synthetic diamond, or a combination of both, and can be obtained in a variety of shapes and grades as desired. Other ultrahard material particles or elements known in the art may also or alternatively be used. In such cases, the matrix material should be selected to provide sufficient abrasion resistance so that ultrahard particles or elements are not prematurely released.
Along surfaces, such as the blade tops, larger ultrahard particles or elements can used, as desired, to allow for prolonged retention in matrix material due to increased grip area around the particles for matrix material to hold them in place longer. For example, in selected embodiments the blade tops and other surfaces on the bit can be impregnated with diamond grit of any grain size. In one embodiment, diamond grit having a grain size of around 700 μm or more (150 spc or less) was used for prolonged resistance. In another embodiment, diamond grit having a size of around 850 μm more (100 spc or less) were used.
Alternatively, ultrahard particles embedded in the matrix material may be disposed both at and below the outer surface of the matrix material for prolonged abrasion resistance. Ultrahard particles infiltrated in matrix material to a selected depth beneath surfaces of the bit may be provided so that as the matrix material wears and ultrahard particles at the surface fall out, additional particles will become exposed below the surface for prolonged abrasion resistance. Bits having surfaces infiltrated with ultrahard particles to a selected depth maintain their ability resist abrasion and erosion for longer periods of time, even after surface particles are worn down, which can also increase the length or number of runs a bit can be used for before having to be rebuilt.
Ultrahard particles or elements embedded in matrix material may also be coated to achieve a stronger bond in matrix material. Examples of coatings that may be used are described in U.S. application Ser. No. 10/928,914 to Oldham, filed Aug. 26, 2004, titled “Coated Diamond for Use in Impregnated Diamond Bits,” assigned to the assignee of the present invention and incorporated herein by reference.
As noted, ultrahard elements formed of any abrasion resistant material may be embedded in the blade tops behind the cutters or along other surfaces of the bit. Examples of ultrahard elements that may be used include diamond grit-hot pressed inserts (GHIs), PCBN elements, and TSP elements. For example, GHIs or other elements containing abrasive resistant material can be placed behind the cutters, such as similar to that described for example in U.S. Pat. Nos. 4,823,892, 4,889,017, 4,991,670 or 4,718,505. GHIs may be infiltrated or brazed into surfaces of the bit, as discussed in U.S. Pat. No. 6,394,202, to Truax and assigned to the assignee of the present invention.
A bit having selected surfaces impregnated with ultrahard particles or elements, as described above, can be formed by placing the ultrahard particles or elements in predefined locations of a bit mold. Alternatively, composite components, or segments comprising a matrix material infiltrated with diamond particles or the like can be placed in predefined locations in the mold. Once the ultrahard material or components are positioned, other components for forming the bit can be positioned in the mold and then the remainder of the cavity filled with matrix material, such as a charge of tungsten carbide powder. Finally, an infiltrant or binder can be placed on top of the matrix powder and the assembly then heated sufficiently to melt the infiltrant for a sufficient period to allow it to flow into and bind the powder matrix and segments. Using this process, a bit body that incorporates the desired ultrahard particle containing sections and/or components can be formed.
As discussed above and shown in
Referring to
The cutters of the bit shown in
The cutters can also be arranged at a back rake angle to provide enhanced steerability when desired for particular horizontal drilling applications, such as for drilling the pay zone of a heavy oil reservoir. Cutters oriented with back rake provide a less aggressive cutting structure which may be more resistant to drilling out of the pay zone of drilling heavy oil reservoirs which are typically bounded above and below by more consolidated formations. In particular, the responsiveness of the bit to a formation change increases with back rake such that if a more competent formation is encountered during drilling the bit will be more prone to skip or bounce along the bounding formation and remain in the desired drilling zone. Also cutters with higher back rake are less likely to sustain damage when drilling float equipment or a shoe in the path of the bit, such as at the start of horizontal drilling section. Providing a bit that is more sensitive to formation changes can also reduce drilling costs by obviating the need for directional equipment in these applications. For unconsolidated, ultra abrasive applications, bits having higher back rakes may be used because the rate of penetration of these bits is not a limiting issue in these applications. Additionally, a bit's sensitivity to formation changes may be further increased by using a short parabolic profile along with increased back rake angles.
Orienting cutters at a back rake angle can also help reduce erosion on cutter substrates 212. For example, as shown in
In one or more embodiments, one or more cutters may be oriented at a selected a side rake angle. For example, cutters may also be oriented at a side rake angle toward the outside of the bit that is greater than 0°. Providing cutters oriented to include a side rake angle may help increase a bits resistance to drilling out of a desired formation zone and may also help to direct abrasive cuttings away from the bit for enhanced cuttings evacuation and reduced wear.
Referring to
When conventional fixed cutter bits are used in unconsolidated, ultra abrasive applications they suffer excessive wear along the gage pads due to rubbing action against the formation and abrasive slurry flowing past gage surfaces. Therefore, in accordance with embodiments if the present invention, a fixed cutter drill bit for unconsolidated, ultra abrasive environments also includes wear resistant elements, such as diamond or ultrahard material containing elements, embedded in gage pad surfaces to provide enhanced wear resistance at gage.
For selected embodiments, especially those designed for long runs in high flow rate directional drilling applications, additional gage pad protection may be required. In these applications, abrasive slurry containing sharp sands tends to abrade matrix material along the leading edge which exposes inner regions of the gage pad to a greater amount of abrasive wear. As a result, matrix material around the wear resistant elements in the pad may eventually become worn away causing the wear resistant elements to fall out.
Therefore, in selected embodiments, wear resistance of a gage pad may be increased by placing wear resistant elements proximal a leading edge of the gage pad to serve as a barrier to abrasive slurry impacting the leading edge. Wear resistance may also be increased by providing a greater amount of diamond coverage on the gage pad. This is done by using larger wear resistant elements with longer substrates or extensions for embedding into the matrix material to increase the ability of the gage pad to retain the wear resistant elements during drilling.
One example of a novel abrasive resistant gage pad arrangement that may be used on an embodiment of the invention described above to enable longer drilling runs or on any PDC bit for enhanced abrasive resistance is shown in
The wear resistant elements 1227 in the embodiment shown in
In the embodiment shown, the larger wear resistant elements 1277 comprise diamond enhanced inserts (“DEIs”) which include a layer of polycrystalline diamond material bonded to a substrate. The DEIs are arranged in three rows which generally spanning the length of the gage pad. Five DEIs are disposed in the rows closest to the leading edge and the trailing edge. Four DEIs are positioned in the interior region of the gage pad. The DEIs used on selected bits may have diameters of 13 mm or more to provide larger bearing surface areas of greater than 130 mm2, and may include substrates having lengths of 9 mm or more to allow for good retention during drilling. The substrate end of the DEI is embedded in the matrix material 1275 with the top surface of polycrystalline diamond exposed at the gage pad surface for contact with abrasive slurry and the walls of the wellbore. In other embodiments, DEIs or other large inserts having super abrasive resistant bearing faces of any size may be used in any arrangement desired. In another example, 16 mm or larger DEI inserts are used proximal the leading edge 1270 which act as larger barriers for abrasive slurry passing over the leading edge to help reduce wear of matrix material from around other wear resistant elements on the gage pad behind the leading DEIs. Also, in other embodiments, DEIs may be arranged in three or more rows or with 3 or more DEIs within a one inch length of the gage pad.
The smaller wear resistant elements 1276 comprise thermally stable polycrystalline diamond (TSP) elements embedded in the gage pad material 1275. The gage pad material 1275 comprises a metal carbide matrix material. In selected embodiments, the gage pad material 1275 may also be impregnated with or coated with ultrahard particles, such as diamond grit, to further increase abrasion resistance. In other embodiments, wear resistant elements of any type, number, shape, or size may be used.
For the embodiment shown in
Another example of a novel gage pad layout that may be used for embodiments of the inventions to permit longer drilling runs in abrasive applications is shown in
Referring to
In the example shown, the wear resistant elements 1378 positioned proximal each edge of the gage pad 1324 are axially aligned and generally arranged end to end along each edge to provide rounded, substantially continuous, and wear resistant edge portions for the gage pad 1324. Small spacing may be provided between the ends of adjacent wear resistant elements 1378 with matrix material disposed there between for enhanced retention of the elements 1378 embedded in the matrix material.
A cross section of the gage pad in
Wear resistant elements 1379 disposed along in the interior region of the gage pad 1324, between the leading edge 1370 and trailing edge 1372, are arranged along the gage pad 1324 to provide super abrasive bearing surfaces for maintaining gage during drilling. In this example, interior wear resistant elements 1379 are generally cylindrical in form with their linear axes generally perpendicular to the outer surface of the gage pad. As shown in
In one example, the wear resistant elements 1378 disposed along the leading edge 1370 and trailing edge 1372 of a gage pad are diamond grit hot-pressed inserts (GHIs), which may be infiltrated or brazed into gage pads of a bit, such as the one shown in
In the example noted, the interior wear resistant elements 1379 positioned along the interior surface of the gage pad 1324 comprise DEIs with carbide substrates. The carbide substrates are embedded into the gage material with the diamond tables exposed at the surface of the gage pad. The DEIs have diameters of up to 13 mm or more with lengths, including substrates, of up to 9 mm or more. In some cases, DEIs having diameters of 16 mm or more and/or substrates of 13 mm or more are used. In other embodiments, wear resistant elements of any type, number, shape, size, or combination may be used in interior regions of the gage pad, including DEIs, PCD elements, TSP elements, PCBN elements, GHIs, or the like or combinations thereof.
Additionally, the gage pad material 1375 may comprise a harder matrix material than that used to form another part of the bit body as described in relation to other aspect of the invention above. Alternatively or additionally matrix material forming part or the entire outer surface of the gage pad may be impregnated (or coated) with ultrahard particles, such as diamond grit, to provide increased abrasion resistance for the gage pad. For example, as shown for the gage pad layout in
In one example, diamond grit having a grain size of around 700 μm or more (150 spc or less) was used to form diamond impregnated surfaces of a gage pad having a similar layout to the one shown in
Additionally, the gage pads of the bit may be configured as replaceable gage pads as is generally know in the art with the gage pad layouts designed in accordance with examples given above. In the case of replaceable gage pads, the gage pads and corresponding bit surface may include complementary securing elements which mutually engage one another and the gage pad removably secured to the bit body by brazing, mechanical locking, or the like. Removable gage pads may be used to facility faster rebuild operations.
In general, it has been found that having rounded wear resistant elements positioned proximal the leading edge of a gage pad can significantly reduce wear on gage pad surfaces and increase bit life, especially in ultra abrasive applications. This can also reduce the time and materials required to repair a bit. Also, using GHIs or similar elements may permit the use of larger wear resistant elements along edges of the gage pad and may also result in increased element retention. Using DEIs with longer substrates permits deeper grip in the gage pad material for increased retention. Additionally, the use of matrix material impregnated with ultrahard particles along the outer surface of the gage pad can help to further reduce wear on the gage pads and increase bit life, especially for bits used in ultra abrasive environments.
Referring to
Back reaming capability is particularly desired for embodiments of the invention designed for horizontal drilling because cuttings tend to fall to the low side of the hole during drilling such that when the bit is retrieved from the borehole it typically has to plow through cuttings built up on the low side of the hole so that the bit can be removed. Because back reaming elements may have to do a lot of work in these applications, larger back reaming elements and/or a plurality of back reaming elements may be used to provide increased cutting capability and abrasion resistance along heel surfaces of the bit.
In selected embodiments one or more back reaming elements 1428 positioned on a heel surface 1429 of the bit may comprise a larger element, such as PDC cutters (or similar elements) having a diameter of about 13 mm, or more. Alternatively, in one or more other embodiments, at least two back reaming elements 1428 are disposed along selected heel surface of the bit to provide efficient removal capability for the bit when pulled out of the hole. The number and/or size of the back reaming elements on each heel surface may be selected to provide a particular amount of diamond coverage. For example, two or more 16 mm back reaming cutters or cutters of any size may be positioned along heel surfaces of each gage pad blade to provide diamond coverage of greater than 300 mm2 along each of the heel surfaces. Providing good back reaming capability on selected embodiments used for directional drilling eliminates issues of the bit getting stuck in the hole and excessive wear on the heel surfaces of the bit that must be addressed in rebuild operations.
In other embodiments, a back reaming element may comprise any type of active cutting structure known in the art including a PCD compact, a PCBN compact, a diamond impregnated insert, and natural diamond elements. PDC back reaming elements have been found to be particularly effective in maintain gage all the way in horizontal, unconsolidated, ultra abrasive applications. PDC elements having longer substrate lengths also permit deeper penetration of the substrate into the blade matrix material for greater retention of the cutter.
In alternative embodiments, back reaming elements positioned on the bit may comprise different types of cutting elements, such as TSPs and GHIs or PCD compacts. Additionally, cutter types may be arranged to alternate along heel surfaces as desired. Heel surfaces of the bit may also be coated with hardfacing material or impregnated with wear resistant material, such as diamond particles or other wear resistant material, to further reduce wear on the heel surfaces that occurs as bits are removed from longer bit runs.
In one or more embodiments, to reduce erosive wear, particularly in high flow rate drilling in unconsolidated, ultra abrasive applications fluid passageway may disposed between the blades may be oriented to direct more of the drilling fluid toward a corresponding junk slot of the bit rather than directly on the cutters. The bit 200 shown in
Other design considerations may also be used to reduce the velocity or impingement of the abrasive slurry on the bit body. For example, in one or more embodiments, one more diffuser nozzles may be used to reduce fluid velocities around the cutters to help reduce erosive wear on the cutting structure during drilling. Alternatively, in one or more embodiments, a bit may be designed to include more nozzles 220 than blades 208 to help lower the concentration of hydraulic energy across the cutting face of the bit. Alternatively, a bit may be designed with an increased total flow area, such as by configuring the one. or more of the passageways 218 or nozzles 220 to have a larger than normal exit port.
Braze material is typically selected for highest braze strength; however, braze strength is not considered a limiting factor in many unconsolidated, ultra abrasive applications. Therefore, in one or more embodiments, a more viscous braze material may be applied between the cutters and the cutter pockets to increase the reusability of cutters and reduce the cost associated with rebuilding the bit. A more viscous braze material may be used so that when a cutter substrate is slightly eroded or has minor nicks on the exposed portion of the substrate, the cutter can be spun during the rebuild operation to coat the substrate with the thicker braze material to fill the small voids or wear marks and provide sufficient adhesion for subsequent runs.
Therefore, in selected embodiments, a braze material which is or can be kept more viscous during the brazing process may be used to bond one or more of the cutters into the cutter pockets on the blades, especially in locations where erosion of the brazed joint or carbide cutter substrate has been observed or predicted. The more viscous braze material can be selected from alloys having a larger difference between the liquidus (L) and solidus (5) temperatures. For example, the commercial braze alloy BAg7 (L=652° C., S=618° C.), may be selectively replaced with BAg18 (L=718 C, S=602 C) or other silver-based alloys. The alloys may include combinations of small percentages of metallic or transitional elements, or of non-melting elements or refractory particles, which may increase the effective viscosity while brazing. The brazing process can also be controlled to use lower temperatures, which also increases effective viscosity. For example, a braze materials having a larger difference between the liquidus and solidus temperatures can be used to braze cutters at a temperature between the liquidus and solidus temperature, such as around midway between the range, so that the braze material remains more viscous during the brazing process.
Also, in one or more embodiments, a hardfacing overlay coating may be applied to portions of the bit, such as exposed surfaces of braze material to minimize erosion of braze material around the cutters during drilling, as discussed for example in U.S. Pat. No. 6,772,849 to Oldham et al., titled “Protective overlay coating for PDC drill bits” discloses a method of increasing a durability of a PDC drill bit by overlaying at least a portion of the exposed surface of the braze material between the cutter and the cutter pocket with a hardfacing material.
Those skilled in the art will appreciate that selected features described above may be combined in various ways as desired for a give application to provide a PDC drill bit capable of drilling longer wellbore segments through abrasive or ultra abrasive formations. It will also be appreciated that in the case of PDC elements or cutters provided on the cutting face of the bit as referenced above, all or a portion of the diamond layer may be leached or otherwise treated to provide increased abrasion resistance.
Bits in accordance with one or more embodiments of the present invention can be used to drill an entire horizontal segment through the pay zone of a heavy oil reservoir, which may extend 1500 meters or more in length. Selected embodiments may provide a drill bit capable of drilling multiple horizontal segments before having to be pulled to the surface and rebuilt. For example, a drill bit may be used to drill a first horizontal leg through a heavy oil reservoir and then side tracked to drill another horizontal leg without having to be pulled back to surface. A drill bit able to drill multiple lateral wells can provide a substantial time and cont savings to a drilling operation. A PDC bit may also include larger cutters such as 16 mm cutters or larger to provide higher ROP as well as durability in drilling heavy oil reservoirs.
In one or more embodiments, erosion between cutters may be reduced by reducing cutter separation distances along surfaces of the bit. In one or more embodiments back reaming capability may be improved by placing larger cutters or a larger number of cutters along heel surfaces of the bit to minimize blade upside wear. Additionally, in one or more embodiments a PDC drill bit may include larger beveled cutters oriented at a back rake for enhanced steerability and/or to help minimize impact damage that can result from drilling out equipment in the wellbore or contacting harder formation stringers that dip into a drilling zone.
In accordance with one or more embodiments erosion on cutter substrates may be reduced by limiting the amount of substrate material exposed to the formation, by placing cutters at higher back rake, and/or by minimizing spacing between cutters. In one or more embodiments, erosion may be reduced around the cutters by placing PDC cutters substantially flush with the blade face and by providing cutter arrangements that do not include additional gaps or spaces, such as cutter pocket relief grooves. Erosion and abrasion may also be reduced by directing fluid nozzles towards the center of fluid channels or slightly away from the corresponding blade front face. Also, in one or more embodiments blades having limited helix may be used and/or and with diamond imbedded in the blade tops and/or cutter substrates to reduce wear behind the cutters and across the blade tops.
Additionally, a novel gage pad configuration may be used on any bit to minimize gage pad wear. Additionally, using gage pads with larger surface area, such as wider or more spiral gage pads, may help maximize diamond coverage on the gage of the bit. In one or more embodiments, the diamond coverage on a gage pad may be 35% or more, and in some cases 50% or more. In one embodiment a gage pad may comprise five or more gage pad elements with diameters of 13 mm or more arranged in a row along the gage pad. In another embodiment, a gage pad may comprise seven or more gage pad elements having diameters of 13 mm or more. In one or more embodiments, larger wear resistant elements, such as GHIs, DEIs or ultrahard compacts, may be placed closer to the leading and/or trailing edges of the gage pads to reduce gage pad wear. Wear resistant elements having rounded surfaces may be disposed proximal the leading edge of the gage pad to provide a rounded edge resistant to sharp sands in the abrasive slurry to help maintain the leading edge longer. Wear resistant elements disposed in the gage pad may be infiltrated or brazed into the gage pad. In one or more embodiments, impregnated diamond grit may be used to form surfaces of the bit, such as part of the gage pad and/or blade tops to provide increased abrasion resistant for extended bit life.
In other embodiments, a coating may also be applied to surfaces of the bit to provide increased abrasion resistance. For example, CVD technology or other coating technology may be applied to coat leading edges or surfaces of the gage pad. PDC bits having enhanced gage features in accordance with one or more embodiments of the present invention may be able to effectively resist going under gage during extended drilling runs, which minimizes the risk of compromising the effective diameter of the wellbore and subsequent operational complications.
One or more embodiments, a PDC bit having cutters closely spaced, limited blade helix, natural diamond embedded in blade tops, rounded wear elements disposed along leading and trailing edges of the gage pad, and impregnated diamond in the gage pad may be used to provide an economic benefit to a high ROP, heavy oil drilling program.
PDC bits including selected features described above may be rebuilt and reusable a sufficient number of times to provide a positive economic impact to an overall drilling program in unconsolidated, ultra abrasive formations and similar formations. Such bits may also make it possible to drill longer horizontal segments in these environments without having to pull a bit to the surface.
While the invention has been described with respect to a limited number of embodiments, those skilled in the art will appreciate that numerous other embodiments can be devised which do not depart from the scope of the invention as set forth in the appended claims.
This patent application is a continuation of U.S. patent application Ser. No. 12/887,198, filed Sep. 21, 2010, which is a continuation of U.S. patent application Ser. No. 11/367,097, filed Mar. 3, 2006 which claims priority to U.S. Provisional Patent Application Ser. No. 60/658,534, filed on Mar. 3, 2005, which is incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 60658534 | Mar 2005 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 12887198 | Sep 2010 | US |
| Child | 13196627 | US | |
| Parent | 11367097 | Mar 2006 | US |
| Child | 12887198 | US |
