WO1996003568A1

WO1996003568A1 - Sacrificial wear bearing

Info

Publication number: WO1996003568A1
Application number: PCT/US1995/009359
Authority: WO
Inventors: Jerome Kemick
Original assignee: Jerome Kemick
Priority date: 1994-07-28
Filing date: 1995-07-20
Publication date: 1996-02-08
Also published as: AU3144995A

Abstract

A sacrificial wear bearing (100) for use on a tool joint (34, 36) or a drill pipe joint (30) to protect the casing (24), drill pipe joint (30) and well bore wall from wear. The sacrificial wear bearing (100) includes a cylindrical sleeve (102) having a first end, a second end, an inner surface (110) and an outer surface (106). The cylindrical sleeve (102) is adapted to rotatably fit on one of the tool joints (34, 36) of the drill pipe joint (30) or on a raceway (220) mounted on the drill tube segment (32). A retainer ring stop (104) is mounted on the tool joint or a bearing raceway (220) adjacent the first and second ends of the cylindrical sleeve (102) to secure the longitudinal location of the cylindrical sleeve (102) on the tool joint (34, 36) or bearing raceway (220).

Description

FOR THE PURPOSES OF INFORMATION ONLY

Codes used to identify States party to the PCT on the front pages of pamphlets publishing international applications under the PCT.

AT Austria GB United Kingdom MR Mauritania

ΛU Australia GE Georgia MW Malawi

BB Barbados GN Guinea NE Niger

BE Belgium GR Greece NL Netherlands

BF Burkina Faso HU Hungary NO Norway

BG Bulgaria IE Ireland NZ New Zealand

BJ Benin IT Italy PL Poland

BR Brazil JP Japan PT Portugal

BY Belarus KE Kenya RO Romania

CA Canada KG Kyrgystan RU Russian Federation

CF Central African Republic KP Democratic People's Republic SD Sudan

CG Congo of Korea SE Sweden

CH Switzerland KR Republic of Korea SI Slovenia

CI Cβte d'lvoire KZ Kazakhstan SK Slovakia

CM Cameroon LI Liechtenstein SN Senegal

CN China LK Sri Lanka TD Chad

CS Czechoslovakia LU Luxembourg TG Togo

CZ Czech Republic LV Latvia TJ Tajikistan

DE Germany MC Monaco TT Tπnidad and Tobago

DK Denmark MD Republic of Moldova UA Ukraine

ES Spain MG Madagascar US United States of America

FI Finland ML Mali uz Uzbekistan

FR France MN Mongolia VN Viet Nam

GA Gabon SACRIFICIAL WEAR BEARING

SPECIFICATION BACKGROUND OF THE INVENTION

1. Field of the Invention. The present invention relates to tool joints and drill pipe, and more particularly to sacrificial wear bearings for tool joints and drill pipe to protect the tool joints, drill pipe, casing, and well bore from wear.

2. Description of the Prior Art. The drill pipe string common in the oil and gas industry in the drilling of well bores is typically comprised of a plurality of threadably connected drill pipe joints. Each drill pipe joint includes a drill tube segment having a tool joint joined to each end of the drill tube segment. The tool joints are typically welded onto the ends of the drill tube segment. The tool joints have threaded ends to form the threaded connection between the drill pipe joints in making up the drill pipe string. Typically, the tool joint at the upper end has internal threads, and the tool joint at the lower end has external threads. The internally threaded tool joint is referred to as the "box," and the externally threaded tool joint is the "pin." When a drill pipe string is made up, i.e., a series of drill pipe joints threadably connected, the downwardly extending pin is stabbed into the upwardly extending box and the connection tightened. The tool joints are typically made of higher strength and harder steel than the drill tube segment. The tool joints typically have a larger outer diameter than the drill tube segment. The tool joint, having a larger outer diameter than the drill tube segment, is generally the first part of the drill pipe string to make contact with the casing or the well bore wall and thus is more susceptible to wear. The contact of the tool joint with the casing also causes wear on the casing.

Casing is a steel pipe placed in an oil or gas well as drilling progresses. The function of casing is to prevent the wall of the well bore from caving in during drilling and to provide a means of extracting the oil if the well is productive.

Quartz is the single most abundant material found in the Earth's crust and varies from 30% to 60% of the bulk material of the Earth's crust. Quartz is harder than the hardest martensitic steel. It is thus apparent that quartz serves as an abrasive and erosional material on the drill pipe string and the casing in the drilling of well bores.

Materials harder than quartz have been placed on drill bits and the drill pipe strings in selected areas to protect them from abrasive and erosional wear. Materials such as tungsten carbide, chromium nitride and chromium diboride and many others, have been used in the hard facing or hard banding of the drill pipe string. The hardness of some of the materials commonly encountered in the drilling of a well bore are listed below. The hardness numbers refer to the Vickers Hardness Test which numbers range from 1 to 10,000 in ascending order of hardness.

HV Austenistic Steel (casing) 300-600

Martensitic Steel (tool joints) 500-1000 Quartz Particles 750-1200

Tungsten Carbide (hard banding) 2000-2400 Diamonds 10,000

Typically, the tool joints are hard faced by protective bands of wear resistant materials in the box area where the tool joint is most susceptible to wear. The hard facing of the tool joint is done in order to protect the tool joint from wear and extend the life of the tool joint and drill pipe joint, at the expense of the casing. Hard facing tool joints add a significant amount of cost to the tool joints and the drill pipe joints. On the further explanation of the drilling of the well bore, it is generally necessary to use a drilling fluid. Drilling fluids are commonly pumped down the hollow bore of the drill pipe string to cool the drill bit and then to remove the cuttings from the well bore by forcing the drilling fluid with the cuttings up to the surface in the annular space between the well bore wall and the drill pipe string. Due to inclusion of particulate material used in the manufacture of a drilling fluid, plus the particulate material derived in cutting formations, the drilling fluids may often contribute to wear of the drill pipe string, casing and the well bore wall. Drilling fluids may vary from a water phase, oil phase, oil-in-water emulsion phase, water-in-oil emulsion phase, or combinations of any or all of the above. On the drilling of a well bore, it is desirable to drill the well bore in a true vertical direction to minimize wear on the drill pipe string, casing and the well bore wall. Inadvertent deviation of the well bore from vertical is very common. The deviation of the well bore from vertical may be caused by a variety of factors. Among these factors are the rotational effects of the drill pipe string and bit; compressive and tensional forces on the drill pipe string and bit; and the formations encountered in the drilling of a well bore.

In the oil and gas industry, there are times when it is desirable for a well bore to deviate from the vertical. Induced factors to cause the deviation from the vertical and control the path of the well bore are common knowledge to those familiar with the drilling of well bores for the oil and gas industry. Well bores deviated from the vertical are often used when a plurality of wells are drilled from a single drilling area as in offshore drilling operations; side-tracked wells necessitated by design or mechanical difficulties; on-shore areas where a specific drill site is available; deviated wells necessary to reach a specific target area as in salt-dome operations, and horizontal wells such as being utilized today for increased production rates and increased cumulative production. It is commonly accepted in the oil and gas industry that any deviation from the vertical significantly increases wear at the contact surfaces on the drill pipe string, the casing exposed to the drill pipe string, and the well bore wall in contact with the drill pipe string below the casing area.

In tribology, i.e. the study of the aspects of the wear processes of surfaces, it is convenient to divide the wear system into four parts: the surface, the mating countersurface, intersurface elements such as the liquid or lubricant phase between the surface and countersurface that may contain particles of diverse shapes and sizes; and the surrounding environmental (operating) conditions existing such as imposed loads, relative motion, temperatures, pressures and others.

On the drilling of a well bore, the motion that occurs between the rotating drill pipe and the stationary casing and/or well bore wall is a sliding motion. This sliding motion between the drill pipe surface area and the casing or well bore wall countersurface area is considered to be the major factor in the wear of the drill pipe string and the casing and/or well bore wall exposed to the drill pipe string.

Wear between a moving surface and countersurface with an imposed load can be described as a physical wear and an abrasive wear. Physical wear, often defined as a two body abrasive wear, results in the removal of material from the surface or countersurface due to adhesion-shear cycles on the asperities that exist on the surface and countersurface of the moving surfaces. Examples in the drilling of a well bore include the wear resulting from the contact of the moving hard tool joint with the less hard casing or the wear resulting from the contact of the moving hard tool joint with harder quartz formation of the open hole.

Abrasive wear, often described as three body abrasive wear, occurs where wear in the surface or countersurface is accelerated by the introduction of abrasive particles in a fluid that are free to come between the surface and countersurface area and inflict wear by grooving, cutting, plowing and chipping. U.S. Patent No. 5,069,297 discloses a drill pipe\casing protector mounted on a drill tube segment adjacent to the tool joint. The drill pipe\casing protector includes a protective sleeve preferably made from a compressible material secured to the exterior of the drill tube segment to rotate with the drill pipe during normal drilling operations and to stop rotating or rotate very slowly while allowing the drill pipe to continue rotating within the sleeve upon frictional contact between the sleeve and the casing or wall of the well bore. The protective sleeve, normally made from a rubber material, is split longitudinally to provide a means for spreading apart the opposite sides of the sleeve when mounting the sleeve to the drill tube segment. It is desirable to reduce or minimize the wear on the drill pipe string resulting from the rotating contact of the drill pipe string with the casing or well bore wall. It is desirable to include a durable sacrificial wear bearing on the tool joints or drill pipe joint to reduce or minimize the wear on the drill pipe string when rotating against the casing or well bore wall. It is further desirable to include a durable sacrificial wear bearing on the tool joints or drill pipe joint to reduce or minimize the wear on the casing and well bore wall when exposed to the rotating action of the drill pipe string. It is also desirable that the sacrificial wear bearing be dependable, durable, long-wearing, economical and easily installed and replaced.

SUMMARY OF THE PRESENT INVENTION

The present invention is a sacrificial wear bearing adapted to be installed on the drill pipe string to reduce or minimize the wear on the drill pipe string resulting from the rotating contact of the drill pipe string with the casing or well bore wall. The sacrificial wear bearing also reduces or minimizes the wear on the casing and well bore wall when exposed to the rotating action of the drill pipe string. The sacrificial wear bearing is dependable, durable, long-wearing, economical and easily installed and replaced. The sacrificial wear bearing is a cylindrical sleeve which loosely and rotatably fits onto the 8 tool joint or the drill pipe joint. The sacrificial wear bearing is restrained from longitudinal movement relative to the drill pipe joint. The drill pipe joint is permitted to rotate relative to the sacrificial wear bearing as a result of the loose fit of the sacrificial wear bearing on the tool joint. Preferably, the outer surface of the cylindrical sleeve includes a plurality of rotator stops spaced around the periphery of the cylindrical sleeve to prevent rotation of the cylindrical sleeve as it begins to contact the casing or the wall of the well bore. This, in turn, reduces wear on the casing or well bore wall and transfers the wear to the inner surface of the cylindrical sleeve of the sacrificial wear bearing.

The cylindrical sleeve of the sacrificial wear bearing is made of a softer material than the tool joint to allow the wear bearing to serve as a sacrificial type of bearing. The cylindrical sleeve is made of a material hard enough to provide a longlasting wear bearing. The cylindrical sleeve is a continuous cylindrical ring having an inner diameter greater than the outer diameter of the tool joint to permit the cylindrical sleeve to be freely slid onto the drill pipe joint during installation.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to more fully understand the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, in which: Fig. 1 is a diagrammatic elevational view illustrating a prior art deviated, extended reach well showing a drill pipe string, casing and well bore with wear areas on the tool joints, casing, and the well bore wall;

Fig. 2 is a fragmentary elevational view in cross section showing a prior art tool joint section of the drill pipe string centered in the casing; Fig. 3 is a fragmentary elevational view in cross section showing a prior art tool joint section of the drill pipe string centered in the casing with the box end tool joint having a carbon granule hard facing portion;

Fig. 4 is a cross-sectional view taken along line 4-4 of Fig. 3 showing the drill pipe string generally centrally located within the casing;

Fig. 5 is a fragmentary elevational view in cross section showing a prior art hard faced tool joint section of the drill pipe string in contact with the casing and showing severe wear of the casing;

Fig. 6 is a cross-sectional view taken along line 6-6 of Fig. 5 showing the wear area on the tool joint and the casing; Fig. 7 is a fragmentary elevational view in cross section of the pin end tool joint and the box end tool joint with a first embodiment of the sacrificial wear bearing of the present invention installed thereon with the drill pipe string centered in the casing; 10

Fig. 8 is a cross-sectional view taken along line 8-8 of Fig. 7 showing the tool joint with the sacrificial wear bearing generally centrally located within the casing; Fig. 9 is a fragmentary elevational view in cross section showing the pin end tool joint and the box end tool joint with the sacrificial wear bearing in non-rotational contact with the casing;

Fig. 10 is a cross-sectional view of the tool joint taken along line 10-10 of Fig. 9 showing the sacrificial wear bearing in non-rotational contact with the casing;

Fig. 11 is a cross-sectional plan view of the tool joint with the sacrificial wear bearing illustrating the wear lobe areas of the sacrificial wear bearing;

Fig. 12 is a fragmentary elevational view in cross section of elongated pin end and box end tool joints with sacrificial wear bearings installed on both tool joints;

Fig. 13 is a fragmentary elevational view in cross section of the pin end and the box end tool joints with a second embodiment of the sacrificial wear bearing of the present invention installed on the drill tube segment with the drill pipe string centered in the casing;

Fig. 14 is a cross-sectional view taken along line 14-14 of Fig. 13 showing the drill tube segment with the sacrificial wear bearing generally centrally located within the casing; and 11

Fig. 15 is a fragmentary elevational view in cross section showing the sacrificial wear bearing on the drill tube segment in non-rotational contact with the casing with the pin end and box end tool joints out of direct contact with the casing.

DETAILED DESCRIPTION OF THE INVENTION

Referring now to Fig. 1, a diagrammatic elevational view illustrates a deviated, extended reach well showing a drill pipe string 20, drill bit 22, casing 24 and well bore 26. The well is also shown with a surface casing 28 which is the first section of casing set in a well. The drill pipe string 20 is made up of a plurality of the drill pipe joints 30. Referring to Figs. 1 and 2, each drill pipe joint 30 includes a drill tube segment 32, a box end tool joint 34, and a pin end tool joint 36.

As shown in Fig. 1, the drill pipe string 20 does not remain in a substantially straight configuration in a deviated well as it would in a vertical well. In a deviated well, it may be necessary for the drill pipe string 20 to have bends and turns along the length of the drill pipe string 20. The casing 24 and the well bore 26 will also have bends and turns in the deviated well.

A typical drill pipe joint 30 has a length of approximately thirty feet (30'). As shown in Figs. 2 and 3, the tool joints 34 and 36 have a common outer diameter which is greater than the outer diameter of the drill tube segment 32. Thus, 12 typically, the outer surfaces 38 and 40 (Figs. 2 and 3) of the tool joints 34 and 36, respectively, are the surfaces which come into contact with the casing 24 and the well bore wall 42 as shown in Figs. 1 and 5. Referring to Figs. 1 and 5, wear areas 44 are formed on the casing 24 at the locations where the tool joints 34 and 36 contact the casing 24. Wear areas 46 are also formed on the well bore wall 42 at the locations where the tool joints 34 and 36 contact the well bore wall 42 as shown in Fig. 1. The outer surfaces 38 and 40 of the tool joints 34 and 36, respectively, also become worn due to the contact with the casing 24 and the well bore wall 42. As shown in Figs. 2-4, the preferred situation is when the tool joint 34 and the drill pipe string 20 are substantially centrally located in the casing 24 and, thus, the rotating drill pipe string 20 has no contact with the casing 24. Reference numeral 50 refers to a line indicating the direction of rotation of the drill pipe string 20 during typical drilling operations. The outer diameter of the tool joints 34 and 36 is less than the inner diameter of the casing 24 or the well bore 26. Thus, an area 48, preferably annular, is formed between the drill pipe string 20 and the casing 24 or the well bore wall 42.

Referring to Figs. 3-6, in certain instances the prior art box end tool joint 34 is modified to include a lower portion 34a which is hard faced or hard banded by a protective layer or band of wear 13 resistant material. Typically, the protective band comprises a mild steel overlay machined to the outer diameter of the tool joint 34. The overlay is comprised of carbide granules in a mild steel matrix. Although not shown, the pin end tool joint 36 may also have a hard facing portion.

Referring to Figs. 5 and 6, the tool joints 34 and 36 may come into rotational, sliding contact with the casing 24 or the well bore wall 42. This results in a deterioration of the wall of the casing 24 or well bore wall 42 since the tool joints 34 and 36 and the hard facing portion 34a are made of a harder material than the casing 24. Thus, most of the wear occurs on the wall of the casing 24, as shown in Figs. 5-6. As shown in Fig. 6, the continued wear on the casing 24 can eventually result in a hole or rupture 44a forming in the wall of the casing 24.

Referring to Figs. 2, 3 and 5, the tool joints 34 and 36 include an outer surface area called a tong area 34t and 36t, respectively. The tong areas 34t and 36t provide locations on the tool joints 34 and 36, respectively, where drilling rig tongs (not shown) can be applied to the tool joints 34 and 36 to make up the drill pipe string 20 or break out the drill pipe joints 30. With reference to Figs. 3 and 5, it is important to understand that the hard facing portion 34a is generally separate from the tongs area 34t because the tongs would damage the hard facing portion 34a if applied thereto. 14

Referring to Figs. 7-12, a first embodiment of the sacrificial wear bearing according to the present invention, designated generally as 100, comprises a cylindrical sleeve 102 adapted to be installed on the tool joints 34 and 36. The cylindrical sleeve 102 has a substantially smooth inner surface 110 and a substantially smooth outer surface 106. Preferably, the cylindrical sleeve 102 is a continuous ring. Preferably, the cylindrical sleeve 102 has a uniform inner diameter. The cylindrical sleeve 102 is adapted to rotatably fit on the tool joints 34 and 36. The cylindrical sleeve 102 has an outer diameter sized so as to avoid contact with the casing 24 or the well bore wall 42 when the drill pipe joint 22 is substantially concentrically located therein as shown in Figs. 7 and 8. The outer diameter of the cylindrical sleeve 102 is substantially less than the diameter of the casing 24 and the well bore 26 to allow mud circulation in the annular area 48 during the drilling of the well.

It is to be understood that the sacrificial wear bearing 100 is preferably installed on the box end tool joint 34 (Figs. 7 and 9) due to the typical structural configuration of the tool joints 34 and 36. It is to be further understood that the sacrificial wear bearing 100 would also function on the pin end tool joint 36 as shown in Fig. 12 as will be explained below. It is also to be understood that a sacrificial wear bearing 200 according to a second embodiment of 15 the present invention can also be installed on the drill tube segment 32 as shown in Figs. 13-15 as will be explained below.

Referring to Figs. 7, 9 and 12, the sacrificial wear bearing 100 installed on the drill pipe joint 30 is restrained from longitudinal movement along the drill pipe joint 30 by at least one retainer ring stop 104 located at each end of the sacrificial wear bearing 100. Preferably, the retainer ring stop 104 is a continuous ring. Alternatively, the retainer ring stop 104 can be one or more flange plates attached to the periphery of the tool joint 34, 36. The retainer ring stops 104 are slid onto the tool joint 34, 36 where they are securely attached to the tool joint 34, 36. The retainer ring stops 104 may be secured to the drill pipe joint 22 by spot welding, continuous welding, cold- sweating, heat-sweating, pressing or by mechanical means, such as screws or pins. The method of attachment of the retainer ring stops 104 to the drill pipe joint 30 is such that the retainer ring stops 104 may be easily installed or removed. Tools common to the industry are readily available for the removal and installation of the retainer ring stop 104 when it is necessary to replace the cylindrical sleeve 102 of the sacrificial wear bearing 100.

The retainer ring stops 104 are spaced from one another so as to allow a slight clearance between the cylindrical sleeve 102 and the retainer ring stops 104 as shown in Figs. 7, 9 and 12. The retainer ring stops 104 have an outer diameter 16 greater than the inner diameter of the cylindrical sleeve 102 to maintain the longitudinal positioning of the sacrificial wear bearing 100 on the drill pipe joint 30. The outer diameter of the retainer ring stops 104 is less than the outer diameter of the cylindrical sleeve 102 so that the cylindrical sleeve 102 will make first contact with the casing 24 or the well bore wall 42 instead of the retainer ring stops 104. The cylindrical sleeve 102 of the sacrificial wear bearing 100 is longitudinally restrained on the drill pipe joint 30 while being free to rotate relative to the drill pipe joint 30. In the same manner, the drill pipe joint 30 is free to rotate relative to the cylindrical sleeve 102 when the cylindrical sleeve 102 comes into contact with the casing 24 or well bore wall 42.

Preferably, the retainer ring stops 104 are made of an alloy steel compatible in design and strength with the steel of the drill pipe joint 30 where mounted and the sacrificial wear bearing 100. Preferably, a plurality of rotator stops 108 are peripherally spaced and attached to the outer surface 106 of the cylindrical sleeve 102 as shown in Figs. 7-12. The rotator stops 108 may be of various forms, including for example, buttons, ears or a solid ridge extending approximately the length of the cylindrical sleeve 102. Referring to Figs. 10 and 11, the rotator stops 108 prevent the cylindrical sleeve 102 from rotating when the sacrificial wear bearing 100 contacts the casing 24 or the well bore wall 42. This, in turn, reduces 17 wear to the casing 24 or the well bore wall 42 and instead transfers the wear to the inner surface 110 of the cylindrical sleeve 102 of the sacrificial wear bearing 100. As shown in Fig. 11, wear bearing lobe areas 112 form with time between adjacent pairs of rotator stops 108 due to the drill pipe joint 30 rotating relative to the sacrificial wear bearing 100.

It is to be understood that the sacrificial wear bearing 100 may be used either with or without the rotator stops 108.

The sacrificial wear bearing 100 is to be of a material, or materials, such that the cylindrical sleeve 102 is more susceptible to wear than the tool joints 34 and 36, more susceptible to wear than the casing 24, and more susceptible to wear than the usual formations encountered in the drilling of well bores.

The cylindrical sleeve 102 of the sacrificial wear bearing 100 is made of a softer material than the tool joint 34, 36 so that the wear bearing 100 serves as a sacrificial type of bearing. Preferably, the wear bearing material is also softer than the casing 24 so that the wear bearing 100 sacrifices itself in lieu of the casing 24. It is important, however, that the wear bearing material is durable and provides a long-wearing sacrificial wear bearing 100.

The sacrificial wear bearing 100 is designed to be installed on many existing tool joints 34, 36 presently in use. On some tool joints 34, 36 in use 18 today, there is not sufficient length of the tool joint 34, 36 on which to install the sacrificial wear bearing 100 without interfering with the drilling rig equipment used to make up and break out the drill pipe joints 30. However, it is to be understood that the sacrificial wear bearing 100 will eliminate the need to hard face or hard band the tool joint and thus can be installed typically at the location that the hard facing or hard banding would otherwise be located.

The following example illustrates the application of the sacrificial wear bearing 100 on a typical commercially available tool joint. Every HI TORQUE tool joint manufactured by Grant TFW, Inc. for 3-1/2" O.D. (outside diameter) pipe with a 4-

3/4" O.D. tool joint has a pin tong space length of 8" and a box tong space length of 13-1/2". HI TORQUE is a trademark of Grant TFW, Inc. This particular type of tool joint allows a length of approximately 3" to 6" in which to install the sacrificial wear bearing 100. As shown in Figs. 7 and 9, the sacrificial wear bearing 100 is installed on the box end tool joint 34 in the same location as the hard facing portion 34a (Figs. 3 and 5) . In this example, the cylindrical sleeve 102 would have an inside diameter slightly larger than the 4-3/4" O.D. of the tool joint and an outside diameter in the range of approximately 5-1/4" to 5-3/4".

Referring to Fig. 12, the dashed lines indicate the length of typical tool joints 34 and 36. By increasing the length of the tool joints 34 and 36 19 by approximately 3" to 12", the sacrificial wear bearing 100 could be easily installed on both the pin end and the box end tool joints 34 and 36, respectively. For purposes of discussion regarding the bearing material, it is assumed that the sacrificial wear bearing 100 is placed on a tool joint 34, 36 made of SAE/AISI 4137 H steel (0.30-0.50 carbon, 0.80-1.10 chromium and 0.15-0.25 molybdenum) having a hardness of 55 HRC (Rockwell Hardness) .

The choices of bearing material for the sacrificial wear bearing 100 are dictated by the operating conditions in the drilling of a well bore. A few types of preferred bearing materials are listed below:

Material A — White metal alloy (SAE 11, .875 Sn, .0675 Sb, .0575 Cu) cast on a rigid steel shell. This bearing material has good compatibility with hard steel journal, good conformability and excellent embedability of abrasive particles.

Material B — Porous iron bearing formed by pressing powder to shape and then sintering, consisting of pure iron and 2 to 25% copper, impregnated with oil under vacuum conditions. This bearing material is excellent when using a hard shaft.

Material C — Proprietary alloy (Ni) steel austenized with a typical hardness ranging between 30 to 45 HRC. Material C is beneficial to resistance by abrasion since material strain hardens 20 during abrasion and exhibits high ductility or toughness.

The sacrificial wear bearing 100 of the present invention can be easily installed and is easily and economically replaced when wear has exceeded the programmed wear of the sacrificial wear bearing 100. To install, a first retainer ring stop 104 is slid or forcibly driven onto the end of the tool joint 34, 36 of the drill pipe joint 30 and secured to the tool joint 34, 36 at the appropriate location. The cylindrical sleeve 102 is freely slid onto the end of the tool joint 34, 36 until it comes into contact with the first retainer ring stop 104. The second retainer ring stop 104 is then slid or forcibly driven onto the end of the tool joint 34, 36 and secured thereto at the appropriate location. This installation process is extremely quick, simple and economical. To replace the sacrificial wear bearing, the second retainer ring stop 104 nearest the end of the drill pipe joint 30 is removed and the old cylindrical sleeve 102 is slid off the end of tool joint 34, 36. A new cylindrical sleeve 102 is then slid back on the tool joint 34, 36. A second retainer ring stop 104 is then reinstalled on the tool joint 34, 36 to securely position the cylindrical sleeve 102 on the tool joint 34, 36.

As mentioned above, a second embodiment of the sacrificial wear bearing 200 of the present invention may be installed on the drill tube segment 32 as shown in Figs. 13-15. The second embodiment 200 is structurally and functionally very similar to the first embodiment described above. Elements that 21 are structurally similar will be referred to by the identical name and last two digits of the three digit number, with the first digit being a "1" for the first embodiment and a "2" for the second embodiment. It is further to be understood that only the differences between the first and second embodiments will now be discussed.

Referring to Fig. 14, a bearing raceway 220 is formed in generally semi-circular sections 220a and 220b around the drill tube segment 32. The sections 220a and 220b have end faces forming a bevel 222 between each of the opposing end faces when placed around the drill tube segment 32. The inside diameter of the bearing raceway 220 is approximately the same or slightly smaller than the outside diameter of the drill tube segment 32. Preferably, the bearing raceway 220 is rigidly attached to the drill tube segment 32. The bearing raceway 220 may be attached to the drill tube segment 32 by compressing the bearing raceway sections 220a and

220b and welding together the end faces forming the bevels 222. If desirable, the bearing raceway 220 could be preheated, or the drill tube segment 32 cooled, prior to welding to insure a more compressive fit around the drill tube segment 32. Alternatively, the bearing raceway 220 could be welded to the drill tube segment 32 if the integrity of the drill tube segment is not violated. Yet another alternative would be to securely attach the bearing raceway sections 220a and 220b to one another with a series of bolts or screws. 22

Preferably, the bearing raceway 220 has an outside diameter slightly larger than the outside diameter of the tool joints 34 and 36 to allow the passage of the cylindrical sleeve 202 and the retainer ring stops 204 over the tool joint 34, 36 to the location of the bearing raceway 220.

It is believed that the preferred length of the cylindrical sleeve 202 installed on the bearing raceway 220 on the drill tube segment 32 is in the range of approximately 6" to 18". The preferred length will vary in relation to the outside diameter of the drill tube segment 32 and the severity of the drilling conditions expected. The overall dimensions of the cylindrical sleeve 202 will be compatible with the tool joints 34 and 36 and the drill string design.

The retainer ring stops 204 are attached to the bearing raceway in the same manner as discussed above for the first embodiment. The bearing raceway 220 is preferably made of a material harder than the cylindrical sleeve 202, and the same as or harder than the tool joints 34 and 36. The material must also be compatible with the drilling environment. The bearing raceway 220 can be made from many metals, alloys, ceramics and cermets (ceramics and metals) .

Several advantages may be realized by positioning the sacrificial wear bearing 200 on the drill tube segment. One advantage is that the sacrificial wear bearing 200 can be installed and used on all existing drill pipe joints 30 regardless 23 of the length of the tool joints 34 and 36. Additionally, the sacrificial wear bearing 200 according to the second embodiment will not interfere with drilling rig equipment used to make up or break out the drill pipe joints 30. One or more sacrificial wear bearings 200 may be positioned at any location along the length of the drill tube segment 32. The positioning of the sacrificial wear bearings 200 along the drill tube segment 32 will also have the effect of increasing the rigidity of the drill pipe string 20 and reducing the bending moments in the drill pipe string 20 near the tool joints 34 and 36. Additionally, the sacrificial wear bearings 200 will help to dampen dynamic excitation and the harmonic vibration of the drill pipe string 20.

The sacrificial wear bearing 100 and 200 as installed on the drill pipe string 20 is designed such that the designed stress profile of the drill pipe string 20 is not compromised and the parameters of fluid flow as required in the drilling of the well bore are maintained.

The major operating and environmental conditions that exist in the drilling of a well bore 26 cannot be changed to a great extent and the sacrificial wear bearing 100, 200 has been designed to function under those existing conditions. Those existing conditions are as follow: a) the well bore 26 includes cased interval(s) and open hole interval(s); 24 b) the drill pipe string 20 includes drill pipe tube segments 32 and attached tool joints 34 and 36 for the addition and deletion of a drill pipe joint 30 to the drill pipe string 20; c) the tool joints 34 and 36 of the drill pipe joints 30 are made of steel that has a very high tensile strength and an accompanying high hardness property; d) the tool joint 34, 36 is significantly harder than the casing 24; e) the tool joint 34, 36 may be hard faced in part by very hard materials such as tungsten carbide; f) a drilling fluid (not shown) , either in a water phase, an oil phase, a water-oil phase, an oil-water phase or a mist or air phase, is used for the removal of cuttings (not shown) and to cool the bit 22 in the drilling well bore 26; g) the drilling fluid contains abrasive particles, either introduced in the manufacture of the drilling fluid or derived from the cuttings of the well bore 26; h) the abrasive particles are primarily quartz particles and vary in size from colloidal to grit; i) the abrasive particles are significantly harder than the drill pipe tube segment 25

32, the tool joints 34, 36 and the casing 24; j) the axial and radial loads imposed on the drill pipe string 20 and the casing 24, between the drill pipe string 20 and the well bore wall 42 is dependent on the design of the well bore 26; k) the sacrificial wear bearing 100, 200 is designed and made of materials to operate within the constraints of the drill pipe string 20, the casing 24 and the hydraulics involved in the drilling of the well bore 26; and 1) in cases where corrosive elements such as C0₂ and H₂S are present in the well bore

26, the sacrificial wear bearing 100, 200 including the retainer ring stop 104 is made of materials capable of operating in such environments. The properties of hardness, erosion resistance, compressive strength, compatibility, embedability, fatigue resistance, conformability and corrosion resistance should all be taken into consideration in the selection of material(s) for the sacrificial wear bearing 100, 200.

In the case of the drill pipe string 20 (as a shaft or journal) running in the sacrificial wear bearing 100, 200, it is recognized that the drill pipe string 20 and the casing 24 represent sizeable capital investments and are to be preserved at the expense of the sacrificial wear bearing 100, 200. 26

The sacrificial wear bearing 100, 200 of the present invention is practical and will function under the most extreme conditions in the drilling of deviated and horizontal wells. The sacrificial wear bearing 100, 200 will save money for the industry.

The foregoing disclosure and description of the invention is illustrative and explanatory thereof, and various changes in the size, shape, and materials, as well as in the details of illustrative construction and assembly, may be made without departing from the spirit of the invention.

Claims

27

CLAIMS: 1. A sacrificial wear bearing adapted to be used with drill pipe when drilling a well bore, the drill pipe having a pipe segment connected between a first tool joint and a second tool joint, the sacrificial wear bearing comprising: a cylindrical sleeve having a first end, a second end, a non-resilient inner wear surface and a non-resilient outer contact surface, said cylindrical sleeve adapted to loosely fit and freely rotate on one of the tool joints; and means for securing the longitudinal location of said cylindrical sleeve on the tool joint.

2. The sacrificial wear bearing of claim 1, further comprising means for preventing rotation of said cylindrical sleeve when said outer contact surface of said cylindrical sleeve contacts the well bore wall and as the tool joint rotates.

3. The sacrificial wear bearing of claim 2, wherein said means for preventing rotation of said cylindrical sleeve comprises a plurality of non- resilient rotator stops attached to said outer contact surface of said cylindrical sleeve, said plurality of rotator stops nominally extending from said outer contact surface.

4. The sacrificial wear bearing of claim 1, wherein said means for securing comprises a retainer 28 ring stop mounted on the tool joint adjacent said first and second ends of said cylindrical sleeve.

5. The sacrificial wear bearing of claim 4, wherein the tool joints have outside diameters of the same size and said inner wear and outer contact surfaces of said cylindrical sleeve are smooth and continuous and said cylindrical sleeve has an inside diameter slightly larger than the outside diameter of the tool joint.

6. The sacrificial wear bearing of claim 5, wherein said cylindrical sleeve has an outside diameter approximately one inch greater than the outside diameter of the tool joint.

7. The sacrificial wear bearing of claim 5, wherein said cylindrical sleeve is made of metal having a hardness less than that of the tool joint so that the wear between said cylindrical sleeve and the tool joint occurs on said cylindrical sleeve.

8. A tool joint assembly for a drill pipe joint used to drill a well bore, the drill pipe joint having a pipe segment with a pair of pipe ends, the tool joint assembly comprising: a cylindrical tube having an outer diameter, a first end and a second end, said first end adapted to be connected to one of the pipe ends, said second end including means for threadably connecting to a second drill pipe joint; and 29 a sacrificial wear bearing assembly comprising: a cylindrical sleeve having a first end, a second end, a non-resilient inner wear surface and a non-resilient outer contact surface, said cylindrical sleeve loosely fitting on said cylindrical tube and allowed to freely rotate thereon; and means for securing the longitudinal location of said cylindrical sleeve on said cylindrical tube.

9. The tool joint assembly of claim 8, wherein said cylindrical tube has a first outer surface portion and a second outer surface portion, said first outer surface portion adapted to receive drilling equipment tools and said second outer surface portion receiving said sacrificial wear bearing assembly.

10. The tool joint assembly of claim 9, wherein said sacrificial wear bearing assembly further comprises means for preventing rotation of said cylindrical sleeve when said outer contact surface of said cylindrical sleeve contacts the well bore wall and as said cylindrical tube rotates.

11. The tool joint assembly of claim 10, wherein said means for preventing rotation of said cylindrical sleeve comprises a plurality of non- resilient rotator stops attached to said outer contact surface of said cylindrical sleeve, said 30 plurality of rotator stops nominally increasing the cross-sectional area of said sacrificial wear bearing assembly.

12. The tool joint assembly of claim 8, wherein said means for securing comprises a retainer ring stop mounted on said cylindrical tube adjacent said first and second ends of said cylindrical sleeve.

13. The tool joint assembly of claim 12, wherein said inner wear and outer contact surfaces of said cylindrical sleeve are smooth and said cylindrical sleeve has an inside diameter slightly larger than the outside diameter of said cylindrical tube.

14. The tool joint assembly of claim 13, wherein said cylindrical sleeve has an outside diameter approximately one inch greater than the outside diameter of said cylindrical tube.

15. The tool joint assembly of claim 14, wherein said sacrificial wear bearing is made of metal having a hardness less than that of said cylindrical tube so that the wear between said cylindrical sleeve and said cylindrical tube occurs on said cylindrical sleeve.

16. A sacrificial wear bearing adapted to be used with drill pipe when drilling a well bore, the 31 drill pipe having a pipe segment connected between a first tool joint and a second tool joint, the first and second tool joints having an outer diameter greater than an outer diameter of the pipe segment, the sacrificial wear bearing comprising: a raceway rigidly mounted to the pipe segment, said raceway having a substantially smooth, non- resilient cylindrical outer surface, said raceway having an outer diameter approximately the same as or slightly greater than the outer diameter of the tool joints; a cylindrical sleeve having a first end, a second end, a smooth and continuous inner wear surface and a smooth and continuous outer contact surface, said cylindrical sleeve rotatably fitting on said raceway, said cylindrical sleeve having an inside diameter slightly larger than the outer diameter of the tool joints; and means for securing the longitudinal location of said cylindrical sleeve on said raceway.

17. The sacrificial wear bearing of claim 16, further comprising means for preventing rotation of said cylindrical sleeve when said outer contact surface of said cylindrical sleeve contacts the well bore wall and as the pipe segment rotates.

18. The sacrificial wear bearing of claim 16, wherein said means for securing comprises a retainer ring stop mounted on said raceway adjacent said first and second ends of said cylindrical sleeve. 32

19. The sacrificial wear bearing of claim 18, wherein said cylindrical sleeve has an inside diameter slightly larger than the outer diameter of said raceway.

20. The sacrificial wear bearing of claim 19, wherein said cylindrical sleeve is a continuous ring made of metal having a hardness less than that of said raceway so that the wear between said cylindrical sleeve and said raceway occurs on said cylindrical sleeve.