Patent Grant
11560773
Not applicable
Not applicable
The present invention relates to a method and apparatus for cleaning a wellbore with specially configured drill string mounted tools. More particularly, the present invention relates to a tool apparatus that enables debris removal tools (e.g., scraper blades, brushes or magnetic members/magnets) to be mounted to the outer cylindrically shaped surface of a section or joint of a drill string/drill pipe with a specially configured locking clamp or clamps.
The Drilling of an oil well typically requires the installation into the wellbore of steel walled casing. This casing is cemented into place to provide a gas tight seal between the overlapping casing strings and also between the casing and the formation or rock through which the well is drilled. Typical cementing practice requires the cement to be pumped from the surface area or wellhead down a string of internal tubing or down the inner most casing string and displaced through the bottom of the casing string into the casing annulus. This procedure may contaminate the inside of the casing wall or wellbore with the cement. After cementation is completed, it is often required to drill out cement and the associated cementation equipment (commonly referred to as shoe track, floats shoe, landing collar, and darts).
Chemicals, solids, greases and other fluids used in the drilling process can and do adhere to the casing wall. These chemicals often mix to become a sticky and viscous substance which is largely resilient to chemical treatments and difficult to remove. As the wellbore casing is steel walled, it can and is prone to rusting and scaling.
During the drilling and other downhole activities, pieces of the drilling or wellbore equipment may need to be milled. Through various other processes (purposeful or accidental), pieces or parts can be left inside the wellbore. The aforementioned situations result in contaminants being left in the wellbore, which will for the purposes of this document be referred to as debris.
During the completion phase in a well lifecycle, several pieces of hardware are semi-permanently installed into the wellbore. These vary greatly in complexity and cost. Their primary function is the transportation of produced hydrocarbons (or injection from surface of other fluids) between the reservoir and the Christmas tree/wellhead (or vice versa) as well as maintaining hydrostatic control of the wellbore at all times. Completions typically include steel tubular piping to transport the fluids, at least one hydrostatic sealing device (packer) and one safety valve. More complex completions may include gauges to measure pressure and temperature at multiple points in the wellbore. Other items may include chokes, screens, valves and pumps. Advancements in downhole electronics make the placement of measuring and controlling equipment more accessible and more commonplace.
Typically these components are sensitive to debris. It has been well documented that debris is a leading root cause of failure during completion operations. In response, a niche industry has developed since the late 1990s, which is focused on the removal of debris and the cleaning of the wellbore. This niche of the oil industry is known as wellbore cleanup. The wellbore cleanup operations will typically take place between the drilling and completion of the well.
Generally speaking, the practice of wellbore cleanup is not new. Examples of prior art go back many years when basic embodiments of wellbore cleanup tools were developed, including scrapers, brushes, magnets, junk catchers and variations thereof. These were basic tools designed to fit a basic need, examples of which are still in use today.
As advancements in drilling and completion technologies were made (particularly starting in the 1990's with the inclusion of downhole electronics, sand control, intelligent completions and extended reach drilling) improvements to the design and functionality of wellbore cleanup tools were marketed, and the practice of improving the cleanliness of oil wells prior to installation of the completion components became almost standard practice. During the wellbore cleanup operations, an assembly of tools (referred to as a bottom hole assembly or BHA) will be run into the wellbore to clean each casing section. These tools are fastened together using threaded connections located at either end of the tool. The tools or BHA are then fastened together with the drill string or work string consisting of multiple lengths of drill pipe, collars, heavy weight drill pipe, wash pipe or tubing also featuring threaded connections. These threaded connections are typically industry standard connections as defined in ANSI/API Specification 7-2 (for example 4½″ IF/NC50 or 3½″ IF/NC38) and commonly referred to as API connections. Also available are proprietary connections which are licensed from manufacturers of high strength drill pipe. Popular proprietary connections are supplied by NOV-Grant Prideco (eXtreme Torque, HI Torque, Turbo Torque), Hydrill (Wedge Thread) and others. The proprietary connections are often referred to as premium drill pipe connections and are typically used when higher mechanical strengths are required (e.g., torque, tensile strength, fatigue resistance, etc.) or when larger diameter drill pipe is preferred relating to the improvement of drilling hydraulics. For example, it is common now to use 5⅞″ OD drill pipe inside 9⅝″ casing to improve hydraulics whereas in the past it would have been more common to use 5″ drill pipe).
The table below shows some examples of drill pipe and connection combinations used for a typical casing size; however, due to the many manufacturers and standards available, there may be thousands of combinations.
Note: The Drill Pipe OD refers to the Pipe Body OD and not the maximum external of the component. The Tool Joints are always of larger diameter. Also the Casing Size is defined by the Nominal OD and the linear weight per foot. API 5-CT allows for a tolerance in the diameter and ovality. Therefore the Casing ID may vary significantly.
Wellbore cleanup tools come in a variety of types and brand names. However, they can be categorized generally as one of the following: a scraper, brush, magnet, junk basket, debris filter, circulation sub, drift or a combination of two or more of these. These tools shall typically consist of a tool body onto which the various components can be attached. The tool body may consist of one or more pieces, but shall in all cases include threaded drill pipe connections, either API or Premium type. The tool body is typically an integral drill string component when made up into the drill string and shall bear all the tensile, torque, fatigue and pressure loading of the drill string. The tool body is typically made of steel and customized to allow attachment of the various components in order for it to function in the manner described.
Due to the many variations of drill pipe connections, the variety of casing sizes, and the many types of wellbore cleanup tools required, it would be commercially impractical for a company providing wellbore cleanup tools to stock every combination required from every customer. Therefore the practice of designing wellbore cleanup tools to cover a range of casing sizes as well as a variety of functions has become common practice, whereby the tool body can be used with interchangeable external components to cover both the size range and in some cases also to alter the function of the tool (for example from a scraper to a brush). This allows standardization of the tool body, however as the drill pipe connections are hard cut onto the tool body, a degree of standardization of the tool body connections are required. Typically this is the API drill pipe connection common to that casing size (NC50 for 9⅝″ casing or NC38 for 7″ casing). In some cases the wellbore cleanup tool manufacturer may supply the tools with premium drill pipe connections, however for commercial reasons this is usually limited to specific projects or markets where the use of the corresponding drill pipe justifies this.
It is common for suppliers of wellbore cleanup tools to supply either individual tools or assemblies of tools where the individual tools have a type of drill pipe connection which is not the same as that used in the drill string. In this case it is common for the tools to be supplied with crossovers. Crossovers are typically short “subs” (joints of tubing) with differing connections at each end. For example, a XT-57 box thread can be at the top with an API NC50 pin at the bottom. This allows components of the drill string with non-interchangeable threaded end connections to be made up together into a singular integral drill string. Further to this, it is often practice to supply pup joints which are typically ten feet (10′) or less in length and have a profiled external diameter which matches the drill pipe and which fits into the drilling elevators and drill pipe slips to facilitate the installation and removal of the drill string into/from the wellbore in a timely fashion. There also exists pup-overs which are a combination of pup joint and crossover and which combines the functionality of both.
Wellbore cleanup tools and drill string often have mismatching threaded connections, and the wellbore cleanup tools are usually rated to lower strengths. The lower strength of the cleanup tools in effect reduces the overall strength of the drill string, which is typically rated by the strength of its weakest link. This has become an acceptable practice provided the drilling parameters do not exceed the limitations of the weakest point. The situation can arise during the cleanup operations that high torque can be observed during rotation of the drill string which results in rotation of the string being suspended. Drill string rotation is a key function of wellbore cleanup in the removal of debris from the wellbore, the lack of which significantly impacts the efficiency and effectiveness of the wellbore cleanup.
The requirement to include crossovers and pup joint into the drill string increases the number of threaded connections into the drill string which in turn increases the time and cost to deploy the drill string, increases the inspection costs and increases the likelihood of failure. The inventory of crossovers and pup joints needs to be managed, which includes storage, handling, inspections and maintenance. Due to the many types of drill pipe connections and the varying sizes, and the need to maintain sufficient inventory for multiple overlapping operations, the stocking and management of these inventories is a cost prohibitive endeavor.
The apparatus of the present invention solves the problems confronted in the art in a simple and straightforward manner.
The present invention provides an improved wellbore cleaning method and apparatus whereby wellbore cleanup tools perform the functions of a scraper, brush, magnet and wellbore filter. The tool apparatus of the present invention provides external mounting to the drill pipe cylindrical portion in between the pipe “pin” and “box” end portions and securely attached by a special method and configuration which prevents the tools from being accidentally removed during the wellbore cleanup operations.
Drill pipe joints provide a solid tubular body with uniform diameter and external ‘tool joints’ (i.e., pin and box) of larger diameter which contain the threaded connections. Since the tools are mounted externally to the drill pipe, there are no tool bodies as such, and therefore there is no reduction in the drill string strength through the introduction of a tool body, crossover, pup joint, and drill pipe connection. This arrangement eliminates the need to maintain an inventory of crossovers or to have stock of tool bodies with multiple threaded connections.
The wellbore cleanup tools of the present invention are designed with the principal that if one component were to fail, it would not result in the equipment coming loose from the drill pipe and being left in the wellbore.
In one embodiment the tool internal components are split longitudinally and bolted together about the drill pipe. Robust external rings of single piece construction and with robust internal threads are mated to the split internal components. This external ring covers the aforementioned bolts to prevent them from loosening. The external ring is prevented from loosening by two methods. First, the thread is orientated in such a way that rotating the drill pipe in the conventional manner (clockwise) will tighten the thread due to the friction of the tool against the casing. Secondly grub screws are backed out into internal pockets and secured with springs which prevent any movement of the external ring once secured. This arrangement works positively with the resultant centrifugal forces imparted during rotation of the string.
The tool designs of the present invention are modular and can be deployed individually or in any combination as required by a user or customer. The tools are mounted to the drill pipe body only radially and are free to rotate or move longitudinally along the pipe. They could not move past a tool joint (pin or box end) due to the larger external diameter. There can also be included in the present invention a locking device which consists of a set of toothed dogs, external threaded rings, and an internal split type clamp. When fully made up, the teeth grip the drill pipe, preventing any longitudinal movement. The purpose of this arrangement is to allow mounting of the locking device at any location on the drill pipe. This location may be above or below the mountable wellbore cleanup tools and be designed to limit the longitudinal movement of these tools which the drill string is being moved in the wellbore.
Prior art wellbore cleanup tools typically include drill pipe connections at either end, and have particular components allowing the tools to perform their designed actions, such as a scraper, brush, magnets, junk sub, debris filter or a combination thereof. In the prior art, it is common practice to deploy several such tools screwed together end on end, and it is also common to include crossovers, due to frequent incompatibility between the wellbore cleanup tool connections and the drill pipe connections. To reduce handling time on the rig floor while picking up and laying down such equipment, the installation of pup joints and/or handling pups is also common practice.
The main disadvantages to the above prior art systems are as follows:
This is generally a time-consuming practice and there is also an impact on the safety of the individuals running the equipment as they are exposed to manual handling of heavy equipment, pressure, dropped objects and other hazards typical of a rig floor.
Prior art methods of installation of prior art wellbore cleanup tools typically involve the following steps:
1. Placement or ‘layout’ of the required tools onto the ‘catwalk’ (temporary storage place for drill pipe and equipment being run into or pulled out of the wellbore) using slings, cranes, and/or forklifts. Risks include exposure to dropped objects and accidental crushing from working in proximity to heavy moving equipment.
2. Installation of lifting subs or handling pups to the individual tools and/or making the tools into small sub-assemblies to reduce handling time of the rig. Risks include manual handling of heavy equipment with injuries to fingers and toes.
3. Lifting the sub-assemblies and/or tools to the rig floor using the crane, tugger lines (winches) and/or forklifts. Risks include exposure to dropped objects.
4. In the case that the tools are already made into a completed assembly with pup joints that are of the correct type, it may be possible to install the pup joint directly into the drill pipe elevators and by use of the crane/tugger lines and other devices lift the entire assembly and make it up into the drill string.
5. More commonly the tools and sub-assemblies will be picked up individually. Typically one or more joints of drill pipe (or drill collars) will be suspended in the elevators with the lower pin connection around shoulder height on the rig floor. Alternatively a ‘lifting sub’ may be suspended in the elevators which has an external upset and a pin connection facing down typically compatible with the tools which shall be suspended from it.
6. Depending on the design of the BHA and drill string, there may be either drill pipe, or drill collars suspended from the rotary table by slips. The use of either type requires specialized ‘slips’ and possibly the installation of a ‘dog collar’ (a safety device designed to catch the string should the drill collar slips fail). There may be no lower string, in which case a bit or mill will be installed at the end of the wellbore cleanup BHA.
7. The sub-assemblies or tools are picked up one at a time using winches and the connections made up manually to the drill string. This is a time consuming process which involves the manual use of chain/strap wenches, pipe wenches, drill collar slips, dog collars and hammers. Each connection is also ‘torqued’ using either the semi-manual pipe tongs or using an automated unit such as a ‘mechanical rough neck’ before being lowered into the wellbore.
8. This process presents a risk to personnel as it involves multiple persons working with heavy equipment in close proximity. Drill pipe tongs and associated equipment are notorious for causing injuries to fingers while being used or causing crushing injuries when being handled or swinging free.
9. A further risk is accidental dropping of the string during make-up. Most tools typically come with ‘slick’ tool joints (no external upset) and are often shorter than ideal to allow safe installation of the drill collar type slips and the necessary dog collar. Drill collar slips rely on friction to suspend the drill string and are typically less reliable than drill pipe slips which suspend the string from an upset. If the drill collar were to fail and the dog collar not to hold, then the string would be dropped and free-fall into the wellbore resulting in a costly retrieval (fishing) operation.
Drilling operations are often conducted in remote locations, whether on land, or at sea. Often drilling may take place in countries with limited operational support bases, requiring equipment to be transported to and from the rig over vast distances requiring the use of air, land and sea transportation. Compounding this issue, downhole oilfield equipment tends to be elongated and heavy, requiring specialized baskets to deliver the equipment to the rig site as well as special boats with large deck space. These baskets can be as long as 40 ft. Furthermore, transportation of equipment by air is expensive due to length and weight of equipment and there is typically a premium to be paid to transport such equipment. Offshore drilling rigs have limited deck space to store equipment and minimizing the use of deck space is important to efficient operations. Servicing of the equipment at a logistics base is a labor intense process and requires specialized equipment, trained operators as well as access to third party inspectors.
The application of the invention in the method outlined in the following steps mitigates, eliminates or improves the problems listed above in the following manner.
1. Drill String Integrity—The wellbore cleanup tools as disclosed are externally mounted and secured to the drill pipe without the use of tool bodies. The drill string integrity remains intact as there are no inclusions of additional integral components and therefore no reduction in the integrity of the drill string.
2. Rig Time—The wellbore cleanup tools can be mounted to a single joint of drill pipe at the rig site. This action can be completed on the deck or catwalk away from the main area of operation. When required to be run in the hole, the single joint can be picked up to the rig floor either using the rig's automated systems or in the same manner as running a single joint from the catwalk or mouse-hole which would be the same method used when picking up single joints of drill pipe. It would also be possible to rack the joint in the derrick as part of a stand of pipe in the same manner as the other drill pipe stands are racked.
3. Logistics—As the wellbore cleanup tools do not have tool bodies, and are not required to be made into sub-assemblies prior to shipping, it is possible to ship them in short containers, without the need for the elongated basket typically used to ship other types of tools. This reduces the burden on the deck space onboard the rigs, supply boats and trucks. Furthermore, it reduces the cost of air transportation as the shipping boxes are no longer required to be elongated.
4. Safety—The use of this technology eliminates the need to perform single or sub-assembly pickups on the rig floor, which reduces exposure to common hazards of working on a rig floor such as finger injuries and crushing injuries while using the manual and semi-automated tools and equipment.
The following method describes the general application of one embodiment of attaching a mountable wellbore cleanup tool of the present invention to a joint of drill pipe on a rig location.
1. Begin with a single joint or section of drill pipe which is identical to the joints of drill pipe that comprise the drill string which is to be deployed in the wellbore.
2. Attach a support sleeve, which consists of two or more mated and largely identical pieces split longitudinally, about the drill pipe. These pieces when mated shall make a complete concentric part. The support sleeve can have an internal diameter slightly larger than the external diameter of the drill pipe body to permit rotation of the support sleeve relative to the drill pipe. The internal diameter of the support sleeve can be less than the external diameter of the drill pipe tool joints, such that the support sleeve can be abutted against the tool joint to limit the longitudinal movement of the support sleeve relative to the drill pipe.
3. The pieces of the support sleeve are mated using bolts, pins, hinges, or similar screw type fasteners. Depending on the configuration of the tools, either scraper, brush or magnetic elements may be attached to the support sleeve.
4. Typically the fasteners which secure the support sleeve together may not be of sufficient strength alone to prevent accidental detachment of the support sleeve downhole with disastrous effect. It is therefore necessary to install a plurality of centralizer rings to the support sleeve, which are to be inserted (slide) over the ends of the drill pipe tool joints. These centralizer rings can be of singular piece construction for strength. The internal diameters of the centralizer rings can be slightly larger than the external diameter of the drill pipe tool joints. The centralizer rings can be threaded internally and mated to an external thread on the support sleeve. Alternatively they may be secured to the support sleeve using bolts, pins, or screws and a combination of these fasteners/methods. Once installed, the centralizer rings shall completely or partially cover the fasteners used to mate the support sleeve pieces (e.g. halves) to prevent them from accidentally being removed.
5. To prevent the support sleeve and the assembled components from traveling longitudinally relative to the drill pipe it is necessary to install a locking clamp assembly. Once installed, the support sleeve and assembled components shall abut against the locking clamp at one end and can abut against a drill pipe tool joint at the other, thus preventing any longitudinal movement relative to the drill pipe. Alternatively, two locking clamps can be used to secure the support sleeve and assembled components.
6. To install the locking clamp to the drill pipe, the split slip ring is installed about the drill pipe body. This consists of a plurality of near identical pieces which when mated together make a concentric component. The internal diameter of the split slip ring is slightly larger than the drill pipe body to allow it to be installed and moved into position. The split slip ring pieces are mated using bolts, pins, hinges or similar screw type fasteners.
7. A plurality of slip segments are installed into or adjacent to the split slip ring. The slip segments have an internal profile which matches the external diameter of the drill pipe body and includes a toothed or serrated surface which engages the drill pipe body and prevents longitudinal and rotational movement once sufficient collapsing force is applied. The external profile of the slip segments is conical such that when a mated external component applies a longitudinal force, this conical section converts this force into a collapsing force using the mechanical advantage of the conic shape.
8. A plurality of slip cone rings are installed over the slip segments with an internal conical mating profile to engage the slip segment.
9. To complete the installation of the locking clamp, a tensioner sleeve is slid over the drill pipe tool joints and engaged by a thread to the split slip ring. This can be of singular piece construction. As the tensioner sleeve thread is tightened, it drives the slip cone rings longitudinally which in turn engage the slip segments, which in turn engage the drill pipe body. The tensioner sleeve internal diameter is slightly larger than the drill pipe tool joints to allow installation from one end.
10. The drill pipe single joint complete with installed mountable wellbore cleanup tool can then be picked up to the rig floor by whatever methods are employed upon that particular rig. This may include laying the single joint on the catwalk, placing it in the mouse-hole, making it up to a stand, or racking it in the derrick.
11. After completion of the wellbore cleanup operations, the installation process is reversed. The components can be stored back in their box for later operations or returned to the supply base.
For a further understanding of the nature, objects, and advantages of the present invention, reference should be had to the following detailed description, read in conjunction with the following drawings, wherein like reference numerals denote like elements and wherein:
The tool apparatus 20 provides a tool assembly 15 which can be mounted to a standard, commercially available drill pipe joint or section 12 as will be described more fully hereinafter. In
In one embodiment, tool assembly 15 can be mounted to cylindrical portion 23 in between a connector end portion 21, 22 and a locking clamp 28 (see
Tool assembly 15 provides a support sleeve 25. The support sleeve 25 has sleeve halves 26, 27 (see
Once centralizer ring 29 is threaded upon the external threads 37 of support sleeve 25, a threaded connection 31 is perfected between centralizer ring 29 and support sleeve 25. Grub screw 35 is spring loaded using conical spring 36. After the threaded connection 31 is perfected, the grub screw 35 can be backed out slightly to engage a correspondingly shaped recess or socket 43 on centralizer ring 29 (see
A plurality of magnets 40 are mounted to magnet spacers 41 and magnet internal support sleeve 39. The support sleeve 25 has minimal thickness sections 42 that cover the magnets 40 as shown in
A snap ring 49 is placed in between split slip ring 47 and tensioner sleeve 50. Annular grooves can be provided on the outside surface of split slip ring 47 and on the inside surface of tensioner sleeve 50. In
Each of the slips or slip segments 45 has an inner toothed portion 51 that grips the cylindrical outer surface 24 of cylindrical portion 23 of drill pipe joint 12. A gap 52 is provided in between each of the slip segments 45 (see
Pins 74 attaches to sleeve 66 and to broach or scraper 70 as shown in
A plurality of brush segments 84 are mounted to support sleeve 81 at provided mating grooves 85 (see
In
In
In
The following is a list of Reference Numerals used in the present invention:
The foregoing embodiments are presented by way of example only; the scope of the present invention is to be limited only by the following claims.
This is a continuation of U.S. patent application Ser. No. 16/846,500 (issuing as U.S. Pat. No. 10,961,822 on Mar. 30, 2021), which is a continuation of U.S. patent application Ser. No. 16/259,617, (now U.S. Pat. No. 10,619,454), which is a continuation of U.S. patent application Ser. No. 15/888,287, (now U.S. Pat. No. 10,190,393), which is a continuation of U.S. patent application Ser. No. 15/390,881, filed on Dec. 27, 2016, (now U.S. Pat. No. 9,885,227), which is a continuation of U.S. patent application Ser. No. 14/829,136, filed on Aug. 18, 2015, (now U.S. Pat. No. 9,528,325), which is a continuation of U.S. patent application Ser. No. 13/710,644, filed on Dec. 11, 2012 (now U.S. Pat. No. 9,109,417), which claims benefit of U.S. Provisional Patent Application Ser. No. 61/665,110, filed Jun. 27, 2012, each of which applications/patents are incorporated herein by reference and to/of each of which priority is hereby claimed.
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| Number | Date | Country |
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| WO-9316833 | Sep 1993 | WO |
| Number | Date | Country | |
|---|---|---|---|
| 20210317725 A1 | Oct 2021 | US |
| Number | Date | Country | |
|---|---|---|---|
| 61665110 | Jun 2012 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 16846500 | Apr 2020 | US |
| Child | 17215834 | US | |
| Parent | 16259617 | Jan 2019 | US |
| Child | 16846500 | US | |
| Parent | 15888287 | Feb 2018 | US |
| Child | 16259617 | US | |
| Parent | 15390881 | Dec 2016 | US |
| Child | 15888287 | US | |
| Parent | 14829136 | Aug 2015 | US |
| Child | 15390881 | US | |
| Parent | 13710644 | Dec 2012 | US |
| Child | 14829136 | US |
