The present invention provides methods and an apparatus for treating patients having ulcerations of the lower foot, including patients suffering from diabetic neuropathy. The brace generally includes a pair of rigid shells, a fastening system for joining the shells together to form a unified brace and a combination of bladders which engage the patient""s leg and ankle to off-weight the plantar surface, prevent plantar flexing and minimize shearing forces to the plantar surface. The volume of the bladders may be adjusted by the addition or removal of a filler in order to maintain a uniform pressure between the bladders and the patient""s leg. The filler contained in the bladders preferably does not undergo significant expansion or contraction in response to temperature or altitude changes. The brace also preferably includes a series of full-length bladders and a specially designed adjustable bladder located within the ankle and heel region of the brace to maximize off-weighting and to prevent the foot from moving downward toward the footbed of the brace. In addition to providing an effective means for off-weighting the plantar surface of a patient, the brace is reuseable, easy to apply and fully adjustable to accommodate changes in a patient""s leg size.

The present invention relates to the field of foot treatment and more particularly to the field of treating ulcers on the plantar surface of the foot. The present invention also relates to the field of leg braces. Unlike other devices for treating plantar ulcers, the brace of the present invention is reuseable, adjustable to a variety of leg sizes, easily applied and capable, through the use of a novel system of bladders and other design features, of effectively off-weighting the plantar surface and reducing shearing forces thereto, thereby allowing the ulcers to heal.
The development of effective means for treating foot sores or ulcerations, especially diabetic foot ulcerations, presents a significant medical challenge. Diabetic foot ulcers result in more than 55,000 lower extremity amputations per year (nearly half of all amputations performed in the United States) and account for more hospitalizations than any other single complication of diabetes. Of the 14 million diagnosed diabetics, 15 percent, or 2.1 million, suffer from foot ulcerations. In fact, foot ulcers are the leading cause of hospitalization of patients with diabetes and account for 10 percent of the costs related to diabetic care.
The burdens of such complications can also have a devastating effect on patients and their families. Patients"" quality of life can rapidly decline leaving them unable to work, and dependent on family members to spend their time and resources caring for the patient. Disabilities due to diabetes result in more than $5.6 billion per year in lost wages and earnings.
The problem is compounded by the fact that many diabetics suffer from peripheral neuropathy and thus cannot feel pain. Since pain is often a primary incentive for patient compliance, neuropathy patients frequently do not comply with voluntary off-weighting techniques, resulting in further deterioration of the wound and possibly leading to infection. It is, therefore, crucial that the off-weighting treatment device does not set patients up for failure by allowing them to walk on the wound, thus preventing healing.
The typical cycle for this medical complication is chronic foot ulceration, infection, hospitalization, amputation and rehabilitation. This costly cascade of events need not take place since two-thirds of diabetic amputees do have an adequate blood supply to heal ulcerations. The key factor for effective treatment then is to remove the patient""s weight from the ulcerated site to give the ulcers an opportunity to heal.
Currently, there are several options for off-weighting diabetic foot ulcers to enable them to heal. These options have varying degrees of success depending upon the degree of patient compliance, wound location, and grade of wound. The following is a brief description of the most frequently used therapies for treating diabetic foot ulcers and their advantages and disadvantages.
Prescribing the use of crutches and/or wheelchair use is perhaps one of the simpler treatment methods. However, these options have produced poor clinical results due to lack of patient compliance. Patients with peripheral neuropathy in particular are not motivated to use these devices.
A variety of specially designed sandals and modified shoes have been tried. One sandal, referred to as the temporary healing sandal, provides a cut-out region in the sole to alleviate pressure to the ulcerated site. The problem with this type of sandal is that since the human foot is not flat, when pressure is removed from the area of the ulcer site, there is increased pressure to other metatarsal heads which creates the potential for transfer lesions. A second sandal, the custom sandal, is made from an impression of the patient""s foot. Like the temporary sandal, an area in the sole aligned with the location of the ulcers is cut out to relieve pressure at the ulcerated site. Because the patient""s weight is more evenly distributed as compared to the temporary healing sandal, the likelihood of transfer lesions being formed is reduced. However, this type of sandal provides no relief from shearing forces.
Several devices generically referred to as xe2x80x9cwalkersxe2x80x9d have been designed which are similar to the sandals just described. The DH Walker, for example, is similar in design to the temporary healing sandal. It includes a flat surface upon which the foot rests, but the surface includes plugs which can be removed to accommodate the area of the wound. Not surprisingly given the similarity in design, the DH Walker suffers from the same problem as the temporary sandal in that weight is transferred to adjacent metatarsal heads and the potential for the formation of transfer lesions is great. The sandal also fails to alleviate shearing forces. Another walker called the Cam Walker is essentially equivalent to a DH walker, except that it does not have removable plugs within the device. Consequently, the Cam Walker does not effectively off-weight the wound.
A variety of modified shoes have been tried. Ipos shoes are half shoes that are cut off at the middle of the foot, leaving the forefoot overhanging the cut-off area. Studies have shown that this shoe can be effective, provided the patient is diligent in wearing it. Compliance during the evening, however, is often a problem. Moreover, the Ipos shoe is only applicable to forefoot ulcers and has a high potential for generating transfer lesions.
A different approach involves placing felt directly on the foot and then covering the felt with foam which includes a cut-out region to correspond to the location of the wound. This approach has been shown to be efficacious. However, the method can also cause damage to the skin during the removal process, since the plantar skin can be easily torn.
The Charcot Restraint Orthotic Walker (C.R.O.W.) is a cast manufactured of polypropylene which is effective in the treatment of plantar ulcerations, but only so long as the leg remains the size it was when first casted. Cost is another problem; the average casting cost is $1,200 per cast. In general, C.R.O.W.s have shown limited utility since changes in the patients"" leg reduce the effectiveness at which the foot is off-weighted over time.
All of these methods have proven successful provided they are used on the right patient at the right time, and that patient compliance is not an issue. However, the primary current ambulatory method that ensures off-weighting of the wound is the Total Contact Cast (TCC). The TCC is a cast that is formed using a complicated procedure involving wrapping the patient""s leg in plaster wrap and fiberglass. Although the TCC has the disadvantage of being difficult to apply, it has been shown to be effective in healing up to 90 percent of cases.
Total contact casts relieve the forces that prevent healing by: 1) shortening stride length, 2) decreasing walking velocity (which diminishes vertical forces), 3) eliminating motion at the ankle joint (sagittal plane), 4) eliminating the propulsive phase of gait, 5) redirecting body weight from the foot to the lower leg, and 6) eliminating shearing forces. One study concluded that the effectiveness of the TCC is a consequence of its ability to decrease plantar pressures to nearly imperceptible levels (as low as 0.34 N/cm2) and to essentially eliminate motion in the cast, thus substantially curtailing shearing forces (Todd, W. F., et al. Wound/Ostomy Management, 41: 48-49, 1995).
Yet, despite its efficacy when used properly, numerous difficulties have resulted in significantly lower TCC usage than might be expected. First, application of the total contact cast is a complex, 15-step process requiring a high degree of skill and approximately one hour of time to complete. Improper application can also have significant negative consequences. For example, casts applied over an active infection raise the potential for loss of the infected leg, improper application of the cast can create new ulcerations, and the failure to remove wrinkles in the stocking inside the cast may irritate the patient""s skin.
Secondly, the TCC cannot accommodate the changes in patient leg size which frequently occur due to decreased edema and atrophy of the muscle. Typically, the patient must be reexamined three days after the initial casting to check for decreases in leg volume that could allow the leg to xe2x80x9cpistonxe2x80x9d (slide) within the cast. Pistoning requires immediate recasting. Casts that consistently piston call for weekly recasting. Even casts that do not piston must still be changed at least every two weeks. Patients with large wounds may require recasting twice per week. Patients must be vigilant for abnormalities which require an immediate cast change. Thus, the complexity of the casting process is compounded by the frequent need for a recasting and the high cost of multiple applications.
Finally, cast removal is also difficult, and improper removal can have adverse consequences. For example, because there is little or no interior padding in the TCC, utilizing a saw to remove the cast without cutting, abrading or burning the patient requires significant practice. Incorrect technique can result in lacerations to the patient""s leg.
For the foregoing reasons, many physicians have opted to use other methods for treating plantar ulcers. Moreover, even if physicians could be properly trained on a widespread scale to apply and remove the TCC, it is doubtful that use of the TCC would increase significantly since many practitioners find that such time-consuming and labor intensive procedures are not profitable.
While the TCC and the other devices listed above have been specifically designed to address the need to treat patients suffering plantar ulcers, it should also be noted that a number of related adjustable leg casts have also been developed. These casts have significant advantages since they are adjustable and reuseable. These casts, however, differ from the TCC and the brace of the present invention in that the casts are designed primarily for fracture care rather than for treating plantar ulcers.
One example of such a cast is described in U.S. Pat. Nos. 3,580,248 and 3,701,349 to Larson. The cast includes two rigid, plastic shells, each containing an inflatable air bag disposed therein. These air bags run essentially the full length of the cast and fully surround the leg. Once a patient""s leg is inserted into cast and the two halves fastened together, air can be used to inflate the bags to create a pressure against the leg for immobilizing the fractured limb.
A second example of such a cast includes the one described in U.S. Pat. No. 3,955,565 to Johnson, Jr. This cast is quite similar in construction to that described in the Larson patents and is also designed to treat fractures. However, the shells in the Johnson cast have sufficient flexibility so that the edges of one shell can be flexed to fit over the edges of the other shell. This enables the two shells to be radially adjusted with respect to each other to increase and decrease the size of the cast interior, thereby allowing the cast to accommodate a variety of leg sizes. Like the Larson cast, the Johnson cast includes air bags in both shell halves. Unlike the Larson cast, inflated air bags need not fully surround the leg; rather there are sections in which the shell and a portion of the leg are in indirect abutting relationship, the shell and leg only being separated by an uninflated portion of the air bag.
Because these casts are designed primarily for fracture care, they function quite differently than the brace of the current invention. As casts, these devices are designed primarily to immobilize an area surrounding the fracture; in particular, the casts are designed primarily to prevent flexing of the fracture. The device of the current invention, however, is not a cast but a brace. It is designed not to simply prevent a bone from flexing, but acts to redirect or redistribute a patient""s weight throughout the brace itself rather than the patient""s foot. More specifically, the brace of the present invention accomplishes the more difficult goals of effectively off-weighting the plantar surface of a patient""s foot, immobilizing the patient""s ankle to prevent plantar flexing and significantly reducing shearing forces at the plantar surface. Existing casts do not appear to effectively achieve all of these results.
Thus, in view of the limitations of the current devices specifically designed for treating plantar ulcers, as well as casts designed for fracture care, there is a need for a device which is equally effective as the TCC in treating patients suffering from plantar ulcerations but without its associated limitations. In particular, there is a need for a brace which off-weights the plantar surface and prevents flexing of the foot within the brace in order to minimize the shearing forces on the ulcerated sites and promote rapid healing. Unlike the TCC, however, the brace should be easily applied and removed, reuseable and adjustable.
The brace of the present invention satisfies the need identified above. Unlike current adjustable casts which only restrict the fractured limb from flexing, the brace of the current invention satisfies the key requirements for effective treatment of plantar ulcerations: 1) the brace off-weights the plantar surface, i.e., the brace redistributes a patient""s weight throughout the brace so that there is little or no direct pressure of the plantar surface against the footbed of the brace, 2) the brace restricts downward movement of the foot toward the footbed about the ankle joint, i.e., the brace restricts plantar flexing and 3) the brace significantly reduces shearing forces at the plantar surface. To achieve these goals, the brace of the present invention involves a novel design including a complementary pair of rigid shells and a unique combination of adjustable bladders, as well as cushions which need not be adjustable. Unlike existing casts, the brace of the current invention includes a combination of full-length and ankle bladders to effectively immobilize the leg within the cast and to prevent plantar flexing about the ankle joint. Furthermore, whereas other adjustable casts use air to inflate the bladders, the brace of the current invention preferably utilizes special fillers which have a thermal coefficient of expansion which is less than that of air. This ensures that there is consistent pressure against the leg and avoids the discomfort and the potential of the leg pistoning within the brace which can occur when air within the bladders expands or contracts with changes in temperature or altitude.
The brace of the present invention includes a number of additional benefits and avoids the inherent problems associated with the application and removal of the TCC. For example, the brace of the present invention ensures consistency of care between specialists (vascular surgeons, plastic surgeons, orthopedic surgeons, podiatrists, physical therapists and ET nurses) because only minimal practitioner intervention is required during the treatment period. Further, the brace is removable, easily modified to conform to changes in leg size as swelling decreases, restricts motion at the ankle joint, eliminates the propulsive phase of gait and shearing forces, and is easily applied and removed from the patient. Because the brace is highly effective in off-weighting the plantar surface, the brace is especially useful in treating the plantar ulcers of neuropathy patients that are incapable of recognizing and communicating physical discomfort in the foot and leg.
The brace of the present invention generally comprises: (a) a pair of rigid shells which are adapted to receive the lower portion of a patient""s leg, (b) a fastening system which joins the first and second shell and immobilizes the shells around the patient""s leg, (c) and at least one adjustable bladder disposed within the first or second shell which is capable of engaging the brace against the patient""s leg such that the patient""s leg does not move within the brace and the plantar surface is off-weighted. The brace also significantly reduces plantar flexing and shearing forces at the plantar surface.
More specifically, the shells of the brace include a first and second shell which are generally L-shaped. These shells have a generally semi-cylindrical cross-sectional configuration and are adapted for receiving a lower leg and a foot of a patient suffering from plantar ulcerations. Both shells including a vertical and horizontal section. The vertical section of the first shell has sufficient length to extend from a the patient""s calf to a location beneath the heel portion of the patient""s foot. Hence, the vertical section of the first shell includes a calf section and an ankle section which are adapted to receive the patient""s calf and ankle, respectively. The horizontal section of the first shell extends outwardly at substantially a right angle to the vertical section of the first shell and has sufficient length to receive at least a majority of the patient""s foot and preferably extends the length of the patient""s foot. In like manner, the vertical section of the second shell has sufficient longitudinal dimension to extend from the patient""s shin to the instep. The horizontal section of the second shell extends outwardly from the vertical section of the second shell at substantially a right angle and has sufficient length to cover at least a majority of the top of the patient""s foot and preferably covers the entire length of the top of the patient""s foot.
The brace also preferably includes a first adjustable bladder positioned in the first shell and a second bladder or cushion which is positioned in the second shell. At least the first bladder is adjustable, i.e., filler material can be injected or withdrawn in order to maintain a relatively constant desired pressure of the brace bladder against the leg. The ability to adjust the interior volume of the brace using the adjustable bladder(s) allows the brace to accommodate a variety of leg sizes and means the size of the bladders can be altered in accordance with changes in altitude or with changes in the patient""s leg size resulting from edema or atrophy. These bladders preferably contain a filler which undergoes only minimal expansion or contraction with changes in altitude or with temperature changes within the brace which arise due to fluctuations in ambient temperature and/or changes in patient activity. The filler should have a lower thermal coefficient of expansion than air. Especially preferred fillers include those which are substantially non-compressible such as non-compressible silicone. Other potential fillers include injectible polyurethane foam, silicone wax liquid composites and compressible silicone liquid. Although it is used nearly exclusively in existing inflatable casts, air is not a preferred filler given its tendency to expand and contract with changes in temperature and altitude.
In a preferred embodiment, the brace also includes a third bladder. The volume of this bladder is preferably adjustable and the third bladder is positioned in the ankle region of the first shell. The third bladder also preferably has a structure in which two wings are located on opposing sides of a central region which is connected to the interior of the first shell. These wings can be wrapped around the patient""s ankle region, including the sides of the patient""s ankle. The third bladder is important in effectively immobilizing the patient""s ankle and preventing plantar flexing.
A fastening system attached to the shells immobilizes the first and second shell around the patient""s leg to form a unified brace. The fastening system can include a variety of systems but typically includes some type of strap which is anchored to one side of the first shell, passes over the second shell and is connected to the other side of the first shell. Thus, belts made of hook and loop type material (e.g., material sold under the trademark VELCRO) can be used. Various buckle systems can also be employed, including systems comprising serrated straps which connect to a cam mechanism. A locking mechanism can be added to prevent patients or other unauthorized personnel from opening the brace before the treatment program has been completed.
A layer of absorbent material can optionally be attached to the bladders to form a layer between the inserted leg and the bladders. This absorbent layer wicks away moisture from the patient to increase overall comfort and to minimize allergic reactions for patients with sensitive skin.
A cushion is attached to the footbed of the first shell. The cushion is made of materials which mold to the bottom of the foot such as low density foam or silicone. Although there is only minimal pressure on the bottom of a patient""s foot, the cushion is designed to enhance the patient""s comfort and to minimize shearing forces and friction.
A pressure sensor or transducer can be positioned between a bladder and the interior surface of the shell to enable clinicians to easily and accurately monitor the pressure of the bladders against the patient""s leg. Proper pressure levels are important to ensure that there is adequate pressure to prevent movement of the leg within the brace; yet, the pressure cannot be unduly excessive such that blood circulation through the leg is compromised. Pressure can also be monitored by measuring back pressure at the inlet valve for the bladder and then using a previously determined relationship between back pressure at the valve to pressures on the leg to calculate leg pressure.
The present invention also includes a method for treating patients suffering from ulcerations on the plantar surface utilizing the brace of the present invention. The method generally comprises: (a) inserting a patient""s leg between a set of first and second shells which are adapted to receive the lower leg and foot of a patient, (b) positioning at least one adjustable bladder so that it is sandwiched between the first or second shell and the patient""s leg, (c) fastening the shells together using a fastening system to form a unified brace; and (d) adjusting the volume of the adjustable bladder(s) to engage the brace against the patient""s leg so that the patient""s leg does not move within the brace and the patient""s plantar surface is off-weighted.
More specifically, the method preferably includes placing the patient""s leg within the first shell and arranging the first bladder (and third bladder, if present) to surround the calf and ankle region of the leg. Care is taken to avoid direct contact between the ulcerated portion of the foot and the footbed of the first shell. The second shell is placed over the front of the patient""s leg and the bladder disposed within the second shell arranged to cover the shin and instep portion of the patient""s leg. The two shells are then fastened together using the fastening system to form a unified brace around the patient""s leg. Filler material is then added into the adjustable bladders to create a desired uniform pressure around the circumference of the leg. This uniform pressure redistributes the patient""s weight throughout the brace and off-weights the plantar surface. The pressure also immobilizes the ankle to prevent plantar flexing.

Methods and apparatus for treating plantar ulcerations


Methods and apparati are disclosed for continuous circulation of drilling fluids while adding or removing tubulars to and from a drill string, and also for continuing drilling during the addition or removal of tubulars to and from the drill string.

The present invention relates to a method for drilling wells, particularly drilling for hydrocarbons.
In drilling wells for hydrocarbons, particularly petroleum, the drill string is rotated to drive the drill bit and mud is circulated to cool lubricate and remove the rock bits formed by the drilling.
As the drill penetrates into the earth, m ore tubular drill stems are added to the drill string. This involves stopping the drilling whilst the tubulars are added. The process is reversed when the drill string is removed e.g. to replace the drilling bit. This interruption of drilling means that the circulation of the mud stops and has to be re-started on recommencement of the drilling which, as well as being time consuming is and expensive, can also lead to deleterious effects on the walls of th e well being drilled and can lead to problems in keeping the well xe2x80x98openxe2x80x99.
A method for continuous rotation of the drill bit whilst adding or removing tubulars is described in patent Application PCT 97/02815.
In this application there is provided a method for drilling wells in which a drill bit is rotated at the end of a drill string comprising tubular members joined together and mud is circulated through the tubular drill string, in which method tubular members are added to or removed from the drill string whilst the circulation of mud continues.
The method provides for supplying mud, at the appropriate pressure in the immediate vicinity of the tubular connection that is about to be broken such that the flow of mud so provided overlaps with flow of mud from the top drive, as the tubular separates from the drill string the flow of mud to the separated tubular is stopped e.g. by the action of a blind ram or other preventer or other closing device such as a gate valve.
The separated tubular can then be flushed out e.g. with air or water (if under water) depressured, withdrawn, disconnected from the top drive and removed. The action of the preventer is to divide the tubular connection into two parts e.g. by dividing the pressure chamber of the connector connecting the tubular to the drill string. The drill string continues to be circulated with mud at the required pressure.
In a preferred embodiment of the invention a tubular can be added using a clamping means which comprises a coupler, and the top end of the drill string is enclosed in and gripped by the lower section of the coupler, in which coupler there is a blind preventer which separates the upper and lower sections of the coupler, the tubular is then added to the upper section of the coupler and is sealed by an annular preventer and the blind preventer is opened and the lower end of the tubular and upper end of the drill string joined together.
In use, the lower section of the coupler below the blind preventer will already enclose the upper end of the drill string before the tubular is lowered and when the tubular is lowered into the coupler the upper section of the coupler above the blind preventer will enclose the lower end of the tubular.
The tubular can be added to the drill string by attaching the lower section of the coupler to the top of the rotating drill string with the blind preventer in the closed position preventing escape of mud or drilling fluid. The tubular is lowered from substantially vertically above into the upper section of the coupler and the rotating tubular is then sealed in by a seal so that all the drilling fluid is contained, the blind preventer is then opened and the tubular and the drill stand brought into contact and joined together with the grips bringing the tubular and drill string to the correct torque.
The lower end of the tubular and the upper end of the drill string are separated by the blind preventer such that the tubular stand can be sealed in by an upper annular preventer so that when the blind preventer is opened there is substantially no escape of mud or drilling fluid and the tubular stand and drill string can then be brought together and made up to the required torque.
To remove another tubular from the drill string the tubular spool or saver sub under the top drive penetrates the upper part of the pressure chamber, is flushed out with mud and pressured up; the blind ram opens allowing the top drive to provide circulating mud and the spool to connect to and to torque up the into the drill string. The pressure vessel can then be depressured, flushed with air (or water if under water) and the drill string raised until the next join is within the pressure chamber, the xe2x80x98slips and gripsxe2x80x99 ram closed, the pressure chamber flushed with mud and pressured up and the cycle repeated.
Preferably the coupler includes rotating slips which support the drill string while the top drive is raised up to accept and connect another tubular.
The coupler may be a static coupler connected to and above the wellhead BOP stack with a top-drive or mobile coupler handling the tubulars above the static coupler working hand-to-hand.
The coupler may be a mobile coupler disconnected from the wellhead BOP stack with a top-drive or second mobile coupler handling the tubulars above it working hand-to-hand and thereby allowing the string to move steadily in the vertical plane when tripping is in progress or allowing drilling to continue while a tubular stand is being added.
The coupler may be a mobile coupler disconnected from the wellhead BOP stack with one or more identical mobile couplers, above, which take it in turns to become the bottom coupler thereby working hand-over-hand and also facilitating steady movement of the string when tripping is in progress or drilling is continuing while a tubular is being added to the string.
The method disclosed in Patent Application PCT/GB97/02815 locates the grips and slips either inside or outside the coupler pressure hull.
I have now devised an improved structure and method of continuous drilling.
According to the invention there is provided a well head assembly which comprises a BOP stack above which there are positioned sequentially:
(i) a lower annular preventer
(ii) lower grips and slips adapted to engage a downhole drill string
(iii) a blind preventer
(iv) upper grips and slips adapted to engage a tubular to be added to the drill string and
(v) an upper annular preventer
in which the upper grips and slips are able to pass through the blind preventer when the blind preventer is in the open position.
This is illustrated in FIG. 1 of the accompanying drawings and the sequence of operation of adding a tubular to the string is illustrated in FIG. 2.
The grips are the means of gripping the tubulars strongly enough to transfer a rotational force or torque, by friction surfaces shaped to fit the external surface of the tool joint, or the shaft of the tubular, or by powered rollers, both methods of which are common in conventional iron roughnecks.
The slips are the means of applying an axial force to the tubular to prevent it slipping, by wedge action and or by obstructing the passage of the upset of the tool joint, as is common in conventional slips.
The grips and slips combine the functions of gripping and slipping either by modifying the profile of the friction pads, rollers or slips or by integrating the separate grips and slips to operate in concert.
The orientation of the well head assembly refers to the well head assembly when in position on a drill string.
The gripping mechanism with or without integrated slips may be achieved by simply altering the materials and profile of the inserts of the conventional Rotary BOP, Diverter, Preventer, or Rotating Control Head. Alternatively the gripping may be achieved by conventional methods of wedge, lever, motorised rollers screw or other mechanical means caused by hydraulic, electrical or mechanical means such as is currently applied within collett connectors, casing tongs rotary power slips or current iron roughnecks.
In use, the invention enables a tubular to be added to a drill string when a drill string is rotating and drilling mud is flowing. The lower grips and slips grip support and rotate the drill string, the circulation of tubular string continues uninterrupted and over or under balanced pressure in well bore and annulus is maintained continuously.
The upper preventer is open and the new tubular is positioned on the blind preventer, preferably there being a locating means so that the tubular is correctly positioned above the drill string e.g. by landing the tubular on a raised star on the blind preventer, i.e. the tubular is xe2x80x9czero indexedxe2x80x9d.
The upper preventer and upper grips and slips are then shut and the new tubular can have air (or water if the drilling is taking place underwater) replaced by the appropriate drilling fluid.
The blind preventer is then opened and the circulation (or reverse circulation) of tubular string continued uninterrupted from two overlapping sources and over or under balanced pressure in well bore and annulus is maintained continuously.
The new tubular is then brought into contact with the drill string by passing through the blind preventer and is controlled by the upper slips and grips and, when the tubular is in contact with the drill string, the new tubular turns faster than the drill string so that the new tubular is xe2x80x9ctorqued upxe2x80x9d by the upper grips and slips acting against the lower grips and slips, whilst both continue to rotate and the new tubular is screwed to the top of the drill string.
Preferably the new tubular is not rotating as fast as the string when it first makes contact with the string such that the jumping of the threads can be xe2x80x98feltxe2x80x99 and the acceleration of the rotation of the tubular can be initiated immediately after a jump is felt thus eliminating any possibility of cross threading due to lack of alignment or synchronisation.
The upper annular preventer and grips and slips are opened and the drill string lowered and the process can be repeated. To remove a tubular the sequence is reversed.
It is a feature of the method of PCT/GB97/02815 that either or both of the upper and lower grips and slips can be located inside or outside the pressure hull of the Coupler and that, if outside, then the function of the upper grips and slips may be carried out by a top drive and the function of the lower grips and slips may be carried out by a rotary power table and this is shown diagrammatically in FIG. 3.
The upper grips and slips, if outside the Coupler pressure hull can be a top driveor the upper section of an iron rougneck, (but with limited ability to snub a tubular against an internal pressure) or manual roughnecking (with no ability to snub against an internal pressure).
The lower Grips and Slips, if outside the pressure hull,-can be a powered rotary slips, capable of supporting a tubular string, or the lower section of an iron roughneck with limited ability to support the weight of a tubular string, or a bottom drive of an unconventional type like the pipe gripping tracks used in offshore pipelaying.
The Upper and Lower Grips and Slips, if inside the Coupler pressure hull, can be rotary slips of the type developed by Varco BJ or the gripping components of a conventional an iron roughneck, modified to support the weight of the tubular string and to rotate and torque the upper and lower boxes of the tool joint by differential gearing, thus allowing both boxes to continue rotating as they are connected or disconnected.
The Upper and Lower Grips and Slips, if inside the Coupler pressure hull can be above or below the blind preventer or pass through it when it is open. The preferred solution is to support the string with grips and slips, mounted in a large bearing in the lower section of the Coupler pressure hull and to grasp the tubular with upper grips and slips in the upper section, while it is filling with mud, and then move the tubular down through the open blind ram to make the connection.
The required snubbing force, against maximum internal mud pressure is much higher than is possible by pushing the tubular into the wellhead using external forces. By using the pair of grips and slips in close proximity, the force lines are short and are contained within the massive body of the pressure hull. To enable the threads to be engaged without undue force, the vertical motion of the upper grips and slips is pressure balanced within the pressure hull.
It is the preferred solution to have both the upper and lower grips and slips located inside the pressure hull of the Coupler for several reasons, which include the following: (a) The gripping to takes place on the thicker wall of the tool joint box with its rougher surface and larger diameter, (b) The scaling takes place on the smoother surface and smaller diameter of the tubular shaft (c) The slips act positively on the upset shoulder of the box, (d) the path of the force lines is minimised, (e) The accuracy of the mating is maximised.
Concerning the making and breaking of tool joint connections under high pressure, even up to full pressure rating of the preventers, the possibility of xe2x80x9csnubbingxe2x80x9d tubulars into the well-head is practically impossible. Even for quite moderate pressures special handling equipment is necessary to snub tubulars into a pressured well head.
This invention, however, allows snubbing to take place by xe2x80x98pullingxe2x80x99 the two halves of the tool joint together within the Coupler instead of, as is currently the practice, pushing the tubular with external rigging. This invention allows tubulars to be added to the string even at the full pressure rating of the BOP stack.
To achieve accurate and controlled making and breaking of tool joints when subjected to high mud pressures, the two halves of the tool joint may be moved together, or apart, with minimum force, by pressure balancing the axial motion of the upper grips and slips as shown in FIGS. 1 and 2 which is the preferred basic coupler solution.
Additionally, as the two grips and slips are so close together and within a massive body, the torquing of the one against the other is simplified.
In the Basic Coupler, the grips and slips do no more than a conventional iron roughneck achieves but it is carried out under the pressure of the inlet mud during normal mud circulation. This is to hold the string still, while screwing in the tubular and then torquing up the connection to as much as 70,000 ft lbs. This invention enables this to be done under pressure inside the Coupler up to the full discharge pressure of the mud pumps or the pressure rating of the preventers, whichever is the lower.
This Basic Coupler enables mud circulation to continue uninterrupted while adding, or removing tubulars, which achieves most of the advantages of the new drilling method, such as steady ECD (Equivalent Circulating Density), good formation treatment and avoidance of stuck bits and BHAs.
The Basic Coupler can be assembled from proven iron roughneck and ram preventer components and requires little development. It is suitable for retrofitting onto most of the existing Rigs that employ Kelly Drilling. The Basic Coupler has to be located beneath the rotary table in order that the Kelly bushing does not have to pass through the Coupler. The Basic coupler therefore has to be designed to support the weight of the string during tool joint connections and disconnections. As such the sequence of Coupler Operations is as shown in FIG. 4.
In the Rotary Coupler, the two sets of grips and slips both rotate while connecting and disconnecting so that the string can continue rotating. The screwing and torquing of the tool is achieved by differential gearing which ensures that the torquing of the connection is independent of the torque required to rotate the string.
This Rotary Coupler enables mud circulation and string rotation to continue uninterrupted while tubulars are added or removed from the string, which achieves almost all of the benefits listed below.
The Rotary Coupler can be assembled from well proven iron roughneck, rotary power slips and rotary BOP components with a moderate amount of engineering development. It is suitable for retrofitting on most of the existing rigs that utilise Top Drive Drilling. As such the sequence of Coupler operations is as shown in FIG. 6. The possibility of integrating the coupler with the BOP stack reduces the overall height still further as shown in FIG. 7.
In the case of Kelly Drilling, when connecting or disconnecting the Kelly to or from the string, the Kelly Saver Sub provides the gripping surface for the grips to grasp, an upset shoulder for the slips to act on and a smooth shaft for the preventer to seal on.
In Kelly drilling the drilling itself has to stop while a new tubular is added to the string because the Kelly has to be retrieved from the hole, which raises the bit off the bottom by some 30 ft or more and, as such, it matters less that string rotation is not continuous. The majority of the benefits are still gained by the continuous mud circulation as already stated.
However it is possible, with this invention, to relocate the rotary table 30 ft higher so that the bottom of the Kelly reaches the Coupler when it is time to add another tubular the string. By this method the bit can remain on the bottom while adding a new tubular to the string. This would normally invite problems but continuous mud circulation avoids the settling of cuttings and debris around the bit and BHA. This is shown in FIG. 5.
So, provided that a bumper sub (or thruster) is included above the drill collar section, drilling can continue, provided that the bit can rotate. If a Basic Coupler is used then continuous bit rotation requires a mud motor utilising the continuous mud circulation now available. If the bit is rotated by the string then a Rotary Coupler can be used to maintain string rotation. Either way, and, subject to relocating the rotary table and/or Kelly bushing rotating system, drilling on most rigs, which employ Kellys, can now be continuous, with or continuous string rotation.
In Top Drive Drilling, the Basic Coupler similarly enables continuity of mud circulation and drilling provided that a mud motor is used. If no mud motor is used continuous drilling is possible if a Rotary Coupler is used. In either case little modification is required to install a Coupler on a rig using Top Drive Drilling.
In Top Drive Drilling, there is the alternative shown in FIG. 8 where the Coupler is mounted on a short hoist to follow the drill bit down during connections and eliminate the need for a bumpersub. Whereas this is a heavy mechanical feat, it eliminates the problem that bumpersubs wear out quickly and that the bit weight, during connections, has to be pre-set.
The invention has the advantage that the rotation of the tubing and circulation of fluids can be continuous, over or underbalanced pressure can be maintained continuously and over or underbalanced drilling is possible without interruption, the tubing string bore is never open to the environment and the method is easier than existing methods to automate. The method can also eliminate the need for heavily weighted muds and the exposed well bore is less likely to collapse. The ease of transition from Drilling Coupler to casing Coupler eliminates the need to employ damaging kill fluids between drilling and casing.
Future drive systems are anticipated where the drive will be xe2x80x98Bottom Drivexe2x80x99 probably by the type of pipe tensioning tracks that are used in offshore pipe laying, where very high axial tensions are transmitted to the pipe. If such a mechanism were to be rotated then the Sequence using a Coupler would be as illustrated in FIG. 9.
Total elimination of Top Drive and Bottom Drive Systems would be possible with a Coupler and a Rotary Table both mounted on long hoists one above the other as shown in FIG. 10 This requires a considerable vertical travel but no more than is used conventionally to stack stands of doubles and triples. The benefit of this system is that tripping can be carried out in a smooth steady operation, which benefits the downhole hydraulics, accelerating slowly to a velocity that is very much higher than is currently possible and an overall duration that is far shorter. Again, minimising damage to the exposed formation will usually be more valuable than the time saved. Continuous tripping can achieve the time saving without damaging the exposed formation.
The longer term future application of the Coupler as anticipated and described in PCT/GB97/02815 is as a Coupler that splits vertically and of which two can work hand-over-hand as in FIG. 11. Such Couplers will benefit from xe2x80x98weight engineeringxe2x80x99 to reduce their mass and clever engineering design for the closing and latching mechanisms but they offer the best opportunity to simplify the total rig design and achieve the fastest tripping times. They can flexibly handle singles, doubles or triples or varying lengths of tubular assemblies including BHAs with large diameter components such as centralisers and under reamers and can be interchangeable and even operate hand-over-hand in threes. They eliminate all other drives, drawworks and swivels and could be mounted on the ground without any rig structure. However they are likely to be mounted on hydraulic masts.
Both the Basic and Rotary Drilling Couplers can handle a range of tubular diameters From below 4 inches to about 7 inches. It is intended that two or more casing couplers will handle a range of casing diameters from about 9 inches to 20 inches or more including stab, twist and squnch joints.
All Couplers require the preventers to actuate far faster than is normal, which can be achieved by adding a secondary low pressure/high flow hydraulic system connected with high pressure valves that can only open under a low pressure differential. Thus the past motion actuation is achieved by the low pressure/high flow system and the high closing force is achieved by the high pressure/low flow system.
All Couplers require a compliant landing surface on the top of the Blind Ram blade, such that the impact of the pin of the tubular on the blade is absorbed without damage to pin or blade and that the landing surface is star shaped so that the tubular can be easily flushed out with mud, or air, or water while still in contact with the blade.
The casing Coupler is of significant value in Underbalanced Drilling since it is possible to leave the well, prior to casing it, in a steady and controlled pressure regime without having to introduce weighted mud to kill the well, which usually damages the exposed formation, which is to produce later.
All Couplers require xe2x80x9cdopingxe2x80x9d of the threads prior to connection and this may be achieved by one or more high pressure mud jets set in the Coupler body impinging on the rotating pin and box immediately before coupling.
The mud is required to be free of particulates or fines above a given screen mesh size and heavy weighting material is unlikely to be required when drilling with Couplers. In the event that significantly sized particulates cannot be economically filtered out, fresh mud can be specially piped under high pressure to the said jets for activation briefly as the pin and box come together.
All Couplers assist in centralising and aligning the tubular and string axially and the stand off distance of the pin from the box is set by zeroing the pin against the blind ram blade. However, variations in the height of the box from the upset shoulder to the top surface of the box will not matter since the tubular is inserted with only enough force to seat the threads without damaging them and the acoustic or mechanical signal of the jumping of the threads is the signal to proceed with screwing up, as explained before.
Although the Coupler is able to centralise the tubular and string onto the centre line of the Coupler within reasonable accuracy as does a conventional roughneck; the centre line of the pin thread may be eccentric to its tool joint and the box thread likewise. Additionally the tubular and string may not be completely aligned axially. The initial landing of the pin threads on the box threads may therefore often cause high point loading between threads, which is the common situation with conventional drilling with Kellies or with Top Drives which often damages the threads.
It is intended in this invention that the Tubular and String are brought together in a more controlled method which will avoid the possibility of damaging the threads of either the pin or the box.
This is firstly achieved by using the upper grips and slips to insert the pin into the box in a pressure balanced situation where the force necessary to move the tubular downwards is minimal. Additionally hydraulic oil pressure as shown in FIG. 1 compensates for various different tubular diameters, which would otherwise upset the predetermined pressure balancing ratio.
As referred to elsewhere, the method of orientating the tubular relative to the string can be achieved by an anticlockwise rotation of the pin relative to the box until the threads jump, which can be detected mechanically of acoustically after which the pin and box can be made up. In the Basic Coupler, the String is static and the tubular is rotated anticlockwise to reach the jump point. In the Rotary Coupler, the string is rotating so the tubular is static until the jump point is found. By making up the connection from a small rotation anticlockwise from the jump point, any possibility of cross threading is minimised.
However, this does not avoid the high stresses possible when initially landing the pin in the box and it is the intention with this Coupler to take advantage of the more automated process and improve control of this particular activity of landing the pin in the box. In this invention it is planned to ensure that the Tubular and String are relatively orientated in azimuth, such that the tapered threads of the pin and box avoid the situation where they collide with too little overlap of threads to absorb the shock without plastic deformation.
The insufficient overlap of threads can either occur on the landing surface as shown in FIG. 13a, or it can occur due to impact with the thread above, particularly if the pin and box are not concentric, as shown in FIG. 13b. FIG. 13c indicates the range of safe operation to avoid either of the above damaging situations.
It is estimated that just being in the preferred half of a rotation would very greatly reduce the thread damage that is currently experienced. To pick on the best relative orientation will almost eliminate such damage. The specific best orientation will vary with thread design but all tapered threaded connections will benefit from this method.
The marking of the pins and boxes to identify the best relative orientation can be carried out using a matching master pin and box and marking up the tubulars on site regardless of their source of supply.
The actual marking cannot be visible since the string may be totally enclosed and must be picked up mechanically or electrically. The simplest method being to produce a structural change on the shaft of the tubular, within inches of the upset shoulder between the surfaces acted upon by the slips and the RBOP seal. This structural change (bump, weld, or signal emitter, etc) can then be detected (for example, mechanically, acoustically, electrically or radiographically) and the upper grips and slips can orientate the tubular accordingly. By this method the finding of the jump point, which is how threads are usually orientated manually, is not necessary. By this method of marking the best relative orientation for the optimum landing of pin in box is achieved, which is facilitated by this mechanised approach to Coupling. The combination of the Coupler""s internal design and the improved method of physically inserting the pin in the box, should provide much faster coupling, plus improved repeatability and reliability and therefore reduced cost and improved safety.
In offshore drilling in particular, by using the couplers, the number of casing strings may be reduced and/or the reach of the drilling vertically and horizontally may be increased significantly.
In deep water drilling, where conventional drilling is very costly, the use of such couplers, which isolate the tubular string from the marine environment may be used to great advantage in xe2x80x9cRiserless Drillingxe2x80x9d which is currently under development.
In very deep water, where drilling is currently uneconomic, the application of these couplers on drilling rigs of the future which will be located on the sea bed, will be of great value.
Concerning the routine change out of the Rotating BOPs, it is preferred that the BOP stack itself is mounted above a diverter so that the BOP stack RBOP may be changed out without opening the well bore to the environment. As has been explained this RBOP is intended, according to the invention, to be operated at lower differential pressure, low sealing force and wet on both sides so that the rate of wear is greatly reduced. Additionally it may reduce its sealing force as a tool joint passes through whenever the RBOP above it is closed, thus increasing the life of the stack RBOP seal. Preferably the wellhead drilling assembly consists of a near standard BOP stack, including a stack RBOP, on top of which is connected a coupler consisting of the lower RBOP, a lower slips and grips unit, a blind ram or diverter and an upper slips and grips unit above this is connected the upper RBOP.
Hence the upper RBOP can be most easily changed out with the string supported in the lower slips and grips and sealed of by the blind ram. The lower RBOP can also be changed out without difficulty, but this may only be required once during the drilling of a well and can be done when a bit or bottom hole assembly has to be inserted into the well or changed out. The upper slips and grips of the coupler will have the ability to move vertically in order to connect or disconnect a tubular to or from the tubular string. The upper RBOP can optionally be a double RBOP in order to have a back up seal and the ability to test the lower seal for excessive leakage.
Since in drilling rig couplers both RBOP assemblies are required to work primarily on drill pipe, it is economic to design the operation such that it is not required for them to pass the larger diameters of tubular components such as drill collars, bits and reamers. Hence provision is preferred for the insertion and removal of such larger diameter components without passing through the coupler.
It is preferred therefore that when inserting or removing, large diameter components, the drilling coupler be removed. To do this without connecting the well bore down the well to the environment above ground or mud line, requires that a through bore valve or diverter is placed in the well at depth below ground level or mud line that allows a complete bit or down hole assembly to be installed, inserted or contained in the well above it. This will be required at an early stage but usually not before the 20 inch casing has been installed and it could be that the, so called, down hole diverter can be of the same bore as the largest BOP to be used during the drilling, maybe 13xe2x85x9c in. If, because of the pressure rating perhaps, the diverter cannot fit within the 20 inch casing then the 20 inch casing may have to be hung off, latched and locked at the level of the diverter with the next casing up, perhaps 24 in, sized at the full well pressure rating from the diverter level to the wellhead.
The diverter used in this application can have inserts installed to match the casing program such that, as each casing is installed the diverter internal diameter is reduced and the diverter can shut in the well at various sizes, e.g. from 13xe2x85x9c in down to production tubing size.
It is only required that the diverter operates down to the internal diameter of the drilling coupler. Such a diverter has been disclosed.
The down hole diverter allows the lower RBOP and stack RBOP to be changed out without opening the well to the environment and without having to operate one of the BOP stack rams. The down hole diverter allows the BOP stack to be changed out and the well to be completed with a production tree, without opening the well to the environment and hence there is never a need to circulate kill fluid into the well to hold it in.
Concerning safety, the down hole diverter, set as much as 300 ft or so down the well also provides an extra barrier to the down hole safety valve (DHSV) and is similarly a convenient cut off location, clear of seabed sloughing, iceberg scour, beam trawling and, on land, earthquakes, storm damage and the like and sabotage.
Concerning the installation of casings; once one is approaching likely hydrocarbon horizons with, for example a 20 in casing already installed and a 13xe2x85x9c BOP stack in place, then, when withdrawing the drill string while continuously circulating and rotating as described earlier, the string is removed until only the bit assembly is still within the well, at this point the circulation can be stopped and the diverter closed below the bit. The string is gripped or hung off within the BOP stack and the two RBOP assemblies removed. The bit assembly is then removed from the well and the running of the casing commences.
Before running the casing, instead of the drilling coupler a single large diameter drilling coupler is installed above the BOP stack to allow each casing to be connected to the casing string without opening the well to the environment. This drilling coupler consists of an annular RBOP with, on top of it, a lower casing slip and grips, a blind ran, an upper casing slips and grips and an upper RBOP. Each stand of casing has a casing head allowing the circulation of fluid down the well and the returning fluid is contained by the stack RBOP and flows to the mud processing unit which is itself totally enclosed (as are most processing plants). The casing is installed and connected the same way as the drill pipe but the need for high torque is absent and many variations to the method of connection such as stab and squnch can be handled by the casing Connector.
The stability of the uncased hole still benefits greatly from continuous pressure maintenance plus continuous mud circulation and continuous rotation; all of which maintains the wall of the exposed formation in the optimum steady state regime that has been established since it was first drilled. Only when the string has been fully installed and the cement has been circulated to the required location is the rotation of the casing stopped. This casing rotation assists greatly the creation of a continuous unbroken cement job.
It is envisaged that such special casing couplers will exist for all casings up to as much as 20 inch casings, where shallow gas or shallow water may be present, down to 9⅝ inch and possibly 7 inch liner for example, two or three casing couplers will probably encompass all casing diameters up to twenty inches. For the 7 inch and smaller strings, either of the two drilling Couplers can be used with appropriate inserts on the slips and grips.
There is the option under water to make up the entire bit or downhole assembly of some 100 to 300 ft and lower the entire assembly into the well in one operation. Above ground, however, it is assumed that this is not likely to be a preferred as making up the assembly in convenient lengths of 30, 60 or 90 ft or so at a time and connecting and torquing them up they pass down through the BOP stack. As such provision has to he made to grip and support the string within the BOP stack while the top drive (or side drive or bottom drive) adds another section. If the BOP stack is to be reserved for its traditional role then a simple and near conventional slips and grips assembly can be installed above the BOP stack to achieve this instead.
The structure of the invention is a coupler and it is a feature of the invention that the basic or rotary coupler may, with minor modification, be used in conjunction with a top-drive or bottom drive or one or more couplers to achieve hand-over-hand or hand-to-hand operations with the bottom coupler being static or mobile during the connection or disconnection of tubulars.
The whole purpose of the above equipment and methods is to use xe2x80x9coff the shelfxe2x80x9d components and tried and tested methods as much as possible; but to combine these in such a way that the well bore, at least from the 20 in casing onwards, is never again opened to the environment. This then eliminates the one situation, which currently requires that an additional barrier is placed in the well, that of the heavy kill fluid, of which the reliability is naturally limited to only one pressure i.e. the static head of the mud chosen.
By contrast, with this new method the weight of the fluid is chosen specifically to achieve the correct xe2x80x98pressure gradientxe2x80x99 from the top to the bottom of the wall of the exposed formation. The actual pressure at the exposed formation is set by the inlet and outlet pressures at the wellhead and these can be set at will, changed immediately and can be kept continuous, while tubulars and tubular components of all sorts can be added or removed from the string and the strings themselves can be changed out as well, without disturbing the optimum steady state.
Preferably the coupler is as short as possible to minimise the overall BOP and coupler height beneath a drilling derrick and the mobile coupler is as light as possible; the invention achieves this by integrating each slips and grips into one unit and by allowing the upper grips and slips to pass through the open blind preventer to meet up with the lower slips and grips and by combining the space required for the upper slips and grips with the space required for flushing the mud in or out.
All vertical motions may be carried out at an angle to the vertical as in the case of slant drilling where the wellhead is set at an angle to the vertical.
All references to a drill string apply equally to a casing string or production string or stinger or snubbing pipe or any other tubular made up of discrete lengths.
All references to a tubular apply equally to a single tubular or a stand of two or more tubulars.
All references to drilling mud apply also to all fluids that are pumped into the well bore for any purpose during the drilling and life of the well.
All references to the environment apply equally to drilling underwater as they do to drilling in air.
It is a feature of the invention that:
1. There is greater drilling efficiency because the tubulars can be added to the string without interrupting the drilling (so there is no delay while a tubular is added and the optimum drilling status is being re-established). The drilling continues steadily and continuously at the optimum conditions so that the fullest attention can be concentrated on small adjustments to bit weight, rotary speed, bottom hole pressure, circulation rate and mud composition etc; to improve ROP. With steady state drilling, small deviations in downhole measurements are much easier to identify and interpret, particularly as the density, and temperature of the annular mud is now kept steady and consistent. xe2x80x94MWD and PWD are more effective since they are contiguous and are of significant importance against a steady state background.
Continuous drilling at steady optimum conditions increases bit life and reduces the damage that often occurs when returning the bit to bottom either impacting the rock or grinding through several feet of debris.
2. There are fewer Drilling Problems because continuous circulation keeps the cuttings on the move so that settlement around the bit and bit assemblies does not occur and the cuttings density is constant throughout the annulus. With no cuttings settlement, stuck bits or BHAS, or string differential sticking, the need for hole cleaning is almost eliminated. With continuity of downhole pressure regime, variations of pressure at the exposed formation wall are very greatly reduced and almost eliminated, resulting in far less losses or wall instability.
3. Safety is increased because: Identifying small variations in pressure, flow, temperature, and density are very much easier with steady state background conditions and improve well control. Continuous closure of the string improves safety and also allows the string to be run back to bottom if needed in extreme kick conditions while circulating continuously. Continuous circulation under any desired pressure, regardless of the current mud weight, allows improved and immediate response to kicks.
4. There are lower Drilling Costs per Well because: With no interruptions to drilling when adding tubulars, with continuity of drilling at steady state optimum conditions, with longer life of the drilling bits, with much less chance of stuck bits, BHAs and drill string, with less costly mud weighting and gel components in the mud, with better downhole measurement and control and safety, the drilling costs per well should equate to a saving of several days on most wells, to weeks on extended reach wells and/or in difficult formations. Secondly, on platform rigs drilling several holes in succession, the overall additional early production is very significant to the DCF return on investment. The savings can be equated to those quoted for Coiled Tubing, to which can be added the benefits of string rotation. Additionally the assembly can be retro-fitted to all current rigs that use top drive, which provides the potential for a very large saving in drilling costs to the Drilling Industry worldwide.
5. Hole Quality is improved because: by drilling continuously, with steady state down hole conditions, the exposed formation wall is subjected to less damage from xe2x80x98pumpingxe2x80x99 of cuttings, finds and mud components into the formation and the quality of the producing formation is improved.
These benefits can result in very large operators"" savings per rig particularly in deviated wells off shore and can amount savings per rig amounting to several million dollars per year.


A controlled conversion resin having an epoxy functionality of greater than 2 and comprising moieties derived from epoxy resin, dihydric phenol, acid anhydride, or amine. The resin is prepared by reacting an epoxy resin with a dihydric phenol, an acid anhydride, or amine or other branching agent in the presence of a catalyst and terminating the reaction at a point such that the reaction product contains both epoxy and terminal hydroxyl groups.

This invention relates to controlled conversion epoxy resins, hereinafter referred to as CCR resins, to a process for preparing said resins and to compositions containing these resins.
High molecular weight epoxy resins are generally prepared by a two-step process wherein a lower molecular weight epoxy resin is prepared initially by reacting a polyhydric phenol with epichlorohydrin and alkali metal hydroxide in the presence of a catalyst. Thereafter, the initial polyepoxide reaction product is advanced by its reaction with additional amounts of polyhydric phenol to form the higher molecular weight material. In conventional techniques for preparing the epoxy resins, the reaction of the polyepoxide and polyhydric phenol is typically carried out to complete conversion such that the final, advanced epoxy resin, also known as fully advanced resin, contains relatively low amounts of residual phenolic hydroxyl groups. For example, epoxy resins having an EEW (epoxy equivalent weight) between about 500 and about 700 prepared from bisphenol A and the diglycidyl ether of bisphenol A typically contain less than about 800 parts per million of phenolic hydroxyl groups which represents more than about 98 percent conversion of the phenolic hydroxyl groups employed in preparing the epoxy resin. A higher molecular weight epoxy resin having an EEW from greater than about 2000 to about 4000 typically contains less than about 2500 ppm of phenolic OH groups which represents more than about 95 percent conversion of the phenolic hydroxyl groups. Any residual hydroxyl groups in the advanced resin have been stated to cause viscosity instability of the resulting resin mixture, particularly at elevated temperatures.
Controlled conversion epoxy resins (CCR resins) are known and are described, for example, in U.S. Pat. No. 4,722,981, incorporated herein by reference. As described in this patent, CCR resins have improved cure rate over standard fully advanced resins. The cure rate of CCR resins has been further improved by increasing its functionality through the addition of a multi-functional phenol epoxy novolac to the CCR resins as described in copending U.S. patent application Ser. No. 08/875,969, filed Feb. 10, 1995. Since multi-functional phenol epoxy novolac resins usually have a lower softening point than the CCR resins, addition of novolac resins to CCR resins tend to decrease the softening point of the CCR resins.
Copending U.S. patent application Ser. No. 60/213,965, filed Jun. 23, 2000, describes increasing the functionality of fully advanced resins by using acid anhydride as a branching agent. The resulting product has increased viscosity compared to the standard fully advanced resin and standard CCR resin.
It would be desirable to provide a process for preparing CCR resins with increased functionality, and thus, cure rate, without lowering its softening point or increasing its viscosity.
As used herein, the term xe2x80x9cfunctionalityxe2x80x9d refers to the average number of epoxy groups per resin molecule.
In one aspect, the present invention is a controlled conversion epoxy resin (CCR resin) containing both epoxy and terminal hydroxyl groups and having an epoxy functionality of greater than 2 and comprising moieties derived from an epoxy resin and a dihydric phenolan acid anhydride, or an amine.
By the term xe2x80x9cepoxy groupxe2x80x9d it is meant a radical of the following structural formula:
having an equivalent weight of 43 and by the term xe2x80x9cterminal hydroxyl groupxe2x80x9d it is meant a terminal hydroxyl group having an equivalent weight of 17. For the purposes of this invention, the percent epoxy groups and the terminal phenolic hydroxyl groups in the CCR resin reaction product are determined by the methods described in U.S. Pat. No. 4,722,981, Footnotes 1 and 2, respectively, the descriptions incorporated herein by reference.
In a second aspect, the present invention is a process for preparing the CCR resin of the first aspect which comprises branching an epoxy resin by reacting a liquid epoxy resin and a dihydric phenol with an acid anhydride or an amine in the presence of a catalyst and terminating the reaction at a point such that the reaction product contains both epoxy and terminal hydroxyl groups, the acid anhydride being employed in an amount sufficient to achieve the desired epoxy functionality but insufficient to form gels in the anhydride-modified epoxy resin.
The present reaction can be done in one step wherein a liquid epoxy resin (LER), anhydride, dihydric phenol and catalyst are reacted and the reaction terminated at a point such that the reaction product contains both epoxy and terminal hydroxyl groups.
Alternatively, the liquid epoxy resin and the dihydric phenol are reacted first and then the anhydride is added or, the LER and anhydride are reacted first, and then the dihydric phenol is added to the reaction and the reaction terminated at a point when the reaction product contains both epoxy and terminal hydroxyl groups.
The reaction can be done using a batch process or a continuous process conducted in a reactive extruder, such as that described in European Patent No. EP 0193809.
In preparing the CCR resins, the dihydric phenol, the acid anhydride and the epoxy resin components are contacted in the presence of a catalyst for the reaction between the hydroxyl groups of the dihydric phenol or the acid anhydride groups and the epoxy groups of the epoxy resin and at conditions sufficient to form the desired CCR resin. Preferably, this reaction is conducted neat, i.e., in the absence of any reaction diluent.
Although not preferred, the reaction of the dihydric phenol, acid anhydride and epoxy resin components can be conducted in the presence of a reaction diluent. If employed, the reaction diluent is preferably a solvent for or miscible with both the dihydric phenol, acid anhydride groups and the epoxy resin. Representative solvents which can be employed include various glycol ethers such as ethylene or propylene glycol monomethylether and esters thereof such as ethylene glycol monoethylether acetate; ketones such as methylisobutylketone, methylethylketone and acetone; and aromatic hydrocarbons such as toluene, xylene or mixtures thereof. If employed, the organic liquid reaction diluent is generally employed in an amount from about 5 to about 300 percent based on the total weight of all the reactants.
The reaction of the dihydric phenol and the epoxy resin, anhydride or amine is advantageously carried out at an elevated temperature, preferably, from about 60xc2x0 C. to about 200xc2x0 C., more preferably from about 100xc2x0 C. to about 150xc2x0 C. and, more preferably, from about 120xc2x0 C. to about 140xc2x0 C. The reaction is continued until the desired conversion, as determined by measuring the residual epoxy and terminal hydroxyl content in the resin, is achieved, at which point, the reaction is effectively terminated.
Any method which effectively inhibits the reaction upon reaching the desired degree of conversion can be employed herein. The reaction is effectively inhibited when the rate of reaction of the hydroxyl and epoxy group is sufficiently reduced such that further reaction, if any, does not significantly and deleteriously affect the product or its handling characteristics. Preferably, the reaction is sufficiently inhibited such that the solution viscosity of the CCR resin remains essentially constant or increases only marginally with time. For example, upon reaching the desired degree of conversion, the reaction mixture can be quenched to stop the reaction. However, the rapid quenching of the reaction mixture must be conducted carefully to prevent clotting or lumping of the CCR resin and to prevent the CCR resin from forming a large solid mass which cannot subsequently be used.
A convenient method for quenching the reaction mixture comprises the addition of a solvent to the mixture, thereby diluting the mixture and reducing its temperature. The amount of organic solvent to be added is dependent on the reaction temperature and the temperature at which reaction is effectively terminated. The addition of organic solvent to the reaction mixture is particularly preferred when the CCR resin is subsequently to be applied from solution.
A most preferred method for inhibiting the reaction comprises adding a material to the reaction mixture which effectively inhibits further reaction such as by deactivating the catalyst, or by interrupting the reaction mechanism, thereby inhibiting further reactions between the polyol and the polyepoxide.
Strong inorganic and organic acids and the anhydrides and esters of said acids (including half esters and part esters) have been found to be particularly effective as reaction inhibitors. By the term xe2x80x9cstrong acidxe2x80x9d it is meant an organic acid having a pKa value below about 4, preferably below about 2.5. Representative reaction inhibitors include inorganic acids such as hydrochloric acid, sulfuric acid and phosphoric acid; inorganic acid anhydrides such as phosphoric acid anhydride; esters of inorganic acids such as dimethyl sulfate; the organic acids such as alkyl, aryl and aralkyl and substituted alkyl, aryl and aralkyl sulfonic acids such as p-toluene sulfonic acid and phenyl sulfonic acid and stronger organic carboxylic acids such as trichloroacetic acid and alkyl esters of said acids, such as the alkyl esters of p-toluene sulfonic acid, e.g., methyl-p-toluene sulfonate, and ethyl-p-toluenesulfonate, methanesulfonic acid methylester and mixtures thereof. An example of an acid anhydride of a strong organic acid that can be employed herein is p-toluene sulfonic acid anhydride. Of the reaction inhibitors, the alkyl esters of sulfuric acid: the aryl or aralkyl sulfonic acids and the alkyl esters of said acids are preferably employed herein. Most preferably, an alkyl ester of para-toluene sulfonic acid, particularly methyl or ethyl-p-toluene sulfonic acid is employed as the reaction inhibitor herein.
The amounts of reaction inhibitor added to the reaction mixture are dependent on the specific inhibitor employed and the catalyst employed in preparing the CCR resin. In general, the inhibitor is added in an amount sufficient to overcome the catalytic activity of the catalyst. Preferably, at least about 0.9, more preferably at least about 2, equivalents of the inhibitor are added for each equivalent of the catalyst employed. Although the maximum amount of inhibitor added to the reaction mixture is dependent on the desired properties of the resin and the expense of adding excess inhibitor, the inhibitor is preferably added in an amount not exceeding about 5 equivalents for each equivalent of catalyst in the reaction mixture.
The reaction is terminated at a point such that the resulting CCR resin contains the desired amounts of epoxy groups and terminal hydroxyl groups. In this invention, the CCR resin will contain at least about 0.25 percent, by weight, of each of the epoxy and terminal hydroxyl groups. The epoxy resins which can be employed in the practice of the present invention for preparing the CCR resins include the diglycidyl ethers of dihydric phenols, such as those described in U.S. Pat. Nos. 5,246,751; 5,115,075; 5,089,588; 4,480,082 and 4,438,254, all of which are incorporated herein by reference, or the diglycidyl esters of dicarboxylic acids such as those described in U.S. Pat. No. 5,171,820.
The diglycidyl ethers of dihydric phenols are preferably the diglycidyl ethers of resorcinol, hydroquinone, 4,4xe2x80x2-isopropylidene bisphenol (bisphenol A), 4,4xe2x80x2-dihydroxydiphenylethylmethane, 3,3xe2x80x2-dihydroxy-diphenyldiethylmethane, 3,4xe2x80x2-dihydroxydiphenyl-methylpropylmethane, 4,4xe2x80x2-dihydroxydiphenyloxide, 4,4xe2x80x2-dihydroxydiphenylcyanomethane, 4,4xe2x80x2-dihydroxy-biphenyl, 4,4xe2x80x2-dihydroxybenzophenone (bisphenol-K), 4,4xe2x80x2-dihydroxydiphenyl sulfide, 4,4xe2x80x2-dihydroxydiphenyl sulfone, 2,6-dihydroxynaphthalene, 1,4xe2x80x2-dihydroxy-naphthalene, catechol, 2,2-bis(4-hydroxyphenyl)-acetamide, 2,2-bis(4-hydroxyphenyl)ethanol, 2,2-bis(4-hydroxyphenyl)-N-methylacetamide, 2,2-bis(4-hydroxy-phenyl)-N,N-dimethylacetamide, 3,5-dihydroxyphenyl-acetamide, 2,4-dihydroxyphenyl-N-(hydroxyethyl)-acetamide, and other dihydric phenols listed in U.S. Pat. Nos. 3,395,118, 4,438,254 and 4,480,082 which are hereby incorporated by reference as well as mixtures of one or more of such diglycidyl ethers. Of these preferred diglycidyl ethers, those of bisphenol-A, hydroquinone, and resorcinol are more preferred, with the diglycidyl ether of bisphenol-A being most preferred.
The diglycidyl esters of dicarboxylic acids are preferably the diglycidyl esters of terephthalic acid, isophthalic acid, 2,6-naphthalenedicarboxylix acid, 3,4xe2x80x2-biphenyldicarboxylic acid, 4,4xe2x80x2-biphenyldicarboxylic acid, malonic acid, succinic acid, glutaric acid, adipic acid, pumelic acid, suberic acid, azaleic acid, sebasic acid, 1,4-cyclohexanedicarboxylic acid, 1,10-decanedicarboxylic acid, tartaric acid, malic acid, citramalic acid and hydroxyglutaric acid. The more preferred diglycidyl esters are the diglycidyl esters of terephthalic acid, isophthalic acid, adipic acid, 1,4-cyclohexanedicarboxylic acid and 1,10-decanedicarboxylic acid.
Other suitable epoxy resins include xcex1, xcfx89-diglycidyloxyisopropylidene-bisphenol-based epoxy resins (commercially known as D.E.R.(trademark) 300 and 600 series epoxy resins), xcex1, xcfx89-diglycidyloxy tetrabromoisopropylidene-bisphenol-based phenoxy resins, such as D.E.R. 542, both are products of The Dow Chemical Company. Preferred epoxy resins are the epoxy resins having an epoxy equivalent weight of from about 100 to about 4000. Most preferred epoxy resins are the diglycidyl ethers of bisphenol A; bisphenol F; 4,4xe2x80x2-sulfonyldiphenol; 4,4-oxydiphenol; 4,4xe2x80x2-dihydroxybenzophenone; resorcinol; hydroquinone; 9,9xe2x80x2-bis(4-hydroxyphenyl)fluorene; 4,4xe2x80x2-dihydroxybiphenyl or 4,4xe2x80x2-dihydroxy-alpha-methylstilbene and the diglycidyl esters of the dicarboxylic acids mentioned previously.
The amount of epoxy resins used depends on the targeted molecular weight and epoxy functionality. In general, the epoxy resin is used in an amount of from about 30 wt. % to about 85 wt. %, more preferably, from about 40 wt. % to about 75 wt. % and, most preferably, from about 45 wt. % to about 70 wt. %, based on the weight of reactants.
The anhydrides which can be employed in the practice of the present invention for preparing the anhydride-modified epoxy resin (epoxy-functional polyester/polyether oligomer or polymer) include diglycolic anhydride, dichloromaleic anhydride, maleic anhydride, succinic anhydride, glutaric anhydride, citraconic anhydride, itaconic anhydride, tetrabromophthalic anhydride, phthalic anhydride, tetrahydrophthalic anhydride, hexahydrophthalic anhydride, tetrachlorophthalic anhydride, 4-methylhexahydrophthalic anhydride, methyl-5-norbornene-2,3-dicarboxylic anhydride, 1,8-naphthalic anhydride, trimilletic anhydride, 1,2,4,5-benzenetetracarboxylic dianhydride and halogenated acid anhydride such as tetrabromophthalic anhydride.
Preferred anhydrides are phthalic anhydride, maleic anhydride, tetrahydrophthalic anhydride, 4-methylhexahydrophthalic anhydride, hexahydrophthalic anhydride, methyl-5-norbornene-2,3-dicarboxylic anhydride and succinic anhydride. Most preferred are phthalic anhydride, 4-methylhexahydrophthalic anhydride, tetrahydrophthalic anhydride, hexahydrophthalic anhydride succinic anhydride and mixtures thereof.
The amount of anhydride used depends on the molecular weight of the anhydride, the amount of branching desired in the CCR and the targeted equivalent weight of the CCR. In general, the anhydride is used in an amount of from about 0.1 wt. % to about 20 wt. %, preferably from about 1 wt. % to about 15 wt. % and, most preferably, from about 1 wt. % to about 10 wt. %, based on the amount of reactants used.
The dihydric phenols which can be employed in the practice of the present invention for preparing the CCR include 4,4xe2x80x2-isopropylidene bisphenol (bisphenol A), 4,4xe2x80x2-dihydroxydiphenylethylmethane, 3,3xe2x80x2-dihydroxy-diphenyldiethylmethane, 3,4xe2x80x2-dihydroxydiphenyl-methylpropylmethane, bisphenol, 4,4xe2x80x2-dihydroxy-diphenyloxide, 4,4xe2x80x2-dihydroxydiphenylcyanomethane, 4,4xe2x80x2-dihydroxybiphenyl, 4,4xe2x80x2-dihydroxybenzophenone, 4,4xe2x80x2-dihydroxydiphenyl sulfide, 4,4xe2x80x2-dihydroxydiphenyl sulfone, 2,6-dihydroxynaphthalene, 1,4xe2x80x2-dihydroxy-naphthalene, catechol, resorcinol, hydroquinone, halogenated bisphenol such as tetrabromobisphenol A and other dihydric phenols listed in U.S. Pat. Nos. 3,395,118; 4,438,254 and 4,480,082 which are hereby incorporated by reference. In addition, mixtures of different dihydric phenols can be employed. Of these other dihydric phenols, bisphenol A, hydroquinone and mixtures thereof are most preferred.
The amount of dihydric phenol used depends on the molecular weight of the phenol, the molecular weight of the epoxy, the molecular weight of the anhydride, as well as the target equivalent weight of the SER and level of branching. In general, the dihydric phenol is used in an amount of from about 1 wt. % to about 60 wt. %, more preferably, from about 5 wt. % to about 50 wt. % and, most preferably, from about 20 wt. % to about 45 wt. %, based on the weight of reactants.
Preferred catalysts are, but not limited to, phosphines, amines, quaternary ammonium and phosphonium salts, such as tetraethylammonium chloride, tetraethylammonium bromide, tetraethylammonium iodide, tetraethylammonium hydroxide, tetra(n-butyl)ammonium chloride, tetra(n-butyl)ammonium bromide, tetra(n-butyl)ammonium iodide, tetra(n-butyl)ammonium hydroxide, tetra (n-octyl) ammonium chloride, tetra(n-octyl) ammonium bromide, tetra(n-octyl)ammonium iodide, tetra(n-octyl)ammonium hydroxide, methyltris(n-octyl)ammonium chloride, bis(tetraphenylphosphoranylidene)ammonium chloride, ethyltri-p-tolylphosphonium acetate/acetic acid complex, ethyltriphenylphosphonium acetate/acetic acid complex or combinations thereof and the like as described in U.S. Pat. Nos. 5,208,317, 5,109,099 and 4,981,926. Most preferred catalysts include tetraethylammonium bromide, tetraethylammonium hydroxide, ethyltritolylphosphonium acetate and ethyltriphenylphosphonium acetate.
The amount of catalyst used depends on the molecular weight of the catalyst, the activity of the catalyst and the speed at which the polymerization is intended to proceed. In general, the catalyst is used in an amount of from 0 wt. % to about 1 wt. %, more preferably, from about 0.01 wt. % to about 0.5 wt. % and, most preferably, from about 0.1 wt. % to about 0.2 wt. %, based on the weight of reactants.
The temperature at which the reaction is most advantageously conducted depends on the specific compounds and catalyst employed. In general this temperature is from about 50xc2x0 C. to about 200xc2x0 C., more preferably from about 90xc2x0 C. to about 1800xc2x0 C. and, most preferably, from about 120xc2x0 C. to about 150xc2x0 C.
The CCR resin of the present invention can be cured with a variety of epoxy curing agents such as phenolics, amines, carboxylic acids, phenol formaldehyde resins, and anhydrides, as well as through the hydroxyl group or an epoxy group. The CCR resins of the present invention can be reacted with a hardener such as, for example, an amine-terminated polymer, a carboxy-terminated polymer, a phenol-terminated polymer, a multifunctional amine, carboxylic acid or phenol.
The CCR resins of the present invention can be used in a variety of industrial applications or other epoxy applications such as coatings, laminates and composites. Industrial coatings are surface protective coatings (paint coatings) applied to substrates and typically cured or crosslinked to form continuous films for decorative purposes as well as to protect the substrate. A protective coating ordinarily comprises an organic polymeric binder, pigments, and various paint additives, where the polymeric binder acts as a fluid vehicle for the pigments and imparts Theological properties to the fluid paint coating. Upon curing or crosslinking, the polymeric binder hardens and functions as a binder for the pigments and provides adhesion of the dried paint film to the substrate. The pigments may be organic or inorganic and functionally contribute to opacity and color in addition to durability and hardness. The manufacture of protective coatings involves the preparation of a polymeric binder, mixing of component materials, grinding of pigments in the polymeric binder, and thinning to commercial standards.
The polymeric binder can include a wide variety of other additives such as, for example, hardeners, dyes, pigments and flow modifiers, fire-retardants, self extinguishing agents, desiccants and all manner of additives which are used herein for their known purposes. Examples of fire retardants include: monoammonium phosphate, diamonium phosphate and aluminum trihydrate. These additives can be in the form of liquids or particles so long as the binder remains solid, has the desired particle size and impart no adverse effects to the binder.
Powder paints can be obtained which comprise the CCR resin of the present invention, and suitable pigments, catalysts and additives. These powder paints and coatings therefrom have a surprisingly good combination of highly prized properties. Depending on the choice and the amount of polymer, crosslinker, catalyst and other components one can obtain, for example good flow, good chemical resistance, high gloss, high scratch resistance, good mechanical properties, good outdoor durability and good color stability.
Water-dispersed coating compositions containing the CCR resin of the present invention are highly desirable for can and coil coating compositions.
The following examples are for illustrative purposes only and are not intended to limit the scope of this invention. Unless otherwise indicated, all parts and percentages are by weight

Epoxy resins and process for making the same