Patent Application
20160108698
The present disclosure broadly relates to well cementing and completions. More particularly, the present disclosure relates to an apparatus and method for providing zonal communication interruption.
After a section of a well is drilled, a metal casing is lowered and cement is pumped inside the casing. The cement then travels through the annulus between the formation rock and the external face of the casing and allowed to set in the annulus. Cementing accomplishes the following purposes: zonal isolation, pressure isolation, casing corrosion protection, casing support and drilling fluid recovery.
However, in many situations the cement does not perform as expected. This can cause the well to lose integrity, producing zonal communication that can have catastrophic results. Communication between zones is usually through micro channels in the cement. Examples of these situations include: cement slurry not placed properly within the annulus due to poor centralization, poor hole quality, inefficient mud removal, etc.; cement slurry contamination with formation fluids; and long term failure due to changes in pressure and/or temperature.
Current solutions to prevent micro channels include the use of centralizers, including bow springs, rigid centralizers and solid centralizers. Centralizer efficiency is dependent upon hole quality; so in the case of washouts, centralizer efficiency is greatly reduced. Another solution presently employed is the use of swellable packers: These are elastomeric rings placed within the annulus that swell to fill the gap space between casing and formation. However, like most current technologies, swellable packers can only address the micro channels between pipe and cement and not between cement and formation. Another current solution is the use of compressible cements, thixotropic cements, surfactant cements, etc.
Despite these solutions, there exists a need to address problems associated with imperfect zonal isolation. Therefore, what is needed is an improved method and apparatus for providing zonal communication interruption in a wellbore.
In one aspect, disclosed is a method for providing zonal communication interruption in a wellbore. The method includes the steps of positioning a plurality of cement diverters axially along an outer surface of a tubular member, each cement diverter having an axial length and an azimuthal extension of less than 360°, wherein the azimuthal position of at least one cement diverter is axially rotated from an adjacent cement diverter; positioning the tubular member within the wellbore; and flowing cement into an annulus formed between an inner surface of the wellbore and the outer surface of the tubular member, wherein the positioning of the plurality of cement diverters provides zonal communication interruption about every 10 to 20 feet (about every 3.0 to about 6.1 meters) axially along the tubular member.
In some forms, a first cement diverter of the plurality of cement diverters is positioned at a first distance from a first end of the tubular member. In some forms, a second cement diverter of the plurality of cement diverters is positioned at a second distance from a first end of the tubular member, the second distance greater than the first distance, the azimuthal position of the second cement diverter rotated by at least about 30° from the first cement diverter.
In some forms, a third cement diverter of the plurality of cement diverters is positioned at a third distance from a first end of the tubular member, the third distance greater than the second distance, the azimuthal position of the third cement diverter rotated by at least about 30° from the second diverter segment. In some forms, a fourth cement diverter of the plurality of cement diverters is positioned at a fourth distance from a first end of the tubular member, the fourth distance greater than the third distance, the azimuthal position of the fourth cement diverter rotated by at least about 30° from the third cement diverter.
In some forms, the azimuthal position of each cement diverter is rotated between about 30° and about 270° from an adjacent cement diverter. In some forms, the azimuthal position of each cement diverter is rotated between about 90° and about 180° from an adjacent cement diverter.
In some forms, each of the plurality of cement diverters has an azimuthal extension of between about 35° and about 270°. In some forms, each of the plurality of cement diverters has an azimuthal extension of between about 90° and about 180°.
In some forms, each of the plurality of cement diverters is between about two and about ten feet (about every 0.6 to about 3.0 meters) in length.
In some forms, each of the plurality of cement diverters is axially spaced apart along the tubular member by about 3 to about 20 feet.
In some forms, each of the plurality of cement diverters is swellable. In some forms, each of the plurality of cement diverters has a swellable coating applied thereto.
In some forms, of the plurality of cement diverters is inflatable.
In some forms, the wellbore comprises an inclined and/or horizontal section.
In another aspect, disclosed is an apparatus for providing zonal communication interruption in a wellbore. The apparatus includes a tubular member having a plurality of cement diverters positioned axially along an outer surface of a tubular member, each cement diverter having an axial length and an azimuthal extension of less than 360°, wherein the azimuthal position of at least one cement diverter is axially rotated from an adjacent cement diverter and the positioning of the plurality of cement diverters is effective to provide zonal communication interruption about every 10 to 20 feet (about every 3.0 to about 6.1 meters) axially along the tubular member.
In some forms, a first cement diverter of the plurality of cement diverters is positioned at a first distance from a first end of the tubular member. In some forms, a second cement diverter of the plurality of cement diverters is positioned at a second distance from a first end of the tubular member, the second distance greater than the first distance, the azimuthal position of the second cement diverter rotated by at least about 30° from the first cement diverter.
In some forms, a third cement diverter of the plurality of cement diverters is positioned at a third distance from a first end of the tubular member, the third distance greater than the second distance, the azimuthal position of the third cement diverter rotated by at least about 30° from the second diverter segment. In some forms, a fourth cement diverter of the plurality of cement diverters is positioned at a fourth distance from a first end of the tubular member, the fourth distance greater than the third distance, the azimuthal position of the fourth cement diverter rotated by at least about 30° from the third cement diverter.
In some forms, the azimuthal position of each cement diverter is rotated between about 30° and about 270° from an adjacent cement diverter. In some forms, the azimuthal position of each cement diverter is rotated between about 90° and about 180° from an adjacent cement diverter.
In some forms, each of the plurality of cement diverters has an azimuthal extension of between about 35° and about 270°. In some forms, each of the plurality of cement diverters has an azimuthal extension of between about 90° and about 180°.
In some forms, each of the plurality of cement diverters is between about two and about ten feet (about every 3.0 to about 6.1 meters) in length.
In some forms, each of the plurality of cement diverters is axially spaced apart along the tubular member by about 3 to about 20 feet (about 0.9 to about 6.1 meters).
In some forms, each of the plurality of cement diverters is swellable. In some forms, each of the plurality of cement diverters has a swellable coating applied thereto.
In some forms, the plurality of cement diverters are part of the completion, forming protuberances radially extending from the outer surface of the tubular member or casing.
In some forms, the plurality of cement diverters is inflatable.
In some forms, the wellbore comprises an inclined and/or horizontal section.
In another aspect, disclosed is a method of creating a wellbore in an underground formation. The method includes the steps of drilling a borehole in the underground formation; installing a tubular member into the borehole, the tubular member having a plurality of cement diverters positioned axially along an outer surface of the tubular member, each cement diverter having an axial length and an azimuthal extension of less than 360°, wherein the azimuthal position of at least one cement diverter is axially rotated from an adjacent cement diverter; and flowing cement into an annulus formed between an inner surface of the wellbore and the outer surface of the tubular member, wherein the positioning of the plurality of cement diverters provides zonal communication interruption about every 10 to 20 feet (about every 3.0 to about 6.1 meters) axially along the tubular member.
In yet another aspect, disclosed is a method of producing hydrocarbons from a production well of an underground formation. The method includes the steps of installing a tubular member into a wellbore of an underground formation, the tubular member having a plurality of cement diverters positioned axially along an outer surface of the tubular member, each cement diverter having an axial length and an azimuthal extension of less than 360°, wherein the azimuthal position of at least one cement diverter is axially rotated from an adjacent cement diverter; flowing cement into an annulus formed between an inner surface of the wellbore and the outer surface of the tubular member to form a production well; and producing fluids containing hydrocarbons from the production well, wherein the positioning of the plurality of cement diverters provides zonal communication interruption about every 10 to 20 feet (about every 3.0 to about 6.1 meters) axially along the tubular member.
In one form, each cement diverter may be a 180 degree extension of a solid with a swellable elastomer on its outer surface. The length of each cement diverter is between about two and ten feet (about every 3.0 to about 6.1 meters). In one form, the cement diverters may be positioned about 3 to about 20 feet (about 0.9 to about 6.1 meters) apart along the tubular member. In one form, a first cement diverter is rotated 180° from a second cement diverter. In one form a third cement diverter may be rotated 90° with respect to the second cement diverter and then the pattern is repeated. The result of this arrangement is to force slurry into small gaps, which in turn assures that there will be channel interruption every 10 to 20 feet (about every 3.0 to about 6.1 meters) in the worst case eccentricity scenario.
In general, structures and/or features that are, or are likely to be, included in a given embodiment are indicated in solid lines in the figures, while optional structures and/or features are indicated in broken lines. However, a given embodiment is not required to include all structures and/or features that are illustrated in solid lines therein, and any suitable number of such structures and/or features may be omitted from a given embodiment without departing from the scope of the present disclosure.
By use of the term “vertical,” “vertically” or “vertical section,” when referring to a well, a wellbore, tubing or tubular member, or section or portion thereof, is meant that such well, wellbore, tubing or tubular member, or section thereof, is positioned or is to be positioned, so as to be substantially normal to a plane formed at the ground or surface level of the well or wellbore.
By use of the term “inclined” or “inclined section,” when referring to a well, a wellbore, tubing or tubular member, or section or portion thereof, is meant that such well, wellbore, tubing or tubular member, or section thereof, is positioned, or is to be positioned, so as to deviate in direction from vertical and encompasses a well, a wellbore, tubing or tubular member, or section or portion thereof, extending in horizontally or in a horizontal direction.
By use of the term “horizontal,” “horizontally” or “horizontal section,” when referring to a well, a wellbore, tubing or tubular member, or section or portion thereof, is meant that such well, wellbore, tubing or tubular member, or section thereof, is positioned or is to be positioned, so as to travel along a plane substantially parallel to a plane formed tangentially at the ground or surface level of the well or wellbore.
By use of the term “zonal communication interruption,” when referring to a well, a wellbore, tubing or tubular member, or section or portion thereof, is meant that communication between one or more zones of a well, usually through micro-channels in a cement sheath, placed between a wellbore and a tubular member, is at least partially blocked or impeded with respect to flow. Such communication between one or more zones of a well may be due to the presence in the cement sheath of channels, micro-channels, annuli, or the like.
Referring now to
Still referring to
In some forms, a third cement diverter 18′″ of the plurality of cement diverters 18 is positioned at a third distance d3 from the first end 14 of tubular member 12, the third distance d3 greater than the second distance d2. Also, as shown in
In some forms, a fourth cement diverter 18″″ of the plurality of cement diverters 18 is positioned at a fourth distance d4 from first end 14 of the tubular member 12, the fourth distance d4 greater than the third distance d3. Also, as shown in
Still referring to
In some forms, each of the plurality of cement diverters 18 has an azimuthal extension E of between about 35° and about 270°. In some forms, each of the plurality of cement diverters 18 has an azimuthal extension E of between about 90° and about 180°.
In some forms, each of the plurality of cement diverters 18 has a length L between about two and about ten feet (about every 3.0 to about 6.1 meters) in length. In some forms, each of the plurality of cement diverters 18 has an axial spacing S along the tubular member of between about 3 to about 20 feet (about 0.9 to about 6.1 meters).
To enhance the performance of cement diverters 18, one or more of the plurality of cement diverters may be swellable. In some forms, one or more of the plurality of cement diverters 18 has a swellable coating applied thereto. In some forms, one or more of the plurality of cement diverters 18 may be of an inflatable design.
As is well known to those skilled in the art, swellable materials have the characteristic of being able to move from a retracted position to an expanded position when exposed to the action of a triggering agent. The triggering agent may be a fluid absorbed by the material that consequently swells. In its expanded position, the volume of the swellable material is greater than in its non-swollen position, which makes it able to fill adjacent spaces unoccupied prior to swelling and therefore seals fluid channels in its vicinity. Swellable materials can be deployed downhole in their retracted position prior to swelling and activated downhole.
Suitable water-swellable materials include acrylic acid type polymers, carboxymethyl cellulose type polymers, highly swelling clay minerals, isobutylene maleic anhydride, polyethylene oxide polymers, polyvinyl alcohol cyclic acid anhydride graft copolymer, sodium bentonite (montmorillonite), starch polyacrylate acid graft copolymer, starch polyacrylonitrile graft copolymers, vinyl acetate-acrylate copolymers, and combination thereof. More generally, they can also include super absorbent polymers (SAPs) or hydrogels.
Suitable hydrocarbon-swellable materials include natural rubber, polyisoprene rubber, vinyl acetate rubber, polychloroprene rubber, acrylonitrile butadiene rubber, hydrogenated acrylonitrile butadiene rubber, ethylene propylene diene monomer, ethylene propylene monomer rubber, polynorbornen, styrene butadiene rubber, styrene/propylene/diene monomer, brominated poly(isobutylene-co-4-methylstyrene) (BIMS), butyl rubber, chlorosulphonated polyethylenes, polyacrylate rubber, polyurethane, silicone rubber, brominated butyl rubber, chlorinated butyl rubber, chlorinated polyethylene, epichlorohydrin ethylene oxide copolymer, ethylene acrylate rubber, ethylene propylene diene terpolymer rubber, sulphonated polyethylene, fluoro silicone rubbers, fluoroelastomer, substituted styrene acrylate copolymer and combination thereof.
The operation of the apparatus 10 for providing zonal communication interruption in a wellbore, according to the present disclosure, will be described by reference to
Examples of zonal isolation problems will now be described. Referring to
In a horizontal well example, a channel may form on top of the casing, where water separates (called free water). As such, micro-channels can appear either between the casing 112 and the cement 106 or between the formation 100 and the cement 106. For example, bad drilling mud removal may occur while pumping the cement slurry in the annulus 108, thereby leaving mud films either between the casing 104 and the cement 106 or between the cement 106 and the formation 100. This results in fluid channeling and loss of zonal isolation. Both types of micro-channels may also appear during the life of the cement due to the phenomenon of cement debonding.
An even more complex zonal isolation problem results from cracks in the cement. Cracks develop due to cement ageing, seismologic activity in the formation or vibrations of the casing or pressure/temperature variation.
Referring now to
As shown in
In some forms, after another axial spacing of about 3 to 20 feet (about 0.9 to about 6.1 meters), another cement diverter 418 is positioned, this time, by way of example, but not of limitation, rotated 180° with respect to the previous cement diverter 418, then the next one rotated 90°. As may be appreciated by one of skill in the art, the pattern may be repeated. The apparatus for providing zonal communication interruption in a wellbore then forces slurry into the small gaps, which in turn assures that there will be zonal communication interruption about every 10 to 20 feet (about every 3.0 to about 6.1 meters), in the worst case eccentricity/borehole quality scenario.
By seeking to address the worst case eccentricity/borehole quality scenario, the apparatus for providing zonal communication interruption in a wellbore may be said to be designed using minimax principles for these adverse scenarios. Minimax, sometimes referred to as minmax, is a decision rule used in decision theory, game theory, statistics and philosophy for minimizing the possible loss of a worst case, maximum loss, scenario. Originally formulated for two-player, zero-sum game theory, covering both the cases where players take alternate moves and those where they make simultaneous moves, it has also been extended to more complex games and to general decision making in the presence of uncertainty.
Minimax theory has been extended to decisions where there is no other player, but where the consequences of decisions depend on unknown facts. For example, deciding to prospect for minerals entails a cost that will be wasted if the minerals are not present, but will bring major rewards if they are discovered. One approach is to treat this as a game against nature, and using a similar mindset as Murphy's law, take an approach which minimizes the maximum expected loss, using the same techniques as in the two-person zero-sum games.
A key feature of minimax decision making is being non-probabilistic: in contrast to decisions using expected value or expected utility, it makes no assumptions about the probabilities of various outcomes, just scenario analysis of what the possible outcomes are. It is thus robust to changes in the assumptions, as these other decision techniques are not.
Further, minimax only requires ordinal measurement (that outcomes be compared and ranked), not interval measurements (that outcomes include “how much better or worse”), and returns ordinal data, using only the modeled outcomes: the conclusion of a minimax analysis is: “this strategy is minimax, as the worst case is (outcome), which is less bad than any other strategy.” Compare to expected value analysis, whose conclusion is of the form: “this strategy yields E(X)=n.” Minimax thus can be used on ordinal data, and can be more transparent. Modeling a downhole completion case where micro-channels will be present due to casing eccentricity or poor borehole quality, and the various completion design approaches to deal with such issues, may be thought of in this manner.
As such, disclosed herein is a method for providing zonal communication interruption in a wellbore, comprising: positioning a plurality of cement diverters axially along an outer surface of a tubular member, each cement diverter having an axial length and an azimuthal extension of less than 360°, wherein the azimuthal position of at least one cement diverter is axially rotated from an adjacent cement diverter; positioning the tubular member within the wellbore; and flowing cement into an annulus formed between an inner surface of the wellbore and the outer surface of the tubular member, wherein the positioning of the plurality of cement diverters provides zonal communication interruption about every 10 to 20 feet (about every 3.0 to about 6.1 meters) axially along the tubular member.
Also disclosed herein is a method of producing hydrocarbons from a production well of an underground formation, comprising the steps of: installing a tubular member into a wellbore of an underground formation, the tubular member having a plurality of cement diverters positioned axially along an outer surface of the tubular member, each cement diverter having an axial length and an azimuthal extension of less than 360°, wherein the azimuthal position of at least one cement diverter is axially rotated from an adjacent cement diverter; flowing cement into an annulus formed between an inner surface of the wellbore and the outer surface of the tubular member to form a production well; and producing fluids containing hydrocarbons from the production well, wherein the positioning of the plurality of cement diverters provides zonal communication interruption about every 10 to 20 feet (about every 3.0 to about 6.1 meters) axially along the tubular member.
As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.
As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.
In the event that any patents, patent applications, or other references are incorporated by reference herein and define a term in a manner or are otherwise inconsistent with either the non-incorporated portion of the present disclosure or with any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was originally present.
As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.
The apparatus and methods disclosed herein are applicable to the oil and gas industry.
It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.
It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure.
This application claims the benefit of U.S. Provisional No. 61/914,735, filed Dec. 11, 2013, which is incorporated herein in its entirety for all purposes.
