Patent Application
20250172053
Various challenges are encountered during drilling and production operations of a hydrocarbon production well. For example, fluids used in drilling, completion, or servicing of a wellbore can be lost to a subterranean formation. In particular, the fluids may enter the subterranean formation via depleted zones, zones of relatively reduced pressure (as compared to the wellbore), “loss circulation zones” having naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the drilling fluid, and so forth. The extent of fluid losses to the formation may range from minor losses (for example, less than 10 barrels/hour (bbl/hr)), also referred to as “seepage loss”, to severe losses (for example, greater than 100 bbl/hr), to even greater amounts, such as where fluid fails to return to the surface (“complete fluid loss”). As well, the type of degree fluid loss may differ depending on the type of fluid in the wellbore. The degree of loss for oil- and synthetic oil-based muds is considered more significant versus the same quantity for water-based muds due to the potential economic and environmental impacts.
Lost circulation can be encountered during any stage of operations. Lost circulation may occur when drilling fluid (or drilling mud) pumped into a well returns partially or does not return to the surface. While de minimis fluid loss is expected, excessive fluid loss is not desirable from a safety, an economical, or an environmental point of view. This is especially true when working with water-bearing formations, such as aquifers that have drinking quality fresh or mineral water, or such as brine- or formation water-bearing formations, which may contaminate hydrocarbon production, cause corrosion issues, and foul cement jobs. Lost circulation is associated with problems with well control, borehole instability, pipe sticking, unsuccessful production tests, poor hydrocarbon production after well completion, and formation damage due to plugging of pores and pore throats by mud particles. Lost circulation problems may also contribute to non-productive time (NPT) for a drilling operation. In extreme cases, lost circulation problems may force abandonment of a well.
The Summary is provided to introduce a selection of concepts that are further described in the Detailed Description. The Summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In one aspect, embodiments disclosed herein relate to a treatment sub useful for treating a lost circulation zone. The treatment sub comprises a communications device configured to receive an external communication and an internal fluid conduit configured to convey a wellbore fluid through the treatment sub. The treatment sub also comprises an interior defined between a sub exterior surface and the internal fluid conduit. The treatment sub may include a sonic frequency source configured to generate a sonic frequency in the wellbore fluid.
In another aspect, embodiments disclosed herein relate to a method of treating a lost circulation zone during a wellbore drilling program. The method comprises introducing into a wellbore a treatment sub, where the treatment sub is part of a bottom hole assembly of a drill string used in the wellbore drilling program. The method further comprises detecting lost circulation of a wellbore fluid from the wellbore, introducing a resin agent into the wellbore fluid, introducing a crosslinking agent into the wellbore fluid, operating the treatment sub such that a sonic frequency is generated in the wellbore fluid, maintaining both the wellbore and the treatment sub for a treatment period, and determining that lost circulation of the wellbore fluid from the wellbore has been mitigated.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
This section describes specific embodiments in detail with reference to the accompanying figures. Where the figures include like elements between them, they may be denoted by like reference numerals. The use of letters with a number may indicate a like element, apparatus, or system; however, there is a material change between the like element, apparatus, or system. The use of the prime or “′” mark with a numeral may indicate a like element in a different state of operation or condition than previously referenced; however, other aspects remain the same.
Typically, down is toward or at the bottom and up is toward or at the top of the figure. “Up” and “down” are oriented relative to a local vertical direction. However, in the oil and gas industry, one or more activity takes place in deviated or horizontal wells. Therefore, one or more figure may represent an activity in deviated or horizontal wellbore configuration.
“Uphole” may refer to objects, units, or processes that are positioned closer to the surface entry in a wellbore. “Downhole” may refer to objects, units, or processes that are positioned farther from the surface entry in a wellbore. The terms “upstring” and “downstring” may relate in similar ways to a position along a string of tools or pipe, such as a drill string, while positioned in a wellbore. The terms “upflow” and “downflow” may relate in similar ways to a position relative to the general flow of a fluid, such as a wellbore or drilling fluid circulating in a wellbore. The terms are relativistic and may not be considered mutually exclusive. For example, a first unit may be described as “upstring” from a second unit but also be “downflow” form the same relative to the flow of a fluid in a wellbore annulus.
Treating lost circulation during drilling is a common operation in formations that are fractured, highly permeable, porous, cavernous, or vugular. Epoxy-based systems are useful to solve the problem of the lost circulation. Such epoxy-based systems are typically hardened using curing or crosslinking agents. However, one of the known challenges with epoxy-based systems is initiating hardening or crosslinking in the section of the wellbore so that the system effectively blocks the leakage but not the wellbore. Furthermore, it is beneficial to treat the lost circulation during drilling operations such that progress in the drilling program is not seriously compromised.
The present disclosure relates to systems, apparatuses, and methods for treating loss circulation zones (LCZs) by forming lost circulation material (LCM) proximate to the LCZs. The chemical system product is used with a triggering apparatus—a treatment sub—to facilitate the interaction of the reactive components of the chemical system in situ to remedy LCZs of all sizes, configurations, and loss rates. The chemical system in combination with the triggering apparatus improves operational safety, uptime for drilling equipment and personnel, and prevents wellbore fluid losses, including potentially catastrophic losses that may endanger the environment or personnel.
Subsurface formations 1004 may include one or more porous or fractured rock formation that resides beneath the surface 1010. The surface 1010 may be dry land or ocean bottom. Well system 1006 may be formed for the purposes of developing a hydrocarbon well, such as an oil well, a gas well, a gas condensate well, a mixture thereof, or another type of well, such as a fresh, brine, or mineral water well. The subsurface formations 1004 and the lost circulation zone 1002 may each have heterogeneity with varying characteristics, such as degree of density, permeability, porosity, pressure, temperature, and fluid saturations of the rock within each formation.
In the instance of the well system 1006 intending to be operated as a production well, the well system 1006 may facilitate the extraction of hydrocarbons (or “production”) from a reservoir or otherwise hydrocarbon-bearing formation. In the case of the well system 1006 being operated as an injection well, the well system 1006 may facilitate the injection of fluids into the subsurface formations 1004. In the case of the well system 1006 being operated as a monitoring well, the well system 1006 may facilitate the monitoring of various characteristics of the subsurface formations 1004, such as pressure or saturation of a particular formation.
The well system 1006 may include a wellbore 1014, a well control system (or “control system”) 1054, and a drilling system 1018. The control system 1054 may regulate various operations of the well system 1006, such as well drilling operations, well completion operations, well production operations, or well or formation monitoring operations.
The wellbore 1014 may include a bored hole that extends from the surface 1010 into the subsurface formations 1004 such that fluid communication is established with the lost circulation zone 1002. Wellbore 1014 is a void that is defined by wellbore wall 1022. Although shown as a vertical well, the configuration of the wellbore 1014 may also be deviated, approximately horizontal or horizontal, and combinations thereof, as a person of ordinary skill in the art well appreciates. The one or more embodiments are adaptable and applicable to all wellbore configurations.
The wellbore 1014 may be created, for example, by the drilling system 1018 boring through the subsurface formation 1004. In one or more embodiments, the drilling system 1018 includes a drilling rig 1024 supporting and manipulating a drill string 1026. The drill string 1026 may include drill pipe 1028 with a bottom hole assembly (BHA) 1029 coupled to the distal end of the drill pipe 1028. Drill pipe 1028 may also include drill collars. A drill bit 1030, which features members that can bore through the subsurface formations 1004 to form the wellbore 1014, is part of and attached to the distal end of the drill string 1026.
In one or more embodiments, the treatment system comprises a treatment sub as a component of a drill string. As shown in
Treatment sub 2000 in
In one or more embodiments, the treatment sub is positioned upstream of the face of the lost circulation zone. “Upstream” in this sense is relative to the circulation pathway of wellbore fluid. Being positioned upstream based upon the flow of the wellbore fluid permits the treatment sub to initiate a treatment, such as generation of a sonic frequency, such that the lost circulation material (LCM) forms before or within the face of the LCZ. If wellbore fluid is circulating downhole through the drill pipe 1028 and uphole in a wellbore annulus 1036, such as shown in
The mud circulation system 1034 is part of drilling system 1018 and serves a number of useful functions during operations, as one of ordinary skill in the art appreciates. A wellbore fluid 1032, such as a drilling fluid or “mud”, circulates in the wellbore 1014 during drilling operations (as well as other types of operations as previously described). The wellbore fluid 1032 typically flows downhole through an internal fluid conduit of the drill string 1026 (as will be described further), out the drill bit 1030, and back uphole through the wellbore annulus 1036. Cuttings and other drilling debris are conveyed from the bottom of the wellbore 1014 uphole. In one or more embodiments, the flow pathway is reversed as previously described.
In
In
Upon reaching the surface 1010, the wellbore fluid 1032 passes into mud receiving tank 1040, where the cuttings and dissolved gases are separated from the wellbore fluid 1032. The degassed wellbore fluid 1032 passes into the mud storage tank 1042, where the wellbore fluid is held until it is pumped back into the drill string 1026. The mud return line 1044, coupled to the mud storage tank 1042 and the drill string 1026, provides the fluid conduit for the wellbore fluid to start the mud circulation cycle again.
Shown in
In one or more embodiments, a well control system 1054 may use information obtained from the operations of the drilling system 1018 in conjunction with a set of pre-determined instructions and algorithms retained in a memory of a computer system to maintain or modify operations of the drilling system 1018, such as the operation of the drill bit 1030 or the treatment sub 2000. In
The well control system 1054 may be coupled to a control terminal 1048 to relay information for viewing by an external viewer. The information may be numerically displayed, graphically displayed, or both. An external viewer may include a computer monitor, a television, a printer, or any other form of temporal or permanent version of record keeping, communicating, and displaying that can be visually and audibly appreciated.
Supporting equipment for embodiments of the system may include additional standard components or equipment that enables and makes operable the described apparatuses, processes, methods, systems, and compositions of matter. Examples of such standard equipment known to one of ordinary skill in the art includes, but are not limited to, heat exchanges, blowers, single and multi-stage compressors and pumps, separation equipment, manual and automated control and isolation valves, switches, analogue and computer-based controllers, and pressure-, temperature-, level-flow-, and other-sensing devices.
In one or more embodiments, the disclosed system and method relates to the formation of a lost circulation material (LCM) useful for mitigating a lost circulation zone (LCZ). In such embodiments, resin and capsules comprising a crosslinking agent may be introduced into the wellbore fluid. Once downhole, the cross-linking agent may be released to initiate crosslinking of the resin, which solidifies to seal the LCZ.
After a capsule shell has been exposed to a useful sonic frequency (arrow 217), each of the capsules 200, 210 have had their capsule shell (formerly 215) ruptured or otherwise destroyed, forming several broken shells 216. The broken shells 216 are soft polymer debris or micro/nano-sized solids that pose no potential injury to the wellbore fluid 1032 or mechanical equipment downhole or on the surface.
In
During polymerization, a sonic frequency may be present that influences and encourages acceleration of the polymerization reaction by adding energy into the wellbore environment around the intermingling agents. Such energy may take the form of turbulent mixing due to cavitation—the formation of bubbles and implosion thereof. Cavitation creates fluidic microjets that have sufficient force to burst the capsule shells and to further mix the wellbore fluid. In addition, increased localized fluid temperature due to heating of the wellbore fluid or the wellbore wall may also occur from the input of sonic energy. Uneven localized heating may also create convection currents in the wellbore fluid, increasing mixing of the agents.
As the polymerization reaction between the two agents runs to completion (arrow 225), the resultant LCM 230 forms in wellbore fluid 1032. The LCM 230 may comprise various shapes and sizes based upon the amounts and ratios of resin agent and crosslinking agent that react with each other in a given location. Although shown in
In one or more embodiments, a resin agent is introduced into the wellbore fluid. In one or more embodiments, the resin agent is introduced into the wellbore fluid encapsulated in a shell. While the embodiment shown in
The resin agent may be any resin suitable for producing a solid lost circulation material. Such resin agents may react with a crosslinking agent to form an effective, solid LCM product that may withstand the differential pressure as the LCM material bridges the face of the LCZ. In one or more embodiments, the resin may be an epoxy resin.
In one or more embodiments, the resin agent includes an epoxide resin. Generally, such epoxide resins are derived from a polyether derivative of a polyhydric organic compound, where the derivation includes a 1,2-epoxy groups and where the polyhydric organic compound includes polyhydric alcohols, polyhydric phenols, and ethers that contain at least two phenolic hydroxy groups.
Polyhydric phenols for deriving useful epoxide resins include, but are not limited to, mononuclear phenols, such as, but not limited to, resorcinol, catechol, hydroquinone; polynuclear phenols, such as, but not limited to, bis(4-hydroxyphenyl)-2,2-propane (bisphenol-A), 4,4′-dihydroxybenzophenone, bis(4-hydroxyphenyl)-1,1-ethane, bis(4-hydroxyphenyl) 1,1-isobutane, bis(4-hydroxyphenyl)-2,2-butane, bis(4-hydroxy-Z-methylphenyl)-2,2-propane, bis (4 hydroxy-Z-tertiary butylphenyl)-2,2-propane, bis(4′ hydroxy-2,5-dichlorophenyl)-2,2-propane, 4,4′-dihydroxybiphenyl, 4,4-dihydroxy-pentachlorobisphenyl, bis (2 hydroxynaphthyl)-methane, 1,5-dihydroxy naphthalene, phloroglucinol, 1,4-dihydroxynaphthalene, and 1,4-bis(4-hydroxyphenyl)cyclohexane; and complex polyhydric phenols, such as, but not limited to, pyrogallol and phloroglucinol.
Aliphatic polyhydric alcohols for deriving useful epoxide resins include, but are not limited to, ethylene glycol, propylene glycol, trimethylene glycol, triethylene glycol, butylene glycol, diethylene glycol, 4,4-dihydroxydicyclohexyl, glycerol, and dipropylene glycol. Alcohols with more than one hydroxyl group are useful for deriving epoxide resins.
Ethers for deriving useful epoxide resins include, but are not limited to, glycerol, mannitol, sorbitol, polyallyl alcohol, and polyvinyl alcohol. Such glycidyl polyethers also have a 1,2-epoxy value greater than 1.0.
In one or more embodiments, the epoxide resin may comprise a novolacs resin, bisphenol-based resins, aliphatic resins, halogenated resins, glycidilamine resins, or reactive diluent.
In one or more embodiments, the resin agent further includes a co-epoxide resin. The co-epoxide resin may be any of the previously described resins or epoxide resins derived from the previously described resin precursors. Useful co-epoxide agents include, but are not limited to, bisphenol-A-epichlorohydrin epoxy resin with the reactive diluent oxirane mono [(C12-C14)-alkyloxy)methyl] derivatives; C12-C14 alkyl glycidyl ether; 2,3-epoxypropyl-o-tolyl ether; 1,6-hexanediol diglycidyl ether; bisphenol A/epichlorohydrin resin and butyl glycidyl ether resin; bisphenol A/epichlorohydrin and butyl glycidyl ether and cyclohexanedimethanol resins; and cyclohexanedimethanol diglydicyl ether. Such co-epoxy agents may be useful for modifying the physical or chemical properties of the product LCM versus a formed LCM without the co-epoxy agent, for example, by increasing or decreasing elasticity of the thermoset material or increasing or decreasing swelling at wellbore conditions.
In one or more embodiments, a crosslinking agent is introduced into the wellbore fluid. In one or more embodiments, the crosslinking agent is introduced into the wellbore fluid encapsulated in a capsule shell.
The crosslinking agent may be any crosslinking agent suitable for producing a solid lost circulation material. As previously described, such crosslinking agents are configured to react with the resin agent to form an LCM product. In one or more embodiments, the crosslinking agent may also be configured to react with the co-epoxy agent at downhole conditions in the wellbore fluid.
In one or more embodiments, the crosslinking agent is an amine type curing agent. Amine type curing agents may include a low molecular weight compound having a primary-, secondary- or tertiary amino group, and combinations thereof. “Low molecular weight” compounds having a primary amino group include, but are not limited to, primary amines, such as ethylenediamine, diethylenetriamine (DETA), triethylenetetramine, tetraethylenepentamine, hexamethylenediamine, isophorone diamine, bis(4-amino-3-methylcyclohexyl) methane, diaminodicyclohexylmethane, m-xylenediamine, diaminodiphenylmethane, diaminodiphenylsulfone, diethyltoluenediamine, polyoxypropylene diamine, and m-phenylenediamine; guanidines, such as dicyandiamide, methylguanidine, ethylguanidine, propylguanidine, butylguanidine, dimethylguanidine, trimethylguanidine, phenylguanidine, diphenylguanidine, and toluylguanidine; acid hydrazides, such as succinic acid dihydrazide, adipic acid dihydrazide, phthalic acid dihydrazide, isophthalic acid dihydrazide, terephthalic acid dihydrazide, p-hydroxybenzoic acid hydrazide, salicylic acid hydrazide, phenylaminopropionic acid hydrazide, and maleic acid dihydrazide.
Low molecular weight compounds having a secondary amino group include, but are not limited to, piperidine, pyrrolidine, diphenylamine, 2-methylimidazole, and 2-ethyl-4-methylimidazole.
Low molecular weight compounds having a tertiary amino group include, but are not limited to, imidazoles, such as 1-cyanoethyl-2-undecylimidazole-trimellitate, imidazolylsuccinic acid, 2-methylimidazole-succinic acid, 2-ethylimidazole-succinic acid, 1-cyanoethyl-2-methylimidazole, 1-cyanoethyl-2-undecylimidazole, and 1-cyanoethyl-2-phenylimidazole.
In one or more embodiments, the resin agent, the crosslinking agent, or both may each separately be encapsulated by a capsule shell. The capsule shell is a barrier with a surface that defines an interior void in which the resin agent or the crosslinking agent is present. The capsule shell encapsulates the contained fluid or solid, and the contained fluid or solid is separated from other fluids, such as its associated agent or a wellbore fluid.
The capsule shell is configured to rupture or disassociate upon exposure to an appropriate sonic frequency. The shell by be ruptured directly by the sonic frequency forms acting upon the capsule shell, the shell agent, or the fluid contained within. The shell may also be ruptured by the microfluid jets within the wellbore fluid impacting the surface of the capsule shell and damaging or disintegrating the capsule shell. Through either mechanism, or both, or others, once the capsule shell is ruptured, the contained agent is exposed to the wellbore fluid and, potentially, its associated counteragent.
In one or more embodiments, the resin agent is not encapsulated. In such embodiments, the resin agent may be introduced into the wellbore fluid without a shell. In such an instance, the only LCM agent capsules introduced into the wellbore fluid are crosslinking agent capsules.
“Micro-sized” is defined as having an average dimension, such as a diameter (sphere), a diagonal (cube, prism), or an average of a length and a diameter (ellipsoid) in a range of from about 100 micrometers (μm) to about 100 nanometers. “Nano-sized” is defined similarly in a range of from about 100 nanometers (nm) to 1 nanometer.
In one or more embodiments, the thickness of the capsule shell may be in a range of from about 500 nm to 10 μm.
The capsule shell is configured such that the capsule shell is operable to withstand the wellbore conditions, including elevated temperatures, elevated pressure, and elevated salinity. “Elevated” in the context of temperature and pressure means greater than room temperature and pressure, respectively. “Elevated” in the terms of salinity means greater than the salinity of fresh water, such as one of ordinary skill would expect for a brine, many wellbore fluids, a brine, or formation water.
The capsule shell may be made of a resin agent. The resin agent may be configured to encapsulate the cross-linking agent. The capsule shell may also be made of a shell agent. The shell agent used to encapsulate the resin agent, the crosslinking agent, or both separately, is not configured to react or otherwise neutralize the contained agent from its purpose of forming LCM upon reaction with its associated counter material. The shell agent does not prevent the contained agent from being released upon exposure to an appropriate sonic frequency.
In one or more embodiments, the resin agent and the crosslinking agent are encapsulated using capsule shell comprising the same shell agent. In one or more embodiments, the resin agent and the crosslinking agent are encapsulated using capsule shell comprising different shell agents. For example, the resin agent may be encapsulated by a first polymer while the crosslinking agent may be encapsulated by a Pickering stabilizer or a second polymer.
In one or more embodiments, the shell agent useful for encapsulation may comprise a polymeric material. Useful types of polymeric materials may include, but are not limited to, melamine-formaldehyde, urea-formaldehyde, phenol-formaldehyde, melamine-phenol-formaldehyde, furan-formaldehyde, epoxy, polysiloxane, polyacrylate, polyester, polyurethane, polyamide, polyether, polyimide, polyolefin, polypropylene-polyethylene copolymers, polystyrene, functionalized polystyrene derivatives, gelatin, gelatin derivatives, cellulose, cellulose derivatives, starch, starch derivatives, polyvinyl alcohol, ethylene-vinylacetate copolymers, maleic-anhydride based copolymers, polyacrylamide, polyacrylamide based copolymers, polyacrylic acid, polyacrylic acid based copolymers, polyvinylpyrrolidone, polyvinylpyrrolidone based copolymers, polyacrylate based copolymers, polyacrylamide, polyacrylamide based copolymers, propylene-acrylate copolymers, propylene-methacrylate copolymers, oxidized polypropylene, oxidized polyethylene, propylene-ethylene oxide copolymers, styrene-acrylate copolymers, and acrylonitrile-butadiene-styrene copolymers.
In one or more embodiments, the shell agent for encapsulation may be comprised of Pickering stabilizer. Pickering stabilizers are nanoparticles that have surface-active properties. Pickering stabilizers are solid materials that stabilize an emulsion between two phases, such as a liquid hydrocarbon phase and an aqueous phase, by absorbing onto the interface of the dispersed phase. In this case, the Pickering stabilizers surround the agent—the resin or the crosslinker as the disperse phase—and form a solid barrier at the interface between the agent and the external continuous phase. The nanoparticles prevent premature reaction between the two agents and permit the agents to be handled more like solid particles than liquids. Non-limiting examples of Pickering stabilizers include silica nanoparticles, clay nanoplatelets, polymer latexes, graphene oxide, and combinations thereof.
The agent capsule containing either crosslinking agent or resin agent are configured to be buoyant in the wellbore fluid for which they are introduced into, as one of ordinary skill would appreciate. In one or more embodiments, the specific gravity of the capsules to the mud may be from approximately 0.8 to 1.2. In one or more embodiments, the diameter of an agent capsule is in a range of from about 0.5 μm (micrometer) to 1000 μm, such as in a range of from about 1 μm to 500 μm.
In one or more embodiments, a treatment sub is introduced into a wellbore and positioned proximate to a face of a lost circulation zone. The treatment sub may be introduced as part of a treatment system.
Bifurcation view line A-A′ of
There are several options for providing power to a sonic frequency source of a treatment sub. As previously described, the treatment sub may have an onboard battery that provides powers to one or more sonic frequency sources. In some configurations, there may be a battery unit that is a separate part of the BHA that is electrically coupled to the treatment sub that provides power. Another option is a “mud motor” that may be used to convert flow energy of the wellbore fluid passing through the internal fluid conduit of the BHA into electrical power. An electrical conduit optionally coupled to a power source at the surface, such as a generator or a utility line, may be used to provide power directly to the sonic frequency source. Other options are available and are appreciated by one of ordinary skill in the art.
Several options known to those of skill in the art are feasible for communicating with the treatment sub. As shown in
As shown in
In one or more embodiments, the sonic frequency source is configured to generate multiple sonic frequencies simultaneously. For example, a single sonic frequency source may generate a plurality of acoustic frequencies.
In one or more embodiments, the sonic frequency source may be configured to generate a single frequency. However, as is understood by those skilled in the art, even a single frequency generally includes a narrow range of frequencies. Thus, as used herein, “a single frequency” generally refers to a narrow spectrum of acoustic frequencies. In one or more embodiments, the sonic frequency source is configured to generate sonic frequency at multiple frequencies. In one or more embodiments, the sonic frequency source is configured to generate a single type of sonic frequency at multiple sonic frequencies sequentially. For example, the sonic frequency source may generate an ultrasonic frequency comprised of a first single frequency during a first period and then alternate to a second single frequency during a second period. In one or more embodiments, the sonic source is configured to generate multiple sonic frequencies simultaneously. In such configurations, the periods may be very short to cause oscillations in the patterns in the sonic frequency. For example, an acoustic source may generate a sonic frequency comprised of a plurality of acoustic frequencies. In such embodiments, a plurality of sonic sources may be included and configured in the BHA system to provide the plurality of frequencies. This frequency oscillation may facilitate bubble generation and cavitation, capsule rupture, or reaction of the LCM agents.
Each sonic frequency source may be configured to direct a generated frequency independently of or in coordination with another sonic frequency source. In one or more embodiment, a plurality of sonic frequency sources may be configured such that a plurality of generated frequencies may not intersect. In the example provided for regarding treatment sub 400A, both sonic frequency sources 452A, 452B are configured such that the generated frequencies produced are directed normally 454′ towards wellbore wall 1022. With this configuration, the generated frequencies from sonic frequency sources 452A, 452B are directed such that they are effectively parallel to one another. Because of the distance between the sub exterior surface 428 of the treatment sub 400A and a surface, such as a wellbore wall 1022 as given in
In one or more embodiments, a plurality of sonic frequency sources may be configured such that at least some of the plurality of generated frequencies intersect within the annulus of a wellbore. In one or more embodiments, a plurality of sonic frequency sources may be configured such that a plurality of generated frequencies may intersect at a wellbore wall. In one or more embodiment, a plurality of sonic frequency sources may be configured such that a plurality of generated frequencies may intersect within a subterranean formation.
In one or more embodiments, the configuration of the transmission sub permits the formation of a standing sonic frequency within the wellbore fluid. In one or more embodiments, travelling sonic frequencies may be generated using instruments such as an acoustic tweezer. Acoustic tweezers may generally be used to concentrate LCM capsules and move them to desired locations using acoustic waves at given frequencies.
Bifurcation view line B-B′ of
The treatment area may be described in relative terms of the total (cross-sectional) area of the wellbore annulus at the position of the wellbore where the sonic frequency source is present. The plane of such a cross-sectional area of the wellbore annulus would be normal to the longitudinal axis of the treatment sub. For example, in
Bifurcation view line B-B′ of
Bifurcation view line B-B′ of
The term “total” means 100% of the overall value of something by the stated unit of measure (for example, area, mass, volume, mole). The term “majority” means greater than 50.00% but less than 100% that is, less than totality) of the overall value of something by the stated unit of measure. The term “substantial” means greater than 10.00% but less than or equal to 50.00% (that is, less than a majority) of the overall value of something by the stated unit of measure. The term “significant” means greater than 1.00% but less than or equal to 10.00% (that is, less than substantial) of the overall value of something by the stated unit of measure. The term “detectable” means equal to or greater than 0.01% but less than or equal to 1.00% (that is, less than significant) of the overall value of something by the stated unit of measure. The term “incidental” means less than 0.01% of the overall value of something by the stated unit of measure. However, “incidental” does not exclude something; rather, the term indicates that if determined to be present using industry-available analytical equipment its presence may be considered is de minimus for the purposes of this application.
In one or more embodiments, the treatment sub is configured such that the treatment area is the total cross-sectional area of the wellbore annulus. In one or more embodiments, the treatment sub is configured such that the treatment area is a majority of the cross-sectional area of the wellbore annulus. In one or more embodiments, the treatment sub is configured such that the treatment area is a substantial cross-sectional area of the wellbore annulus. In one or more embodiments, the treatment sub is configured such that the treatment area is a significant cross-sectional area of the wellbore annulus. In one or more embodiments, the treatment sub is configured such that the treatment area is a detectable cross-sectional area of the wellbore annulus. In one or more embodiments, the treatment sub is configured such that the treatment area is an incidental cross-sectional area of the wellbore annulus. In one or more embodiments, the treatment area is in a range of from about 0.1 to 100% of the cross-sectional area of the wellbore annulus.
Bifurcation view line B-B′ of
In one or more embodiments, the treatment sub is configured such that the treatment area is the total cross-sectional area of the internal fluid conduit. In one or more embodiments, the treatment sub is configured such that the treatment area is a majority of the cross-sectional area of the internal fluid conduit. In one or more embodiments, the treatment sub is configured such that the treatment area is a substantial cross-sectional area of the internal fluid conduit. In one or more embodiments, the treatment sub is configured such that the treatment area is a significant cross-sectional area of the internal fluid conduit. In one or more embodiments, the treatment sub is configured such that the treatment area is a detectable cross-sectional area of the internal fluid conduit. In one or more embodiments, the treatment sub is configured such that the treatment area is an incidental cross-sectional area of the internal fluid conduit. In one or more embodiments, the treatment area is in a range of from about 0.1 to 100% of the cross-sectional area of the internal fluid conduit.
In the partial reveal feature of
The agent capsule container may contain one or more types of LCM agent capsules. In one or more embodiments, the agent capsule container may contain a plurality of LCM agent capsules. In such an embodiment, the plurality of LCM agent capsules are only resin agent capsules. In other such embodiments, the plurality of LCM agent capsules are only crosslinking agent capsules. In yet other embodiments, the plurality of LCM agent capsules are a combination of both resin agent capsules and crosslinking agent capsules.
In one or more embodiments, the treatment sub may be fitted with a plurality of agent capsule containers. For example, the treatment sub 600A is shown with an agent capsule container 660 and a second agent capsule container 663. In one or more embodiments, each agent capsule container contains the same mixture of resin agent capsules and crosslinking agent capsules. This may permit multiple treatments for multiple detected LCZs. In one or more embodiments, each capsule container contains a different type of LCM agent capsule. Such a configuration may permit a single yet massive distribution of LCM agent capsules downhole in an attempt to halt a detected LCZ. Other configurational and operational aspects of the plurality of the agent capsule containers, such as where each container distributes capsules, size of each agent capsule container, mix of LCM agent capsules, and coordination or lack thereof in distributing LCM agent capsules with other agent capsule containers, is at the discretion of a person of ordinary skill.
In the partial reveal feature of
In the second example system provided for with treatment sub 600C, an electrochemical system 673 is shown. The electrochemical system is positioned within the sub interior 627 and is configured to generate a compressible gas product utilizing the wellbore fluid. In electrochemical system 673 of
An externally directed bubble generator 670 is positioned downstream of and fluidly coupled to the chemical reaction system 671. The externally directed bubble generator 670 not only is configured to transform the produced compressible gas product from the chemical reaction system into bubbles but also to direct the bubbles to the exterior of treatment sub 600B, such as into the wellbore annulus. In one or more embodiments, the chemical reaction system may be fluidly coupled to an internally directed bubble generator, such as internally directed bubble generator 672. The compressible gas products for the electrochemical system 673 are passed through internally directed bubble generator 672, where the compressible gas products are converted into bubbles and introduced into the wellbore fluid in the internal fluid conduit 1016 of the treatment sub 600C. In one or more embodiments, the electrochemical system may be fluidly coupled to an externally directed bubble generator.
In one or more embodiments, an additional material may be released from the treatment sub downhole. In such configurations, the additional material may be an agent that catalyzes the cross-linking reaction of the LCM. The additional material may also be configured to delay progression of the cross-linking reaction of the LCM.
In the partial reveal feature of
As one of ordinary skill may appreciate, none, some, or all of these optional features and others not specifically described here may be combined as part of a treatment sub for use in mitigating a lost circulation zone. As well, one of ordinary skill may also appreciate there are variations to such systems that are envisioned and appreciated.
One or more embodiments may include a modified wellbore fluid. The modified drilling wellbore comprises a wellbore fluid along with the previously described resin agent and the crosslinking agent.
The “wellbore fluid” is a wellbore service fluid, that is, a fluid used to drill (a “drilling fluid”), complete, work over, or in any way useful to service a well bore. For example, the wellbore fluid may serve as a drilling fluid, a completion fluid, a work-over fluid, a gravel packing fluid, a formation fracturing fluid, a stimulating fluid, or a packer fluid. Other types of fluids for which the wellbore fluid may be used would be apparent to one skilled in the art. The concentration of each component in the wellbore fluid depends upon the intended use of the wellbore fluid. For the purposes of this application, the terms “wellbore fluid” and “drilling fluid” are used interchangeably.
In one or more embodiments, a wellbore fluid includes an aqueous-based fluid. The aqueous-based fluid includes water. The water may be distilled water, deionized water, tap water, fresh water from surface or subsurface sources, production water, formation water, natural and synthetic brines, brackish water, natural and synthetic sea water, black water, brown water, gray water, blue water, potable water, non-potable water, other waters and combinations thereof that are suitable for use in a wellbore environment, that is, the contaminants do not interfere with the function of the drilling fluid. In one or more embodiments, the water used may naturally contain contaminants, such as salts, ions, minerals, organics, and combinations thereof, as long as the contaminants do not interfere with the function of the drilling fluid.
The wellbore fluid may contain water in a range of from about 50 to 97 wt % (weight percent) based on the total weight of the wellbore fluid. In one or more embodiments, the embodiment wellbore fluid may comprise greater than 70 wt % water based on the total weight of the wellbore fluid.
In one or more embodiments, the water used for the wellbore fluid may have an elevated level of salts or ions versus fresh water, such as salts or ions that are naturally present, such as in formation water, production water, seawater, and brines. In one or more embodiments, salts or ions are added to the water used to increase the level of a salt or ion in the water to effect certain properties, such as density of the wellbore fluid or to mitigate the swelling of clays that come into contact with the wellbore fluid, such as in “synthetic” brines and seawaters. Without being bound by any particular theory, increasing the saturation of water by increasing the salt concentration or other organic compound concentration in the water may increase the density of the water, and thus, the drilling fluid. Suitable salts may include, but are not limited to, alkali metal halides, such as chlorides, hydroxides, or carboxylates. In one or more embodiments, salts included as part of the aqueous-based fluid may include salts that disassociate into ions of sodium, calcium, cesium, zinc, aluminum, magnesium, potassium, strontium, silicon, lithium, chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, sulfates, phosphates, oxides, and fluorides, and combinations thereof. Without being bound by any particular theory, brines may be used to create osmotic balance between the drilling fluid and portions of the subterranean formation. Salts present in aqueous-based drilling fluids may affect the electrostatic interactions between the polymers described here and the surface of tools used in drilling.
In one or more embodiments, the wellbore fluid may comprise one or more salts in an amount that ranges from about 1 to 300 ppb (pounds per barrel). For example, the drilling fluid may contain the one or more salts in an amount ranging from a lower limit of any of 1, 10, 50, 80, 100, 120, 150, 180, 200, 250, and 280 ppb to an upper limit of any of 20, 30, 40, 50, 70, 100, 120, 150, 180, 200, 220, 240, 260, 280, and 300 ppb, where any lower limit can be used in combination with any mathematically-compatible upper limit.
In one or more embodiments, the wellbore fluid may include at least one pH adjuster. The drilling fluid composition may optionally include at least one alkali compound. Examples of alkali compounds may include, but are not limited to, lime (calcium hydroxide, calcium oxide, or a mixture thereof), soda ash (sodium carbonate), sodium hydroxide, potassium hydroxide, and combinations thereof. The alkali compounds may react with gases, such as CO2 or H2S (also known as acid gases), encountered by the drilling fluid composition during drilling operations to prevent the gases from hydrolyzing components of the drilling fluid composition. In one or more embodiments, the wellbore fluid compositions may optionally include having a pH adjuster in a range of from about 0.01 wt % to 0.7 wt %, such as from 0.01 wt % to 0.5 wt %, from 0.01 wt % to 0.3 wt %, from 0.01 wt % to 0.1 wt %, from 0.01 wt % to 0.05 wt %, from 0.05 wt % to 0.7 wt %, from 0.05 wt % to 0.5 wt %, from 0.05 wt % to 0.3 wt %, from 0.05 wt % to 0.1 wt %, from 0.1 wt % to 0.7 wt %, from 0.1 wt % to 0.5 wt %, from 0.1 wt % to 0.3 wt %, from 0.3 wt % to 0.7 wt %, from 0.3 wt % to 0.5 wt %, or from 0.5 wt % to 0.7 wt % pH adjuster based on the total weight of the drilling fluid composition. Some drilling fluid compositions may optionally include in a range of from about 0.01 ppb to 10 ppb of at least one pH adjuster based on the total volume of the drilling fluid composition.
The wellbore fluid may have a neutral or alkaline pH. In one or more embodiments, the drilling fluid may have a pH in a range of from about 7 to 11, such as from about 7, 7.5, 8, 8.5, 9, 9.5, and 10 to about 7.5, 8, 8.5, 9, 9.5, 10, 10.5, and 11, where any lower limit may be combined with any mathematically feasible upper limit.
Optionally, in one or more embodiments, the drilling fluid may include weighting agents that may be dispersed in the drilling fluid. The solids may be finely divided having a specific gravity (SG) that when added to an aqueous-based fluid may increase the density of the drilling fluid. Examples of weighting materials suitable for use include, but are not limited to, barite (minimum SG of 4.20), hematite (minimum SG of 5.05), calcium carbonate (minimum SG of 2.7-2.8), siderite (minimum SG of 3.8), ilmenite (minimum SG of 4.6), magnesium tetroxide (minimum SG of 4.8), and combinations thereof.
The wellbore fluid may include an amount of weighting material sufficient to increase the density of the drilling fluid composition to allow the drilling fluid composition to support the wellbore and prevent fluids in downhole formations from flowing into the wellbore. The wellbore fluid composition may include weighting material in a range of from about 1 to about 30 wt % based on the total weight of the drilling fluid composition. For example, the wellbore fluid may contain weighting agents in an amount ranging from about 1 to 700 ppb, such as from about 10 to 650 ppb, from about 50 to 700 ppb, or from about 100 to 600 ppb, or from about 200 to 500 ppb.
In one or more embodiments, the wellbore fluid may have a density in a range of from about 62 pounds cubic foot (pcf) to about 170 pcf as measured using Fann Model 140 Mud Balance according to ASTM Standard D4380. For instance, the wellbore fluid may have a density in a range of from about 63 pcf to 150 pcf, such as from about 65 pcf to 140 pcf, from about 70 pcf to 160 pcf, from about 80 pcf to 150 pcf, from about 90 pcf to 140 pcf, from about 100 pcf to 160 pcf, from about 70 pcf to 150 pcf, from about 70 pcf to 100 pcf, and from about 120 pcf to 160 pcf. The drilling fluid may have a density that is greater than or equal to 62 pcf, such as greater than or equal to 70 pcf, and such as greater than or equal to 100 pcf.
In one or more embodiments, the modified wellbore fluid may include the previously described resin agent. In one or more embodiments, the modified wellbore fluid includes the previously described resin agent and the crosslinking agent. In one or more embodiments, one or more of the agents may be encapsulated. Components of the modified wellbore fluid, such as the resin agents and the crosslinking agent, may be added to the wellbore fluid as needed during continued operations, such as drilling operations, either simultaneously or separately.
In one or more embodiments, a method of treating a loss circulation zone is disclosed.
In one or more embodiments, a treatment sub is introduced into the wellbore. In
In one or more embodiments, the treatment system introduced consists of or consists essentially of the treatment tool coupled to the distal end of a drill pipe, wireline, or coiled tubing. In such a configuration, the treatment sub is not part of a BHA or drill string; rather, the treatment sub is mounted on the end of a drill pipe, wireline, or coiled tubing and is then introduced into the wellbore as a dedicated downhole tool to mitigate a previously-detected lost circulation zone. Such a dedicated treatment sub solution may be utilized in an instance where a prior treatment of the LCZ is not satisfactory or the treatment sub was not initially included as part of a BHA package.
The treatment sub introduced into the wellbore may be configured as previously described, such as the various treatment sub configurations provided for in
In one or more embodiments, lost circulation in the wellbore is detected. The method 700 includes detecting lost circulation of the wellbore fluid from the wellbore 704. During drilling operations, a lost circulation zone may be encountered and traversed. One of ordinary skill in the art of drilling mud management has the skill, information, and experience necessary to detect even a minor outflow of wellbore fluid into an underpressurized or non-saturated formation structure, such as a vug, a non-pay sand, or a fault, that may make up a LCZ.
In one or more embodiments, a determination of the rate of outflow through the LCZ may be made. The determination of the rate of outflow may be made from a determination of the rate of loss. The determination of the rate of loss of the LCZ may be categorized as a seepage loss, a partial loss, a severe loss, or a complete loss. In such categorizations, the seepage loss may be up to 1 m3/h (meters cubed per hour), the partial loss may be up to 10 m3/h, the severe loss may be up to 15 m3/h, or the complete loss may yield no return flow.
In making such a determination, a person of ordinary skill may determine, in turn, a sufficient amount of resin agent and crosslinking agent to introduce into the lost circulation zone to mitigate the LCZ. In one or more embodiments, an amount of LCM capsules may be used to treat a severe loss or a complete loss. The amount of LCM capsules and a volume of the LCM capsules should be calculated based on an evaluation of the LCZ. The evaluation of the LCZ may include a determination of the diameter of a drilled area. In an exemplary embodiment, a determined rate of loss is 15 m3/h, and the determined diameter of the loss circulation zone of a drilled area is 12.25 inches. The amount of LCM capsules for LCZ treatment is determined to be 15-20 m3, and the amount of LCM capsules with a cross-linking agent will be determined by a required thickening time. The required thickening time may require a number of LCM capsules with a cross-linking agent in a range of 1000 to 2500 kg (kilograms).
The method 700 includes halting drilling activities 706. In one or more embodiments, halting the wellbore drilling program in response to the detection of lost circulation. In one or more embodiments, the rate of wellbore fluid circulation may be increased in response to the detection of lost circulation. In one or more particular embodiments where the rate of lost circulation is minimal, drilling activities may continue while the LCM agent is introduced. In such embodiments, the LCM agent may be introduced via the drilling mud, for example.
The method 700 includes introducing a resin agent into the wellbore fluid 708. In one or more embodiments, a resin agent is introduced into the wellbore fluid. In one or more embodiments, the resin agent may be encapsulated within a capsule shell. In one or more embodiment, the capsule shell may comprise a polymer shell agent. In one or more embodiments, the capsule shell may comprise a Pickering stabilizer agent. In one or more embodiments, the capsule shell may further comprise a micro or nano-sized particle susceptible to magnetic waves. In one or more embodiments, the resin agent comprises an epoxide resin. In one or more embodiments, the resin agent further comprises a co-epoxide resin. In one or more embodiments, the resin agent is not encapsulated.
The wellbore fluid may be circulating through the wellbore and processed through the wellbore circulation system on the surface. In one or more embodiments, the resin agent is introduced into the wellbore fluid at the surface. In
In one or more embodiments, the resin agent is introduced into the wellbore fluid in the wellbore. As suggested by combining the treatment sub of
The treatment sub is operated by sending a command signal from a control system on the surface, such as well control system 1054 (comprising control signal lines 1046 and control terminal 1048 of
In one or more embodiments, where the resin agent is introduced into the wellbore fluid in an internal fluid conduit of the treatment sub. In one or more embodiments, the resin agent is introduced into the wellbore fluid in the wellbore annulus of the wellbore. As previously described as part of
The method 700 includes introducing a crosslinking agent into the wellbore fluid 710. In one or more embodiments, a crosslinking agent is introduced into the wellbore fluid. The crosslinking agent is encapsulated within a capsule shell. In one or more embodiments, the capsule shell may comprise a polymer shell agent. In one or more embodiments, the capsule shell may comprise a Pickering stabilizer agent. In one or more embodiments, the capsule shell for the resin agent and the crosslinking agent are comprised of the same shell agent. In one or more embodiments, the capsule shell of the cross-linking agent is the resin agent. In one or more embodiments, the crosslinking agent is an amine type curing agent. In one or more embodiments, the crosslinking agent further comprises a micro or nano-sized particle susceptible to magnetic waves.
In one or more embodiments, the crosslinking agent is introduced into the wellbore fluid at the surface. In one or more embodiments, the crosslinking agent is introduced into the wellbore fluid in the wellbore. In one or more embodiments, where the crosslinking agent is introduced into the wellbore fluid in an internal fluid conduit of the treatment sub. In one or more embodiments, the crosslinking agent is introduced into the wellbore fluid in a wellbore annulus of the wellbore.
In one or more embodiments, the introduction of each of the resin agent and the crosslinking agent into the wellbore fluid occurs at a same location. In one or more embodiments, the introduction of each of the resin agent and the crosslinking agent into the wellbore fluid occurs at different locations. For example, the resin agent may be introduced into the wellbore fluid at the surface whereas the crosslinking agent may be introduced into the wellbore fluid downhole.
In one or more embodiments, the introduction of both the resin agent and the crosslinking agent into the wellbore fluid may occur simultaneously. In one or more embodiments, the introduction of the resin agent and the introduction of the crosslinking agent into the wellbore fluid may occur sequentially.
Upon introduction of both the resin agent and the crosslinking agent into the wellbore fluid, the modified wellbore fluid forms.
In one or more embodiments, the treatment sub is operated such that a capsule conduit bypass is selectively opened. The method 700 includes operating the treatment sub such that the capsule conduit bypass is opened 712. As previously described, the treatment sub may be operated by transmitting a command signal that results in the treatment sub opening the capsules conduit bypass to be partially opened or fully open.
In one or more embodiments, the treatment sub is operated such that bubbles are introduced into the wellbore fluid. The method 700 includes operating the treatment sub such that the treatment sub introduces bubbles into the wellbore fluid 714. As previously described, the treatment sub may be operated by transmitting a command signal that results in the treatment sub producing a gas that is converted into bubbles using a bubble generator and introduced into the wellbore fluid. In one or more embodiments, the produced bubbles may be introduced into the wellbore fluid of the internal fluid conduit. In one or more embodiments, the produced bubbles may be introduced into the wellbore fluid in the wellbore annulus.
In one or more embodiments, the produced bubbles may be generated using a chemical reaction occurring inside the treatment sub. In one or more embodiments, the produced bubbles may be generated using an electrochemical reaction occurring inside the treatment sub.
In one or more embodiments, the treatment sub is operated such that a sonic frequency is generated in the wellbore fluid. The method 700 includes operating the treatment sub such that the treatment sub generates a sonic frequency in the wellbore fluid 716. As previously described, the treatment sub may be operated by transmitting a command signal that results in the treatment sub generating a sonic frequency in the wellbore fluid of the wellbore. In one or more embodiments, the treatment sub may generate a sonic frequency in the wellbore fluid of the internal fluid conduit. In one or more embodiments, the treatment sub may generate a sonic frequency in the wellbore fluid of the wellbore annulus.
In one or more embodiments, the sonic frequency may be comprised of an ultrasonic frequency with a range of from about 1 to 500 kHz. In generating a sonic frequency, cavitation of the wellbore fluid as previously described may occur.
In one or more embodiments, the sonic frequency generated may be a plurality of sonic frequencies. In one or more embodiments, the sonic frequency generated may comprise a plurality of types of sonic frequencies, such as an acoustic frequency and ultrasonic frequency.
In one or more embodiments, the generated sonic frequency may encompass a portion of the cross-sectional area of the wellbore annulus of the wellbore. In one or more embodiments, the generated sonic frequency may encompass a total cross-sectional area of the wellbore annulus. In one or more embodiments, the sonic frequency may encompass a majority of the cross-sectional area of the wellbore annulus. In one or more embodiments, the sonic frequency may encompass a substantial cross-sectional area of the wellbore annulus. In one or more embodiments, the sonic frequency may encompass a significant cross-sectional area of the wellbore annulus. In one or more embodiments, the sonic frequency may encompass a detectable cross-sectional area of the wellbore annulus. In one or more embodiments, the sonic frequency may encompass an incidental cross-sectional area of the wellbore annulus. In one or more embodiments, the sonic frequency may encompass an area in a range of from about 0.1 to 100% of the cross-sectional area of the wellbore annulus.
In one or more embodiments, the generated sonic frequency may encompass a portion of the cross-sectional area of the internal fluid conduit within the treatment sub. In one or more embodiments, the generated sonic frequency may encompass a total cross-sectional area of the internal fluid conduit. In one or more embodiments, the generated sonic frequency may encompass a majority of the cross-sectional area of the internal fluid conduit. In one or more embodiments, the generated sonic frequency may encompass a substantial cross-sectional area of the internal fluid conduit. In one or more embodiments, the generated sonic frequency may encompass a significant cross-sectional area of the internal fluid conduit. In one or more embodiments, the generated sonic frequency may encompass a detectable cross-sectional area of the internal fluid conduit. In one or more embodiments, the generated sonic frequency may encompass an incidental cross-sectional area of the internal fluid conduit. In one or more embodiments, the generated sonic frequency may encompass an area in a range of from about 0.1 to 100% of the cross-sectional area of the internal fluid conduit.
As previously described in association with
The method 700 includes maintaining both the wellbore and treatment sub for a treatment period 718. In one or more embodiments, the method optionally includes maintaining the wellbore and the treatment sub for a treatment period to permit formation and emplacement of the LCM. During this period, a number of actions are occurring in the wellbore: the product LCM is forming in the wellbore fluid from the crosslinking reaction between released resin agent and the crosslinking agent. In and around the generated sonic frequency, this process is accelerated as previously described. The product LCM is being circulated by the flow of the wellbore fluid into the face of the lost circulation zone. As the product LCM continues to react and harden into a solid polymer material, the product LCM settles and stacks in the lost circulation zone. This settling and stacking under the influence of differential pressure between the wellbore and the lost circulation zone fluidically seals the LCZ. Upon formation of the fluidic seal by the LCM product, the lost circulation zone has been mitigated.
Maintaining the wellbore during the treatment period includes a number of maintenance actions appreciated by those associated with lost circulation mitigation and general drilling operations, such as monitoring the wellbore fluid properties and detecting any changes to the wellbore fluid returns, such as a decrease or cessation of lost circulation. In one or more embodiments, the treatment period may be in a range of from about 0.1 to 24 hours. The treatment period in some instances may begin upon detection of lost circulation and the cessation of drilling activities. The treatment period in some instances may end upon the determination that lost circulation has been mitigated and drilling activities have resumed.
The method 700 includes determining that lost circulation of the wellbore fluid from the wellbore has been mitigated as shown in 720. One of ordinary skill in the art of drilling mud management has the skill, information, and experience necessary to determine that the lost circulation event has been mitigated by the treatment.
The method 700 includes the option of deactivating the treatment sub 722. One or more command signals may be transmitted to the treatment sub from the surface in order to deactivate the treatment sub depending upon features activated for the treatment. A command signal may be transmitted such that the treatment sub ceases generation of the sonic frequency in the wellbore fluid. Other signals may be communicated to the treatment sub. For example, a command signal may be transmitted such that the treatment sub ceases the generation of bubbles. In another example, a command signal may be transmitted such that the treatment sub selectively closes the capsule bypass conduit to halt bypass wellbore fluid flow.
The method 700 includes restarting the wellbore drilling program. In one or more embodiments, the wellbore drilling program may be resumed upon determination of the mitigation of the lost circulation zone.
The systems, apparatuses, and methods of use described here may provide at least one of the following advantages. Due to the targeted release of the resin agent and crosslinking agent, the crosslinking agent does not react with the resin agent in undesirable portions of the formation, where LCM solids may interfere with mechanical tools and devices or may pass through the drill bit nozzles. The reaction that forms the LCM is largely proximate to the face of the lost circulation zone or within the lost circulation zones. In instances where the treatment sub is part of a drill string in active drilling operations, the disruption to drilling operations is minimized. The treatment sub can be quickly positioned near the position of the detected lost circulation zone, the drilling fluid modified by the introduction of the resin agent and the capsules containing LCM resin crosslinking agent, and then treatment of the lost circulation zone with the transmission sub. After treatment, drilling operations may immediately resume.
The singular forms “a,” “an,” and “the” include plural referents, unless the context clearly dictates otherwise.
As used here and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.
When the word “approximately” or “about” are used, this term may mean that there can be a variance in value of up to ±10%, of up to 5%, of up to 2%, of up to 1%, of up to 0.5%, of up to 0.1%, or up to 0.01%.
“Optionally” means that the subsequently described event or circumstances may or may not occur. The description includes instances where the event or circumstance occurs and instances where it does not occur.
Ranges may be expressed as from about one particular value to about another particular value, inclusive. When such a range is expressed, it is to be understood that another embodiment is from the one particular value to the other particular value, along with all particular values and combinations thereof within the range.
While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims. Thus, particular implementations of the subject matter have been described. Other implementations are within the scope of the following claims.
Although only a few example embodiments have been described in detail, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the scope of the disclosure. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112 (f) for any limitations of any of the claims, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.
It is noted that one or more of the following claims utilize the term “where” or “in which” as a transitional phrase. For the purposes of defining the present technology, it is noted that this term is introduced in the claims as an open-ended transitional phrase that is used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term “comprising.” For the purposes of defining the present technology, the transitional phrase “consisting of” may be introduced in the claims as a closed preamble term limiting the scope of the claims to the recited components or steps and any naturally occurring impurities. For the purposes of defining the present technology, the transitional phrase “consisting essentially of” may be introduced in the claims to limit the scope of one or more claims to the recited elements, components, materials, or method steps as well as any non-recited elements, components, materials, or method steps that do not materially affect the novel characteristics of the claimed subject matter. The transitional phrases “consisting of” and “consisting essentially of” may be interpreted to be subsets of the open-ended transitional phrases, such as “comprising” and “including,” such that any use of an open-ended phrase to introduce a recitation of a series of elements, components, materials, or steps should be interpreted to also disclose recitation of the series of elements, components, materials, or steps using the closed terms “consisting of” and “consisting essentially of.” For example, the recitation of a composition “comprising” components A, B, and C should be interpreted as also disclosing a composition “consisting of” components A, B, and C as well as a composition “consisting essentially of” components A, B, and C. Any quantitative value expressed in the present application may be considered to include open-ended embodiments consistent with the transitional phrases “comprising” or “including” as well as closed or partially closed embodiments consistent with the transitional phrases “consisting of” and “consisting essentially of.” The words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.
| Number | Date | Country | Kind |
|---|---|---|---|
| 2022104769 | Feb 2022 | RU | national |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2023/013755 | 2/24/2023 | WO |
