Patent Application
20130062072
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The present inventions relate to the field of wellbore completions. More specifically, the inventions relate to systems and methods for isolating selected zones along a wellbore to facilitate the stimulation of those zones for the injection of acid.
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation.
A cementing operation is typically conducted in order to fill or “squeeze” the annular area with cement. This serves to form a cement sheath. The combination of cement and casing strengthens the wellbore and facilitates the isolation of the formations behind the casing.
It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. Thus, the process of drilling and then cementing progressively smaller strings of casing is repeated several or even multiple times until the well has reached total depth. The final string of casing, referred to as a production casing, is cemented into place. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface, but is hung from the lower end of the preceding string of casing.
In some instances, a well may be completed as an open-hole completion. This means that the final tubular body run into the wellbore is not cemented into place; instead, a perforated liner may be installed. Where the producing formation is located in a sandstone or other loose or unconsolidated formation, a sand screen may alternatively be used. A production string or “tubing” is then positioned inside the wellbore extending down to the last string of casing.
There are certain advantages to open-hole completions versus cased hole completions. First, because open-hole completions have no perforation tunnels, formation fluids can converge on the wellbore radially 360 degrees. This has the benefit of eliminating the additional pressure drop associated with converging radial flow and then linear flow through particle-filled perforation tunnels. The reduced pressure drop associated with an open-hole completion virtually guarantees that it will be more productive than an unstimulated, cased hole in the same formation.
Second, open-hole completions, including gravel pack techniques, are oftentimes less expensive than cased hole completions. For example, the use of perforated liners and gravel packs eliminates the need for cementing, perforating, and post-perforation clean-up operations.
As an additional step in the wellbore completion process, production equipment such as tubing, packers and pumps may be installed within the wellbore. A wellhead (or “tree”) is installed at the surface along with fluid gathering and processing equipment. Production operations may then commence.
Before beginning production, it is sometimes desirable for the drilling company to “stimulate” the formation by injecting an acid solution through the casing. This is particularly true when the formation comprises carbonate rock. In operation, the drilling company injects a concentrated formic acid or other acidic composition into the wellbore, and directs the fluid along and even into the near-wellbore region. This is known as acidizing. The acid helps to dissolve carbonate material, thereby opening up porous channels through which hydrocarbon fluids may flow into the wellbore. In addition, the acid helps to dissolve drilling mud that may have invaded the formation. Acid stimulation as described above is a routine part of petroleum industry operations.
In many wellbores, it is now common to complete a well through multiple zones of interest. Such zones may represent up to about 30 meters (100 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation, then more complex treatment techniques may be required to obtain treatment of the entire target zone. In this respect, the drilling company must isolate various zones to ensure that each separate zone is adequately treated. In this way the operator is sure that stimulation fluid is being injected into each zone of interest or along the entire zone of interest to effectively increase the flow capacity at each desired depth.
To do this, various fluid diversion techniques may be employed. Two general categories of fluid diversion have been developed to help ensure that the acid reaches the desired rock matrix—mechanical and chemical. Mechanical diversion involves the use of a physical or mechanical diverter that is placed within the wellbore. Chemical diversion, on the other hand, involves the injection of a fluid or particles along and into the formation itself
Referring first to chemical diverters, chemical diverters include foams, particulates, gels, and viscosified fluids. Foam commonly comprises a dispersion of gas and liquid wherein a gas is in a non-continuous phase and liquid is in a continuous phase. Where acid is used as the liquid phase, the mixture is referred to as a foamed acid. In either event, as the foam mixture is pumped downhole and into the porous medium that comprises the original, more permeable formation, additional foam is generated. The foam initially builds up in the areas of high permeability until it provides enough resistance to force the acid into the new zone of interest having a lower permeability. The acid is then able to open up pores and channels in the new formation.
Particulate diverters consist of fine particles. Examples of known particulate diverters are cellophane flakes, oyster shells, crushed limestone, gilsonite, oil-soluble naphthalenes, and even chicken feed. Within the last several years, solid organic acids such as lactic acid flakes have been used. As the particles are injected, they form a low permeability filter-cake on the face of wormholes and other areas of high permeability in the original formation. This then forces acid treatment to enter the new zone(s) of interest. After the acidizing treatment is completed, the particulates hydrolyze in the presence of water and are converted into acid.
Viscous diverters are highly viscous materials, sometimes referred to as gels. Gels use either a polymer or a viscoelastic surfactant (VES) to provide the needed viscosity. Polymer-based diverters crosslink to form a viscous network upon reaction with the formation. The crosslink breaks upon continued reaction and/or with an internal breaker. VES-based diverters increase viscosity by a change in micelle structure upon reaction with the formation. As the high-viscosity material is injected into the formation, it fills existing wormholes. This allows acid to be injected into areas of lower permeability higher in the wellbore. The viscosity of the gel breaks upon exposure to hydrocarbons (on flowback) or upon contact with a solvent.
Chemical diverters may have limited effectiveness in certain situations. For example, if the density of the acid and the diverting fluid is considerably different, or if the wellbore significantly deviates from vertical, the interface of the acid with the diverter may break down or experience distortion while traveling down the wellbore. In some cases, this distortion may involve the mixing of acid and an acid-containing diverter. This, in turn, reduces the viscosity of the diverter, thereby reducing the diverter effectiveness and the overall performance of the stimulation job. Depending on stage size, fluid density, fluid viscosity, and pumping rate, the interface distortion may be severe.
Referring now to mechanical diverters, various types of mechanical diverters have been employed. These generally include ball sealers, plugs, and straddle packers. For example, U.S. Pat. No. 3,289,762 uses a ball that seats in a baffle to cause mechanical isolation. U.S. Pat. No. 5,398,763 uses a wireline to set and then to retrieve a baffle. The baffle isolates a portion of a formation for the injection of fluids. U.S. Pat. No. 6,491,116 provides a fracturing plug, or “frac plug.” Frac plugs are common in the industry and rely upon a ball that is either dropped from the surface to land on a seat, or that is integral to the plug itself. Frac plugs generally require a wireline for setting. Frac plugs may also be retrieved via wireline, although in some instances frac plugs have been fabricated from materials that can be drilled out. Drilling out the material adds time and expense to the stimulation operation.
Mechanical plugs are used to isolate an interval after successfully stimulating each zone. Although the stimulation of each zone separately can be very effective, multiple electric line runs and acid stimulations may be required to fully stimulate a long interval, increasing the time and cost of the acid treatment. Further, while mechanical plugs can provide high confidence that formation treatment fluid is being diverted, there is a risk of incurring high costs due to mechanical and operational complexity of the plugs. Plugs may become stuck in the casing resulting in a lengthy and costly fishing operation. If unsuccessful, a drill rig may be needed to be brought on-sight to drill the plug out. Drilling out the plug is not preferred due to the time and cost associated with mobilizing a drill rig on location. In some situations, the well may have to be sidetracked or even abandoned. Mechanical plugs particularly have a history of reliability issues in large diameter wells. In this respect, it can be difficult to locate a plug suitable for a large borehole, and those that are available have a history of failures.
A need therefore exists for an acid diverting system and method that offers the reliability of a mechanical plug without the risk of mechanical failure or sticking. Further, a need exists for a system that optimizes the acid circulation process by removing the need for a wireline, and yet has greater reliability than a viscous chemical diverter. A need further exists for a system that improves the stimulation of a formation along the entire length of a deviated, open-hole wellbore.
A system is provided for stimulating a multi-zone well. The system first includes a pre-perforated tubular body. The tubular body is dimensioned to be received within a wellbore. In one aspect, the tubular body is a liner made up of a plurality of joints.
The tubular body comprises pre-drilled holes placed along a wall of the tubular body. The holes may be arranged in repeating patterns. The tubular body is also apportioned into at least a first zone and a second zone. Optionally, a third zone (and additional zones) may also be provided. The tubular body extends at least 10 feet (3.0 meters) along each of the first, second, and third zones. Preferably, the third zone has a measured depth that is less than the second zone, while the second zone has a measured depth that is less than the first zone. However, the inverse may apply.
The wellbore may be completed substantially vertically. Alternatively, the wellbore may be completed as a deviated wellbore. In one aspect, the deviated wellbore is completed to have a substantially horizontal portion such that the horizontal portion has a heel and a toe. In one aspect, the first zone resides at the toe of the horizontal portion of the wellbore.
The system has at least two sets of dissolvable plugs. A first set of plugs is placed in holes along the pre-perforated tubular body within the first zone. The plugs in the first set of plugs are fabricated to substantially dissolve upon contact with an acidic stimulation fluid within a first selected time. A second set of dissolvable plugs is placed in holes along the tubular body within the second zone. The plugs in the second set of plugs are fabricated to substantially dissolve upon contact with the acidic fluid within a second selected time that is greater than the first selected time. A third set of dissolvable plugs is optionally placed in holes along the tubular body within a third zone. The plugs in the third set of plugs are fabricated to substantially dissolve upon contact with the acidic fluid within a third selected time that is greater than the second selected time. Alternatively, holes placed along the third zone may not have plugs.
The acidic fluid may comprise, for example, hydrochloric acid, acetic acid, or formic acid. The acid is used to clean drilling mud damage and stimulate the reservoir rock before the well is brought on line for production.
In one preferred aspect of the system, the pre-perforated tubular body further comprises a fourth zone. The fourth zone has a measured depth that is greater than the first zone, and resides at the toe of the horizontal portion of the wellbore. The holes in the tubular body along the fourth zone do not have the dissolvable plugs. In this way, an initial injection of stimulation fluid immediately enters the near-wellbore region adjacent to the fourth zone.
Concerning the plugs, in one embodiment each dissolvable plug is fabricated to have a central body. The central body has a diameter that is dimensioned to closely fit within a diameter of a respective pre-drilled hole in the tubular body. In addition, each plug has a top end. The top end has a diameter that is larger than the diameter of the respective hole in the tubular body. In addition, each plug has a bottom end. The bottom end has a diameter that is at least as large as the diameter of the respective pre-drilled hole in the tubular body. The bottom end is preferably partially fabricated from an elastomeric material so that it may be compressed and inserted through the respective hole.
A method of stimulating a multi-zone well using an acidization treatment is also provided herein. In one embodiment, the method includes setting a pre-perforated tubular body in a wellbore. The tubular body preferably comprises a plurality of joints, and is dimensioned to be received within a wellbore. The tubular body may be, for example, a liner.
The tubular body comprises a plurality of perforations, or holes, pre-drilled into a wall of the tubular body. The holes may be arranged in repeating patterns along the tubular body. The tubular body is also apportioned into at least a first zone and a second zone. Optionally, the tubular body may be further apportioned into a third zone.
The tubular body includes a first set of dissolvable plugs. These plugs are placed in the holes along the tubular body within the first zone. Each of the plugs in the first set of plugs is fabricated to substantially dissolve upon contact with an acidic stimulation fluid within a first selected time.
The tubular body also includes a second set of dissolvable plugs. These plugs are placed in the holes along the tubular body within the second zone. Each of the plugs in the second set of plugs is fabricated to substantially dissolve upon contact with the acidic stimulation fluid within a second selected time that is greater than the first selected time.
The pre-perforated tubular body may further include a third set of dissolvable plugs. These plugs are placed in the holes along the tubular body within the third zone. Each of the plugs in the third set of plugs is fabricated to substantially dissolve upon contact with the acidic stimulation fluid within a third selected time that is greater than the second selected time.
The method also includes injecting an acidic solution into the well under pressure. The acidic fluid may be, for example, hydrochloric acid or formic acid. Injecting the acidic solution causes the first set of plugs to dissolve. This exposes a subsurface formation outside of the tubular body along the first zone. This further insures that the formation along the first zone is adequately treated without concern that some acidic fluid will be lost along the second and third zones.
The method further includes injecting the acidic solution into the well under pressure so as to dissolve the second set of plugs. Injecting the acidic solution causes the second set of plugs to dissolve. This, in turn, exposes a subsurface formation outside of the tubular body along the second zone.
Where a third zone is provided along the tubular body, the method also includes further injecting the acidic solution into the well under pressure so as to dissolve the third set of plugs. Injecting the acidic solution causes the third set of plugs to dissolve. This, in turn, exposes a subsurface formation outside of the tubular body along the third zone.
Preferably, the third zone has a measured depth that is less than the second zone, and the second zone has a measured depth that is less than the first zone. However, the inverse may apply.
The wellbore may be completed substantially vertically. Alternatively, the wellbore may be completed as a deviated wellbore. In one aspect, the deviated wellbore is completed to have a substantially horizontal portion such that the horizontal portion has a heel and a toe.
In one aspect, the tubular body further comprises a fourth zone. Note that the term “fourth”, and similar numeric indicators used herein, are merely used herein to simplify illustration and discussion purpose only, as in relation to the exemplary embodiments discussed herein. Same for such terms as used in the claims. Such numeric terms are not intended to be defined narrowly in relation to only a specific and sequential set of only such zones, nor does they indicate that there are only such number of zones in the wellbore.
In still other aspects, the wellbore contains a fourth or additional zone. Such zone merely has a measured depth that is greater than the first zone, and for illustration purposes, resides at or near the toe of a horizontal portion of the wellbore. The holes in the tubular body along the fourth zone do not have plugs. The method then further comprises injecting the acidic solution into the well under pressure so as to expose a subsurface formation along or near the toe of the wellbore to an acid solution before the acidic solution contacts the subsurface formation along at least the first (or other) zone.
In another aspect, the inventive methods include performing a wellbore fluid swap while the annulus is open or not yet packed off, by circulating or otherwise introducing weak-acid or substantially non-reactive fluids (e.g., fluids that do not substantially immediately stimulate the formation or react substantially with the completion component materials) into the well such as over the full or partial length of the completion section of the wellbore. Such process may leave the wellbore conditioned or otherwise prepared for more substantial and reactive acid or other stimulation. It is understood that in the presence of swellable packers such fluids are circulated before the packers completely swell.
So that the present inventions can be better understood, certain drawings, charts, graphs and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.
In
In
Definitions
As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring, hydrocarbons including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.
As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions, or at ambient conditions (15° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coal bed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.
As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, and combinations of liquids and solids.
As used herein, the term “condensable hydrocarbons” means those hydrocarbons that condense at about 15° C. and one atmosphere absolute pressure. Condensable hydrocarbons may include, for example, a mixture of hydrocarbons having carbon numbers greater than 4.
As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.
As used herein, the term “formation” refers to any definable subsurface region. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation.
The terms “zone of interest” or “interval” refers to a portion of a formation containing hydrocarbons.
As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shapes. As used herein, the term “well”, when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”
The term “tubular member” refers to any pipe, such as a joint of casing, a portion of a liner, or a pup joint.
The term “perforation” includes a pre-drilled hole or slot placed in a tubular body.
The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions.
The wellbore 100 includes a wellhead, shown schematically at 120. The wellhead 120 contains various items of flow control equipment such as a lower master fracturing valve 122 and an upper master fracturing valve 124. It is understood that the wellhead 120 will include other components during the formation and completion of the wellbore 100, such as a blowout preventer (not shown).
The wellbore 100 has been completed by setting a series of pipes into the subsurface 110. These pipes include a first string of casing 130, sometimes known as surface casing or a conductor. These pipes also include a final string of casing 150, known as a production casing. The pipes also include one or more sets of intermediate casing 140. Typically, the surface 130 and intermediate 140 strings of casing are set in place through cement 115.
Referring specifically to the production casing 150, the production casing 150 may also be set in place using a cement sheath 115. However, in the illustrative wellbore arrangement of
The illustrative wellbore 100 is completed horizontally. A horizontal portion is shown at 160. The horizontal portion 160 has a heel 162. The horizontal portion 160 also has a toe 164 that extends through a hydrocarbon-bearing interval. While the wellbore 100 is shown as a horizontal completion, it is understood that the present inventions have equal application in vertical wells or in deviated wells that extend through multiple formations or zones of interest.
In
The wellbore 100 also includes at least one packer 152. The at least one packer 152 is placed along the outer diameter of the liner 150. In the arrangement of
Swellable packers are known, and include at least one swellable packer element fabricated from a swelling elastomeric material. Suitable examples of swellable materials may be found in Easy Well Solutions' CONSTRICTOR™ or SWELLPACKER™, and Swellfix's E-ZIP™. The thickness and length of the swellable packer 152 must be able to expand to the wellbore wall and provide the required pressure integrity at that expansion ratio. The swellable packer 152 may be fabricated from a combination of materials that swell in the presence of both water and oil, respectively. Stated another way, the swellable packer element 152 may include two types of swelling elastomers—one for water and one for oil. In this situation, the water-swellable element will swell when exposed to the water-based drilling fluid or formation water, and the oil-based element will expand when exposed to hydrocarbon production.
Swellable elastomeric materials may include, for example, natural rubber; acrylate butadiene rubber; polyacrylate rubber; isoprene rubber; choloroprene rubber; butyl rubber; brominated butyl rubber; chlorinated butyl rubber; chlorinated polyethylene; neoprene rubber; styrene butadiene copolymer rubber; ethylene vinyl acetate copolymer; silicone rubbers; nitrile rubber; and many other swellable elastomeric materials. The swelling elastomeric material may be determined to swell in the presence of one of a conditioned drilling fluid, a completion fluid, a production fluid, an injection fluid, a stimulation fluid, or any combination thereof However, the present inventions are not limited to the particular design of the packer 152.
In completing the wellbore 100 for the production of hydrocarbons, the operator may wish to stimulate the formation “F” by circulating an acid solution. This serves to clean out residual drilling mud both along the wall of the borehole 105 and into the near-wellbore region (the region within formation “F” close to the production casing 150). However, and as noted above, known methods present technical difficulties, particularly in horizontal or highly deviated wells. Chemical diverters tend to mingle with the acid, making it difficult if not impossible to ensure that the entire formation is adequately treated; mechanical diverters can become stuck and oftentimes require numerous and time consuming trips in and out of the wellbore 100 with wirelines, setting tools, plugs, and other devices.
In addition, with long horizontal and highly deviated wells, the pressure differential along the wellbore makes it difficult to inject the acid treatment evenly. In this respect, the hydrostatic head formed by the fluid creates a high pressure at the heel 162 of the horizontal (or deviated) portion 160, while friction losses substantially reduce the pressure at the toe 164 of the horizontal portion 160. This pressure differential is particularly marked when the horizontal (or deviated) portion 160 is long, such as greater than 3,000 feet (914 meters), or even over 10,000 feet (3,048 meters).
To address these concerns, novel systems and methods are offered herein. Particularly, a pre-perforated tubular body is employed having small plugs (seen at 300 in
The liner 250 is a cylindrical body having a wall 252. The wall 252 defines a bore 254 running therethrough. In addition, the liner 250 has a plurality of pre-drilled holes 255. Preferably, the holes 255 are of the same diameter, and are spaced equi-distantly apart. The holes 255 may optionally be arranged in repeating patterns, such as the one shown in
It is understood that the liner 250 is actually an elongated tubular body. The liner 250 is preferably made up of a plurality of joints in order to extend hundreds and perhaps thousands of feet through one or more subsurface zones of interest. The liner 250 may be interrupted by one or more packers, such as swellable packer 152. In this case, the liner 250 may further be interrupted by short sections of blank pipe 153 on either end of the packer 152.
The holes 255 in the liner 250 are dimensioned to receive a dissolvable plug 300.
The plug 300 has a central body 310. The central body 310 has a diameter D1 that is dimensioned to closely slide and fit into the holes 255. The central body 310 is preferably a substantially rigid, cylindrical body. In another embodiment, the central body 310 may be covered by or be made of elastomeric material.
The plug 300 also has a top end 320. The top end 320 is arranged as a small, rigid disc that is connected to the central body 310 at one end. The top end 320 has a diameter D2 that is slightly greater than diameter D1. In addition, diameter D2 is dimensioned to be larger than the diameter of the pre-drilled holes 255. In this way, the top end 320 will rest on an outer surface of the liner 250.
The plug 300 also has a bottom end 330. The bottom end 330 is also arranged as a small, rigid disc, and is connected to the central body 310 at an end opposite the top end 320. The bottom end 330 has a diameter D3 that is slightly greater than diameter D2. In addition, the bottom end 330 includes a circular wing or edge 332, fabricated from a flexible, elastomeric material. The elastomeric nature of the edge 332 allows the bottom end 330 to be compressed and placed through a pre-drilled hole 255. Optionally, the entire bottom end 330 is fabricated from a thin, highly elastomeric material.
The plug 400 also has a top end 420. The top end 420 is arranged as a small, rigid disc that is connected to the central body 410 at one end. The top end 420 has a diameter D2 that is slightly greater than diameter D1. In addition, diameter D2 is dimensioned to be at least as large as the diameter of the pre-drilled holes 255. In this way, the top end 420 will rest on an outer surface of the liner 250. In addition, the top end 420 includes a circular wing or edge 422, fabricated from a flexible, elastomeric material.
The plug 400 also has a bottom end 430. The bottom end 430 is also arranged as a small, rigid disc, and is connected to the central body 410 at an end opposite the top end 420. The bottom end 430 has a diameter D3 that optionally is slightly greater than diameter D2. In addition, the bottom end 430 includes a circular wing or edge 432, fabricated from a flexible, elastomeric material. The elastomeric nature of the edge 432 allows the bottom end 430 to be compressed and placed through a pre-drilled hole 255.
The elastomeric material at the top 420 and bottom 430 ends of the plug 400 are fabricated from a material that will dissolve in the presence of an acidic fluid. It is acknowledged in
It can be seen in
The plugs 300 are fabricated from a material that will dissolve in the fluid making up the acid solution. An example of an acidic fluid is a fluid comprised of about 15% to 50% hydrochloric acid or formic acid. The current methods are not limited by the nature of the acidic composition. Examples of suitable material for dissolving in the acidic fluid include sodium bicarbonate, calcite rock, chalk rock, or combinations thereof
In accordance with the present inventions, and as noted above, the plugs 300 are “tuned” to dissolve in the fluid making up the acid solution according to a selected time. In this way, the portion of the formation “F” closest to the heel 162 of the deviated portion 160 of a wellbore 100 may be isolated from a portion of the formation “F” at the toe 164 of the wellbore 100, and even intermediate portions of the formation “F.”
It can be seen in
In operation, the liner 150 along zone 154 will simply be a pre-perforated liner 250 without plugs 300. This is shown in the illustrative view of
In one aspect, the holes 255 within the liner 150 along zone 154 may also have plugs 300. In that instance, the plugs 300 along zone 154 will be fabricated to dissolve very quickly, such as within ten minutes, or even five minutes, in the presence of the acidic stimulation fluid. Then, the plugs 300 along zone 156 will be fabricated to dissolve more slowly than the plugs 300 along zone 154, to allow zone 154 to obtain the desired amount of acidic fluid. For example, the plugs 300 along zone 156 may be tuned to dissolve within about 15 to 60 minutes.
As shown in
In order to adjust the dissolution rate of various sets of plugs 300, an outer layer may be provided over the plugs 300 to delay the reaction with the acidic fluid and the dissolving of the plugs 300 in the wellbore 100. Examples of suitable coating material are polyester, polycarbonates, polylactic acid, nylon, cellulose, starch, acrylonitrile, polyurethane, and polyacrylate. The thicker the coating along the outer layer, the more slowly a particular plug will dissolve. In one aspect, plugs 300 along zone 158′″ (representing a zone closest to the heel 162) may be coated such that the plugs 300 will not begin to dissolve until after about 30 minutes, or even three hours, of exposure to an acidic fluid.
It is preferred that the coating material be elastomeric in nature. This enables the bottom end 330 of each plug 300 to be folded or compressed, and then inserted through corresponding perforations 255. Depending on the composition of the elastomeric material and the volume percent of acid in the stimulation fluid, a 0.5 mm thickness of coating may represent a 5 minute delay.
In addition to the use of a coating, or alternatively, the amount of material used in the bottom end 330 of the various plugs 300 may be adjusted. Where a set of plugs 300 is intended to dissolve more slowly, then the amount of dissolvable material in the bottom end 330 may be increased. In general, the dimensions, density, shape and amount of material may be selected to meet specific operational needs.
As another way of adjusting dissolution rates, the spacing between perforations 255 (or holes) may be adjusted. In
As yet another way of adjusting dissolution rates, the diameter of the holes 255 may be adjusted. In
A method of stimulating a multi-zone well using an acidization treatment is also provided herein.
The method includes setting a pre-perforated tubular body in a wellbore. This is shown at Box 610. The tubular body preferably comprises a plurality of joints, and is dimensioned to be received within a wellbore. In one aspect, the tubular body is a liner.
The tubular body also comprises a plurality of pre-drilled holes in a wall of the tubular body. The holes may be arranged in repeating patterns along the tubular body.
The tubular body is apportioned into at least a first zone, a second zone, and a third zone. This is shown in Box 620. In one aspect, the tubular body extends at least 30 feet (9.1 meters) along each of the first, second, and third zones, and preferably at least 50 feet (15.2 meters).
The pre-perforated tubular body includes a first set of plugs. These plugs are placed in the holes along the tubular body within the first zone. Each of the plugs in the first set of plugs is fabricated to substantially dissolve upon contact with an acidic fluid within a first selected time.
The tubular body also includes a second set of plugs. These plugs are placed in the pre-drilled holes along the tubular body within the second zone. Each of the plugs in the second set of plugs is fabricated to substantially dissolve upon contact with the acidic fluid within a second selected time that is greater than the first selected time.
The tubular body may further include a third set of plugs. These plugs are placed in the holes along the tubular body within an optional third zone. Each of the plugs in the third set of plugs is fabricated to substantially dissolve upon contact with the acidic fluid within a third selected time that is greater than the second selected time. It is understood that additional zones with additional sets of plugs may also be employed. For example, an extremely long horizontal wellbore may have even four or five discrete zones, with plugs designed to substantially dissolve over increasingly long periods of time.
The method 600 also includes pumping an acidic solution into the well under pressure. This is indicated at Box 630. The acidic fluid may be, for example, hydrochloric acid, acetic acid, formic acid, or combinations thereof. The acid may be injected in a bullhead fashion. Pumping the acidic solution causes the first set of plugs to dissolve. This exposes a subsurface formation outside of the tubular body along the first zone. This further insures that the formation along the first zone is adequately treated without concern that some acidic fluid will be lost along the second and third zones.
The method 600 further includes pumping the acidic solution into the well under pressure so as to dissolve the second set of plugs. This is seen at Box 640. Injecting the acidic solution causes the second set of plugs to dissolve. This, in turn, exposes a subsurface formation outside of the tubular body along the second zone.
The method 600 also includes optionally injecting the acidic solution into the well under pressure so as to dissolve the third set of plugs. This is shown at Box 650. Injecting the acidic solution causes the optional third set of plugs to dissolve. This, in turn, exposes a subsurface formation outside of the tubular body along the third zone.
Preferably, the third zone has a measured depth that is less than the second zone, and the second zone has a measured depth that is less than the first zone. However, the inverse may apply.
The wellbore may be completed substantially vertically. Alternatively, the wellbore may be completed as a deviated wellbore. In one aspect, the deviated wellbore is completed to have a substantially horizontal portion such that the horizontal portion has a heel and a toe.
In one preferred aspect, the tubular body further comprises a fourth zone. The fourth zone has a measured depth that is greater than the first zone, and resides at the toe of a horizontal portion of the wellbore. In this embodiment, the pre-drilled holes in the tubular body along the fourth zone do not have plugs. The method then further comprises injecting the acidic solution into the well under pressure so as to contact a subsurface formation along the toe of the wellbore before the acidic solution contacts the subsurface formation along the first zone.
As can be seen, the above method provides a way to perform acid stimulation in multi-zone wells without the use of chemical diverters, viscous fluids, or mechanically-placed plugs. The method takes advantage of plugs pre-placed along a pre-drilled liner string, with the plugs being fabricated from an acid-reactive material. Certain of the plugs may be covered by a gel or reactive polymer to delay the reaction with the acidic fluid. In this way, selective zones along the liner string are tuned to dissolve at different rates. Some plugs may be fabricated so that they do not dissolve for 30 minutes, or 45 minutes, or even over ten hours after contacting acidic fluid.
A plug's rate of reaction with the acid may be a function of the properties of the rock behind the tubular body, the length of the completion interval, wellbore hydraulics, and the volume of acid desired in each zone of the completion interval. The times needed for the acid to break through a plug (that is, to dissolve the plugs enough to allow acid to flow through the corresponding perforations) in certain sections of the well may be well above ten hours. This is desirable, for example, for very long horizontal wells being treated at a low pump rate.
It is noted that packers may be placed along the outside of the perforated liner to assist in the diversion. This optional step is shown at Box 660. In addition, it is preferred that a zone be preserved along the tubular body that does not have dissolvable plugs. This means that the pre-drilled holes along the tubular body at an apportioned zone are left open. This optional step is shown at Box 670. The apportioned zone is ideally at the end of the wellbore, and allows acidic solution to be injected into the near-wellbore region before stimulation of zones that have plugs. The apportioned zone may be the third zone, or a separate fourth zone as discussed above.
The method has particular application in wells that are completed as an open-hole for the production of hydrocarbons. In one aspect, the hydrocarbon-producing formation contains carbonates. The perforated or pre-drilled liner may be run into the open-hole portion of the wellbore and placed inside another pre-drilled liner that may or may not have plugs in its pre-drilled holes.
A method of creating a liner string is also provided herein. In one aspect, the method first includes providing a first set of threaded joints. The first set of threaded joints has pre-drilled holes along a body of each of the joints, This may be, for example, in accordance with the tubular body 250 of
The method also includes providing a second set of threaded joints. The second set of threaded joints also has pre-drilled holes along a body of each of the joints. The method further includes providing a third set of threaded joints. The third set of threaded joints also has pre-drilled holes along a body of each of the joints.
The method also includes inserting plugs into each of the holes in the second and third sets of joints. This may be, for example, in accordance with the tubular body 250 of
In one embodiment of the method, each plug is in accordance with plug 300 of
While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof.
This application claims the benefit of U.S. Provisional Patent Application 61/366,693 filed Jul. 22, 2010 entitled SYSTEM AND METHOD FOR STIMULATING A MULTI-ZONE WELL, the entirety of which is incorporated by reference herein.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US11/33803 | 4/25/2011 | WO | 00 | 11/29/2012 |
| Number | Date | Country | |
|---|---|---|---|
| 61366693 | Jul 2010 | US |
