WO2013085621A1

WO2013085621A1 - Method for setting a balanced cement plug in a wellbore

Info

Publication number: WO2013085621A1
Application number: PCT/US2012/060105
Authority: WO
Inventors: Franz D. Bunnell; Ottis G. BENGE; Thomas H. Lopez; Meghan N. WILSON
Original assignee: Exxonmobil Upstream Research Company
Priority date: 2011-12-06
Filing date: 2012-10-12
Publication date: 2013-06-13

Abstract

Method of placing a cement plug into the tubing string of a wellbore including setting a mechanical plug within a bore of the tubing, and forming a flare along the tubing at a selected location above the plug. The flare reduces the area of annular space between the tubing and surrounding string of casing. Through-openings are formed above the flare and a cement slurry is pumped down the tubing, through the through-openings, and into the annular space above the flare. When the cement slurry is set, a plug is formed.

Description

METHOD FOR SETTING A BALANCED CEMENT PLUG IN A WELLBORE

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of U.S. Provisional No. 61/567,524, filed December 6, 201 1.

BACKGROUND OF THE INVENTION

[0002] 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.

FIELD OF THE INVENTION

[0003] This invention relates generally to the field of wellbore operations. More specifically, the invention relates to the setting of a cement plug in production tubing or other tubular body.

General Discussion of Technology

[0004] 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 surrounding formations.

[0005] A cementing operation is typically conducted in order to fill or "squeeze" the annular area with columns of cement. The combination of cement and casing strengthens the wellbore and facilitates the zonal isolation of the formations behind the casing.

[0006] It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. A first string may be referred to as a conductor pipe or surface casing. Such casing string serves to isolate and protect the shallower, fresh water-bearing aquifers from contamination by any other wellbore fluids. Accordingly, these casing strings are almost always cemented entirely back to the surface. The process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. 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. The final string of casing, referred to as a production casing, is also typically cemented into place.

[0007] During the formation of a wellbore, it is sometimes desirable to place a so-called cement plug along the casing. For example, a drilling company may desire to use a long cement plug in forming a sidetrack well. Such a sidetrack well may be used to avoid a stuck fishing tool or to initiate directional drilling. In another example, a cement plug may be needed to solve a lost circulation problem during the drilling operation, or to plug back a zone.

[0008] Cement plugs are also employed in connection with wells that are to be plugged and abandoned, or at least temporarily plugged and abandoned (TP&A). In this instance, the operator will place a column of cement along the casing across and above a zone of interest. In some instances, the operator may attempt to leave the production tubing in place, and spot the plug in both the tubing and the annular space around the tubing. This is known as a balanced cement plug. However, obtaining a strong seal, particularly within the annular space around the tubing, presents technical challenges to the operator, especially when using an open-ended pipe.

[0009] Perhaps the biggest challenge relates to instability of the cement material as the balanced cement plug is spotted down the wellbore. In this respect, the cement slurry is usually denser than the well fluids within the wellbore, creating the possibility that the cement slurry will mingle with the well fluids and fall through the fluid column. One study has suggested that a density differential of greater than about 3 lb/gal can result in cement settling problems. The result is that the top of the cement (TOC) is usually deeper in the well than anticipated, and may be weakened or completely ineffective.

[0010] To mitigate this obstacle, it is known to provide support below the cement slurry using a mechanical plug in the tubing. However, mechanical plugs offer no bottom support on the annular side, that is, in the area between the tubing string and the surrounding casing.

[0011] As an alternative, a highly viscous or weighted fluid pill may be spotted in the wellbore. Alternatively, a Reactive Fluid System (RFS) may be employed. The RFS typically contains a chemical component that reacts with calcium chloride brine or with cement to create a rapid-forming gel. This gel then acts as a "bridge" upon which the cement slurry can reside until the cement slurry builds enough strength to support itself. Unfortunately, fluid plugs, including RFS plugs, have been found to be difficult to place and are sometimes unreliable. Further, RFS plugs require down-hole reaction with the cement. In addition, these fluid-based systems also suffer from problems with respect to placement in the annular space.

[0012] Another option involves the use of a diverter sub. Diverter subs reduce agitation and mixing of fluid columns, and help to prevent channeling of the cement phase into the fluid column below the sub. However, diverter subs require the use of a separate downhole tool.

[0013] Therefore, a need exists for an improved method of setting a balanced cement plug in a wellbore containing a string of production tubing. Specifically, a need exists for an improved method of setting a cement plug that involves the placement of a mechanical barrier in the annular area around the tubing to provide support for the cement slurry until setting.

SUMMARY OF THE INVENTION

[0014] The assemblies and methods described herein have various benefits in the conducting of oil and gas exploration and production activities.

[0015] A method of placing a cement plug in a wellbore is provided. The wellbore has a string of casing that has been cemented into place along the subsurface. The wellbore also has a string of tubing within the casing. The method is particularly beneficial for those instances where the tubing is a string of production tubing.

[0016] The method first includes setting a mechanical plug. The plug is installed within a bore of the tubing at a selected depth.

[0017] The method also includes forming at least one flare along the tubing at a selected location above the plug. The flare reduces the area of an annular space between the tubing and the surrounding string of casing. Preferably, the at least one flare is formed by using an explosive jet cutter. The jet cutter creates a circumferential window through the tubing. In this instance, the at least one flare is a lower flare and an upper flare, straddling the window. In another instance, forming a flare along the tubing comprises expanding a swage in order to apply a mechanical force against an inner diameter of the tubing. The tubing is expanded along selected radial locations, or even circumferentially. In this instance, a window is not formed.

[0018] The method also includes forming at least one through-opening in the tubing above the flare. The through-opening provides fluid communication between the bore of the tubing and the annular space around the tubing. Preferably, the at least one through- opening does not penetrate through the surrounding casing.

[0019] In one aspect, forming at least one through-opening in the tubing above the flare comprises directing an abrasive slurry under pressure against an inner diameter of the tubing. In another aspect, forming at least one through-opening in the tubing is done by perforating the tubing. In yet another aspect, forming at least one through-opening in the tubing is performed by using a cutting tool to create an opening in the tubing.

[0020] The method also includes pumping a cement slurry down the tubing while taking returns up the annulus (or, optionally, vice versa). The cement slurry is further pumped through the at least one through-opening, and into the annular space. The slurry is then allowed to set within the tubing and the annular space. In this way, a competent cement plug is formed.

[0021] The method may optionally include pumping a slurry of bridging material into the tubing and down to the selected location. This is done before the step of pumping the cement slurry. The slurry of bridging material may include, for example, any solid material such as mica, nutshells or fibers properly sized to plug the restricted area at the "flared" tubing. The bridging material is generally used when the flaring step also creates a window through the tubing at the selected location. The bridging material is then allowed to set within both the bore of the tubing and the annular space adjacent the window.

BRIEF DESCRIPTION OF THE DRAWINGS

[0022] 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.

[0023] Figure 1 presents a side view of a well site. A partial cross-sectional view of a wellbore is shown at the well site. The wellbore is lined with strings of casing, and also has a string of production tubing therein.

[0024] Figures 2A through 2F present a progression of steps for forming a balanced cement plug in a wellbore. In each view, a string of casing is shown in cross-section. A tubing string is also shown within the string of casing, forming an annular space around the tubing.

[0025] Figure 2A is a first side view of the wellbore. Here, a mechanical plug has been set in a bore of the production tubing.

[0026] Figure 2B is a second side view of the wellbore. A flare has been formed at a selected location along the tubing. A window has optionally been formed. [0027] Figure 2C is a third side view of the wellbore. A slurry of bridging material is being pumped down the bore of the tubing to the mechanical plug. The bridging material is represented by solids suspended in a liquid.

[0028] Figure 2D is a next side view of the wellbore. The bridging material has reached the plug, and has set in the tubing. Solids have built up around the top and bottom cuts or flares along the tubing, while the carrier medium begins to leak away from the solids.

[0029] Figure 2E is a fourth side view of the wellbore. The carrier medium has leaked away and solids are packed around the top and bottom cuts or flares along the tubing. Through-openings have been formed in the tubing above the window. In this view, the through-openings are perforations.

[0030] Figure 2F is a fifth side view of the wellbore. Here, a cement slurry has been pumped into the tubing. The cement has squeezed through the perforations and is setting, thereby forming a cement plug above the flares.

[0031] Figures 3A through 3C provide a progression of steps for forming a flare along a string of production tubing in a wellbore, in an alternate embodiment. Here, a swage is used.

[0032] Figure 3A is a first side view of the wellbore. A mechanical plug has been set in a bore of the production tubing. In addition, a mechanical swage is being run into the wellbore.

[0033] Figure 3B is a second side view of the wellbore. The swage has been set in the tubing, and has been actuated. The tubing is being expanded outwardly at a selected location.

[0034] Figure 3C is a next side view of the wellbore. The mechanical swage has been reversed and pulled from the tubing. A completed flare is shown.

[0035] Figures 4A through 4C present another progression of steps as part of forming a cement plug. Here, a base is being formed below a flare along a string of production tubing in a wellbore.

[0036] Figure 4A is a first side view of the wellbore. A mechanical plug has been set in a bore of the production tubing. In addition, a flare has been formed at a selected location along the production tubing. The flare includes a window. [0037] Figure 4B is a second side view of the wellbore. Here, the wellbore has received an expandable, elastomeric disc.

[0038] Figure 4C is a third side view of the wellbore. The elastomeric disc has been actuated, forming a seal across the wellbore within the window.

[0039] Figure 5 is a flow chart showing steps for a method of placing a cement plug in a wellbore. The wellbore has a string of casing and a string of tubing within the casing.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions

[0040] As used herein, the term "hydrocarbon" refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. 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.

[0041] 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, coalbed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.

[0042] As used herein, the terms "produced fluids" and "production fluids" refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, oil, natural gas, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).

[0043] 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, combinations of liquids and solids, and combinations of gases, liquids, and solids. [0044] As used herein, the term "gas" refers to a fluid that is in its vapor phase at 1 atm and 15° C.

[0045] As used herein, the term "oil" refers to a hydrocarbon fluid containing primarily a mixture of condensable hydrocarbons.

[0046] As used herein, the term "subsurface" refers to geologic strata occurring below the earth's surface.

[0047] 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.

[0048] The terms "zone" or "zone of interest" refers to a portion of a formation containing hydrocarbons. Alternatively, the formation may be a water-bearing interval.

[0049] For purposes of the present patent, the term "casing" includes a surface casing, a production casing, an intermediate casing string, a liner string, or any other tubular body fixed in a wellbore. Similarly, the term "tubing" refers to any tubular body that resides within casing and that is used to convey fluids within a wellbore to or from the surface.

[0050] The term "millable" means any material that may be drilled or ground into pieces within a wellbore. Such materials may include aluminum, brass, cast iron, steel, ceramic, phenolic, composite, and combinations thereof.

[0051] 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."

Description of Selected Specific Embodiments

[0052] 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.

[0053] Figure 1 presents a side view of a well site 100. A partial cross-sectional side view of a wellbore 150 is shown at the well site 100. The wellbore 150 defines a bore that extends from the surface 105 of the earth, and into the earth's subsurface 110. The wellbore 150 has an upper end 152 at the surface 105, and a lower end 154.

[0054] The wellbore 150 is formed with a series of casing strings. The wellbore 150 is first formed with a string of surface casing 120. The surface casing 120 has an upper end 122 at the surface 105, and a lower end 124. The surface casing 120 is secured in the wellbore 150 with a surrounding cement sheath 126.

[0055] The wellbore 150 also includes a string of production casing 140. The production casing 140 is also secured in the wellbore 150 with a surrounding cement sheath 146. The production casing 140 has an upper end 142 and a lower end 144. The lower end 144 of the production casing 140 preferably extends to the bottom 154 of the wellbore 150.

[0056] At least one intermediate string of casing 130 may be provided in the wellbore 150. The intermediate string of casing 130 has an upper end 132 and a lower end 134. The intermediate string of casing 130 is optionally cemented into place using a cement sheath 136.

[0057] It is noted that the production casing 140 is actually a liner string, that is, a string of casing that is not extended back to the surface 105. In this instance, a liner hanger 148 is provided at the lower end 134 of the intermediate string of casing 130 for hanging the production casing 140. The liner hanger 148 hangs the production casing 140 from the intermediate casing string 130.

[0058] It is also noted that in many wellbores, multiple strings of casing are provided, with each string having a progressively smaller outer diameter. The wellbore 150 of Figure 1 with its three casing strings is merely illustrative.

[0059] A wellhead 170 is provided above the wellbore 100. The wellhead 170 is placed at the earth surface 105. It is understood that where a wellbore is formed in an offshore environment, the components shown in the wellhead 170 may be on an ocean bottom or on a production platform above the surface of the water. The wellhead 170 is used to selectively seal the wellbore 100. During completion, the wellhead 170 includes various spooling components, sometimes referred to as spool pieces. The wellhead 170 and its spool pieces are used for flow control and hydraulic isolation during rig-up operations, stimulation operations, and rig-down operations.

[0060] The spool pieces may include a crown valve 172. The crown valve 172 is used to isolate the wellbore 100 from a lubricator (not shown) or other components above the wellhead 170. The spool pieces also include a lower master fracture valve 125 and an upper master fracture valve 135. These lower 125 and upper 135 master fracture valves provide valve systems for isolation of wellbore pressures above and below their respective locations. Depending on site-specific practices and stimulation job design, it is possible that one of these isolation-type valves may not be needed or used.

[0061] The upper end 122 of the surface casing 120 is in sealed connection with the lower master fracture valve 125. The upper end 132 of the production casing 130 is in sealed connection with the upper master fracture valve 135. The upper 125 and lower 135 fracture valves are preferably spaced apart to permit elongated tool strings to be dropped from the surface 105 while maintaining pressure control within the wellbore 150.

[0062] The wellhead 170 and its spool pieces may also include side outlet injection valves 174. The side outlet injection valves 174 provide a location for injection of stimulation fluids into the wellbore 150. The side outlet injection valves 174 are provided along injection line 171 below the crown valve 172. The piping from surface pumps (not shown) and tanks (not shown) used for injection of the stimulation fluids are attached to the injection valves 174 using appropriate fittings and/or couplings.

[0063] It is understood that the various items of surface equipment and components of the wellhead 170 are merely illustrative. A typical completion operation will include numerous valves, pipes, tanks, fittings, couplings, gauges, pumps, and other devices. Further, downhole equipment may be run into and out of the wellbore using an electric line, coiled tubing, or a tractor, none of which are shown. Upon completion, the upper 125 and lower 135 fracture valves will serve as a wellhead, or will be replaced by a smaller wellhead.

[0064] The wellbore 150 has been completed in a zone of interest 160. The zone of interest 160 contains valuable hydrocarbon fluids. The wellbore 150 may be completed for the purpose of producing those hydrocarbon fluids to the surface 105. Alternatively, the wellbore 150 may be completed for the purpose of injecting water, steam, or carbon dioxide for either sequestration or for an enhanced hydrocarbon recovery program.

[0065] To facilitate any of these purposes, the production casing 140 has been perforated. Illustrative perforations are seen at 156. In addition, the formation 110 has been fractured. Fractures 158 are seen emanating from the perforations 156. The fractures 158 create enhanced flow channels at the depth of the zone of interest 160.

[0066] The well site 100 also includes a string of production tubing 180. The production tubing 180 extends from the wellhead 170 down substantially to the zone of interest 160. The production tubing 180 has a bore 185 that conveys fluids. Where the wellbore 150 is for a producer well, the bore 185 will convey production fluids from the zone of interest 160 to the surface 105; where the wellbore 150 is for an injector well, the bore 185 will convey injection fluids such as water or carbon dioxide down to the zone of interest 160. In either instance, the wellhead 170 may be modified once the well site 100 is completed to accommodate the purpose for the wellbore 150.

[0067] As production from the zone of interest 160 declines, the operator will eventually elect to plug the wellbore 150. This may be done by dumping cement into the bottom 154 of the wellbore 150. However, in many instances, particularly with TP&A operations, the operator may prefer to create a balanced cement plug above the zone of interest 160. The present disclosure offers methods for creating a cement plug in a wellbore having an open- ended tubing, such as the wellbore 150 of Figure 1.

[0068] Figures 2A through 2F present a progression of steps for forming a balanced cement plug in a wellbore 200. In each view, a string of casing 210 is shown in cross- section. A tubing string 220 is also shown within the string of casing 210.

[0069] Figure 2A is a first side view of the wellbore 200. The string of casing 210 is shown set within a surrounding subsurface formation 205. A cement sheath 212 isolates the wellbore 200 from the subsurface formation 205.

[0070] The casing 210 defines a bore 215 therein. The tubing string 220 is seen placed within the bore 215 of the casing 210. An annular space 215 is formed between the tubing 220 and the surrounding casing 210.

[0071] The tubing string 220 also defines a bore 225 therein. A mechanical plug 250 has been set in the bore 225 of the production tubing 220. A cement plug will be formed within the wellbore 200 and above the mechanical plug 250.

[0072] Figure 2B is a second side view of the wellbore 200. Here, flares 222 have been formed at a selected location along the tubing 220. In the arrangement of Figure 2B, the flares 222 are represented by a lower flare 222L and an upper flares 222U. The flares 222 have been formed at a selected location along the tubing 220 by expanding the outer diameter of the tubing 220.

[0073] In order to form the flares 222, an expander tool 230 is used. In one interpretation of Figure 2B, a jet cutting tool is used as the expander tool 230. The jet cutting tool 230 is lowered into the bore 225 of the tubing string 220 by means of a working string 235. Preferably, the working string 235 is a wire line or an electric line. [0074] The jet cutting tool 230 is preferably an explosive cutting device. The tool 230 includes a shaped explosive charge, indicated at 232. The cutting device uses the detonation of a shaped explosive charge to cut the surrounding tubing or casing wall. The cutting device may be any known jet cutting tool such as those cutters available from Schlumberger Limited of Sugar Land, Texas or Weatherford International Ltd. of Houston, Texas. Such tools contain explosives enclosed in a metal sheath designed to cut metal or steels. When the shaped charged are detonated, a high velocity jet impacts the tubing with pressures exceeding the pipe's yield strength, pushing the target material to either side of the path of the jet.

[0075] Of benefit herein, the cutting action of the jet cutting tool 230 tends to flare the cut ends. This enables the formation of the flares 222L and 222U. When using a jet cutter as the cutting device 230, the working string 235 is preferably a wire line or an electric line, although a coiled tubing string may also be employed.

[0076] Before running in the jet cutter 230, the operator should consider the thickness and yield strength of the pipe making up the tubing string 220 to be cut. The explosive charge from the jet cutter 230 must be of sufficient energy to cut through the tubing string 220 without, preferably, cutting through the surrounding casing 210.

[0077] Other arrangements for a jet cutting tool 230 may be employed. In one embodiment, the jet cutting tool 230 receives a hydraulic fluid under high pressure. The hydraulic fluid is directed through nozzles, and against an inner diameter of the tubing string 220. The hydraulic forces of the fluid will act against the tubing string 220 and at least partially expand its outer diameter, forming a flare. In this embodiment, the working string 235 is a string of coiled tubing, and the openings 232 are hydraulic jetting nozzles. Optionally, the fluid is an abrasive slurry that forms at least a partial window through the tubing 220. Alternatively, the fluid is a heated chemical that deforms or even cuts through the tubing 220.

[0078] In another arrangement of Figure 2B, the jet cutting tool 230 comprises a single circumferential explosive charge.

[0079] In any of the arrangements described above, a window 255 is formed in the tubing string 220. The window 255 represents an area in which the tubing 220 has been expanded and, preferably, circumferentially cut. The window 255 is formed by using a severing means such as those mentioned above. [0080] As can be seen in Figure 2B, the flares 222L, 222U and the window 255 are formed above the mechanical plug 250. In order to know where to form the flares 222 and the optional window 255, the operator may rely upon a casing collar log (CCL) as a reference. Ideally, the flares 222 and the window 255 are formed intermediate threaded collars (not shown) along the tubing 220.

[0081] The operator will most likely choose to acquire a CCL log set from a logging company to determine a suitable depth. A casing collar locator may be run into a wellbore on a wireline or electric line to detect magnetic anomalies along the tubing string 220. A CCL data set is created that correlates continuously recorded magnetic signals with measured depth. In this way, the depths of tubing collars may be determined based on the length and speed of the wireline pulling a CCL logging device. It is also noted that the target setting depth for a given cement plug is often defined by regulatory requirements. In the current methods, a CCL may be used to correlate cutting/perforating/setting tools to the required depth. The working string 235 is then unspooled a length that corresponds to the desired depth for the flares 222 and the window 255.

[0082] Figure 2C provides a third side view of the wellbore 200. Here, a slurry of bridging material 240 is being pumped down the bore 225 of the tubing 220. The slurry of bridging material 240 is pumped ahead of brine or other well fluids 245. The bridging material 240 is pumped down to the depth of the window 255 between flares 222U, 222L and just above the mechanical plug 250. As the bridging material 240 reaches the window 255, it will bridge off the restricted area between the lower flare 222L and the casing 210, and settle out to fill the bore 225 of the tubing 220 up to the window 255 and the upper flare 222U.

[0083] The bridging material 240 may be any solid material suspended in a carrier fluid. The carrier fluid may be a high viscosity gel, a low viscosity gel, or even brine. The solid materials may include synthetic fibers, cellulosic fibers, polyester or polyethylene pellets, ceramic pellets, mica, nutshells, sand particles, or any other suitably-sized solid material. However, the bridging material will not harden as it is not a cement-based product.

[0084] During pumping, the bridging material 240 bridges across the formed window 255. As the slurry 240 reaches the one or more flares 222, the solids will be trapped at the annular space 215 immediately adjacent the window 255. It is noted here that the window 255 need not require a circumferential opening; rather, the opening may be substantially radial, or may even be partially radial, so long as bridging material is able to substantially circumferentially fill the annular space 215, and so long as flares 222 are formed. [0085] Figure 2D is a next side view of the wellbore 200. In this view, the bridging material 240 has reached the plug 250. In addition, the bridging material 240 has filled the bore 225 of the tubing 220 above the mechanical plug 250 and up to the upper flare 222U. The bridging material 240 is beginning to plug the flares 222 and to settle in the tubing 220 above the plug 250. Of significance, a portion of the bridging material 240 has filled the annular space 215 around the tubing 220 adjacent the window 255.

[0086] Figure 2E is a fourth side view of the wellbore 200. In this figure, it can be seen that the bridging material 240 has set in the tubing 220 above the mechanical plug 250. The carrier fluid has filtered out of the solid material, leaving primarily just the solid material across the window 255. In operation, the operator will sense an increase in pumping pressure as the bridging material 240 begins to pack across the window 255. The operator will then know that an appropriate bridge has been formed.

[0087] It is also seen in Figure 2E that through-openings 224 have been formed in the tubing 220. In this view, the through-openings 224 are perforations. The perforations 224 have been formed above the window 255. The perforations 224 create fluid communication between the bore 225 of the tubing and the surrounding annular space 215.

[0088] Figure 2F is yet a fifth side view of the wellbore 200. Here, a cement slurry 260 has been pumped into the tubing 220. Specifically, the cement slurry 260 has been pumped down the bore 225 of the tubing string 220 and down to the level of the bridging material 240. Because of the substantially solid plug formed by the setting of the bridging material 240, the column making up the cement slurry 260 generally maintains its integrity. Stated another way, the plug of set bridging material 240 in Figure 2F prevents the cement slurry 260 from fingering through the lighter wellbore fluids until the cement can set and cure, thereby forming a durable plug.

[0089] In operation, the cement slurry 260 is pumped down the bore 225 of the tubing, pushing any wellbore fluids or residual bridging material 240 ahead of it. Optionally, a spacer 265 is provided ahead of and behind the cement slurry 260. The portion of the spacer 265 that is ahead of the cement slurry 260 will end up in the annular space 215 around the tubing 220.

[0090] A small amount of cement slurry 260 will likely mingle with the wellbore fluids or residual bridging material 240 ahead, creating a zone of contaminated cement 246. However, most of the wellbore fluids or residual bridging material 240 will be pushed back up the annular space 215. [0091] In Figure 2F, the cement slurry 260 has been squeezed through the perforations 224. The perforations 224 create a veritable in situ diverter sub. The cement slurry 260 is setting above the mechanical plug 250, thereby forming a cement plug 270.

[0092] It is preferred that the perforations 224 be specially-formed charges that are angled upward. In this way, the cement slurry 260 will be urged to flow upward in the annular space 215 of the wellbore 200.

[0093] Figures 2A through 2F present one progression of steps for forming a balanced cement plug in a wellbore 200. However, some of these individual steps may be performed in different ways. For example, in lieu of forming the window 255, the operator may choose to use only flares 222, meaning that the tubing is expanded but no window is actually formed. Further, the flares 222 may be formed mechanically rather than through explosive action.

[0094] Figures 3A through 3C provide a progression of steps for forming a flare 322 along a string of production tubing 320 in a wellbore 300, in an alternate embodiment. Here, a swage 330 is used for mechanically forming a flare 322.

[0095] Figure 3A is a first side view of the wellbore 300. The wellbore 300 includes a string of casing 310. The string of casing 310 is shown set within a surrounding subsurface formation 305. The cement sheath 312 isolates the wellbore 300 from the subsurface formation 305. The wellbore 300 also includes a string of production tubing 320. The production tubing 320 resides within the casing string 310, forming an annular space 315 there around.

[0096] A mechanical plug 350 has been set in a bore 325 of the production tubing 320. In addition, a swage 330 is being run into the wellbore 300. The swage 330 is being run in on an electric line 335 that provides electrical power to a motor 334 of the swage 330. The swage 330 is seen within the bore 325 of the tubing 320.

[0097] The swage 330 includes an elongated drive screw 332. The drive screw 332 represents a threaded bar. The drive screw 332 is threadedly received by opposing ends of arms 336 of the swage 330.

[0098] The swage 330 also includes the electric motor 334. The electric motor 334 rotates the drive screw 332. As the threaded bar making up the threaded screw 332 turns, it causes the opposing ends of the sage arms 336 to move along the screw 332. The opposing ends of the swage arms 336 move closer together, thereby urging the arms outward in "frog-leg" fashion. [0099] Actuation of the electric motor 334 also preferably causes a set of slips 331 to be moved outwardly. The slips 331 ride outwardly from the motor 334 along wedges (not shown) spaced radially around the motor 334. The slips 311 extend radially to "bite" into the tubing 320 when actuated. This, in turn, holds the mechanical swage 330 in position above the mechanical plug 350 for formation of a flare.

[0100] Figure 3B is a second side view of the wellbore 300. In this view, the slips 331 have been set in the tubing 320. In addition, the drive screw 332 is being turned. This causes the ends of the arms 336 of the swage 330 to be drawn inward. In addition, rotation of the drive screw 332 causes the arms 336 to expand outwardly.

[0101] It can be seen in Figure 3B that as the arms 336 move outwardly, they contact the surrounding tubing string 320. As mechanical force is applied by the arms 336, the tubing 320 is expanded outwardly. This, in turn, creates a flare 322. The flare 322 need not be a circumferential expansion of the tubing 320 at the selected location; rather, it is preferably an expansion at two, three, four, or five points. The arms 336 of the swage 330 need not be rotated, but need only expand in place until the wall of the tubing 220 has approached or even contacted the surrounding casing 310. The arms 336 form bearing surfaces for applying a mechanical force.

[0102] It is noted that other swage or expander tool designs may be employed for creating the flare 322. For example, U.S. Pat. No. 7,156,179, issued in 2004 to Weatherford/Lamb, Inc., describes various swages as may be used for expanding tubular bodies within a wellbore. Those swages employ hydraulically-actuated rollers that are rotated within a tubular body such as a liner string. The rollers become bearing surfaces for applying force against the surrounding tubular body. Figures 2 and 3 of the Ί 79 patent and associated text are incorporated herein by reference.

[0103] Figure 3C is a next side view of the wellbore 300. In this view, the swage 330 has been reversed, meaning that the electric motor has caused the threaded rod 332 to rotate in the opposite direction. This causes the ends of the swage arms 336 to move apart from each other, thereby causing the arms 336 to contract. The swage 330 has been pulled from the tubing 320.

[0104] As shown in Figure 3C, a fully-formed flare 322 is left in the wellbore 300. The flare 322 represents a bulbous area 355 along the string of tubing 320. The bulbous area 355 serves as at least a partial restriction to the flow of cement slurry down the annular space 315. Thus, after perforations have been formed (as shown in Figure 2E), and after the cement slurry has been placed in the bore of the tubing and squeezed into the annular space (as shown in Figure 2F), the cement slurry will generally maintain its position above the bulbous area 355 in the annular space 315.

[0105] Figures 4A through 4B present another progression of steps in connection with forming a cement plug. In these figures, an expandable or inflatable disc or plug 430 is used for forming a base below a flare.

[0106] Figure 4A is a first side view of the wellbore 400. The wellbore 400 includes a casing string 410. The casing string 410 is set in the wellbore 400 by means of a cement sheath 412. The wellbore 400 also includes a string of production tubing 420. The production tubing 420 resides within the casing string 410, forming an annular space 415 there around.

[0107] A mechanical plug 450 has been set in a bore 425 of the production tubing 420. In addition, a flare 422 has been formed at a selected location along the production tubing 420. The flare includes a window 455.

[0108] The flare 422 and window 455 may be formed using the explosive cutting tool 230 of Figure 2B. Alternatively, the flare 422 and window 455 may be formed using another expander tool that operates by cutting, milling, perforating or burning. U.S. Pat. No. 5,709,265 entitled "Wellbore Window Formation," and U.S. Pat. No. 6,536,525 entitled "Methods and Apparatus for Forming a Lateral Wellbore," describe numerous techniques for forming openings in tubular bodies. Some of those techniques may necessarily create flares along with windows. The '265 patent and the '525 parent are incorporated herein by reference in their entireties.

[0109] Figure 4B is a second side view of the wellbore 400. Here, the wellbore 400 has received a flow restriction tool 430. The flow restriction tool 430 is being run into a bore 425 of the tubing string 420 using a working string 432. In the illustrative arrangement of Figure 4B, the working string 432 represents coiled tubing. However, the working string 432 may be a wire line or electric line.

[0110] The flow restriction tool 430 includes a plug body. In Figure 4B, the plug body is shown in an unexpanded or uninflated state, indicated at 435'. The coiled tubing 432 is connected to the elastomeric body 435' proximate an upper end of the body 435'.

[0111] The flow restriction tool 430 further includes a counter-force string 434. The counter-force string 434 resides within the coiled tubing 432 and extends into the elastomeric body 435'. In one aspect, the counter-force string 434 is a cable such as a wireline or slickline. In another aspect, the counter-force string 434 is a rod, a pipe, or a cable having a rod or pipe at an end (not shown) for connecting to the elastomeric body 435'.

[0112] In the view of Figure 4B, the elastomeric body 435 has been run into the wellbore 400 to a depth of the window 455. The flow restriction tool 430 is now ready to be set.

[0113] Figure 4C is a third side view of the wellbore 400. Here, the elastomeric body has been actuated, as indicated at 435". The elastomeric body 435" is actuated by pulling on the counter-force string 434 within the coiled tubing 432. This serves to squeeze the elastomeric material forming the body 435", thereby extruding it outwardly. As the body 435" is actuated, it forms a seal across the bore 415 of the casing 410 within the window 455.

[0114] In an alternative embodiment, the flow restriction tool 430 utilizes an expandable/inflatable plug as the elastomeric body 435. The plug is run into the tubing 420 on an electric line, meaning that coiled tubing would not be used, and the counter-force string 434 would not be present. The electric line would include a conventional wireline setting tool (not shown) for setting and releasing the expandable/inflatable plug 435. The plug 435 may be, for example, the Petal Basket^™ offered by OilData Wireline Services Ltd. of Houston, Texas.

[0115] In either arrangement, the actuated plug body 435" serves as restriction to the flow of cement slurry in the annular space 415. Thus, after perforations have been formed (as shown in Figure 2E), and after the cement slurry has been placed in the bore of the tubing and squeezed into the annular space (as shown in Figure 2F), the cement slurry will generally maintain its position above the disc 435" in the annular space 415.

[0116] Figures 2A through 2E, 3A through 3C, and 4A through 4C demonstrate steps useful for creating a balanced cement plug. Figure 5 is a flow chart textually showing steps for a method 500 of placing a cement plug in a wellbore, in one embodiment. The method 500 involves the placement of a cement slurry into a string of tubing, and into the annular space around the tubing, at a selected location.

[0117] The method 500 first includes providing a wellbore. This is shown at Box 510. The wellbore has a string of casing that has been cemented into place along the subsurface. The wellbore also has a string of tubing within the casing. The method 500 is particularly beneficial for those instances where the tubing is an open-ended string of production tubing. [0118] The method 500 next comprises setting a mechanical plug. This is seen in Box 520. The plug is set within a bore of the tubing.

[0119] The method 500 also includes forming one or more flares along the tubing at a selected location above the plug. This is provided at Box 530. The flare reduces the area of an annular space between the tubing and the surrounding string of casing.

[0120] In one instance, forming a flare along the tubing comprises directing an explosive charge against an inner diameter of the tubing. This may be done using, for example, a perforating gun or an explosive jet cutter having shaped charges. The explosive energy will preferably cut through and even sever and flare the tubing, leaving a window. In another instance, forming a flare along the tubing comprises mechanically expanding a swage in order to apply a force against an inner diameter of the tubing. This serves to expand the tubing, or at least portions of the tubing, outwardly towards the surrounding casing. In yet another instance, forming a flare along the tubing comprises using a mechanical cutting tool to form at least a partial window through the tubing, with the window having flares.

[0121] Where the technique of forming a flare results in the tubing being severed, a window is formed through the tubing. Preferably, the window is a circumferentially formed opening, with separate lower and upper flares being formed in the tubing. In this instance, the flare is actually a pair of flares.

[0122] The method 500 also includes forming at least one through-opening in the tubing above the flare. This is seen at Box 540. The through-opening provides fluid communication between the bore of the tubing and the annular space around the tubing. Preferably, the at least one through-opening does not penetrate through the surrounding casing.

[0123] In one aspect, forming at least one through-opening in the tubing above the flare comprises directing an abrasive slurry under pressure against an inner diameter of the tubing. In another aspect, forming at least one through-opening in the tubing is done by perforating the tubing. Specially-designed perforation charges that direct the cement slurry upward are preferred. In yet another aspect, forming at least one through-opening in the tubing is performed by using a cutting tool to mechanically form at least a partial window through the tubing.

[0124] The method 500 may optionally include pumping a slurry of bridging material into the tubing and down to the selected location. This is shown at Box 550. The slurry of bridging material may be, for example, fibrous material, granular material, mica, nutshells, polyethylene or polypropylene pellets, or other suitably-sized solid material placed in a carrier medium. The bridging material is preferably used when the flaring step also creates a window through the tubing at the selected location. The bridging material is then caused to set. This is provided at Box 560. In this context, "setting" means that solid particles have packed around the one or more flares, with carrier medium dropping out.

[0125] The method 500 also includes pumping a cement slurry down the tubing. This is provided at Box 570. The cement slurry is further pumped or squeezed through the at least one through-opening, and into the annular space. This is indicated at Box 580. The slurry is then allowed to set within the tubing and the annular space. In this way, a cement plug is formed.

[0126] As demonstrated herein, methods are provided for forming a cement plug. Mechanical support is provided for a cement slurry, particularly in the annular space, while the cement slurry sets.

[0127] 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.

Claims

Claims What is claimed is:

1. A method of placing a cement plug in a wellbore, the wellbore having a string of casing and a string of tubing within the casing, and the method comprising:

setting a mechanical plug within a bore of the tubing;

forming at least one flare along the tubing at a selected location above the plug, wherein the at least one flare reduces the area of an annular space between the tubing and the surrounding string of casing;

forming at least one through-opening in the tubing above the at least one flare;

pumping a cement slurry down the tubing, through the at least one through-opening, and into the annular space; and

allowing the cement slurry to set within the tubing and the annular space and above the at least one flare, thereby forming a cement plug.

2. The method of claim 1 , wherein forming a flare along the tubing comprises (i) directing an explosive charge against an inner diameter of the tubing, (ii) expanding a swage in order to apply a mechanical force against an inner diameter of the tubing, (iii) using a cutting tool to form at least a partial window through the tubing, or (iv) combinations thereof.

3. The method of claim 2, wherein forming at least one through-opening in the tubing above the flare comprises (i) directing an abrasive slurry under pressure against an inner diameter of the tubing, (ii) perforating the tubing, (iii) using a cutting tool to form a partial window through the tubing, or (iv) combinations thereof.

4. The method of claim 3, wherein the at least one through-opening does not penetrate through the surrounding casing.

5. The method of claim 3, wherein:

forming at least one through-opening in the tubing comprises firing explosive jet shots at the tubing to form perforations; and

the perforations are angled upward relative to the mechanical plug.

6. The method of claim 1 , wherein:

the tubing is a string of production tubing; forming the at least one flare along the tubing comprises forming a window through the production tubing such that the flare comprises a lower flare below the window, and an upper flare above the window; and

the method further comprises:

pumping a slurry of bridging material into the production tubing and down to the selected location; and

allowing solid particles in the bridging material to bridge across the annular space adjacent the window before pumping the cement slurry.

7. The method of claim 6, wherein the bridging material extends to the upper flare.

8. The method of claim 7, wherein the solid particles in the slurry of bridging material are initially suspended in a carrier medium comprising a viscous gel or brine.

9. The method of claim 6, further comprising:

pumping a spacer into the tubing before pumping the slurry, after pumping the slurry, or both.

10. The method of claim 2, wherein forming a flare along the tubing comprises expanding a swage in order to apply a mechanical force against an inner diameter of the tubing.

1 1. The method of claim 10, wherein the swage comprises:

a downhole motor;

a threaded rod configured to be selectively rotated by the downhole motor; and at least one pair of expandable swage arms that traverse the threaded rod together in response to rotation of the threaded rod by the downhole motor.

12. The method of claim 1 1 , wherein the swage further comprises a set of slips for holding the mechanical swage at the selected location.

13. The method of claim 2, wherein:

forming a flare along the tubing comprises cutting the tubing in order to form a radial window; and

the method further comprises:

running an elastomeric body into the tubing and down to the radial window, and expanding the elastomeric body into engagement with an inner wall of the surrounding casing, thereby forming a base within the window.

14. The method of claim 13, wherein:

the elastomeric body is an expandable plug;

the expandable plug is run into the tubing using wire line, electric line, or coiled tubing; and

expanding the elastomeric body comprises setting the expandable plug using a setting tool.

15. The method of claim 13, wherein:

the elastomeric body is run into the tubing using a tubular working string;

the elastomeric body is mechanically connected to the end of a counter-force string that generally resides within the tubular working string; and

expanding the elastomeric body comprises compressing the elastomeric body in response to tension being applied on the counter-force string.

16. The method of claim 14, further comprising:

pumping a slurry of bridging material into the tubing and down to the expanded plug; and

allowing solid particles in the bridging material to bridge across the annular space before pumping the cement slurry.

17. The method of claim 1 , wherein:

forming a flare along the tubing comprises:

running an expander tool into the tubing to the selected location on a string of coiled tubing; and

pumping hydraulic fluid through the coiled tubing in order to actuate bearing surfaces outward from the expander tool, and thereby apply a force against an inner diameter of the tubing.

18. The method of claim 1 , wherein the string of tubing is an open-ended string of production tubing.

19. A wellbore containing a cement plug, the wellbore comprising:

a casing string lining a bore of the wellbore along a subsurface formation; a string of production tubing within the casing string also along the subsurface formation;

a mechanical plug set within a bore of the production tubing;

at least one flare along the production tubing at a selected location above the plug, wherein the at least one flare reduces the area of an annular space between the tubing and the surrounding string of casing;

at least one through-opening in the production tubing above the at least one flare; and

a plug of set cement residing within the production tubing, through the at least one through-opening, and into the annular space above the at least one flare, thereby providing a cement plug.

20. The wellbore of claim 19, further comprising:

a plug of set bridging material residing in the tubing and on the mechanical plug, the bridging material extending up to the at least one flare and below the cement plug.

21. The wellbore of claim 20, wherein:

the at least one flare along the production tubing further comprises a window through the production tubing;

the flare comprises a lower flare below the window, and an upper flare above the window; and

the bridging material extends to the upper flare, through the window, and across the annular space adjacent the window.