MOVING LINER FRACTURING METHOD

Abstract

A method for treating a production wellbore involves a moving liner run-in on a work string to a treatment zone. Treatment fluid is pumped at high flow rate and pressure down the annulus, through a crossover to the interior of the liner and to the treatment zone. Zones co-extensive with the liner are shielded from treatment as a path of least resistance is defined into the treatment zone. Relatively tight liner clearance and high treatment flow rates prevent treatment of shielded zones. Flow rate is reduced, but pressure maintained, while the moving liner is pulled, exposing another zone.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a U.S. non-provisional application claiming priority and benefit of prior-filed U.S. Provisional Application No. 61/825,888, filed May 21, 2013.

TECHNICAL FIELD

The disclosure generally relates to the field of producing crude oil or natural gas from a well. More particularly, the disclosure relates to methods of treating subterranean hydrocarbon-bearing formations for enhanced production, namely, to methods for fracturing formations having wellbores extending therethrough for recovery of oil and gas.

BACKGROUND ART

Oil and gas hydrocarbons are naturally occurring in some subterranean formations. A subterranean formation containing oil or gas is sometimes referred to as a reservoir. A reservoir may be located under land or off shore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce hydrocarbons, a wellbore is drilled through at least one hydrocarbon-bearing zone in a reservoir. In a cased-hole wellbore or portion thereof, a casing is placed, and typically cemented, into the wellbore providing a tubular wall between the zone and the interior of the cased wellbore. A work string can then be run in and out of the casing. Similarly, work string can be run in an uncased wellbore or section of wellbore.

As used herein, “work string” refers to a series of connected pipe sections, joints, blanks, cross-over tools, downhole tools and the like, inserted into a wellbore. A work string can be used for drilling, work-over, production, injection, completion, stimulation, fracturing, or other wellbore treatments or operations. Further, in some cases one or more downhole tools can be run on a wireline or coiled tubing. A wellbore can be or include vertical, deviated, lateral, and horizontal bores. Bores can be straight, curved, or branched.

During wellbore operations, a work string is positioned in the wellbore. The work string allows fluids to be introduced into, or flowed from, a remote portion of the wellbore. A work string is created by joining multiple sections of pipe together, typically via male right-handed threads at the bottom of an upper section of pipe and corresponding female threads at the top of a lower section of pipe. The two sections of pipe are connected to each other by applying a right-hand torque to the upper section of pipe while the lower section of pipe remains relatively stationary. The joined sections of pipe are then lowered into the wellbore. The process is referred to as “making up” and “running in” a string and is typically performed using a rig, with a derrick, draw-works, and attendant equipment.

The wellhead is the surface termination of a wellbore which may be on land or seabed. As used herein, “uphole,” “downhole,” and similar terms are relative to the direction of the wellhead, regardless of the orientation of the wellbore (e.g., vertical, horizontal). A zone is an interval of rock along a wellbore that is differentiated from surrounding rocks based on hydrocarbon content or other features, such as perforations or other fluid communication with the wellbore, faults, or fractures.

Completion is the process of making a well ready for production or injection. This principally involves preparing a zone of the wellbore to the required specifications, running in the production tubing and associated downhole equipment, as well as perforating and stimulating as required.

BRIEF DESCRIPTION OF THE DRAWING

The accompanying drawing is incorporated into the specification to help illustrate examples according to the presently most-preferred embodiment of the invention.

FIG. 1 illustrates a wellbore with a deviated segment from the vertical extending generally in the horizontal strata of a hydrocarbon producing zone for dispersing treating solutions through the casing, into the working string and then into the desired areas of the formation;

FIG. 2 illustrates an enlarged section depicting the arrangement for transferring treatment solutions from the casing to the working string and preventing back flow up the working string to the surface.

FIG. 2A illustrates a modification to the working string of FIG. 2 where the working string is a solid rod above the perforated nipple.

FIG. 3 illustrates a vertical wellbore with two radially deviated boreholes angularly displaced from each other.

FIG. 4 is a schematic view of an exemplary wellbore extending through a subterranean formation and having an exemplary liner for injecting fracturing fluid according to an aspect of the invention.

FIG. 5 is a schematic view of an exemplary wellbore having an exemplary work string for injecting treatment fluid moved to a second position uphole from that seen in FIG. 4.

DETAILED DESCRIPTION

Treatment operations performed in a wellbore include, for example, stimulation to enhance or restore productivity. Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a permeable flow path between the formation and the wellbore. Other types of completion or intervention treatments can include, for example, gravel packing, consolidation, and controlling excess water.

As used herein, “treatment” refers to treatment for changing a condition of a wellbore or adjacent formation; however, “treatment” does not necessarily imply a particular treatment purpose. A treatment fluid is simply a fluid used in treating a well. A “treatment zone” refers to an interval of rock along a wellbore into which treatment fluid is directed.

A widely used stimulation technique is acidizing, in which a treatment fluid including an aqueous acid solution is introduced into the formation to dissolve acid-soluble materials. In this way, hydrocarbon fluids can more easily flow from the formation. In addition, acid treatment can facilitate flow of injected treatment fluids.

Hydraulic fracturing, sometimes referred to as fracturing (fracking, fracing) is a common stimulation treatment. A treatment fluid adapted for this purpose is referred to as a fracturing fluid. The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the formation, or zone thereof, to create or enhance fractures in the formation. Creating a fracture means making a new fracture in the formation. Enhancing a fracture means enlarging a pre-existing fracture in the formation.

A high-pressure, high-volume frac pump is used in hydraulic fracturing. Typically, a frac pump is a positive-displacement, reciprocating pump. The pump is resistant to the abrasive and corrosive fluids, such as suspensions of solid particulates (e.g., sand) and acids. The fracturing fluid may be pumped down into the wellbore at high rates and pressures, for example, at a flow rate in excess of 50 barrels per minute (2,100 U.S. gallons per minute) at a pressure in excess of 5,000 pounds per square inch (“psi”). The pump rate and pressure of the fracturing fluid may be even higher in some cases. For example, flow rates in excess of 100 barrels per minute and pressures in excess of 10,000 psi have been used. Fracturing a subterranean formation often uses hundreds of thousands of gallons of fracturing fluid, typically water or water-based liquids.

It is often desirable to fracture more than one treatment zone of a well. The creation or extension of a fracture in hydraulic fracturing occurs suddenly. When this happens, the fracturing fluid suddenly has a fluid flow path through the fracture to flow rapidly away from the wellbore. This may be detected as a corresponding change in pressure or flow rate. A newly-created or newly-extended fracture tends to close after pumping of the fracturing fluid stops. To prevent fracture closing, a material, typically proppant, can be placed in the fracture to prop it open. Proppant is a solid particulate which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture.

Multiple or staged fracturing involves fracturing two or more different treatment zones of a wellbore in succession. Staged hydraulic fracturing operations are commonly performed, for example, from horizontal wellbores in shale reservoirs. In the context of staged fracturing, diversion techniques are used to divert fracturing fluid from one zone to a different zone. Mechanical diversion includes the use of mechanical devices, such as ball sealers, bridge plugs, or packers, to isolate one zone from another and divert a treatment fluid to the desired zone.

In conventional methods of treating subterranean formations, once a first zone (e.g., a less flow-resistant zone, a deeper zone, etc.) has been treated, that zone may be sealed off using a variety of techniques to divert treatment fluids to a more fluid flow-resistant zone of the well. Such techniques may involve, among other things, the injection or placement of particulates, foams, emulsions, plugs, packers, annular seal devices, or blocking polymers adjacent the interval to plug off treated portions of the formation. Subsequent treatment fluids are diverted to later-treated zones (e.g., more fluid flow-resistant zones, higher zones, etc.).

In general, the present invention is directed to increasing fracture complexity in subterranean hydrocarbon-bearing formations, such as shale reservoirs or shale plays. Formations tend to have a naturally occurring network of fractures but are often treated, e.g., fractured, to create or increase the complexity of the fractures. Formations are usually fractured with water-based fluids and suspending concentrations of proppant. The proppant is sized to be appropriate for the fracture complexity of the formation. The overall purpose is to increase or enhance the fracture complexity of such a formation to allow hydrocarbon production.

The methods and apparatus disclosed herein can be used in conjunction with the disclosure of U.S. Pat. No. 7,980,299 and as described here with respect to FIGS. 1-3.

FIGS. 1-3 illustrate a method and apparatus for treating a wellbore while moving a work string and simultaneously pumping fluid from the surface to a location downhole. Wellbore 10 penetrates multiple zones of a subterranean formation. The well includes a substantially vertical, cased wellbore 10b and a horizontal or deviated open hole wellbore 10a. Casing 12 is cemented into place and extends from the surface to below formation 15 along bore 10. Footing 13 assists in maintaining the casing in place. Casing 12 has a sidewall cutout 18 with a whipstock 20 seated in the casing 12 below and adjacent to the cutout 18. The whipstock 20 directs a work string into bore 10a which is an uncased or open wellbore. Additional wellbores, such as deviated or lateral bores, can extend from the wellbores 10a and 10b. Exemplary lateral wellbore 11 is seen in FIG. 3, and can be cased, lined, or open hole.

Wellhead 25 includes a fluid housing 26 with a cover 28. Inlet conduit 29 has a control valve 30, which may be opened or closed by controller 31, here a simple handle. The valve and controller can be of various types as is known in the art, including powered valves and remote or local electronic or digital controller. Inlet 29 provides inflow of treatment fluid for treating a formation. The fluid is typically stored in a tank or pit prior to pumping into the wellbore. A pump, not shown, is used to pump the fluid into the wellbore annulus 50 defined between the casing 12 and the work string 40. Such pumps are known in the art. To prevent pumped treatment fluid from exiting the housing 26 above the wellbore, wellhead 25 is provided with a suitable seal 41. The seal 41 provides an annular seal about the work sting 40 and seals while the work string is raised, lowered, rotated, or otherwise manipulated. Seal 41 can be of rubber or other suitable materials. For example, Beaumont Iron Works has a suitable commercially available rubber seal, generally referred to as the BIW Seal in the “oil patch.”

Work string 40 includes a perforated sub 44, such as a perforated nipple or a crossover tool, having multiple apertures 45 of suitable size to accommodate the intended treatment solution and flow rates. Below the perforated sub 44, an annular sealing device 48, such as a packer or sliding seal, is position on the work string 40. Stationary annular sealing devices, such as packers, etc., are attached to the casing (or open hole in some cases) and are known in the art. Alternately, a moving seal, attached to the work string to move along with the work string along the wellbore can be used. The annular seal 48 seals between the work string and the casing and allows movement and manipulation of the string. A check valve 49, other valve, or plug is positioned in the interior passageway 17 of the work string 40 above perforated the sub 44 to prevent back-flow up work string 40 towards the surface.

Work string 40 can consist of any number of connected downhole tools and tubulars, as is known in the art. The work string 40 preferably includes a dispersing tool 52 at its lower end having apertures 53. The dispersal tool disperses the pumped-in treatment fluid, such as proppant slurry, fracturing fluid, acid, etc. into the formation. Dispersing tool 52 is shown at the downhole end of the string 40 and positioned the “toe” or end of the open bore 10a. The maximum volume of the annulus 50 is utilized to disperse treatment fluid into the formation 15 with the least amount of head loss or pressure drop.

FIGS. 2 and 2A are cross-sectional schematic views of exemplary work strings 40 having perforated subs 44 and annular seals 48 and positioned in a casing 12. FIG. 2 shows a work string having a hollow tubular string extending from the surface through the wellbore. A flow path or interior passageway is defined in the string and can be selectively blocked by a check valve 49 or the like. Note the size of the annulus 50 between the work string 40 and casing 12.

Referring to FIG. 2A, the annulus 50 can be significantly larger when a solid rod or other non-tubular is used to move the perforated sub 44 and seals 48 along the wellbore. A reducer 42 is used above perforated sub 44 to attach the tubular portions of the work string below to the solid rod above. In this embodiment, thousands of feet of tubular work string can be replaced with smaller diameter and lighter solid rods 43. The annulus 50 has a relatively greater volume, further reducing head loss in pumping.

In FIG. 3, the wellbore includes exemplary lateral bore 11 which deviates off of open, horizontal bore 10a. Other horizontal, vertical, deviated and lateral boreholes can be made as well. The treatment methods and apparatus herein can be used, in one trip, to treat multiple boreholes sequentially.

In use, the work string is lowered into the wellbore as it is made-up at the surface of multiple sections of tubular, downhole tools, solid rod sections, etc. The dispersal tool is positioned adjacent the formation to be treated. Treatment fluid is pumped downhole via annulus 50 and is diverted through the apertures 45 in the perforated sub 44 by the annular seals 48. As the treatment fluid is pumped into the wellbore at a selected flow rate and pressure, the work string is moved along the wellbore, uphole and/or downhole. The work string is moved and manipulated without the need to cease pumping. Further, pumping can continue as the work string is pulled out of hole or run in hole, including during temporary pauses for the coupling or uncoupling (addition or removal) of tubing sections at the surface.

Multiple bores can be treated without tripping to the surface. For example, bore 10a can be treated while the work string is pulled uphole. When the lower end of the string reaches the junction at, for example, bore 11, the string can be rotated or otherwise manipulated and tripped into the bore 11. Treatment of bore 11 can be performed during the trip in or the trip out of bore 11. Treatment can be performed on any bore from the bottom up or from the top down, as desired.

Examples of treatment of wells are provided for reference and not as limitations of the scope of the invention. A well in the San Andres formation would typically be treated, if a production or other work string was in the wellbore. A pulling unit would be connected and the work string pulled out of the hole. The well is cased with 4½ inch pipe to 6000 feet with a whipstock in place to facilitate the lateral deviation topped at a depth of 5200 feet below the surface. The whipstock remains in place where the lateral deviation from the casing occurred. The deviated lateral is 3000 feet beyond the casing, thus the borehole length from the surface to the end of the lateral is 8200 feet.

In this well, 3200 feet of 2⅜ inch tubing with a perforated nipple, bull plugged, is affixed on the end of the first work string joint and run in the cased borehole. Next, a casing seal assembly (such as a packer) would be attached, a perforated sub installed above the seal assembly, and a check valve inserted above the perforated sub. In sequence, 5000 feet of pipe would be attached or coupled by section to the string and run in the borehole. The perforated nipple is positioned near the end of the deviated lateral.

With the working string now fully within the borehole, and with a BIW stripper rubber affixed in the wellhead, treatment fluid, such as acid, is pumped via tubular coupled to the annulus between the 4½ inch casing and the 2⅜ inch tubing or working string. Next, the deviated lateral would be treated with 75,000 gallons of acid (approximately 1785 bbl) at 10 bbl per minute while pulling the working string out of the hole at 17 ft/minute.

In another example, a well in the San Andres formation capable of having two or more lateral bores extending from a vertical bore is treated. The vertical borehole is cased with 4½ inch casing to an appropriate distance below the 6,000 foot depth. A deviated horizontal borehole extends from a cut-out in the casing at 6,000 feet to 6,200 feet, and then branches into laterals number 1 and 2, each extending about 3,000 feet in the formation. For this well, 3400 feet of 2 ⅜ inch pipe with a perforated nipple, bull plugged, then a bent joint and UBHO (universal Bottom Hole Orienting Sub) with the orientation prong set with the bend of the bent joint (the “bottom hole assembly”) on the end of the first joint is run in. Next, 2400 feet of pipe or tubing is run in hole, then a wet-connect hanging sub is attached. A steering tool attached on a wireline is run in the hole and seated in the UBHO over the orientation prong. The wireline is clamped and cut, then attached to wet-connect, and the wet-connect hung from the hanging sub. Tubing is attached and run in to 6,250 feet (50 feet beyond the track of either lateral number 1 or 2). Then the wireline, with connector, is run in and coupled into the wet-connect. Lateral telemetry is measured to identify as lateral 1 or 2. The wireline is pulled out, and a fishing tool run in to recover the steering tool. A check valve is placed in the work string. Then, tubing is run in to 9,200 feet (e.g, the extremity of the identified lateral number 1).

The lateral is drag acid treated by pumping acid into the annulus between the casing and work string, through the perforated sub into the work string and then into the formation through a perforated nipple or other dispersing tool. The acid treatment is at a rate of 10 bbl per minute while pulling the pipe string at 17 feet per min. Thus, approximately 1,765 bbl of acid is dispersed in the formation.

After acid treating lateral 1, the work string is pulled until the end of the bottom hole assembly is at 5,800 feet and within the cased borehole. The check valve is removed. Then, the steering tool is run in on a wireline and seated in the UBHO over the prong. The wet-connect is hung, then work string run in to 6,200 feet, that is, just short of the side track juncture or branch. Then, wireline, with connector, is run in and coupled into the wet-connect. Next, the bottom hole assembly is rotated and steered into lateral 2 (the as yet untreated lateral) and positioning confirmed. Then, wireline is pulled and the fishing tool run in to recover the steering tool. A check valve is set in the work string. Next, work string with bottom hole assembly is run in to lateral 2 to its toe. Lateral 2 is drag acid treated, similar to lateral 1.

Alternatively, to decrease head loss, instead of inserting the check valve and attaching tubing to the work string, solid rods of much lesser diameter are used to replace the check valve and the pipe above the working string.

It should be recognized that treatment fluid is pumped down the annulus 50, through perforated sub 44, and blocked from backflow by the check valve 49 or, alternatively, by the reducer 42 and solid rod 43. Therefore, the work string 40 can be withdrawn and joints can be removed from the work string 40 to move the dispersing tool through the open hole portion 10a of the borehole 10. More joints can be returned to the work string 40 for further treatment of portion 10a or a second lateral off of the cased section of borehole 10. In the process, the treating parameters may be maintained in the open hole portion 10a. Further, if under-treatment or no treatment is necessary along a portion of a bore, the work string 40 can be manipulated (extended, retracted or rotated) as needed to achieve the under-treatment or to skip treatment of a selected bore portion.

FIGS. 4-5 show an exemplary work string positioned in an exemplary wellbore at a first position in FIG. 4 and at a later second position FIG. 5.

Presented are exemplary methods for treating a wellbore, or more particularly, zones along a production wellbore, which can be thought of as a “moving liner treatment.” Briefly, a liner is positioned at the downhole end of a work string with openings for treatment fluid at the downhole end. Treatment fluid is pumped at high flow rate and pressure down an upper annulus, through a crossover tool, and down the interior passageway of the liner to a pay zone of the wellbore to be treated. Typically, initial treatment of a staged treatment occurs at the well toe, with subsequent stages at zones located increasingly uphole. The treatment fluid is pumped out of the liner and into the exposed pay zone. The zones co-extensive with the liner are shielded from effective treatment as a path of least resistance is defined for the treatment fluid into the treatment zone. The relatively tight liner clearance and treatment flow rates effectively prevent treatment of the shielded zones. After treatment, flow rate is reduced but pressure maintained while the moving liner is pulled uphole until the next treatment zone is exposed. Flow rate and pressure are increased and the newly-exposed zone is treated. The treatment fluid again follows the path of least resistance into the formation, with the liner clearance effectively blocking significant flow uphole along the liner annulus and the previously treated zone super-charged with previously pumped-in treatment fluid. The process is repeated along stages and zones.

FIG. 4 is a schematic view of an exemplary wellbore extending through a subterranean formation and having an exemplary liner for injecting fracturing fluid according to an aspect of the invention. The exemplary wellbore 100 extends through at least one formation 102. The upper portion of the wellbore is lined with a casing 104 and cemented into position. At the downhole end of the casing 104 is a sliding seal 106. The sliding seal 106 is generally known in the art as are substitute and equivalent seals. The sliding seal provides an annular seal against fluids and pressure around the work string and between the work string and casing. The downhole portion of the wellbore 100 is an open hole portion 108, that is, not lined with a casing or other tubular. The wellbores to be treated are production wellbores.

An exemplary work string 110 is shown positioned in the wellbore 100 creating an annulus 112 which can be thought of as comprising an upper annulus 112a defined between the work string and the casing along the upper portion of the wellbore and a lower annulus 112b defined between the work string and the open hole portion of the wellbore. The work string 110 is made up of a plurality of tubing sections joined together into a jointed tubing string.

A perforated sub 114, such as a perforated nipple, or other crossover tool is positioned in the work string. The perforated sub 114 provides a fluid flow path from the upper annulus 112a above the perforated sub 114 to the interior passageway 116 of the work string below the perforated sub 114. A check valve, one-way valve, other fluid valve 118, or a plug, can be positioned along the passageway 116 above the perforated sub 114 to selectively prevent fluid flow up the passageway.

In a preferred embodiment, one or more moving annular seal members 120 are positioned on the work string downhole from the perforated sub 114. The seal members 120 are attached to the work string and slide up and downhole along the casing as the work string is manipulated in the wellbore. The seal members 120 provide a moving annular seal between the work string and the casing. In an alternate embodiment, a stationary packer or other annular sealing device can be positioned in the casing providing an axial seal through which the work string can move.

The work string 110 downhole from the perforated sub 114 and sealing members 120 is a liner 122. Typically a liner 122 (treatment liner, frac liner, fracking liner, etc.) is formed from a plurality of joined liner sections. The liner continues to define interior passageway 116 for delivery of treatment fluid, such as fracturing fluid downhole. The liner has an effective outer diameter (OD) close to that of the open hole effective minimum diameter.

At or near the downhole end 124 of the string is, in some embodiments, one or more downhole tools 126. For example, the downhole tools 126 can include a dispersal tool, a flow control tool, a valve, a shoe, etc., as is known in the art. The treatment fluid exits the passageway 116 at or near the downhole end of the string. The treatment fluid is pumped down from the surface under pressure great enough to perform the necessary treatment. For example, the fluid is pumped down at fracturing pressure (or above) to cause fracturing in the formation 102. The treatment operations are designed to treat only a section of the wellbore, referred to herein as the “exposed pay zone.” The exposed pay zone is a length of wellbore, a section, exposed to the treatment operation, and the radially extending formation therearound.

In use, a work string 110 is made-up of liner 122 at the surface and lowered into the wellbore. Above the liner 122, the work string includes a perforated sub 114, check valve 116, and moving seal members 120, which can be made-up onto the string as the string is lowered into the wellbore. Above the perforated sub is a plurality of tubing sections, again made-up at the surface as the string is lowered into the wellbore. The liner 122 is positioned downhole at a selected location. In the example described, reference is made to fracturing as the well operation or treatment, frack fluid as the treatment fluid, etc., although it is understood that the disclosure provided herein can be used for other well treatments and with other treatment fluids. For example, using the disclosed technology, a bottom hole assembly (BHA) can be a well head isolator, work string, check valve in the work string above a crossover tool, a moving annular seal below the crossover tool, and a frack liner.

Once the downhole end 124 of the liner 122 is positioned uphole from an exposed pay zone 130, in this example at the toe 128 of the wellbore. The liner 122 effectively shields, masks, or protects the wellbore adjacent the liner, along shielded section 132, such that the shielded section 132 of the wellbore along annulus 112b is not effectively treated. Although some treatment fluid is expected to enter the annulus 112b between the liner and the open hole wellbore, the limited clearance between the liner and the open bore effectively isolates the exposed pay zone from the shielded section. In this manner, the treatment fluid takes the path of least resistance and enters the formation causing fractures rather than the path of greater resistance up the annulus 112b. The combination of the liner clearance and treatment fluid momentum as the injection rate is increased creates a path of least resistance for the injected treatment fluid to follow into the exposed portion of the bore and into the surrounding zone.

At the surface, treatment fluid is pumped through valve 30 and into the housing 26. Seal 41 keeps the fluid from exiting the upper end of the housing and allows the work string to be manipulated and moved up and downhole while still sealing against the pumped fluid pressure.

Treatment fluid is pumped from the surface, down the annulus 112a, through the perforated sub 114, into the passageway 116, downhole through at least one opening in the lower end 124 of the string and into the wellbore at the exposed pay zone 130, here the toe 128. The fluid is pumped at rates and at pressures to force the treatment fluid into the formation along the pay zone. For example, fracturing fluid is pumped downhole and into the formation at the pay zone causing fracturing of the formation.

FIG. 5 is a schematic view of an exemplary wellbore, as in FIG. 4, and having an exemplary work string for injecting treatment fluid moved to a second position, uphole from that seen in FIG. 4. Once the first exposed pay zone is treated (e.g., fracked), the string is moved uphole a selected distance, sections of jointed string are removed as necessary at the surface, and the treatment process is repeated along a newly exposed pay zone. The liner again shields the wellbore further uphole from effective treatment.

For example, in a prep stimulation treatment, acid treatment fluid is spotted at the toe of a lateral wellbore. The frack liner is run into the hole and positioned to expose a pay zone. For example, the end of the liner can be positioned at about 200 to 250 feet from the toe, exposing 200 to 250 feet of pay zone. The stimulation is initiated by pumping acid treatment fluid down the upper annulus, through the passageway 116, and into the wellbore toe to breakdown the exposed formation with the spotted acid. Once fluid flow rate from the surface is established, proppant slurry or fluid is pumped down the work string in the same manner. The proppant enters the wellbore toe and is forced by pressure into the formation at pressures sufficient of fracture the zone. The treatment fluid does not effectively treat the shielded wellbore along the lower annulus 112b due to the tight clearance between the liner and the wellbore which creates a path of greater resistance.

For use as a typical example, fracturing fluid is pumped downhole at a rate of 40 to 100 bbl/min at approximately 4000 psi to treat a selected zone. The pump rate is reduced to approximately 5 bbl/min to facilitate safety during movement of the work string uphole to expose and treat an additional zone.

Once the zone is fracked, the fluid flow to the work string is nippled down at the surface, while pumping continues to the upper annulus at a substantially lower flow rate. The work string is then pulled out of hole (POOH) a selected distance (e.g., 200 to 250 feet), under pressure, thereby exposing additional un-treated formation from the previous shielded zone.

The treatment process is repeated for the newly-exposed pay zone. The previously treated portion of the wellbore is super-charged with treatment fluid previously pumped in. A path of least resistance for the later-injected fluid is created in the newly-exposed portion of the wellbore (exposed by pulling-up of the liner). The newly-exposed pay zone now becomes the path of least resistance and the treatment fluid, once pumped at sufficient rate and pressure, follows the path into the new pay zone.

The treatment method is then repeated along the newly exposed pay zone. This procedure is repeated until the well is fully treated. The methods according to the invention have application in multi-stage fracturing of a subterranean formation having ultra-low permeability. Preferably, a method according to the invention further includes repeating the steps for another treatment zone of the subterranean formation.

The work string can be manipulated in the wellbore, that is, moved up and downhole, during treatment and while pumping fluid. This is possible because of the sliding seal 41 in housing 26, fluid entry at valve 30 into the housing below the seal 41, and the moving seals 120 attached to the work string and sealing the annulus 112a while moving. Alternately, appropriate stationary sealing devices, such as packers, can be used instead of or in conjunction with the moving seals 120. In the example above, pumping continues, at a lower rate, while the string is POOH to a new selected zone.

Usually a wellbore is between about 5 inches to about 36 inches in diameter, with smaller diameters being more common. A borehole can be “stepped down” to a smaller diameter the deeper the wellbore, and as upper portions are cased or lined, meaning progressively smaller work strings and tools must be used to pass through the borehole.

As mentioned above, the methods disclosed herein rely on a relatively tight or small liner clearance with respect to the borehole. For example, a 7 inch OD liner is run into a 7¾ inch diameter bore. The clearance is referred to as half the difference between the liner OD and the bore diameter, here, ⅜ inch. The liner 122 used in the method is typically approximately ¾ inch less in diameter than the open hole or casing diameter. As another example, a common bore ID of 7⅞ inch would take a 7⅛ inch diameter liner. It is preferable to have a relatively tight clearance as described, although it is believed that a greater clearance can be used, especially in conjunction with higher flow rates of treatment fluid.

The method described above with reference to an open bore provides advantages over other methods. In particular, it provides a method of treating an open bore without necessitating first lining the bore, perhaps cementing the liner, and probably perforating the liner. The time and expense savings are obvious. Further, since the open bore remains open, it is possible to later drill additional lateral, multi-lateral, or other bores without first cutting the liner, such as to create a lateral bore window, etc. Re-stimulation remains a readily accomplished later treatment. In conventional treatments, it is first necessary to run in a casing or liner and position the casing or liner in the wellbore, often by cementing it in place. A perforating string is then run to create perforations in most cases. The perfing string is pulled and a treatment string is run in to allow stimulation (e.g., acidizing, fracturing). Multi-stage fracking requires the running or pumping in, and successive activation of, sequential isolating devices or substances.

The disclosed methods and apparatus can also be performed and used in a cased or lined and perforated wellbore or portion thereof. The method is similar to that already described and will not be repeated here in detail. The liner clearance, between liner OD and casing or lined ID, provides a path of least resistance for the treatment fluid through the perforations and into the treatment zone. Here, the lined borehole is distinguishable from the manipulated frac liner 122. The liner 122 is run in to a selected position to treat a selected interval of wellbore. The treatment fluid is pumped in at a desired rate and to a desired pressure and the wellbore interval is treated through perforations in the casing or liner. The pump rate is dropped for safety and the liner pulled uphole a selected distance, thereby exposing another wellbore interval. The pump rate is increased and tis interval treated. The process can be repeated as desired.

Using the technology disclosed in U.S. Pat. No. 7,980,299, dated Jul. 19, 2011, which is incorporated herein by reference for all purposes, it is disclosed herein to stimulate wells as follows: starting at the “toe” or end of a lateral borehole, select an amount of open hole or set of perforations to be stimulated. RIH (run in hole) with a liner with a diameter very close to the inside diameter of the bore to be treated. The liner will be masking or covering the remainder of the horizontal bore towards the heel of the lateral.

At the top of the liner in the cased portion of the hole, insert a SSL (slip stream lubricator). The combination of the liner and fluid momentum as the injection rate is increased creates a path of least resistance of the injected fluid into the exposed portion of the bore. Once this interval is stimulated, the liner is pulled up the hole exposing another predetermined segment of the well bore which establishes a new path of least resistance. The previously exposed portion of the wellbore is super-charged with frac fluids already pumped in, creating a path of least resistance into the wellbore newly-exposed by pulling up of the liner.

In general, according to various embodiments of the invention, and without limitation as to the order, necessity, repetition, or addition of steps and methods, the following methods are presented. The methods are presented as numbered or otherwise labeled for ease of reading; the reference numbers, etc., are not limiting. 1. A method of treating a plurality of zones defined along a wellbore extending through a subterranean formation, the wellbore having a cased portion proximate the surface, the method comprising: a) making-up and running-in a work string to the wellbore to a position adjacent an exposed treatment zone of the formation, the work string, when made-up, having from top-to-bottom a plurality of tubulars, a perforated sub, an annular seal attached thereto, and a liner; b) pumping a treatment fluid downhole at a relatively high first flow rate into an annulus defined between the work string and the casing, through the perforated sub, and into an interior passageway defined in the liner; c) treating the exposed treatment zone, wherein the exposed treatment zone is defined downhole from the lower end of the liner; d) shielding additional treatment zones with the liner, and preventing effective treatment of the additional treatment zones; e) pulling the work string uphole and exposing an additional treatment zone while pumping treatment fluid downhole at a relatively low second flow rate; and f) repeating b) through e), treating the additional exposed treatment zones. Additionally the method can include any of the following steps or actions, in any order and in any combination: 2. further comprising: pumping treatment fluid through a surface housing into the wellbore annulus, the housing having a housing seal positioned in an annulus around the work string; 3. wherein a) further comprises placing a check valve in the work string above the perforated sub; 4. further comprising: sliding the annular seal along the casing; 5. wherein a) further comprises: coupling the plurality of tubulars to one another, end-to-end; 6. wherein the treatment fluid is fracturing fluid and wherein c) further comprises: fracturing the exposed treatment zone; 7. wherein b) further comprises: pumping the fracturing fluid at a relatively high first flow rate of between about 40 and 100 bbl/min; 8. wherein b) further comprises: pumping the fracturing fluid at a pressure of around about 4000 psi; 9. wherein the liner has a clearance of around about ⅜ inches; 10. wherein a path of least resistance is defined for the treatment fluid into the treatment zone in response to a clearance of the liner in the wellbore annulus; 11. wherein the path of least resistance is defined for the treatment fluid into the treatment zone in response to the relatively high first flow rate; 12. wherein the treatment fluid further comprises: an acidizing fluid; 13. wherein b) further comprises: pumping the fracturing fluid at a relatively high first flow rate of above about 40 and 100 bbl/min.; 14. wherein e) further comprises: pumping the fracturing fluid at a relatively low second flow rate of about 5 bbl/min.; 15. wherein the exposed first treatment zone is open hole or has a perforated casing or lining; 16. wherein pulling the work string in e) further comprises: uncoupling or disconnecting one or more of the plurality of tubulars; 17. further comprising: g) treating multiple wellbores extending through the subterranean formation before removing the liner from the well. In another embodiment, a method of sequentially treating treatment zones along a wellbore extending through a subterranean formation, the method comprising: positioning a liner adjacent to an exposed treatment zone; pumping a treatment fluid downhole into the exposed treatment zone, while shielding additional treatment zones with the liner; moving the liner while pumping treatment fluid downhole, thereby exposing an additional treatment zone; and repeating a) through c), treating additional exposed treatment zones.

As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

As used herein, “first,” “second,” or “third” may be arbitrarily assigned and are merely intended to differentiate between two or more fluids, aqueous solutions, etc., as the case may be, that may be used according to the invention. Accordingly, it is to be understood that the mere use of the term “first” does not require that there be any “second,” and the mere use of the word “second” does not require that there by any “third,” etc. Further, it is to be understood that the mere use of the term “first” does not require that the element or step be the very first in any sequence, merely that it is at least one of the elements or steps. Similarly, the mere use of the terms “first” and “second” does not necessarily require any sequence. Accordingly, the mere use of such terms does not exclude intervening elements or steps between the “first” and “second” elements or steps, etc.

As will be appreciated by a person of skill in the art, the methods according to the invention can have application in various kinds operations involved in the production of oil and gas, including drilling, completion, and intervention. The features and advantages of the present invention will be apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the invention.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention.

While methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods also can “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is a conflict in usages of a term in this specification and other patents or documents incorporated herein, the definitions consistent with this specification should be adopted.

Claims

1. A method of treating a plurality of zones defined along a wellbore extending through a subterranean formation, the wellbore having a cased portion proximate the surface, the method comprising:

a) making-up and running-in a work string to the wellbore to a position adjacent an exposed treatment zone of the formation, the work string, when made-up, having from top-to-bottom a plurality of tubulars, a perforated sub, an annular seal attached thereto, and a liner;

b) pumping a treatment fluid downhole at a relatively high first flow rate into an annulus defined between the work string and the casing, through the perforated sub, and into an interior passageway defined in the liner;

c) treating the exposed treatment zone, wherein the exposed treatment zone is defined downhole from the lower end of the liner;

d) shielding additional treatment zones with the liner, and preventing effective treatment of the additional treatment zones;

e) pulling the work string uphole and exposing an additional treatment zone while pumping treatment fluid downhole at a relatively low second flow rate; and

f) repeating b) through e), treating the additional exposed treatment zones.

2. The method of claim 1, further comprising: pumping treatment fluid through a surface housing into the wellbore annulus, the housing having a housing seal positioned in an annulus around the work string.

3. The method of claim 1, wherein a) further comprises placing a check valve in the work string above the perforated sub.

4. The method of claim 1, further comprising: sliding the annular seal along the casing.

5. The method of claim 1, wherein a) further comprises: coupling the plurality of tubulars to one another, end-to-end.

6. The method of claim 1, wherein the treatment fluid is fracturing fluid and wherein c) further comprises: fracturing the exposed treatment zone.

7. The method of claim 6, wherein b) further comprises: pumping the fracturing fluid at a relatively high first flow rate of between about 40 and 100 bbl/min.

8. The method of claim 7, wherein b) further comprises: pumping the fracturing fluid at a pressure of around about 4000 psi.

9. The method of claim 1, wherein the liner has a clearance of around about ⅜ inches.

10. The method of claim 1, wherein a path of least resistance is defined for the treatment fluid into the treatment zone in response to a clearance of the liner in the wellbore annulus.

11. The method of claim 10, wherein the path of least resistance is defined for the treatment fluid into the treatment zone in response to the relatively high first flow rate.

12. The method of claim 6, wherein the treatment fluid further comprises: an acidizing fluid.

13. The method of claim 6, wherein b) further comprises: pumping the fracturing fluid at a relatively high first flow rate of above about 40 and 100 bbl/min.

14. The method of claim 6, wherein e) further comprises: pumping the fracturing fluid at a relatively low second flow rate of about 5 bbl/min.

15. The method of claim 1, wherein the exposed first treatment zone is open hole or has a perforated casing or lining.

16. The method of claim 1, wherein pulling the work string in e) further comprises: uncoupling or disconnecting one or more of the plurality of tubulars.

17. The method of claim 1, further comprising: g) treating multiple wellbores extending through the subterranean formation before removing the liner from the well.

18. A method of sequentially treating treatment zones along a wellbore extending through a subterranean formation, the method comprising:

a) positioning a liner adjacent to an exposed treatment zone;

b) pumping a treatment fluid downhole into the exposed treatment zone, while shielding additional treatment zones with the liner;

c) moving the liner while pumping treatment fluid downhole, thereby exposing an additional treatment zone; and

d) repeating a) through c), treating additional exposed treatment zones.