Patent Application
20190063186
Hydraulic fracturing is used to increase the area of a formation that is in communication with a wellbore and therefore increasing either production of fluids, or increasing the amount of fluids that may be injected into the formation from the wellbore. Hydraulic fracturing has been in commercial use for many decades, but gradual improvements in the size of fractures that can be created and the cost effectiveness of the fractures, along with developments like improved horizontal drilling and directional drilling, have resulted in hydraulic fracturing enabling production of hydrocarbons from formations such as source rocks or other very low permeability formations, that were previously not considered to be economically producible.
Typically, gas and/or oil is produced from low permeability formations such as source rocks, by providing horizontal wells in the formations for distances of a mile or more. The formation is then fractured from the wellbores in as many as twenty to fifty places, with the fractures placed every 15 to 150 meters along the horizontal wellbore. The fractures are provided by pumping fracturing fluids into an isolated section of the wellbore that is in communication with formation at pressures that exceed the pressure that causes the formation to break, and open up. This allows fracturing fluids to enter the formation through into the fracture and further propagate the fracture until the rate at which fluids go into the formation, via the rock faces of the fracture, equals the rate at which fluids can be pumped into the fracture.
Fractures are either propped open after they are formed by including in the fracturing fluids materials such as finely sized sands or ceramic particles, or in carbonate formations, permeability through fractures may be created by including acids in the fracturing which dissolve some minerals at the face of the fracture to create wormholes along the rock surfaces of the fractures. Proppants may be held in suspension within the fracturing fluids by including additives to increase the viscosity of the fracturing fluids, to decrease the settling rate of the proppants. Alternatively, or in addition, proppants may be utilized with lower densities to decrease the rate at which they settle in the fracture fluids,
Polymers used to increase the viscosity of fracturing fluids may be detrimental to formation permeability in the vicinity of the fractures, so techniques referred to as slick water fracturing have been developed. These techniques do not utilize thickening polymers, but instead rely on rapid injection of fracturing fluids.
Fracturing methods are disclosed in, for example, U.S. Pat. Nos. 8,183,179, and 7,451,820, the disclosures of which are incorporated herein by reference.
Methods are known to provide fractures one at a time by providing a cluster of perforations in a casing and isolating the segment containing the cluster of perforations with packers or composite drillable plugs, and then pumping a fracturing fluid into the segment at a pressure which is high enough to fracture the formation through the cluster of perforations. The packers are then moved to another segment of the well bore from which another cluster of perforations have been provided or more composite drillable plugs are added, and the process is repeated. The composite drillable plugs get milled when the total horizontal well has been stimulated to allow the flow of all the fractures.
Providing one fracture at a time is a slow process and there are numerous opportunities for equipment to fail, causing further delays. An improvement has been to provide a set of fractures at one time by isolating a plurality of clusters of perforations, and providing the high pressure fracturing fluid to all of the isolated clusters. This saves a considerable amount of rig time, but results in fracture that vary in size. For example, when a group of four clusters are fracked at one time, it has been found that it is typical for one or two of the clusters of perforations to not be fractured at all, and for significantly more proppant to enter only one fracture. The fractures are therefore not of an optimal size. The number of clusters perforated at one time has generally been limited in order to reduce the number of clusters from which effective fractures are not provided.
Techniques to provide more equally sized fractures include providing diverter material into fracturing fluids at intervals to plug growing fractures and force fracturing fluids into other perforations. Such a method is disclosed, for example, in U.S. patent application publication US2015/0233226.
Other than fracturing through perforations within a wellbore, it is also known to provide the well casing with sleeve valves that can be opened in order to provide communication for fracturing fluids from inside the casing to the formation surrounding the casing. U.S. patent application US2015/0114664 disclose a biased sleeve valve which can be tripped to an open position by, for example, electronic or magnetic signal delivered in a ball which can be dropped into the wellbore when it is desired to open the sleeve. It is also suggested that the apparatus could include a flapper that swings onto a seat when the sliding sleeve moves, thus blocking flow to fractures below the opened sleeve valve. It is suggested that the flapper could be made of a material that decomposes at wellbore conditions, and thus after the fracturing operation, does not inhibit production from fractures below the flapper. The ports are sequentially opened and fractures provided through the sleeves individually. This method may provide fractures one at a time without the need to move packers, but the suggested methods for triggering movement of the combined sleeve valve and flapper require either ports to catch dropped balls, coiled tubing or other mechanisms. Because extended reach wells can be provided that extend for more than a mile, and ideal fracture spacing may be as small as forty five feet, it is desired to have a method and apparatus to provide a casing with an unlimited number of controllable sleeve valves and flapper combinations without the need for a coiled tubing to operate valves and packers.
Sleeve valves are also available that may be controlled remotely, for example, but electrical signals transmitted through wires or through the casing itself, hydraulic lines or by signals carried by fiber optic cables. These valves are generally not cost effective because they considerably increase the cost of a well.
Sliding sleeve valves that are capable of being operated by commercially available wireline tools are known, for example, as described in U.S. Pat. No. 5,263,683.
Fracturing formations with mortar compositions are known, for example, from U.S. patent application publication US 2013/0341024.
A method to provide a fractured subterranean formation comprising: providing a wellbore from a surface location to the subterranean formation and essentially horizontal within the subterranean formation from a heal end to a toe end; providing a casing within the wellbore wherein the casing comprises a plurality of first wire-line controllable valves effective to provide communication between an inside of the wellbore and an outside of the wellbore, and a plurality of second wire-line actuated valves, wherein each second wire-line actuated valve is associated with a first wire-line actuated valve, and each second wire-line activated valve is effective to isolate a portion of the inside of the wellbore upstream from the first valves from a portion of the inside of the wellbore down-stream of the first valve wherein initially all first wire-line controllable valves are closed, and all second wireline controllable valves are open; providing a fracture from the wellbore near the toe end of the wellbore between the toe of the wellbore and the first wire-line controllable valve closest to the toe end of the wellbore; opening the first wire-line controllable valve and closing the second wire-line controllable valve closest to the toe end of the wellbore; providing a fracture into the subterranean formation through the open first wire-line controllable valve; opening a first wire-line controllable valve that is second closest to the toe end and closing a second wire-line controllable valve that is second closest to the toe end; and providing a fracture into the subterranean formation through the open first wire-line activated valve that is second closet to the toe end.
The present invention permits fracturing using single point entry of fluids for each individual fracture with a system that reliably and quickly moves from one fracture to the next fracture, thus addressing the primary disadvantages of single point entry systems presently used.
The present invention could be utilized with a mortar or cement fracturing process, or could be utilized with an acid fracturing, slick water proppant fracturing process, or a polymer gelled proppant fracturing process.
Wellbores may be provided for the practice of the present invention by known means of drilling and completion of wells. The wellbore for the present invention may be vertical, but the present invention is more beneficial when applied to horizontal wells because a significant number of fractures may be provided from horizontal wellbores. Horizontal laterals may be provided by directional drilling techniques that utilize accelerometers to determine positions of the wellbore and steerable motors to drive the drill bit, or by utilizing logging while drilling techniques to maintain the well near a target location within a formation, or within a predetermined distance and direction from a reference wellbore. Techniques are being developed to extend the distance which horizontal wells may be provided, because generally, a longer horizontal section will enable access to a larger volume of a formation more economically because the expense of providing wellheads and wellbores through the overburden are reduced with respect to a volume of formation to be accessed. Techniques such as neutrally buoyant drill pipes or tractors to supplement the weight on the drill bit may be useful to increase a length of horizontal well that may be provided.
After a wellbore is provided, it may be completed, for example, by known means of providing casing and cementing the casing in the wellbore. The casing will generally need to be perforated prior to the operation of fracturing the formation. Perforations maybe provided by placing shaped charges in tools that are positioned in the wellbore and the shaped charges detonated. The shaped charges force open holes in the casing, and through any cement in the annulus between the casing and into the formation. Thus, communication is established between the inside of the casing and the formation.
The casing may be provided in a series of decreasing sizes. This is because the difference between the fracturing pressure of the formation, and the pore pressure of the formation, permits only a certain distance to be drilled before a single drilling fluid density will not be sufficient to keep the pressure within the wellbore above the pore pressure of the formation being drilled, and below the pressure which will fracture the formation, plus a margin of safety. Thus, at that point, the wellbore will need to be provided with a casing, typically cemented into the wellbore, to isolate the wellbore from the formation and permit continued drilling. Thus, wells are typically provided with a series of casings cemented into the wellbore with the largest diameter casing first, and each subsequent casing having a slightly smaller diameter.
The present invention utilizes wire-line controllable valves effective to provide communication between an inside of the wellbore and an outside of the wellbore along the length of the wellbore placed at locations where it is desired to fracture the formation. These valves could be sliding sleeve valves such as the sliding sleeve valves described in U.S. Pat. No. 5,263,683. These valves may be operated by a wire line operated tools capable of latching onto the sliding sleeve and change its position to expose ports initially covered by the sliding sleeve. The wire line operated tool could be, for example, a mechanically shifting ‘stroker’ tool. This tool string or Bottom Hole Assembly (BHA) may be outfitted with a key assembly designed to be compatible with each sliding sleeve to be opened/closed throughout the length of the wellbore. In the case of horizontal wellbores a tractor tool can be added this (BHA) and acts to transport the BHA across the lateral section of the well (towards the toe) in order to access each sleeve to be opened/closed. Such tools are commercially available and could be modified as necessary to operate such any industry offered sleeves.
The wire-line controllable valves effective to provide communication between the inside and the outside of the wellbore may be installed initially in a closed position, so communication is not provided between the inside of the wellbore and the outside of the casing.
The casing is also provided with a plurality of second wire-line actuated valves, wherein each second wire-line actuated valve is associated with a first wire-line actuated valve, and each second wire-line activated valve is effective to isolate a portion of the inside of the wellbore upstream (toward the wellhead) from the first valves from a portion of the inside of the wellbore down-stream (toward the toe end of the well) of the first valve. The second wire-line actuated valves may be flapper valves that swing onto seats from the heal end of a lateral wellbore so that pressure from fracturing fluids will press the flapper against the seat and aid in sealing of the valve. The flapper valves could be made of material that decomposed over time at wellbore conditions so that they would permit production from the wellbore after the fracturing operation is completed. These valves could also operate as check valves where fluid flow from the heal end of the wellbore would press the valves closed but fluid flow from the toe end of the well would pass through the valve.
Flappers may optionally be made of easily millable material where they could be easily drilled through after the fracturing operation is completed. In another embodiment, the flapper valves may be provided that could be opened by an intervention such as a wire-line or coiled tubing conveyed kick-over tool. In another embodiment, the flapper valves could have flapper elements that can be shattered by, for example, a coiled tubing tool after the fracturing operation is completed. Alternatively, the wire line operating tool could be provided with an element that could be used to shatter the flapper valve, and the flapper valve flapper element shattered after the fracture is provided and prior to the wire-line operating tool being moved to operate the next two associated first and second wire-line operatable valves. The flappers could be designed to shatter into pieces small enough so the pieces do not interfere with operation of the well after the fracturing process is completed.
The second wire line controllable valve could be a flapper valve similar to the flapper valve disclosed in U.S. patent application US2015/0114664.
The second wire line controllable valves may be provided in close proximity to the first wire line controllable valves with which they are associated. The volume between the first wire line controllable valve and the second wire line controllable valve could fill with proppant during the fracturing process because inertia of the solid proppants may carry them past the opening into the fracture and accumulate in the volume past this opening. This volume may therefore be minimized to reduce an amount of proppant that may remain in the wellbore after the fracturing operation is completed.
The second wire line actuated valves could be initially installed in the casing in an open position so the casing has communication from the wellbore to the end of the casing.
After the casing is provided in the wellbore, cement may be provided in the annulus between the casing and the wellbore by conventional means. The cement is provided to provide for zonal isolation, and so that fractures, when they are created, will be created near the location of the valves providing communication between the inside of the casing and the outside of the casing. Cement may be, for example, pumped into the casing from the wellhead, followed by a plug that catches on a seat at the lower, or toe end of the casing. After the plug has seated in the toe end of the casing, the cement is then permitted to cure. Fluids behind the plug could be water or mud weighted to enable relatively easy initiation of a fracture. The plug could also optionally be followed by an actuator such as a wire-line kick-over tool connected to a wire line. This would be a convenient time to place such actuator in a position to be used to operate valves after the wellbore cement has cured.
An initial fracture could be provided at the toe end of the well by pressuring cement plug and fracturing the formation at the end of the casing. In this embodiment, the plug could be provided that isolates the cement from the wellbore fluids behind the plug, but is designed to fail upon application of pressure from the wellbore fluids. In another embodiment of the present invention, rather than fracturing through the cement plug, a valve could be provided in the casing near the toe end of the wellbore effective to, after being moved, provide communication from inside of the wellbore to outside of the wellbore. This valve would not need a flapper valve associated with it that is effective to isolate a portion of the inside of the wellbore upstream from the first valves from a portion of the inside of the wellbore down-stream of the first valve. In another embodiment, the casing near the toe end of the well could be perforated by a conventional perforation gun using explosives to provide communication from the inside of the casing to the formation outside of the casing.
After the first fracture is formed, the valve to provide communication form inside the wellbore to outside of the wellbore adjacent to the first fracture could be opened, and the valve associated with it to isolate a portion of the inside of the wellbore upstream from the first valves from a portion of the inside of the wellbore down-stream of the first valve could be closed. This is preferably accomplished with a wire line conveyed tool such as a commercially available wire-line kick-over tool.
With the valve providing communication between the inside of the casing and the outside of the casing open, the formation can then be fractured at the location of this valve.
When the second fracture is completed, the wireline conveyed actuator may be moved past the next set of associated valves, causing the next valve proving communication between the inside of the casing and the outside of the casing to be opened, and closing its associated valve to isolate the portion of the inside of the wellbore down-stream of the first valve. A fracture is then provided into the formation from this next opened valve.
The process of moving the actuator past each set of valves, and fracturing the formation form that next location is then repeated until fractures have been provided from each of the wire-line controllable valves effective to provide communication between an inside of the wellbore and an outside of the wellbore.
The process of the present invention may be used to provide individual fractures so that an amount of fluids provided into each fracture is controlled, and no operations are needed between fractures other than moving an actuator past the nest set of associated valves. Fractures could be provided in a wellbore with less equipment than other single entry methods, for example the use of coil tubing to shift the sleeves. The down-hole equipment that is needed includes only a wire line actuator, and the wire-line operated valves. These are simple and reliable pieces of equipment and much more reliable than, for example, packers which need to set and seal repeatedly in current fracturing operations or less expensive than coil or work-string tubing.
Fracturing, or fracking, of formations may be accomplished by injection of a slurry of fracturing fluid and proppant into the formation at pressures sufficiently great to exceed the tensile strength of the formation and cause the formation to separate at the point of the perforations. Formations will generally have a direction where the formation is under the least amount of stress, and the fracture will initially propagate in a plane perpendicular to the direction of such least stress. In deep formations, such as is generally the case in formations containing what is known as light tight oil, shale gas, or tight sands formation, the weight of the overburden will generally assure that the direction of minimal stress is a horizontal direction. It is generally the goal to provide horizontal wellbores in such formation in the direction of the minimal formation stress so that fractures from the wellbore will tend to be perpendicular to the wellbore. This allows access to the maximum possible volume of formation from a horizontal wellbore of a limited length.
Methods for hydraulic fracturing of formations are suggested, in for example, U.S. Pat. No. 5,074,359 to Schmidt and U.S. Pat. No. 5,487,831, to Hainey et al., the disclosures of which are incorporated herein by reference.
Fracking processes may be initiated by a slug of fluids referred to as a pad, which initiates the fracture, followed by fluids that contain proppants. The proppants are generally finely sized sands. Generally the sands are referred to by the size of mesh which the sand will pass through, and the size of mesh which the sand will not pass through. Typically, a 20-40 mesh sand is used but other sizes, such as 40-50 or 40-60, may be utilized. Sand is also characterized by the “roundness” of the sand particles. Generally rounder sand that is within a narrow range of diameters is utilized in order to create more uniform void spaces between the particles and therefore better permeability within the propped fracture. Fracturing fluids also contain, for example, viscosifiers to slow the rate at which sand will separate from the fluids and permit the sand to be carried farther into the fractures.
Other types of proppants are also known and may be useful in the practice of the present invention. For example, ceramic proppants are known. Coated proppants such as the proppants suggested in U.S. Pat. No. 7,730,948 to Grood et al. may be useful. The coatings suggested by U.S. Pat. No. 7,730,948 are coatings with low coefficients of friction in order to reduce erosion caused by the fracturing fluid. The coatings also are said to make the sand particles more round. Examples of such coatings include antimony trioxide, bismuth, boric acid, calcium barium fluoride, copper, graphite, indium, fluoropolymers (FTFE), lead oxide, lead sulfide, molybdenum disulfide, niobium dielenide, polytetrafluoroethylene, silver, tin, or tungsten disulfideor zinc oxide. Ceramic proppants are suggested, for example, in U.S. Pat. No. 4,555,493 to Watson et al., and low density ceramic proppants are suggested in U.S. Pat. No. 8,420,578 to Usova et al., and such proppants may be useful in the practice of the present invention.
Formations may also be fractured with fracturing fluids that contain a component that reacts with at least some components of the formation, and thereby removing some of the formation at the face of the fracture. Alternatively, the component may react with the formation in a way that creates solids, and the solids could hold the rock faces of the formation apart after pressures are reduced within the fracture. The component that reacts with the formation may be acidic, and the acid may dissolve carbonate rocks on the surface of the fractures, leaving unmatched rock surfaces that close up with paths for fluids to traverse through the fracture to the wellbore. Acid fracturing may be used in conjunction with proppants, or could be used without proppants.
Another additive generally present in fracturing fluids is friction reduction chemicals. U.S. Pat. No. 8,105,985, to Wood et al, for example, discloses acceptable combinations of water soluble fiction reducing polymers useful in fracturing fluids gelled with viscoelastic surfactants. Such friction reduction chemicals may be utilized with the present invention, but optimal amounts of such chemicals may be reduced as a result of the coatings provided to the wellbore tubular.
Fracturing fluids may also contain other components, such as acids for breaking the thickening polymers, salts such as calcium chlorides to increase the density of the fluids, corrosion inhibitors or other additives known to be useful in fracturing fluids.
In one embodiment of the present invention the formation could be fractured in phases as disclosed in U.S. patent application publication 2015/0075784, the contents of which are incorporated herein by reference. Effective placement of fractures in deviated or horizontal wells is challenging. This challenge is highlighted in formations with low permeability. As permeability decreases, smaller spacing is generally necessary to effectively recover hydrocarbons from the formation. However, as the spacing between fractures decreases, the stresses associated with the injection of fluids into the formation to create one fracture is believed to create a “shadow” stress in the formation that negatively influences the placement of the next fracture.
In this embodiment, the effect of stress shadows on subsequent fractures is reduced by providing the fractures in phases in time. The method includes determining a final economically optimized fracture spacing. The desired spacing may be calculated or otherwise determined on the basis of the minimum economic production rate taking into account formation porosity, hydrocarbon saturation, permeability, and costs associated with completion and production. Such determination might involve calculations of net present value, and accounting for various factors including but not limited to current oil and gas prices, operational costs, and capabilities of the facilities. Then create a first set of fractures at an initial fracture spacing. This initial fracture spacing being larger than the final economically optimized fracture spacing. The method includes allowing production of fluids from the formation through the well bore via the first set of fractures for a period of time. This method includes, after the period of time, creating a second set of fractures between the fractures of the first set. The final fracture spacing is less than or equal to an average fracture spacing between the first set of fractures and the second set of fractures. To apply this method of fracture placement with the present invention involves providing the first set of fractures by skipping the necessary (every other one, pairs, etc) set of wire-line controllable valves. The well is then produced from the first set of fractures for a time period sufficient to reduce the stress shadow from the first fractures. After production has relieved the shadow stress is from the first set of fractures a dedicated intervention with the stroker tool is needed to close all the open first wire-line controllable valves and then commence the same sequence to create the second set of fractures. As the second set of fractures is created the previously stimulated sleeves are opened as the wire line tool is moved up in the well to ensure by the end of the stimulation all sleeves are opened for production.
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Cement is separated from fluids 205 pumped into the casing behind the cement by a cement plug 202. Fluids behind the cement plug are pumped into the casing until the cement plug is caught at the extreme end of the casing by catcher 110. Behind the cement plug a wire line 203 conveyed tool effective to operate the wire line controllable valves such as a wire line stroker tool 204. The wire line stroker tool could be attached to the cement plug to ensure that it is transported to the toe end of the wellbore and past the controllable valve closest to the toe end of the wellbore. The fluids 205 could be fracturing fluids that do not contain proppants because the well must remain in this position until the cement 201 has cured, and it is not desireable for the proppant to settle out of the fluids during this time period.
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In one embodiment of the present invention the formation could be fractured using mortar or cement as disclosed in U.S. patent application 2013/0341024. In this embodiment, a coiled tubing could be used to place the cement slurry near the bottom of the casing and optionally replace the wireline used to convey the shifting tool to perform the sequences described in this application and the casing filled with cement slurry until the hydrostatic head of the cement slurry exceeds the fracturing pressure of the formation. In this embodiment the cement slurry may have a specific gravity that is 2 or greater, or between 2.1 and 2.5. With this gravity of slurry, a hydrostatic head of the column of slurry in the casing will generally exceed the fracture pressure of the formation with no excess pressure applied to the fluids in the casing at the surface during the fracturing operation. It may be useful to apply pressure to the fluids in the casing before or after fracturing by the slurry, for example, to create an initial fracture or to remove cement from the casing either by forcing the cement into the fracture or circulating the cement up the casing by injection of brines or other fluids into the casing via, for example, a coiled tubing. When pressure is applied to the fluids in the casing from the surface for these operations, the volume of fluids does not need to be significant. Therefore fracturing pumps with large capacities are not needed. Further, if coiled tubing is used to place cement in the wellbore, the high pressure pumps do not need to pump cement slurry. Only relatively small volumes of fluids containing proppants need to be pumped at high pressures, so maintenance of the pumps is greatly reduced.
In normal fracturing operations, fractures are seen by microsiesmic data to grow in and upward direction from the initial point of fracture. This may be because the hydrostatic head of the normal fracturing fluid in a fracture is generally less than the fracture gradient of the formation, and the pressure to propagate the fracture comes from very high pressure pumps at the surface. Within the fracture, the rock being fractured sees the sum of a hydrostatic head of fluid, plus the pressure applied at the surface, less hydraulic losses due to the flow of fluids. The fracture pressure within the fracture is exceeded more at the top of the fracture then the bottom of the fracture because the hydrostatic head of fluids within the fracture is less than the fracture gradient of the rock being fractured. With a very high density of fracturing fluid, the opposite would be true. With a fracturing fluid that is a cement slurry or mortar slurry having a specific gravity of greater than 2, the fracture pressure within the fracture will be exceeded more at the bottom of the fracture than at the top of the fracture. The fractures will tend to grow downward in the case where the fracture gradient within the formation being fractured is exceeded by the hydrostatic head of fracturing fluids.
In one embodiment of the present invention, a wellbore could be provided with fractures using fracturing fluids having specific gravities which do not exceed the fracture gradient of the formation, thus producing upward fractures, and then fractures could be provided using fracturing fluids having specific gravities which exceed the fracture gradient of the formation being fractured, thus providing fractures that tend to grow downward. The fluids with specific gravities that do not exceed the fracture gradient of the formation could be traditional slick water fracturing fluids, polymer gelled fracturing fluids, or simply slugs of sand and water. More of the formation could be accessed by fractures when fracturing fluids of such differing specific gravities are utilized.
The fractures could be provided in an initial completion process, or, for example, a well that had been provided with fractures using fracturing fluids that do not exceed the fracture gradient of the formation, and optionally produced. This conventionally fractured and produced well could then be refractured with a cement slurry or mortar slurry fracturing process to add fractures that extend down rather than up, and thus accessing a completely unproduced portion of the formation from the existing wellbore.
In another embodiment of the present invention, a specific gravity of a fracturing fluid is selected based on a position of the wellbore in relationship with the formation to be accessed by the fracture. If the formation to be accessed by the fracture is below the wellbore, a fracturing fluid with a specific gravity that exceeds the formation fracture gradient is selected. If the formation to be accessed by the fracture is above the wellbore, a fracturing fluid with a specific gravity that is less than the formation to be fractured is selected. The position of the formation to be accessed may be below the wellbore because, for example, the wellbore was provided initially near the top of the formation to be accessed, or because upward fractures have been provided, and the formation above the wellbore has already been produced. If the wellbore is near the center of the formation to be accessed, a fracturing fluid having a specific gravity within, for example, plus or minus ten percent of the fracture gradient, could be used.
In another embodiment of the invention, when cement slurry or mortar slurry is used as fracturing fluid, a coiled tubing may be used to place cement in the wellbore. After the fracture is formed, cement could be circulated out of the casing prior to moving to the next fracture by circulating a displacement fluid down the coiled tubing. If a coiled tubing is used in this fashion, the coiled tubing could be provided with an actuator to operate the wire line controllable valves.
The initial fracture could include an acid treatment. Acids treatments are often used at the beginning of a fracturing operation to remove some cement from the annulus around perforations or sliding valve openings. This acid treatment can reduce pressure drop in the near wellbore region significantly. Generally a wellbore volume of acid is used for this purpose.
When cement slurry or mortar is used for fracturing, the volume of acid used in the acid treatment could also be larger than the acid treatment normally used. For example, three to ten wellbore volumes of acid could be used. Placing acid into the fracture before fracturing with cement slurry could result in essentially an acid treatment to the surfaces of the cured cement in the fracture. The acid would be forced either deeper into the fracture or into the formation at the face of the fracture. After fracturing pressures are released, the acids, or resulting neutralized salts, would tend to flow back toward the wellbore. The acid would either react with carbonates in the formation, or upon flowing back into the fracture, react with carbonates in the cured cement, thus creating flow paths for formation fluids along the surface of the cement in the fracture.
A useful fluid for acid for use in the present invention is 15% w to 28% w hydrochloric acid. Alternatively, formic, sulfuric, phosphoric, nitric, or acetic acid, or combinations thereof, may be used. These acids are easier to inhibit under high-temperature conditions. However, acetic and formic acid generally cost more than hydrocloric.
Typically, a gelled water or crosslinked gel fluid may be used as a pad fluid to fill the wellbore and break down the formation. The water-based pad is then pumped to create an initial fracture. The acid may be if fluids that are gelled, crosslinked, or emulsified to maintain fracture width and minimize fluid leakoff. Fluid-loss additives may be added to the acid fluid to reduce fluid leakoff.
An acid treatment could be followed by a spacer fluid to reduce back-mixing of acid with cement slurry or mortar slurry. The spacer fluid could be a gelled fluid to match viscosity of the cement slurry or mortar slurry at wellbore temperatures to help reduce back mixing between the spacer and the slurry.
The present invention, when using cement slurry or mortar slurry as a fracturing fluid, could be practiced by continuing to place the slurry into the casing from the surface from creation of the initial fracture until the last fracture is formed. In this embodiment, when sufficient cement has been forced into a fracture, a slug of gelled proppant containing fluid could be put into the casing, followed by a spacer of fluids without proppant, then an acid slug. When the proppant containing fluid is essentially in the fracture, the wire line controllable valves could be operated to isolate the newly created fracture, and open the next first wire line controllable valve providing communications between the inside of the casing and the formation. The acid would be placed to then enter the formation and create a new fracture. During this operation, if the casing is filled with acid rather than cement slurry, it may be necessary to apply pressure to the fluids in the casing from the surface to fracture the formation and force acid into the formation. In this embodiment of the invention, fluids could be pumped into the casing almost continuously from initiation of the first fracture until the last fracture is completed.
An advantage of using cement or mortar slurry as fracturing fluid, compared to either slick water or polymer gel proppant methods, is that water use is reduced by at least half. Further, all of the water that is injected in a normal slick water or polymer gelled fracturing operation is eventually produced. This water, when it is produced, may be saturated with hydrocarbons and salts, and needs considerable treatment prior to disposal. Because most of the water that is used for the cement or mortar slurry fracturing process is consumed in hydration of the cement or mortar, very small amounts of fluids are produced which need to be treated or disposed of. In particular, high density slurries contain a higher ratio of solids to water, and this reduces the amount of unreacted water remaining after the cement or mortar cures. Because water rights can be scarce in some locations, this significant reduction in water consumption is a significant advantage. For example, more than ninety percent of the water injected in the fracturing process could be consumed in hydration of the cement or mortar, or between ninety five and ninety nine percent of the water injected in the fracturing process could be consumed by hydration of the cement or mortar.
Another advantage of using cement slurry or mortar slurry as fracturing fluids is that it is found that after the cement hydrates and production is initiated, because so little water flows back into the wellbore, normal production starts in a very short time period. For example, normal production could be started within one day or within one to three days of initial flow from the wellbore. Typically, after a well is fractured or refractured, production needs to be isolated for five to thirty days because of sand and water contents that exceed the capacity of normal production systems. During this five to thirty day period, temporary equipment and operators costing from $100,000 to $500,000 or more are required for each well, and this temporary equipment and operators are not needed with the present invention.
Another advantage of using cement slurry or mortar slurry for fracturing is that the footprint of required equipment is significantly reduce compared to normal slick water or polymer gelled fracturing fluid methods. Although high head pumps may be needed for initially creating fractures and for forcing cement in the wellbore into the fracture at the conclusion of the fracturing operation, these operations do not require large volumes, so expensive pumps for fracturing fluids are mostly eliminated. In general, power requirements of the present invention can be about a third of power requirements for a slick water fracturing operation.
Another advantage of using cement slurry or mortar slurry for fracturing is that the carbon dioxide and noise foot print are significantly reduced compared to normal slick water or polymer gelled fracturing fluid methods. A significant reduction from both results from reduced horsepower used to place the material into fractures. Additionally, the carbons dioxide is generated and less water is used, along with significant reductions in the amount of water that requires treatment results from flow-back of water after a completion operation being almost eliminated by the present invention. Reduced water use and waste water production also reduces trucking requirements.
Another advantage of the present invention when cement slurry or mortar slurry is used as fracturing fluid is that normal surface well head equipment used for fracturing, referred to as the frac tree, is not needed. The fracturing can be done through a normal blow-out preventer. Not having to change surface equipment reduces cost and time and saves a significant amount of expense.
In another embodiment of the present invention with cement slurry or mortar slurry being used as fracturing fluid, density of the cement is chosen so that the hydrostatic head of a column of cement equal to the elevation from the formation to be fractured to the lowest aquafer exceeds the fracture pressure of the formation to be fractured. By using a cement slurry or mortar slurry of this density, it will not be possible for a fracture to reach the aquifer, and even if cement in the annulus around the casing completely fails, the cement in the annulus will not reach the aquifer.
In another embodiment of the present invention with cement slurry or mortar slurry being used as a fracturing fluid is utilized that has a density that results in a hydrostatic head less than the depth of the well. An advantage of this is that no pressure is needed at the surface during the fracturing process. High pressures required by normal fracturing processes occasionally result in equipment or wellbore failures.
In another embodiment of the present invention when using cement slurry or mortar slurry as fracturing fluid, a slurry is provided from which clear water and solids tend to separate. Although application is not bound by the theory, is is believed that using a slurry from which solids tend to settle results in an interface near the top of the fracture where cement props a fracture open, and a channel above the cement and water interface results in a channel above this interface that extends deep into the fracture and allows for flow back into the wellbore.
A tendency for cement slurry or mortar slurries to separate may be indicated by results of an API Free Fluid test, or an API Sedimentation test.
The API Free Fluid test is conducted in a 250 ml tail glass graduated cylinder that is placed in an oven at the test temperature. The test is 2 hours long and since it is glass separation and visual discoloration can be seen visually. Whether the slurry is stable can be seen visually. The volume of free fluids at the top of the graduated cylinder may be measured. A slurry for practice of the present invention may have greater than two percent by volume of free fluids, or between two and four percent by volume of free fluids, or between one and six percent by volume of free fluid by the API Free Fluid test.
The API Stability test first requires conditioning the slurry to test temperature and then the slurry is poured into a brass mold. The molds are then placed in a pressurized curing chamber at test temperature and the cement is allowed to cure. That is usually for about 36 to 48 hrs. The mold with the set cement inside is then broke open and the density of the set cement is measured in sections from top to bottom. If the slurry has less density at the top then the bottom we say that the slurry has settling. For the present invention it is desirable that the slurry have significant settling tendencies. Cement with a higher density will have a faster development of compressive strength. It is that higher compressive strength that helps to support open the fracture. For the present invention, a slurry could be used that results in greater than one and a half pounds per gallon density difference between the top and the bottom using the API Sedimentation test.
Typically, for applications such as wellbore annulus cementing, chemical additives such as viscosifiers are used to prevent or reduce free water as determined by the API Free Fluid test, or strength difference according to the API Sedimentation test, but for some embodiments of the present invention, additives such as dispersants are included in the cement slurry or mortar slurry to increase the tendency for the cement slurry or mortar slurry to separate. A useful dispersant may be a lignosulfonate based dispersant. Useful concentrations of lignosulfonate based dispersants may be between 0.1 and 0.4 percent by weight based on the dry cement content of the slurry.
Mortar or cement slurry fracturing process, utilizing high density slurry may benefit from single point entry fracturing processes because fractures initiates with such materials may continue to grow downward with no natural limits on the size of the fracture because as the fracture goes to deeper depths, the fracture gradient is exceeded by a larger margin. Thus, if a plurality of clusters of perforations are fractured at one time, the first fracture formed to take all of the slurry, and fractures would be unlikely to form at other perforations. Thus, for fracturing with mortar or cement slurries, an efficient single point entry fracturing process would be desirable.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2017/022545 | 3/13/2017 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 62309699 | Mar 2016 | US |
