US20150159477A1

US20150159477A1 - Method of treating a subterranean formation

Info

Publication number: US20150159477A1
Application number: US14/103,203
Authority: US
Inventors: Bruno Lecerf; Chad Kraemer; Dmitriy Usoltsev; Andrey Bogdan
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2013-12-11
Filing date: 2013-12-11
Publication date: 2015-06-11
Also published as: CA2874323A1

Abstract

A method of treating a subterranean formation, involving performing a fracturing operation and performing a shut in. At a time before or after the shut in is commenced, changes in properties at or near a fracture are estimated based upon monitored data. A plugging agent is injected taking into consideration the estimated changes in properties.

Description

BACKGROUND

Hydrocarbons, such as oil, condensate and gas, are often produced from wells that are drilled into the formations containing them. Oftentimes, the flow of hydrocarbons into the well may be low, at least because of inherently low permeability of the reservoirs or damage to the formation caused by the drilling and completion of the well. To allow for desirable hydrocarbon flow, various treatments, such as hydraulic fracturing or acid fracturing may be performed.
Hydraulic fracturing and acid fracturing of horizontal wells and multi-layered formations often involve using diverting techniques in order to enable fracturing redirection between different zones. Diverting methods may include using mechanical isolation devices such as packers and well bore plugs, setting bridge plugs, pumping ball sealers, and pumping slurred benzoic acid flakes and removable and/or degradable particulates.
Diversion treatments using particulates may be based on bridging of particles of the diverting material behind casing and forming a plug by accumulating the rest of the particles at the formed bridge. In these treatments, some concerns such as reducing bridging ability of diverting slurry during pumping because of dilution with wellbore fluid, using large quantities of diverting materials, and poor stability of some diverting agents during pumping and later treatments may be encountered. Additionally, when an induced fracture is open, there includes a risk that solid particles used for diverting will not actually bridge over the fracture, and the particles may be lost within the fracture.
Performing a diversion treatment with solid particulates may be achieved when the downhole features are narrow, so as to avoid a concern of losing particulates within large, wide open fractures. However, controlling or determining the width of a downhole feature in a near-wellbore region may be difficult. It is difficult to control a width of an induced fracture when fracturing a well, at least because of the large amount of uncertainty in properties of portions of the formation. Further, a plugging agent often carries particular limitations regarding its size and loading, which may lead to plugging agents that may not be capable of plugging a particular fracture width.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, not is it intended to be used as an aid in limiting the scope of the claimed subject matter.
The statements made merely provide information relating to the present disclosure, and may describe some embodiments illustrating the subject matter of this application.
In a first aspect, a method for treating a subterranean formation penetrated by a wellbore is disclosed. The method includes performing a fracturing operation by introducing a treatment fluid into the wellbore at a fluid pressure equal to or greater than a fracture initiation pressure of the subterranean formation to induce a fracture in the subterranean formation. The method further includes estimating changes in fracture geometry by monitoring data from one or more sensors while the fracture is open, performing a shut-in by stopping injection of the treatment fluid and introducing a plugging agent. The plugging agent may be introduced after performing the shut-in, so as to plug an induced fracture. The period of time after which the plugging agent is introduced may be determined based upon the monitored data.
In a second aspect, a method for monitoring a portion of a subterranean formation is disclosed. The method includes performing a fracturing operation by introducing a treatment fluid into the wellbore at a fluid pressure equal to or greater than a fracture initiation pressure of the subterranean formation to induce a fracture in the subterranean formation. The method further includes generating tubewaves on surface from one or more pulses, and detecting a change in reflection of the pulse(s) to thereby determine a characteristic of the fracture of the subterranean formation in real-time, and introducing a plugging agent.
In a third aspect, a method of monitoring a portion of a subterranean formation is disclosed. The method includes performing a fracturing operation by introducing a treatment fluid into the wellbore at a fluid pressure equal to or greater than a fracture initiation pressure of the subterranean formation to induce a fracture in the subterranean formation. The method further includes monitoring a fluid pressure change in the wellbore of the subterranean formation, and treating the fracture in the subterranean formation at a time that is calculated based on when the fluid pressure change in the wellbore reaches a threshold value.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a graphical depiction of a G-plot according to one or more embodiments herein.

FIG. 2 shows a graphical depiction of a pressure plot according to one or more embodiments herein.

FIG. 3 shows a graphical depiction of pulsation reflection according to one or more embodiments herein.

FIG. 4 shows a graphical depiction of a treatment plot according to one or more embodiments herein.

DETAILED DESCRIPTION OF THE EMBODIMENTS

In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it may be understood by those skilled in the art that the methods of the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.
At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation-specific decisions may be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. In addition, the composition used/disclosed herein can also comprise some components other than those cited. In the summary and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary and this detailed description, it should be understood that a range listed or described as being useful, suitable, or the like, is intended to include support for any conceivable sub-range within the range at least because every point within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each possible number along the continuum between about 1 and about 10. Furthermore, one or more of the data points in the present examples may be combined together, or may be combined with one of the data points in the specification to create a range, and thus include each possible value or number within this range. Thus, (1) even if numerous specific data points within the range are explicitly identified, (2) even if reference is made to a few specific data points within the range, or (3) even when no data points within the range are explicitly identified, it is to be understood (i) that the inventors appreciate and understand that any conceivable data point within the range is to be considered to have been specified, and (ii) that the inventors possessed knowledge of the entire range, each conceivable sub-range within the range, and each conceivable point within the range. Furthermore, the subject matter of this application illustratively disclosed herein suitably may be practiced in the absence of any element(s) that are not specifically disclosed herein.
The following definitions are provided in order to aid those skilled in the art in understanding the detailed description.
The methods of the present disclosure may be used to treat at least a portion of a subterranean formation. The term “treat,” “treatment,” or “treating,” does not imply any particular action by the fluid. For example, a treatment fluid placed or introduced into a subterranean formation may be a hydraulic fracturing fluid, an acidizing fluid (acid fracturing, acid diverting fluid), a stimulation fluid, a sand control fluid, a completion fluid, a wellbore consolidation fluid, a remediation treatment fluid, a cementing fluid, a driller fluid, a frac-packing fluid, or gravel packing fluid.
While the embodiments described herewith refer to well treatment it is equally applicable to any well operations where zonal isolation is desired, such as drilling operations, workover operations, and the like. In some embodiments, the methods of the present disclosure may include preventing overdisplacement of a proppant that enters a fracture by forming a removable plug from the plugging agent in the fracture. Such methods are described in “Methods For Minimizing Overdisplacement of Proppant in Fracture Treatments,” to Bruno Lecerf et al. (concurrently filed herewith), the disclosure of which is incorporated by reference herein in its entirety.
As used herein, the term “wellbore” refers to a drilled hole or a borehole, including an openhole or uncased portion of a well. A wellbore may be any type of well, including, a producing well, a non-producing well, an injection well, a fluid disposal well, an experimental well, an exploratory deep well, and the like. Wellbores may be vertical, horizontal, deviated some angle between vertical and horizontal, and combinations thereof, for example a vertical well with a non-vertical component.
As used herein, the term “treatment fluid,” refers to any known pumpable and/or flowable fluid used in a subterranean operation in conjunction with a desired function and/or for a desired purpose. As used herein, a “pill” is a type of relatively small volume of specially prepared treatment fluid placed or circulated in the wellbore.
As used herein, the term “plugging agent” or “removable plugging agent” may refer to a solid or fluid that may plug or fill, either partially or fully, a portion of a subterranean formation. The portion to be filled may be a fracture that is opened by a hydraulic or acid fracturing treatment.
The removable plugging agents may be any materials, such as solid materials (including, for example, degradable solids and/or dissolvable solids), that may be removed within a desired period of time. In some embodiments, the removal may be assisted or accelerated by a wash containing an appropriate reactant (for example, capable of reacting with one or more molecules of the plugging agent to cleave a bond in one or more molecules in the plugging agent), and/or solvent (for example, capable of causing a plugging agent molecule to transition from the solid phase to being dispersed and/or dissolved in a liquid phase), such as a component that changes the pH and/or salinity. In some embodiments, the removal may be assisted or accelerated by a wash containing an appropriate component that changes the pH and/or salinity. The removal may also be assisted by an increase in temperature, for example when the treatment is performed before steam flooding, and/or a change in pressure.
In some embodiments, the removable plugging agent materials may be degradable material and/or a dissolvable material. A degradable material refers to a material that will at least partially degrade (for example, by cleavage of a chemical bond) within a desired period of time such that no additional intervention is used to remove the plug. For example, at least 30% of the removable material may degrade, such as at least 50%, or at least 75%. In some embodiments, 100% of the removable material may degrade. The degradation of the removable material may be triggered by a temperature change, and/or by chemical reaction between the removable material and another reactant. Degradation may include dissolution of the removable material.
Removable materials for use as the plugging agent may be in any suitable shape: for example, powder, particulates, beads, chips, or fibers. When the removable material is in the shape of fibers, the fibers may have a length of from about 2 to about 25 mm, such as from about 3 mm to about 20 mm. In some embodiments, the fibers may have a linear mass density of about 0.111 dtex to about 22.2 dtex (about 0.1 to about 20 denier), such as about 0.167 to about 6.67 dtex (about 0.15 to about 6 denier). Suitable fibers may degrade under downhole conditions, which may include temperatures as high as about 180° C. (about 350° F.) or more and pressures as high as about 137.9 MPa (about 20,000 psi) or more, in a duration that is suitable for the selected operation, from a minimum duration of about 0.5, about 1, about 2 or about 3 hours up to a maximum of about 24, about 12, about 10, about 8 or about 6 hours, or a range from any minimum duration to any maximum duration.
The removable materials may be sensitive to the environment, so dilution and precipitation properties should be taken into account when selecting the appropriate removable material. The removable material used as a sealer may survive in the formation or wellbore for a sufficiently long duration (for example, about 3 to about 6 hours). The duration should be long enough for wireline services to perforate the next pay sand, subsequent fracturing treatment(s) to be completed, and the fracture to close on the proppant before it completely settles, providing an improved fracture conductivity.
Further suitable removable materials and methods of use thereof include those described in U.S. Patent Application Publication Nos. 2006/0113077, 2008/0093073, and 2012/0181034, the disclosures of which are incorporated by reference herein in their entireties. Such materials include inorganic fibers, for example of limestone or glass, but are more commonly polymers or co-polymers of esters, amides, or other similar materials. They may be partially hydrolyzed at non-backbone locations. Any such materials that are removable (due in-part because the materials may, for example, degrade and/or dissolve) at the appropriate time under the encountered conditions may also be employed in the methods of the present disclosure. For example, polyols containing three or more hydroxyl groups may be used. Suitable polyols include polymeric polyols that solubilizable upon heating, desalination or a combination thereof, and contain hydroxyl-substituted carbon atoms in a polymer chain spaced from adjacent hydroxyl-substituted carbon atoms by at least one carbon atom in the polymer chain. The polyols may be free of adjacent hydroxyl substituents. In some embodiments, the polyols have a weight average molecular weight from about 5000 to about 500,000 Daltons or more, such as from about 10,000 to about 200,000 Daltons.
Further examples of removable materials include polyhdroxyalkanoates, polyamides, polycaprolactones, polyhydroxybutyrates, polyethyleneterephthalates, polyvinyl alcohols, polyethylene oxide (polyethylene glycol), polyvinyl acetate, partially hydrolyzed polyvinyl acetate, and copolymers of these materials. Polymers or co-polymers of esters, for example, include substituted and unsubstituted lactide, glycolide, polylactic acid, and polyglycolic acid. For example, suitable removable materials for use as plugging agents include polylactide acid; polycaprolactone; polyhydroxybutyrate; polyhydroxyvalerate; polyethylene; polyhydroxyalkanoates, such as poly[R-3-hydroxybutyrate], poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate], poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], and the like; starch-based polymers; polylactic acid and copolyesters; polyglycolic acid and copolymers; aliphatic-aromatic polyesters, such as poly(ε-caprolactone), polyethylene terephthalate, polybutylene terephthalate, and the like; polyvinylpyrrolidone; polysaccharides; polyvinylimidazole; polymethacrylic acid; polyvinylamine; polyvinylpyridine; and proteins, such as gelatin, wheat and maize gluten, cottonseed flour, whey proteins, myofibrillar proteins, casins, and the like. Polymers or co-polymers of amides, for example, may include polyacrylamides.
Removable materials, such as, for example, degradable and/or dissolvable materials, may be used in the plugging agent at high concentrations (such as from about 20 lbs/1000 gal to about 1000 lbs/1000 gal, or from about 40 lbs/1000 gal to about 750 lbs/1000 gal) in order to form temporary plugs or bridges. The removable material may also be used at concentrations at least 4.8 g/L (40 lbs/1,000 gal), at least 6 g/L (50 lbs/1,000 gal), or at least 7.2 g/L (60 lbs/1,000 gal). The maximum concentrations of these materials that can be used may depend on the surface addition and blending equipment available.
Suitable removable plugging agents also include dissolvable materials and meltable materials (both of which may also be capable of degradation). A meltable material is a material that will transition from a solid phase to a liquid phase upon exposure to an adequate stimulus, which is generally temperature. A dissolvable material (as opposed to a degradable material, which, for example, may be a material that can (under some conditions) be broken in smaller parts by a chemical process that results in the cleavage of chemical bonds, such as hydrolysis) is a material that will transition from a solid phase to a liquid phase upon exposure to an appropriate solvent or solvent system (that is, it is soluble in one or more solvent). The solvent may be the carrier fluid used for fracturing the well, or the produced fluid (hydrocarbons) or another fluid used during the treatment of the well. In some embodiments, dissolution and degradation processes may both be involved in the removal of the plugging agent.
Such removable materials, for example dissolvable, meltable and/or degradable materials, may be in any shape: for example, powder, particulates, beads, chips, or fibers. When the such material is in the shape of fibers, the fibers may have a length of about 2 to about 25 mm, such as from about 3 mm to about 20 mm. The fibers may have any suitable denier value, such as a denier of about 0.1 to about 20, or about 0.15 to about 6.
Examples of suitable removable fiber materials include polylactic acid (PLA) and polyglycolide (PGA) fibers, glass fibers, polyethylene terephthalate (PET) fibers, and the like.
In some embodiments, the plugging agent content may include pre-processed fiber flocks, which represent solids entrapped inside a fiber network.
In some embodiments, the plugging agent may be a non-removable material, which is a material that does not at least partially degrade within a desired period of time. Non-degradable materials suitable for use as a plugging agent include cement, proppant and material of proppant-like composition (for example, ceramics, sands, bauxites). The non-degradable materials form a non-degradable (and/or non-dissolvable) plug, which may subsequently be at least partially or completely removed using other means, such as coil tubing or an abrasive, such as sand.
The term “subterranean formation” refers to any physical formation that lies at least partially under the surface of the earth.
The term “fracturing” refers to the process and methods of breaking down a geological formation and creating a fracture, such as the rock formation around a wellbore, by pumping a treatment fluid at very high pressures (pressure above the determined closure pressure of the formation), in order to increase production rates from or injection rates into a hydrocarbon reservoir. The fracturing methods of the present disclosure may include estimating changes in fracture geometry by monitoring data from one or more sensors while the fracture is open, performing a shut-in by stopping injection of the treatment fluid and introducing a plugging agent, but otherwise use conventional sensors and techniques known in the art.
When hydraulic fracturing is applied in hydrocarbon reservoirs to increase the production rate of hydrocarbons from the reservoir, the primary objective of the well treatment is to increase the production surface area of the formation. Between this increased surface area and the production well, a flow path of higher conductivity than the formation has to be situated. To increase the surface area, high pressure is used, which fractures the rock.
The term “shut-in” refers to a time where a treatment is halted or stopped, either temporarily or permanently, and sufficient pressure is maintained in the wellbore to prevent the well from flowing back.
The term “real-time” refers to the actual time during which a process or event occurs. Real time monitoring of data refers to live monitoring of data, for example data relating to the size or orientation of a fracture, that may allow for an action, for example a plugging application, to be taken based upon the monitoring. According to some embodiments, the real-time monitoring occurs from 0 to about 10 minutes from when an event occurs, or from between 0 and about 7 minutes from when an event occurs, or from between 0 and about 5 minutes from when an event occurs.
Suitable techniques, sensors, and methodology for monitoring data in subterranean formations are discussed in, for example, U.S. Pat. Nos. 7,302,849, and 4,802,144, the disclosures of which are incorporated by reference herein in their entireties. The methods of the present disclosure may be employed in any desired downhole application (such as, for example, hydraulic fracturing and/or stimulation) at any time in the life cycle of a reservoir, field or oilfield.
In embodiments, the methods of the present disclosure, which comprise estimating changes in fracture geometry by monitoring data from one or more sensors while the fracture is open, performing a shut-in by stopping injection of the treatment fluid and introducing a plugging agent, include performing a fracturing operation by introducing a treatment fluid into the wellbore at a fluid pressure equal to or greater than a fracture initiation pressure of the subterranean formation to induce a fracture in the subterranean formation.
The term “field” includes land-based (surface and sub-surface) and sub-seabed applications. The term “oilfield,” as used herein, includes hydrocarbon oil and gas reservoirs, and formations or portions of formations where hydrocarbon oil and gas are expected but may additionally contain other materials such as water, brine, or some other composition.
The term “bridging” refers to intentionally or accidentally plugging off pore spaces or fluid paths in a rock formation, or to make a restriction in a wellbore or annulus. A bridge may be partial or total, and may be caused by solids (drilled solids, cuttings, cavings or junk) becoming lodged together in a narrow spot or geometry change in the wellbore. Bridging can be caused by manufactured shapes such as proppant and diverters in the shapes of fibers, flakes and particles.
The term “tubewave” refers to pressure waves generated on surface and propagating along wellbore walls at the velocity approximately equal to the sound velocity in the fluid. Obstacles in the wellbore, pipe sections with different diameters, perforations and open fractures are characterized by different hydraulic impedances and serve as tubewave reflectors. Hydraulic impedance is ratio of oscillatory pressure to oscillatory flow can be also thought as acoustic rigidity of the media. The downhole reflector's properties can be interpreted in terms of their impedances. One way to determine depths and impedances of reflectors is to generate one or several perturbations and measure travel times and amplitudes of reflected/propagated waves. Pertubation creates transient pressure and flow conditions in the well. The perturbation may be produced by rapidly removing a slug of fluid from the pressurized well by opening and closing a valve, or rapidly injecting a slug of fluid resulting in free oscillation of the well, or by the continuous action of reciprocating pumps, or by other methods that cause transient fluid flow. The tubewave travels down the wellbore along the interface between the fluid in the wellbore and the wall of the wellbore.
In some embodiments, an operation may be performed to treat a subterranean formation. The operation may be a hydraulic fracturing operation, which may include fracturing a portion of the subterranean formation by providing hydraulic pressure. Other operations, such as acidizing a formation to generate a fracture may also be used.
In a hydraulic fracturing operation, a treatment fluid, which includes a predetermined amount of proppant, may be injected into a wellbore at a fluid pressure equal to or greater than a fracture initiation pressure of the subterranean formation. The fluid pressure is the rate (volume/time) at which a fluid is pumped. The term “fracture initiation pressure” refers to the fluid pressure sufficient to induce a fracture in a subterranean formation.
Fracturing a subterranean formation may include introducing hundreds of thousands of gallons of fracturing fluid into the wellbore. In some embodiments a frac pump may be used for hydraulic fracturing. A frac pump is a high-pressure, high-volume pump, such as a positive-displacement reciprocating pump. In embodiments, a treatment fluid may be introduced by using a frac pump, such that the fracturing fluid may be pumped down into the wellbore at high rates and pressures, for example, at a flow rate in excess of about 20 barrels per minute (about 4,200 U.S. gallons per minute) at a pressure in excess of about 2,500 pounds per square inch (“psi”). In some embodiments, the pump rate and pressure of the fracturing fluid may be even higher, for example, at flow rates in excess of about 100 barrels per minute and pressures in excess of about 10,000 psi may be used.
In a hydraulic fracturing operation according to some embodiments, a proppant may be injected into a well, and the proppant may include a crosslinked gel fluid. The operation may then include fracturing according to a sequence of slurries being pumped. The slurries may be pumped at any desired rate, such as a rate of from about 20 bbl (barrels)/min to about 140 bbl (barrels)/min, or a rate of from about 40 to about 100 bbl (barrels)/min.
A treatment fluid including a first slurry to be introduced may be introduced at any desired volume and concentration, such as a pad fluid in which the total volume of the pad is from about 50 bbl to about 1000 bbl, or about 100 bbl to about 800 bbl, and where the fluid is designed to control leakoff into the formation. The treatment fluid may be injected at any desired pressure, such as a pressure that is of a high enough magnitude to induce a fracture in the subterranean formation, for example, any pressure equal to or greater than the fracture initiation pressure, or a pressure sufficient to induce a fracture of width typically exceeding the proppant diameter by a factor of about 4 to about 5. Provided that proppant size is from about 25 microns to 1.7 mm, an open fracture may be at least about 0.15 mm to 1 cm.
The treatment fluid suitable for use in the methods of the present disclosure may also any well treatment fluid, such as a hydraulic fracturing fluid, an acidizing fluid (acid fracturing, acid diverting fluid), a stimulation fluid, a sand control fluid, a completion fluid, a wellbore consolidation fluid, a remediation treatment fluid, a cementing fluid, a driller fluid, a frac-packing fluid, or gravel packing fluid. The solvent (or carrier solvent) for the treatment fluid may be a pure solvent or a mixture. Suitable solvents or use with the methods of the present disclosure, such as for forming the treatment fluids disclosed herein, may be aqueous or organic based. Aqueous solvents may include at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds and mixtures thereof. Organic solvents may include any organic solvent that is able to dissolve or suspend the various other components of the treatment fluid.
In some embodiments, the treatment fluid may have any suitable viscosity, such as a viscosity of from about 1 cP to about 1,000 cP (or from about 10 cP to about 100 cP) at the treating temperature, which may range from a surface temperature to a bottom-hole static (reservoir) temperature, such as from about −40° C. to about 150° C., or from about 10° C. to about 120° C., or from about 25° C. to about 100° C.
While the treatment fluids of the present disclosure are described herein as comprising the above-mentioned components, it should be understood that the treatment fluids of the present disclosure may optionally comprise other chemically different materials. In embodiments, the treatment fluid may further comprise stabilizing agents, surfactants, diverting agents, or other additives. Additionally, a treatment fluid may comprise a mixture of various crosslinking agents, and/or other additives, such as fibers or fillers, provided that the other components chosen for the mixture are compatible with the intended use of the treatment fluid. Furthermore, the treatment fluid may comprise buffers, pH control agents, and various other additives added to promote the stability or the functionality of the treatment fluid. The components of the treatment fluid may be selected such that they may or may not react with the subterranean formation that is to be treated.
In this regard, the treatment fluid may include components independently selected from any solids, liquids, gases, and combinations thereof, such as slurries, gas-saturated or non-gas-saturated liquids, mixtures of two or more miscible or immiscible liquids, and the like. For example, the treatment fluid may comprise organic chemicals, inorganic chemicals, and any combinations thereof. Organic chemicals may be monomeric, oligomeric, polymeric, crosslinked, and combinations, while polymers may be thermoplastic, thermosetting, moisture setting, elastomeric, and the like. Inorganic chemicals may be inorganic acids and inorganic bases, metals, metallic ions, alkaline and alkaline earth chemicals, minerals, salts and the like.
Various fibrous materials may be included in the treatment fluid. Suitable fibrous materials may be woven or nonwoven, and may be comprised of organic fibers, inorganic fibers, mixtures thereof and combinations thereof.
In embodiments, the treatment fluid may be driven into a wellbore by a pumping system that pumps one or more treatment fluids into the wellbore. The pumping systems may include mixing or combining devices, wherein various components, such as fluids, solids, and/or gases maybe mixed or combined prior to being pumped into the wellbore. The mixing or combining device may be controlled in a number of ways, including, for example, using data obtained either downhole from the wellbore, surface data, or some combination thereof.
Next, a suitable amount of a second slurry comprising about 0.5 to 8 pounds of proppant per unit gallon of fluid, carried by a crosslinked fluid may be introduced into the subterranean formation. The crosslinked fluid may be any conventional crosslinking fluid known to those skilled in the art. Typical fluids include guar or guar derivatives such as hydroxypropyl guar (HPG) or carboxymethylhydroxypropylguar (CMHPG), cellulose or cellulose derivative or xanthan gum or viscoelastic surfactant-based fluids. Crosslinkers can be borate, titanium, zirconium or aluminum based.
In some embodiments, the treatment operation may be halted either temporarily or permanently. In embodiments where the treatment operation is halted temporarily, the injection of a stimulating slurry is halted for a predetermined duration, such as about 1 to about 180 minutes, or about 5 to about 150 minutes, about 10 to about 100 minutes, about 15 to about 90 minutes, about 20 to about 60 minutes, or about 30 to about 45 minutes. Such a stoppage of the treatment operation, also referred to as a shut-in, may allow for monitoring of a fracture and/or an area around the fracture to be examined and monitored.
Once the shut-in has commenced, monitoring of data may occur. The monitoring of data may occur immediately upon the commencement of the shut-in, or at some time after the commencement of the shut-in. The monitoring of data may involve any data relating to a fracture in the subterranean formation. The data to be monitored may include data of an average width of a fracture, or a pressure decline in a wellbore, or reflection of pressure waves. Further, the data can be monitored at real-time, or can be stored for future analysis or study. By monitoring data, one skilled in the art would understand that the data can be compiled, analyzed, compared to previously compiled or stored data, and/or any combination of these features.
In some embodiments, the fracture to be examined and monitored may be a fracture in a near wellbore area. The fracture in the near wellbore area may be a fracture that changes shape in a manner that makes it more prone to being plugged. Thus, in some embodiments, changes in geometry of the fracture may be estimated. As fluid leaks off during the duration of the shut-in, changes in fracture characteristics, including the geometry of the fracture, may be estimated. The changes in the fracture geometry may relate to the width, diameter, depth, near-wellbore tortuosity and/or structure of the fracture can be understood. In some embodiments, the width of the fracture may be decreasing when fluid leaks off during the duration of the shut-in, and such a fracture width can be estimated based upon monitoring fluid leakoff.
Fluid leakoff can be determined based upon estimation of a pressure decline in the wellbore after the wellbore is shut. The rate at which the pressure declines can be used to infer a fracture closure time. The fracture closure time may allow for a width of a fracture opening to be determined. In some embodiments, the subterranean formation, including the pressure decline rate, is monitored until the estimated width of the fracture opening has decreased to a predetermined amount. In some embodiments, the effective width of a fracture opening has been reached when the width has decreased to a value prone to be bridged or plugged by the diverter to be used. For a given diverter, the width that can be effectively bridged can be determined in the laboratory. Another method is to decrease the width to a value smaller than the size of the diverter. For example, if a diverter particulate of diameter 2 mm is used, then an appropriate fracture width to be plugged may be any value less than 2 mm Such fracture widths may allow for plugging agents with appropriate size, composition and other characteristics to be used to plug the fracture and allow for bridging over the fracture area.
In some embodiments, the rate of pressure decline in the wellbore can be estimated by G-function analysis using a G-function plot. The G function plot is a plot disclosed in, for example Reservoir Stimulation, 3^rdEdition, Economides M. J. and K. G. Nolte, Sections 9.5.2 and 9F, Wiley Publishing, or Modified Fracture Pressure Decline Analysis Including Pressure-Dependent Leakoff, Castillo J. L. and D. Schlumberger, SPE16417, or Determination of Pressure Dependent Leakoff and Its Effect on Fracture Geometry, Barree, R. D., Marathon Oil Company and Mukherjee H. Dowell Schlumberger, SPE 36424, the teachings of which are hereby incorporated by reference. The G function is a function that can be defined as:
G(Δt _D)=(4/π)[g(Δt _D)−g ₀],
where:
g(Δt_D) is the fluid loss volume function;
g₀is the initial value of the fluid-loss volume function; and
Δt_D=Δt/tp and is the ratio of shut-in (Δt) to the pumping time (t_p)
In some embodiments, the G function plot can be represented by plotting pressure and expressions of pressure derivatives against G. As can be seen in FIG. 1, surface pressure and superposition derivative G. ΔP/ΔG can be plotted with respect to the G function.
In some embodiments, the time at which the superposition derivative G.ΔP/ΔG reaches a constant value can be considered as closure time of a feature of the fracture. The G function plot may be used for characterizing the fracture and/or the subterranean formation entirely. In some embodiments, the G function plot can be used to determine the time at which the near-wellbore region is more prone to being bridged off by a plugging agent. The plot can be obtained in real time using a pressure decline analysis program.
In some embodiments, a plugging agent may be injected at or after some period of time based upon a result of the performed pressure decline analysis. The time may be from about 5 minutes to about 12 hours, or from about 10 minutes to about 1 hour. The time may be determined based upon commencement of the shut-in operation, or at another time where monitoring of data is commenced. In some embodiments, when the superposition derivative G.ΔP/ΔG reaches a plateau, the plugging agent may be pumped. The plugging agent may be pumped at a pressure lower than the pressure to reopen the fracture.
In some embodiments, the plugging agent is introduced after the shut-in is performed. The plugging agent may be introduced into the wellbore, or into any other area of the subterranean formation. In embodiments where the plugging agent is introduced into the wellbore, the plugging agent may be introduced into the wellbore before the shut-in is commenced, or after the shut-in is commenced.
The plugging agent may be a manufactured shape, at a loading sufficiently high to be intercepted in the proximity of the wellbore. The loading may be more than about 50 lb/1000 gal. The manufactured shape of the plugging agent may be round particles having dimensions that are optimized for plugging. Alternatively, the particles may be of different shapes, such as cubes, tetrahedrons, octahedrons, plate-like shapes (flakes), oval, and the like. The plugging agent may be of any dimension that is suitable for plugging. For example, as described in U.S. Patent Application Publication No. 2012/0285692, the disclosure of which is incorporated by reference herein in its entirety, the plugging agent may include particles having an average particle size of from about 3 mm to about 2 cm. Additionally, the plugging agent may additionally include a second amount of particles having an average particle size from about 1.6 to about 20 times smaller than the first average particle size. Alternatively, the plugging agent may include flakes having an average particle size up to 10 times smaller than the first average particle size.
In some embodiments, the plugging agent is a diverter pill. The diverter pill may be a diversion blend with fibers and degradable particles with a particular particle size distribution. The diverter pill may include about 2 to 50 bbl of a carrier fluid. The diverter pill may include a diversion blend that is used as a plug and may have a mass of 10 to 400 lbs. The diversion blend may include about 50 pounds to 200 lbs of fiber per 1000 gallons of blend. It may include about 20 to about 200 pounds of particles per 1000 gallons of blend. The diverter may include beads with an average size such as described in TABLE 1 of U.S. Patent Application Publication No. 2012/0285692 A1, which is hereby incorporated by reference in its entirety.
In some embodiments, a width of a near wellbore fracture can be inferred from monitoring the hydraulic impedance of the fracture, which is the ratio of oscillatory pressure to oscillatory flow. Hydraulic impedance can be monitored by generating pressure pulses and measuring travel times and amplitudes of reflected/propagated waves. The technique can be used to determine when the impedance of the fracture is lower than the initial impedance. When the impedance of the fracture is a threshold amount lower than the initial impedance, the fracture may be of a desirable geometry for plugging, and a plugging agent may be subsequently injected. The threshold amount should be the threshold corresponding to ratio (actual fracture width)/(fracture width which can be bridged by diverter) and can be estimated from the width of the fracture, typically 5-8 times of more the size of the proppant which is used in the fracturing treatment, and the width value which is bridged by the diverter and which can be determined from laboratory testing, or can be assumed of being the size of the largest particle used in the diverter blend.
Pressure waves generated on surface and/or propagating along the wellbore walls at a velocity approximately equal to the sound velocity of the fluid may be referred to as tubewaves. The tubewaves may be reflected by obstacles in the wellbore, pipe sections with different diameters, perforations and open fractures. These components of the subterranean formation may have different hydraulic impedances and thus serve as tubewave reflectors. The impedance of such media is a ratio of the oscillatory pressure to the oscillatory flow, or otherwise can be considered the acoustic rigidity of the medium. Additionally, the downhole reflector's properties can be interpreted in terms of their impedances.
At a time before or after a shut-in is commenced, tubewaves can be generated on a surface using a tubewave source. The tubewaves may be utilized by generating pressure signals from the surface and sending the pressure signals downhole from a tubewave generator. The tubewave source may include a storage chamber, a fast valve to allow exchange of fluid with the tube, and a system to pre-charge the chamber. The generator produces positive pulses with a chamber pressurized at a pressure above the pressure of the tube, such as up to 15000 psi.
To determine depths and impedances of particular reflectors, the travel times of and amplitudes of the reflected and/or propagated waves of the pressure pulses can be measured. Further, the signals for the pressure pulse can be recorded, as well as the signal reflected from the wellbore. Based on a change in reflection of pulsation, it may be inferred that a particular fracture will be more receptive at that time to a plugging agent. Accordingly, a plugging agent can be injected at some time at or after a change in reflection above a threshold value has occurred. The threshold amount should be the threshold corresponding to ratio (actual fracture width)/(fracture width which can be bridged by diverter) and can be estimated from the width of the fracture, typically 5-8 times of more the size of the proppant which is used in the fracturing treatment, and the width value which is bridged by the diverter and which can be determined from laboratory testing, or can be assumed of being the size of the largest particle used in the diverter blend. The change in the fracture property may also be detected by monitoring the time at which the reflected signal changes in shape and reveals a fracture which is closed. The change in reflection may be at about 5 to about 12 hours, or from about 10 to about 1 hour after the shut-in has commenced.
In some embodiments, the plugging agent may be injected at or after some period of time based upon a result of the performed reflection analysis. The time may be any suitable period of time, including from about 5 minutes to about 12 hours, or from about 10 minutes to about 1 hour. The time may be determined based upon commencement of the shut-in operation, or at another time where monitoring of data is commenced. In some embodiments, when the change in reflection of the tubewave has occurred, the plugging agent may be pumped into the fracture so as to plug the fracture.
The foregoing is further illustrated by reference to the following examples, which are presented for purposes of illustration and are not intended to limit the scope of the present disclosure.

Example 1

In a first example, a well is completed in sixteen 300 foot sections, each separated by bridge plugs. Each 300 foot section is fractured with a proppant, which is carried by a cross-linked gel fluid. Each 300 foot section is then fractured using a sequence of slurries, each pumped at 60 bbl/min.
First, 286 bbl of pad is injected to fracture the rock. Next, 2015 bbl of slurry comprising 180,000 lbs of proppant carried by a crosslinked fluid is injected. FIG. 2 shows a typical pressure curve from the pad to the diverter, where the diverter pill generates a pressure of 727 psi. On this well, the maximum pressure increase caused by the diverter when no shut-in was used no diverter pill generates a pressure exceeding was 2242 psi.
Next, in one of the sixteen 300 foot sections, the treatment was shut-in for about 90 minutes. 65 bbl of diverter pill comprising 50 to 75 pounds of a carrier fluid viscosified by non crosslinked guar was then injected. The pressure response obtained when the diverter hit the perforations was 3700 psi, which was 2816 psi above the average pressure generated by the 15 other pills, and 1458 psi higher than the highest pressure recorded in the other stages.

Example 2

In a second example, a well is completed and pressure signals are generated from the surface and sent downhole from a tubewave source. The tubewave generator includes a storage chamber, a fast valve to allow exchange of fluid with the tube, and a system to pre-charge the chamber. The generator produces positive pulses with a chamber pressurized at a pressure above the pressure of the tube.
A shut-in was then performed and tubewaves were generated on the surface using the tubewave source. A positive pressure pulse was generated at 100 second intervals. The pressure was recorded on the surface at a frequency of 500 Hz. The signals for the pressure pulse sent are shown on the top portion of FIG. 3, and the signals reflected from the wellbore are shown on the bottom portion of FIG. 3.
As shown in FIG. 3, for the first 9 pulses sent in the wellbore, the negative reflection at approximately 2.73 seconds shows the open fracture. However, the 10^threflected pulsation shows a change in reflection. The negative reflection from the fracture is no longer visible at 2.73 seconds, but a positive reflection develops at approximately 2.68 seconds. The change in reflection at the 10^thpulsation is explained by change of internal fracture geometry which leads to change of interference picture between waves reflected from fracture mouth and internal fracture reflectors like possible jogs or fracture tip. This may be explained by closing the fracture at the near wellbore region. Plausibly, the fracture still may have relatively wide open fracture in far field and the fracture continues closing after the drastic change event. The knowledge about closure of near wellbore region may provide for a beneficial time to inject a plugging agent.
FIG. 4 displays a time at which the change in reflection occurs. In the pressure plot shown on FIG. 4, the vertical lines represent respectively (i) the time where the well is shut in and (ii) the time at which the 10th pulsation is sent and reflected by a fracture closed in the near wellbore area. At that time where the 10^thpulsation is sent, the plugging agent may be injected to obtain excellent plugging.
Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims. Furthermore, although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the disclosure of METHOD OF TREATING A SUBTERRANEAN FORMATION. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

What is claimed is:

1. A method of treating a subterranean formation penetrated by a wellbore comprising:

performing a fracturing operation by introducing a treatment fluid into the wellbore at a fluid pressure equal to or greater than a fracture initiation pressure of the subterranean formation to induce a fracture in the subterranean formation;

estimating changes in fracture geometry by monitoring data from one or more sensors while the fracture is open;

performing a shut-in by stopping injection of the treatment fluid; and

introducing a plugging agent, after performing the shut-in, plugging the induced fracture;

wherein the plugging agent is introduced after a period of time, the period of time being determined based upon the monitored data.

2. The method according to claim 1, wherein the plugging agent is introduced into the wellbore after the shut-in is performed.

3. The method according to claim 1, wherein the plugging agent is introduced into the wellbore before the shut-in is performed.

4. The method according to claim 1, wherein the plugging agent includes a diverter pill.

5. The method according to claim 1, wherein the period of time is from 5 minutes to 12 hours.

6. The method according to claim 1, wherein the period of time is from 15 minutes to 2 hours.

7. The method according to claim 1, wherein the estimating the changes in the fracture geometry occurs in real-time by monitoring real-time data.

8. The method according to claim 1, wherein a width of the fracture is decreased to a value smaller than the size of the plugging agent.

9. The method according to claim 1, further comprising generating tubewaves on surface, wherein the monitored data comprises data acquired while monitoring tubewave reflections from the fracture.

10. The method according to claim 9, wherein the low-frequency pressure waves comprise one or more pulses.

11. The method according to claim 9, wherein the plugging agent is introduced at a time when the change in values of the tubewave reflections reach a threshold amount.

12. The method according to claim 9, further comprising resuming the introduction of the treatment fluid into the wellbore at a fluid pressure equal to or greater than the fracture initiation pressure of the subterranean formation.

13. The method according to claim 9, wherein the monitoring data comprises monitoring a fluid pressure change in the wellbore after the shut-in is initiated.

14. The method according to claim 13, wherein the fluid pressure change is determined by plotting a G function plot.

15. The method according to claim 13, further comprising determining fluid leakoff based upon the monitored fluid pressure change in the wellbore.

16. A method of monitoring a portion of a subterranean formation, comprising:

generating tubewaves on surface, wherein the tubewaves comprise one or more pulses;

detecting a change in reflection of the pulses to thereby determine a characteristic of the fracture of the subterranean formation in real-time; and

introducing a plugging agent.

17. The method according to claim 16, wherein the characteristic of the fracture of the subterranean formation includes whether a width of an opening of the fracture has decreased by a predetermined amount.

18. The method according to claim 16, wherein the introducing further comprises introducing a plugging agent when the characteristic of the fracture of the subterranean formation has reached a threshold amount.

19. The method according to claim 18, wherein the plugging agent is a diverter pill.

20. A method of monitoring a portion of a subterranean formation, comprising:

monitoring a fluid pressure change in the wellbore of the subterranean formation; and

treating the fracture in the subterranean formation at a time that is calculated based on when the fluid pressure change in the wellbore reaches a threshold value.

21. The method according to claim 20, wherein the threshold value of the pressure change is a value calculated by plotting a G function plot and determining where a measured pressure deviates from linearity.

22. The method according to claim 20, wherein treating the fracture includes introducing a plugging agent into an induced fracture.

23. The method according to claim 22, wherein the plugging agent is pumped at a pressure lower than the fracture initiation pressure.