CA2746368A1 - Hydraulic fracture height growth control - Google Patents
Hydraulic fracture height growth control Download PDFInfo
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- CA2746368A1 CA2746368A1 CA2746368A CA2746368A CA2746368A1 CA 2746368 A1 CA2746368 A1 CA 2746368A1 CA 2746368 A CA2746368 A CA 2746368A CA 2746368 A CA2746368 A CA 2746368A CA 2746368 A1 CA2746368 A1 CA 2746368A1
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Classifications
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/27—Methods for stimulating production by forming crevices or fractures by use of eroding chemicals, e.g. acids
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/08—Fiber-containing well treatment fluids
Abstract
A method is given for creating a fracture, in a subterranean formation, that has a fluid flow barrier at the top, at the bottom, or at both the top and the bottom. The method is applied before or during a conventional hydraulic fracturing treatment and is used to limit undesired vertical growth of a fracture out of the productive zone. A lower- viscosity pad fluid is used to initiate the fracture; a higher-viscosity fluid containing barrier particles is then injected; a lower-viscosity particle-free fluid is then injected to promote settling (or rising) of the barrier particles and to finger through the slug of barrier particles and cut it into an upper and lower portion. If the barrier is to be at the bottom of the fracture, the barrier particles are denser than the fluids; if the barrier is to be at the top of the fracture, the barrier particles are less dense than the fluids. Optionally, between the barrier transport stage and the subsequent lower- viscosity stage, there may be a stage of a higher viscosity particle-free fluid that pushes the barrier particles farther into the fracture. To provide both upper and lower particles in one treatment, the pad stage may be of higher-viscosity, or the barrier particles may include particles less dense than, and more dense than, the fluid.
Description
HYDRAULIC FRACTURE HEIGHT GROWTH CONTROL
Background of the Invention Fracture height control is a common challenge faced by operators designing hydraulic fracture treatments, particularly in low permeability reservoirs. Usually when a fracture is initiated in a productive interval, it grows in all directions until it reaches an interface, for example with upper and lower formations in the common case of a vertical fracture in a horizontal reservoir, and encounters a resistance to its growth. Normally, the surrounding rock contacting the productive formation is tougher and less permeable than the reservoir. If natural barriers exist above and below the reservoir, the vertical growth of the fracture will be restrained and the fracture will propagate within the productive zone. This provides an efficient fracture with the entire surface lying inside the reservoir.
However, when the surrounding formation is too weak to withstand the pressure required to propagate the fracture, the barrier rocks will also crack and the vertical fracture growth will continue. This process results in poor fracture efficiency, since some of the fracture area lies outside the productive zone. Fracture growth downwards may also lead to water breakthrough, if there is a water zone below the reservoir. Water breakthrough limits oil production as well as increases the operational costs in order to separate and dispose of the water. Fracture growth in the upward direction is undesirable as well, since there might be a gas cap and eventually breakthrough into this zone might stimulate gas production. This could also result in the reduced ultimate recovery. Even if there is no gas cap or water zone, undesired fracture growth is wasteful.
Various methods have been tried to control fracture height growth. Use of low specific gravity particles to form an upper barrier by relying on the rising of individual particles in a low viscosity fluid to create and place a diverting barrier was described in U. S. patent No.
4,509,598. Similar treatments may be done with high specific gravity particles that settle and form a lower barrier. Typically these barriers are placed prior to the actual fracturing job by injecting a cross-linked pad followed by a linear gel laden with a special diverting particulate material that is allowed to rise or settle and bridge thedesired fracture upper or lower edge; the fracturing treatment is typically started immediately after placing the barrier.
US Patent Application Publication No. 2005/0016732 describes a method of hydraulically fracturing in two principal steps. In the first step, a fracture in and below the productive zone of a formation is initiated by introducing a fluid free of a proppant. In the second step, proppant-laden slurry that contains a relatively lightweight density proppant is introduced into the subterranean formation. Either the fluid density of the proppant-free fluid is greater than the fluid density of the proppant-laden slurry or the viscosity of the proppant-free fluid is greater than the viscosity of the proppant laden slurry. The method limits undesirable fracture height growth in the hydrocarbon-bearing subterranean formation during the fracturing.
US Patent 4,478,282 describes a method of hydraulically fracturing an underground formation penetrated by a wellbore involving injecting a fracturing fluid pad into the formation, then injecting a non-proppant fluid stage that is a transport fluid and contains a flow block material, the flow block material being sand and silica flour with a particle size distribution of the sand of 10-20, 20-40, and 100 mesh and of the silica flour of 200 mesh, and then injecting a proppant laden fluid slurry into the formation. The method relies on the assumption that the fracture growing into adjacent shale formations is narrower than in the productive formation and so the flow block material will bridge out in the fracture in the shale.
Consequently, one aspect of that invention is that conditions that promote fracture height growth were actually preferred. Fluid viscosities were not considered important.
There is a need for a method of controlling fracture height growth when fractures are growing above the desired interval, when fractures are growing below the desired interval, and when fracture height growth must be limited deep in the formation.
Summary of the Invention A first embodiment of the Invention is a method for creating a fracture, in a subterranean formation, having a barrier to fluid flow out of the top or bottom or both the top and bottom of the fracture; the barrier contains particles.. The method includes the steps of (a) injecting a pad fluid having a viscosity that allows settling or rising of barrier particles toward the top. or bottom to form the barrier, (b) injecting a slurry of the barrier particles in a fluid of a viscosity higher than the pad fluid (the fluid being capable of transporting the barrier particles), and (c) injecting a fluid having a lower viscosity than the fluid of step (b) through which the particles may settle or rise to form the barrier. For placement of at least a barrier at the base of the fracture, the ratio of the particle density to the densities of the particle- and/or proppant-free fluids is in the range of from about 1.0 to about 5.0, preferably in the range of from about 2.5 to about 5Ø For placement of at least a barrier at the top of the fracture, the ratio of the particle density to the densities of the particle- and/or proppant-free fluids is in the range of from about 0.2 to about 1.0, preferably about 0.5 to about 1Ø
Optionally the particles may be a mixture of particles having a ratio of the particle density to the fluid density in the range of from about 0.2 to about 1.0 and particles having a ratio of the particle density to the fluid density in the range of from about 1.0 to about 5Ø The method may also include a step of injecting, between steps (b) and (c), and/or after step (c), a fluid capable of transporting the particles. Optionally, at least a portion of the particles adheres to one another after placement. At least a portion of the particles may dissolve after the treatment. Optionally, at least a portion of the particles releases acid after the treatment. At least a portion of the particles may release a breaker after the treatment. Optionally, one or more of the fluids contains fibers. Optionally, one or more of the fluids contains a fluid loss control additive.
The steps indicated may be followed by a shut in period.
Another embodiment of the Invention is a method for creating a fracture, in a subterranean formation, having a barrier to fluid flow and/or fracture growth out of both the top and bottom of the fracture; the barrier contains particles. The method includes the steps of (a) injecting a pad fluid having a viscosity that does not allow settling or rising of barrier particles toward the top or bottom during the treatment, (b) injecting the barrier particles in a fluid capable of transporting the barrier particles, and (c) injecting a fluid having a lower viscosity than the fluid of step (b) through which the particles may settle or rise to form the barrier. The fluids of steps (a) and (b) may have the same viscosity, or all three fluids may have the same viscosity. The ratio of the particle density to the densities of the particle- and/or proppant-free fluids may be in the range of from about 1.0 to about 5.0, preferably in the range of from about 2.5 to about 5Ø Optionally, the ratio of the particle density to the densities of the particle- and/or proppant-free fluids may be in the range of from about 0.2 to about 1.0, preferably about 0.5 to about 1Ø The particles may also be a mixture of particles having a ratio of the particle density to the fluid density in the range of from about 0.2 to about 1.0 and particles-having a ratio of the particle density to the fluid density--in the range of from about 1.0 to about 5Ø The method may further include a step of injecting, between steps (b) and (c), and/or after step (c), a fluid capable of transporting the particles.
Optionally, at least a portion of the particles adheres to one another after placement. At least a portion of the particles may dissolve after the treatment. Optionally, at least a portion of the particles releases acid after the treatment. At least a portion of the particles may release a breaker after the treatment. Optionally, one or more of the fluids contains fibers.
Optionally, one or more of the fluids contains a fluid loss control additive. The steps indicated may be followed by a shut in period.
Brief Description of the Drawings Figure 1 shows the results of a process for placing a particle slug at the bottom of a fracture.
Figure 2 shows the results of a process for placing a particle slug at the top of a fracture.
Figure 3 shows the results of a process for placing a particle slug at the top and at the bottom of a fracture.
Figure 4 shows the results of a process for placing a particle slug that extends deep into a fracture at the bottom.
Figure 5 shows the results of a process for placing a particle slug that extends deep into a fracture at the top.
Figure 6 shows the results of a process for placing a particle slug that extends deep into a fracture both at the bottom and at the top.
Figure 7 shows results calculated with a simulator of a method for placing a particle slug at the bottom of a fracture.
Figure 8 shows results calculated with a simulator of a method for placing an extended particle slug at the bottom of a fracture.
Figure 9 shows results calculated with a simulator of a method for placing extended particle slugs at the bottom and top of a fracture.
Figure 10 shows results calculated with a simulator of a method for placing an extended particle slug at the bottom of a fracture at very low injection rates.
Detailed Description of the Invention Although the following discussion emphasizes conventional hydraulic fracturing, methods of the Invention may be used before or during hydraulic fracturing, acid fracturing, slickwater fracturing, and combined fracturing and gravel packing in a single operation. The invention will be described in terms of treatment of vertical wells, but is equally applicable to wells of any orientation. The invention will be described in terms of vertical fractures in horizontal target zones, but is equally applicable to fractures of any orientation in formations of any orientation. The invention will be described for hydrocarbon production wells, but it is to be understood that the invention may be used for wells for production of other fluids, such as water or carbon dioxide, or, for example, for injection or storage wells.
It should also be understood that throughout this specification, when a concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated. Furthermore, each numerical value should be read once as modified by the term "about" (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context. For example, "a range of from 1 to 10" is to be read as indicating each and every possible number along the continuum between about 1 and about 10. In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to,within the range, it is to be understood that the inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventors have possession of the entire range and all points within the range.
We describe here a method for placing a barrier at the bottom or the top of a hydraulic fracture to control the undesired growth of the fracture height (explained here in terms of a vertical fracture in a horizontal zone). Note that the barrier is a barrier to fluid flow and a barrier to fracture growth. The method is based essentially on the two following phenomena:
the gravitational settling (or rising) of particles in a fluid, and the penetration of a finger of a low-viscosity fluid into a high-viscosity fluid in a slot, for example a fracture, according to the Saffman-Taylor instability mechanism. Note that the displacement of one fluid by another in a narrow vertical slot (for example a fracture in a subterranean formation) gives rise to the development of the Saffman-Taylor instability only in the case in which the displacing fluid is less viscous than the displaced fluid, thereby providing a thin finger of lower-viscosity fluid which penetrates into the higher-viscosity fluid and cuts the latter into two portions, which are then displaced to the top and the bottom of the slot. If the displacing fluid has the same or higher viscosity than the displaced fluid, the flow is stable.
The process of the barrier placement consists of three necessary stages: (i) the injection of a first relatively low-viscosity particle-free fluid, (ii) then the injection of a thickened barrier-particle-laden fluid, and then (iii) injection of a second relatively low-viscosity particle-free fluid. By "particle-free" we mean not containing sufficient particles to contribute significantly to formation of a barrier; we do not mean that the fluid may not contain any particles of any type; for example, a pad fluid may contain fluid loss particles that are not major contributors, for example greater than 20%, to the barrier. The fluids injected before and after the particle-laden slug provide a relatively low-viscosity medium, in which the slug sediments rapidly to the fracture bottom (or rises rapidly to the fracture top). Below, when we describe the first low-viscosity fluid as having a "low-viscosity", we mean that the fluid has a viscosity sufficiently low that the particles will rise or fall through it to the location required in the time allowed by the pumping schedule and any optional shut in.
Additionally, the low-viscosity fluid injected after the slug cuts the highly-viscous particle-laden fluid into two unequal parts according to the Saffman-Taylor instability mechanism, displacing the lower, larger, part of the slug to the fracture bottom, thereby enhancing the sedimentation of a lumped barrier. The lower portion is larger because of gravitational settling of individual proppant particles towards the bottom of the fracture. Below, when we describe the second low-viscosity fluid as having a "low viscosity", we mean that it fingers through the thickened particle-laden fluid under the pumping conditions, and when we describe the particle-laden fluid as "thickened" or "highly-viscous", we mean that the second low-viscosity fluid will finger through it under the pumping conditions. Low-viscosity fluids have been used in the past to provide particle settling or rising in fracturing, but not to cut a particle-laden fracturing fluid into portions for the purpose of forming fluid flow and fracture growth barriers. When a "stretched" barrier is required (a barrier extending farther out into the fracture from the wellbore in which the fracture is being created than would occur without the auxiliary stage), then an auxiliary stage is introduced between the injection of the slug and the injection of the second low-viscosity fluid. The auxiliary stage is the injection of a highly-viscous particle-free fluid. This fluid bulldozes the particle-laden slug along the fracture (at the top, the bottom, or both) thereby providing an extended barrier, which bridges along a greater portion of the fracture. Below, when we describe the auxiliary stage fluid as being "highly-viscous"
we mean that it is sufficiently viscous to be able to push the barrier particles farther into the fracture.
This method and fluid system for barrier placement assisted by gravitational settling or rising and by an unstable fluid-fluid displacement in a hydraulic fracture makes it possible to control the fracture height growth and to prevent the fracture from propagating into the undesired zones located either above or below the target formation. For example the method and fluids allow the operator to keep a fracture in an oil-bearing formation and avoid water- or gas-bearing regions. The process of placing an extended barrier at the top or bottom of a fracture includes four stages of injecting different fluids into the subterranean formation. The stages are as follows: (i) the injection of a pad of a low-viscosity particle-free fluid into a well in order to open and propagate the hydraulic fracture in the subterranean formation, (ii) then the injection of a more viscous particle-laden fluid, (iii) then the injection of a low-viscosity particle-free fluid, and then (iv) the injection of a highly-viscous particle-free fluid. The particle-free pad injected in the first stage provides a low-viscosity medium, in which the slug sediments rapidly to the fracture bottom or rises rapidly to the fracture top.
In such cases the pad fluid must have a lower viscosity than that of the fluid used to place the barrier particles.
(Whenever we say one fluid has a lower (or higher) viscosity than another, we mean at all shear rates.) The pad fluid must have a sufficiently low viscosity to allow the barrier to settle (or rise), but at the same time it must have a sufficiently high viscosity to open and propagate a fracture, so there must be a balance. In cases in which the formation is high permeability, then the pad fluid will commonly have a fairly high viscosity and in such cases the stage or stages after the barrier injection stage must be long enough, or there must be a shut in period, to allow the time necessary for the barrier to rise or fall in a viscous environment.
Suitable viscosities, stage volumes, optional shut in periods, and pumping rates may be calculated by those skilled in fracturing, for example by using one of the many numerical simulators available. A
conventional fracturing treatment may begin right after the end of stage (iv), or optionally the -well may be shut in to allow additional time for the barrier particles to rise or fall to form the barrier(s). The treatment is designed so that the barrier particles form a barrier by the end of the injection of the last stage before initiation of a conventional fracture treatment, or, if shut in is necessary (because of the need for time for settling (rising) or for any other operational reasons), by the end of the shut in period. The barrier is considered to have been formed when flow out of the top or bottom or both the top and bottom of the fracture has been inhibited such that fracture growth past the barrier does not occur.
When the operator desires to place a barrier both at the top and the bottom of the fracture, a different sequence of fluids may be used; in this case the first stage may be a highly-viscous fluid. When the highly-viscous fluid is injected during the first stage, then the finger of the low-viscosity fluid injected during the third stage cuts the slug into two almost equal parts and displaces the lower and the upper parts downwards and upwards, thereby providing the placement of two barriers, one at the top and one at the bottom of the fracture.
The particles constituting the slug, injected in the second stage, when deposited at the fracture bottom or top, bridge at the fracture edge, reduce the pressure applied to the surrounding rock at the fracture edge to below the critical value required for the fracture to propagate into the surrounding rock, and thus stop the fracture growth in the vertical direction.
This particulate material may consist of small rigid or deformable particles of any shape with the density higher or lower than that of any of the injected fluids. (Note that all the fluids ,will typically be water-based and the densities of the fluids will all typically be about the same and about that of water; in this context, when we speak of the density of the fluid, we mean the density of a carrier fluid, not that of a slurry.) The particles may or may not adhere to one another and/or the surrounding rock after placement, may or may not dissolve in the fluid, and may or may not release acid to etch the surrounding formation. This will be discussed further below; these actions may be instigated by the action of a physical trigger (which may for example be closure stress, a temperature increase, a pH change, contact with water, etc.). The low-viscosity particle-free fluid injected at the third stage penetrates into the slug according to the Saffman-Taylor instability mechanism, cuts the slug into two unequal parts, and in the case of heavy barrier particles displaces the lower bigger part of the slug towards the fracture bottom thereby enhancing the sedimentation of the slug.
The following guidelines are followed for a successful barrier placement:
= the flow rate should be the minimum possible, for example as low as about 3.2 m3/min, although this may favor screening out;
= the density of the particles constituting the barrier should be high (for a barrier at the bottom of the fracture) relative to that of the fluid, for example up to about 3600 kg/m3, although this may favor screening out;
= the particle diameter should be approximately that of conventional proppant or smaller to minimize the risk of a screenout;
= the barrier particle concentration in the slug may be as high as practical, for example up to about 1000 kg/m3, to promote efficiency and to promote fast barrier particle settling (rising); the upper limit is governed by equipment limitations and prevention of a screenout (depending upon the other job design parameters);
= the viscosity of the low-viscosity fluid should be as low as possible without promoting a screenout;
= all parameters (for example fluid density and viscosity, barrier particle size and density, stage length (time)) should be selected to optimize barrier placement while minimizing the likelihood of near-wellbore screenout; such decisions may conveniently be made by modeling with a simulator;
= the barrier placement job consists of three or four stages (exemplary amounts of fluids and particles are given in the examples following this section) in the following order (optionally, additional stages may be added, or stages may be divided into sub-stages, for example as shown in the examples); a specific design is determined, for example, from a series of numerical simulations with a fracture simulator:
o a pad of a clean low-viscosity fluid used to create an initial fracture and to provide a low-viscosity medium inside the fracture, in which the barrier particles will settle or rise rapidly; when it is desired to place, two barriers (one at the bottom and one at the top of the fracture), the pad fluid should, on the contrary, be higher-viscosity; when it is necessary for the pad to have higher viscosity (to initiate and propagate a- fracture) than would be desirable for the barrier placement, the pad may contain a breaker, for example a fast-acting breaker; the suitable balance between a viscosity sufficiently high to initiate and propagate a fracture and sufficiently low to allow barrier particle settling(rising) may be determined by numerical simulation; the volume of the pad should be sufficient to create a fracture of desired length;
o a portion of slurry of a diverting particulate material mixed with, for example, a cross-linked gel to transport the particles through the perforations and to place the slug inside the fracture; the particle concentration is high, for example up to about 8 PPA in oilfield units (about 0.96 kg/L); barrier placement will generally lead to increased fracture width and decreased likelihood of screenout in the subsequent fracturing treatment; the volume should be sufficient to create a barrier of the desired length along the fracture;
o an optional portion of a clean highly-viscous fluid, for example a cross-linked gel, to stretch the slug along the fracture, so that it will settle (or rise) and form a barrier bridging along the entire lower (or upper) edge of the fracture;
when a lumped barrier (most of the barrier material near the wellbore) is acceptable, this stage may be omitted; the volume needed is the volume sufficient to push the barrier to the desired location, or to stretch the barrier over a desired distance along the bottom of fracture;
o a portion of a low-viscosity fluid (for example the same as the pad fluid) to penetrate into the more viscous particle-laden fluid according to the Saffman-Taylor instability mechanism and to displace at least the larger lower part of the slug towards the fracture bottom, or, if the particles are less dense than the fluid, to displace at least the larger portion towards the top; if the pad fluid is highly-viscous, then the slug is cut into two almost equal parts displaced upwards and downwards, which results in the placement of two barriers, on the top and the bottom of the fracture, respectively; the volume of clean lower-viscosity fluid is determined by the time needed for the barrier to settle (rise).
Any oilfield fluid may be used for the lower-viscosity and higher-viscosity fluids of the methods of the Invention. The viscosity suitable for a specific job is determined by simulation, for example by comparing and contrasting a series-of simulations.
The fluids may be oil-based or water-based and may be foamed or energized. Most commonly, the fluids are polymer viscosified water based fluids or viscoelastic surfactant (or other non-polymeric viscosifier) viscosified water-based fluids. If made with polymers, a convenient method is to use the same polymer concentration in each fluid but to crosslink the higher-viscosity fluid.
The crosslinking may optionally be delayed; the fluids may optionally contain breakers. The fluids may contain any of the additives normally found in oilfield fluids, such as, but not limited to, iron control agents, clay control agents, stabilizers, demulsifiers, buffers, etc.
Any particles used in the oilfield as a proppant, lost circulation, or fluid loss control additive may be used as the barrier particles. Mixtures of particles may be used. Particularly suitable are those normally used as proppants, for example, sand, ceramics, plant matter, polymer beads, glass, hollow glass microspheres. Other particularly suitable materials are those normally used as fluid loss control agents such as calcium carbonate flakes and polyester flakes, for example polyglycolic acid or polylactic acid flakes. The choice of particle material (density, shape, size) is based primarily on the settling (rising) rate, fracture width, fluid viscosities, and screenout potential. The nature of the particles, and their amount and concentration, are preferably selected so that the barrier formed has a permeability between about 0.0 and about 1.0 Darcy.
At least a portion of the barrier particles may optionally be selected, or treated, so that they adhere to one another after they are placed. For example, there are many resin coated proppants available that have this property. At least a portion of the barrier particles may optionally be slowly soluble (or hydrolysable) in the fracture fluid or the formation fluid or produced so that they survive long enough to prevent fracture height growth but then dissolve (or hydrolyze) so that they no longer inhibit flow into (or out of) the fracture. For example, the barrier should be gone within a week or a month. Optionally, only a portion of the barrier is subsequently removed, by the same mechanism(s) and over the same time scale. This increases the barrier permeability and so increases the fracture conductivity.
Partial or complete removal of the barrier may be initiated by any of a number of triggers, including, by example, closure stress, temperature, pressure, pH change, contact with reservoir fluid, water or another substance, etc. At least a portion of the barrier particles may optionally be an acid-precursor, such as polylactic acid or polyglycolic acid that releases an acid that may etch carbonate formations. The acid may, for example, differentially etch the fracture faces so that they leave a- flow path when the fracture closes, or it may etch cavities into the surrounding formation; either increases the fracture conductivity. The barrier particles may optionally contain an acid in a protective coating that, for example, under pressure, increased temperature, or in the presence of water, releases the acid, for the same purposes. At least a portion of the barrier particles may optionally be or include a breaker for the viscosifier used in the fracture fluid used in the subsequent fracturing treatment; this breaker may be released after the fracturing treatment to help break the fracturing fluid, thereby decreasing its viscosity and providing a more efficient fracture cleanup. The breaker may optionally also be a breaker for the viscosifier(s) used in the fluid(s) used to place the barrier. The barrier particles may be rigid or deformable and may be of any shape.
The method of the Invention may be applied in many different ways. A barrier may be placed at the bottom of a fracture by the sequential injection of a lower-viscosity particle-free pad, then a higher-viscosity particle-laden thickened fluid, and then a lower-viscosity particle-free fluid, into the subterranean formation. The conventional fracturing treatment may begin immediately after the end of the final stage of the barrier placement stage sequence.
Optionally, there may be a shut-in period before commencement of the conventional treatment; the fracture may optionally be allowed to close during this shut-in period. The apparent viscosity of the lower-viscosity fluids should be significantly lower than that of the higher-viscosity fluid at any shear rate. (The lower-viscosity fluids may be the same or different in composition and in rheology.) When the ratio of the particle density to the fluid density ranges from between about 1.0 and about 5.0 (preferably between about 2.5 and about 5.0 to promote settling), this sequential injection of fluids results in the placement of a "lumped" barrier (most of the barrier material is near the wellbore) at the bottom of the fracture as shown in Figure 1, where the wellbore is shown at [1], the fracture is shown at [2], and the barrier is shown at [3]. When the ratio of the particle density to the fluid density ranges from between about 0.2 and about 1.0 (preferably between about 0.5 and about 1.0 to promote rising), this sequential injection of fluids results in the placement of a "lumped"
barrier (most of the barrier material is near the wellbore) at the top of the fracture as shown in Figure 2, where the wellbore is shown at [1], the fracture is shown at [2], and the barrier is shown at [3]. (The wellbore, fracture and barrier(s) are indicated by the same numbers in each of Figures 1-6.) When the viscosities of the lower-viscosity fluid in the pad and the higher viscosity fluid used to inject the barrier particles are the same (including approximately the same), then the method provides the placement of two barriers (two almost equal portions of the initial. particle slug)-one on the top and one on the bottom of the fracture, respectively (as shown in Figure 3). In this case, the key mechanism providing the two slugs on the top and the bottom is the Saffman-Taylor instability, which results in cutting the slug into two portions by the finger of lower-viscosity fluid. These two portions are then displaced towards the top and the bottom of the fracture. The placement of these barriers is enhanced by the phenomenon of the fluid/fluid displacement; gravitational settling alone would not be sufficient. The relative sizes of the top and bottom barriers may be adjusted by adjusting the relative densities of the particles and the fluid, and the relative viscosities of the different fluids.
Barriers may also be placed at both the top and the bottom of the fracture at the same time by the sequential injection of a lower-viscosity particle-free pad, then a higher-viscosity particle-laden thickened fluid, and then a lower-viscosity particle-free fluid, where the particulate material includes a mixture of (a) particles having a ratio of the particle density to the fluid density ranging between about 1.0 and about 5.0 and (b) particles having a ratio of the particle density to the fluid density ranging from about 0.2 and about 1Ø This results in the placement of two lumped particle slugs, one at the top and one at the bottom of the fracture, respectively, as shown in Figure 3.
In order to extend the barrier farther out into the fracture away from the wellbore, to any of the sequences just described an additional stage of a highly-viscous fluid may be added between the stage of barrier particle injection and the subsequent stage of lower-viscosity fluid. The fluid in this additional stage is a particle-free material, for example a cross-linked gel. At any shear rate the viscosity of the fluid used in this stage is lower than, equal to, or slightly higher than that of the fluid used to inject the particles, but it is highly viscous and is more viscous than the subsequent stage of lower-viscosity fluid. This method results in the placement of a stretched particle slug at the bottom of the fracture (Figure 4), a stretched particle slug at the top of the fracture (Figure 5) or stretched particle slugs at the top and bottom of the fracture (Figure 6).
The barrier placement method of the Invention may be applied during a conventional fracturing treatment if the operator determines that undesirable fracture growth is occurring.
The conventional treatment is stopped, with or without fracture closure and/or shut in, the barrier is placed with the various stages as detailed above, the fracture is optionally allowed to close and/or is- optionally shut in, and then the fracture treatment is resumed, optionally with modifications to the original pumping schedule. In such instances it is advantageous to use the same fluids and proppants used in the fracturing treatment for the barrier placement treatment;
concentrations of components (such as viscosifiers, proppant (barrier particles), crosslinkers, and breakers) may differ in some or all the barrier placement stages from those in any of the fracturing treatment stages and still use chemicals and equipment on hand.
Fibers may be added to any of the fluids used in the barrier placement method of the Invention. Fibers in the pad and in the lower-viscosity fluid injected after the barrier particle slug may inhibit settling (or rising) and may not be desirable unless they are needed for some other purpose, for example the breaker or an acid precursor is in the form of fibers. Fibers (or other proppant retention means) in the barrier particle slug may be used to hold the barrier in place during the subsequent fracture treatment, and to adjust the relative rates of barrier particle settling (rising) and barrier particle transport. Fluid loss control additives may be added to any of the stages used for barrier placement; they would be most advantageous in the pad when a large wide fracture is desired.
When the method of the Invention is applied to a vertical fracture (long axis vertical or having a significant vertical component); for example created from a horizontal well, gravity-driven placement of a barrier particle slug results in barrier particle placement at the tip(s) of the fracture, preventing fracture length growth and promoting fracture width growth and keeping the fracture in the formation. The method of the Invention may be applied to fractures in deviated wells. The method of the Invention may be applied in any situation in which a fracture of any orientation has a vertical component and the operator wishes to limit fracture growth upwards or downwards or wishes to create a wide fracture.
The method of the Invention may be used before or during acid fracturing treatments, or fracture treatments with other formation-dissolving fluids. The fluids used in the barrier placement process may or may not contain an acid or formation-dissolving fluid. The method of the Invention may be used before or during a slickwater treatment, provided that the equipment available can create and pump fluids having high particle concentrations and can formulate higher-viscosity fluids. If only slickwater fluids and pump rates can be used, it is still possible to create barriers by the method of the Invention if the pumping times of the barrier particle stage and subsequent stages are long enough to allow sufficient particles to be placed and to allow sufficient particle settling (rising). The method of the Invention may- be used before frac-pack treatments (fracturing and gravel packing in a. single treatment) without deleteriously affecting the frac-pack; normally this would be unnecessary, but it may be done, for example, if the operator plans a fracture treatment and then part way through the treatment changes it to a frac-pack.
The present invention can be further understood from the following examples.
Example 1:
This example demonstrates how the method of the Invention performs under typical field conditions. Table 1 shows the pumping schedule and Figure 1 demonstrates the particle concentration distribution after the end of stage 4, calculated (as in all the examples) using a pseudo 3D fracturing simulator (fracture design, prediction, evaluation and treatment-monitoring program) commercially available under the trade designation FracCADETM from Schlumberger Technology Corporation, Sugar Land, Texas, U. S. A. The density of the barrier particles (called sand in this and the other examples) was equal to 3600 kg/m3 and the particle mean diameter was 0.589 mm (20/40 mesh sand). The "highly-viscous"
fluid parameters were as follows: the power-law exponent was n=0.59 and the consistency was K=0.383 Pas"; the density was that of water, and the apparent viscosity was g=28.1 cP at a shear rate equal to 170 s 1. (The fluid modeled contains 3.6 kg/m3 bromate-crosslinked guar.) The "low-viscosity" fluid modeled contains 3.6 kg/m3 uncrosslinked guar and was assumed to have the same density and rheology as water. These were the high and low viscosity fluids used in each of the examples.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump rate, Volume, Conc., Mass, Volume, Time, m3/ m3 kg/m3 kg m3 min min 1 6.36 Low- 80 - 0 0 80 12.6 visc 2 6.36 High- 10 Sand 958.61 9586 12.7 2.0 visc 3 6.36 Low- 30 - 0 0 30 4.7 visc 4 6.36 High- 100 - 0 0 100 15.7 visc Table 1: Treatment schedule for Example 1 The first stage was a clean pad. The second stage contained the barrier plug;
the third and fourth stages were clean fluid. In this and all the examples, there was no shut-in time; the calculation shows the position of the barrier at the start of the subsequent fracture treatment.
Figure 7 shows the calculated results. A barrier was placed in approximately the near-wellbore half of the fracture, primarily in the near-wellbore third of the fracture and almost all at the bottom. Not shown is that when a similar treatment was modeled except that all four stages used the high-viscosity fluid, the proppant was distributed throughout the fracture with the highest concentration centered (between the top and the bottom) about two thirds of the way to the tip. The barrier particle distribution was in the shape of a horizontal "U" with the open end toward to wellbore; the viscous fluid following the barrier particle slug pushed the slug into the fracture but there was no low-viscosity fluid through which the particles could settle. Also not shown is that when a similar treatment was modeled except that the first stage was the low-viscosity fluid and the last three stages were the high viscosity fluid, a significant portion of the slug formed a barrier at the bottom of the fracture, and most likely, would bridge the lower fracture edge, but there was an upper wing of the deformed slug that had not settled and thus could mix with the conventional proppant in the treatment to follow.
Also not shown is that when the third stage was lower-viscosity fluid and the other three stages were higher-viscosity fluid, the performance was almost as good as the base case, although the barrier had a slightly lower particle concentration and was a little closer to the wellbore. Thus, for a barrier at the bottom, a lower-viscosity first stage was preferable, and additionally a lower-viscosity stage after barrier slug injection (to displace at least a larger part of the slug towards the bottom of the fracture according to the Saffman-Taylor instability mechanism and to promote barrier particle settling as shown in Figure 7 for the design of Table 1) was more preferable. This lower-viscosity stage after the barrier slug injection is kept small to minimize the possibility of a screenout.
Example 2:
The next example illustrates the placement of a barrier stretched along the bottom edge of the fracture. In order to provide an elongated barrier, an auxiliary stage was introduced between pumping the barrier particle slug (Stage 2) and injecting the low-viscosity fluid (Stage 4 in this example). At this point (Stage 3) a small portion of clean cross-linked gel was introduced. The extended job design is presented in Table 2.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump rate, Volume, Conc., Mass, Volume, Time, m3/ min m3 kg/m3 kg m3 min 1 6.36 Low- 80 - 0 0 80 12.6 visc 2 6.36 High- 10 Sand 958.61 9586 12.7 2.0 visc 3 6.36 High- 20 - 0 0 20 3.1 visc 4 6.36 Low- 30 - 0 0 30 4.7 visc 6.36 High- 100 - 0 0 100 15.7 visc Table 2: Treatment schedule for Example 2 The particle concentration distribution calculated for this job design is shown in Figure 8. It can be seen that the small stage of clean viscous fluid pushed a portion of the barrier slug farther into the fracture. This job design was optimized for this effect by running a series of numerical simulations (not shown) in which the amounts of fluids injected in the different stages were varied.
Example 3:
The next example illustrates the effect of the rheology of the fluid injected before the slug on the final pattern inside the fracture. In this case, the pad fluid used was a highly-viscous cross-linked gel. As a result, two barriers were placed, one at the bottom and one at the top of the fracture; The lower-viscosity fluid fingered into the higher-viscosity fluid according to the Saffman-Taylor instability and cut the barrier particle slug into uneven parts;
the larger portion was displaced and then settled towards the bottom and the smaller portion was pushed towards the top. The particles used in this simulation had a mean diameter equal to 0.661 mm and a density of 2540 kg/m3. The results calculated for the particle concentration distribution are summarized in Figure 9, and the pumping schedule is presented in Table 3.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump rate, Volume Conc., Mass, Volume, Time, m3/ min m3 kg/m3 kg m3 min 1 6.36 High- 80 - 0 0 80 12.6 visc 2 6.36 High- 5 Sand 958.61 4793 6.3 1 visc 3 6.36 High- 10 Sand 958.61 9586 12.7 2.0 visc 4 6.36 High- 20 - 0 0 20 3.1 visc 6.36 Low- 30 - 0 0 30 4.7 visc 6 6.36 High- 140 - 0 0 140 22 visc Table 3: Treatment schedule for Example 3 Example 4:
An investigation into the effect of the flow rate on the process of barrier placement showed that the lower the flow rate, the easier it was to place the barrier accurately. In this example, the flow rate was set to 3.2 m3/min, which is near the lowest pumping flow rate possible for most operators' equipment. (Lower flow rates are better and are permissible if the operator's equipment allows.) The pumping schedule and the resulting particle concentration distributions are shown in Table 4 and Figure 10.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump rate, Volume, Conc., Mass, Volume, Time, m3/ min m3 kg/m3 kg m3 min 1 3.2 Low- 80 - 0 0 80 25 visc 2 3.2 High- 10 Sand 958.61 9586 12.7 4 visc 3 3.2 High- 20 - 0 0 20 6.3 visc 4 3.2 Low- 30 - 0 0 30 9.4 visc 5 3.2 High- 100 - 0 0 100 31.3 visc Table 4: Treatment schedule for Example 4 The concentration pattern shown in Figure 10 corresponds to a quite successful placement of a barrier stretched along the fracture, bridging a substantial portion of the lower fracture edge. Again, this pumping schedule was selected from a number of schedules tried.
For example, not shown was a similar simulation in which the fifth stage was 30 instead of 100 m3; more of the barrier material ended up at the top of the fracture and nearer the wellbore on the bottom. Also not shown is that when a treatment following the schedule of Table 4, but with the higher-viscosity fluid used in all stages, was modeled, the barrier was not placed in the bottom, but rather in the middle (vertically) of the fracture, and the fracture height was much greater, especially near the wellbore. Modeling with any of a number of simulators available may be used by one skilled in the art to select a suitable job design for the nature of the strata to be treated and the desired end result and for the available equipment, fluids, and barrier materials. Conventional fracture treatments are designed so that the velocity of longitudinal proppant transport away from the wellbore is much greater than the velocity of proppant settling (or rising). Barrier placement treatment designs are intended to make these rates approximately comparable, and preferably to make settling (rising) take less time than longitudinal transport.
Background of the Invention Fracture height control is a common challenge faced by operators designing hydraulic fracture treatments, particularly in low permeability reservoirs. Usually when a fracture is initiated in a productive interval, it grows in all directions until it reaches an interface, for example with upper and lower formations in the common case of a vertical fracture in a horizontal reservoir, and encounters a resistance to its growth. Normally, the surrounding rock contacting the productive formation is tougher and less permeable than the reservoir. If natural barriers exist above and below the reservoir, the vertical growth of the fracture will be restrained and the fracture will propagate within the productive zone. This provides an efficient fracture with the entire surface lying inside the reservoir.
However, when the surrounding formation is too weak to withstand the pressure required to propagate the fracture, the barrier rocks will also crack and the vertical fracture growth will continue. This process results in poor fracture efficiency, since some of the fracture area lies outside the productive zone. Fracture growth downwards may also lead to water breakthrough, if there is a water zone below the reservoir. Water breakthrough limits oil production as well as increases the operational costs in order to separate and dispose of the water. Fracture growth in the upward direction is undesirable as well, since there might be a gas cap and eventually breakthrough into this zone might stimulate gas production. This could also result in the reduced ultimate recovery. Even if there is no gas cap or water zone, undesired fracture growth is wasteful.
Various methods have been tried to control fracture height growth. Use of low specific gravity particles to form an upper barrier by relying on the rising of individual particles in a low viscosity fluid to create and place a diverting barrier was described in U. S. patent No.
4,509,598. Similar treatments may be done with high specific gravity particles that settle and form a lower barrier. Typically these barriers are placed prior to the actual fracturing job by injecting a cross-linked pad followed by a linear gel laden with a special diverting particulate material that is allowed to rise or settle and bridge thedesired fracture upper or lower edge; the fracturing treatment is typically started immediately after placing the barrier.
US Patent Application Publication No. 2005/0016732 describes a method of hydraulically fracturing in two principal steps. In the first step, a fracture in and below the productive zone of a formation is initiated by introducing a fluid free of a proppant. In the second step, proppant-laden slurry that contains a relatively lightweight density proppant is introduced into the subterranean formation. Either the fluid density of the proppant-free fluid is greater than the fluid density of the proppant-laden slurry or the viscosity of the proppant-free fluid is greater than the viscosity of the proppant laden slurry. The method limits undesirable fracture height growth in the hydrocarbon-bearing subterranean formation during the fracturing.
US Patent 4,478,282 describes a method of hydraulically fracturing an underground formation penetrated by a wellbore involving injecting a fracturing fluid pad into the formation, then injecting a non-proppant fluid stage that is a transport fluid and contains a flow block material, the flow block material being sand and silica flour with a particle size distribution of the sand of 10-20, 20-40, and 100 mesh and of the silica flour of 200 mesh, and then injecting a proppant laden fluid slurry into the formation. The method relies on the assumption that the fracture growing into adjacent shale formations is narrower than in the productive formation and so the flow block material will bridge out in the fracture in the shale.
Consequently, one aspect of that invention is that conditions that promote fracture height growth were actually preferred. Fluid viscosities were not considered important.
There is a need for a method of controlling fracture height growth when fractures are growing above the desired interval, when fractures are growing below the desired interval, and when fracture height growth must be limited deep in the formation.
Summary of the Invention A first embodiment of the Invention is a method for creating a fracture, in a subterranean formation, having a barrier to fluid flow out of the top or bottom or both the top and bottom of the fracture; the barrier contains particles.. The method includes the steps of (a) injecting a pad fluid having a viscosity that allows settling or rising of barrier particles toward the top. or bottom to form the barrier, (b) injecting a slurry of the barrier particles in a fluid of a viscosity higher than the pad fluid (the fluid being capable of transporting the barrier particles), and (c) injecting a fluid having a lower viscosity than the fluid of step (b) through which the particles may settle or rise to form the barrier. For placement of at least a barrier at the base of the fracture, the ratio of the particle density to the densities of the particle- and/or proppant-free fluids is in the range of from about 1.0 to about 5.0, preferably in the range of from about 2.5 to about 5Ø For placement of at least a barrier at the top of the fracture, the ratio of the particle density to the densities of the particle- and/or proppant-free fluids is in the range of from about 0.2 to about 1.0, preferably about 0.5 to about 1Ø
Optionally the particles may be a mixture of particles having a ratio of the particle density to the fluid density in the range of from about 0.2 to about 1.0 and particles having a ratio of the particle density to the fluid density in the range of from about 1.0 to about 5Ø The method may also include a step of injecting, between steps (b) and (c), and/or after step (c), a fluid capable of transporting the particles. Optionally, at least a portion of the particles adheres to one another after placement. At least a portion of the particles may dissolve after the treatment. Optionally, at least a portion of the particles releases acid after the treatment. At least a portion of the particles may release a breaker after the treatment. Optionally, one or more of the fluids contains fibers. Optionally, one or more of the fluids contains a fluid loss control additive.
The steps indicated may be followed by a shut in period.
Another embodiment of the Invention is a method for creating a fracture, in a subterranean formation, having a barrier to fluid flow and/or fracture growth out of both the top and bottom of the fracture; the barrier contains particles. The method includes the steps of (a) injecting a pad fluid having a viscosity that does not allow settling or rising of barrier particles toward the top or bottom during the treatment, (b) injecting the barrier particles in a fluid capable of transporting the barrier particles, and (c) injecting a fluid having a lower viscosity than the fluid of step (b) through which the particles may settle or rise to form the barrier. The fluids of steps (a) and (b) may have the same viscosity, or all three fluids may have the same viscosity. The ratio of the particle density to the densities of the particle- and/or proppant-free fluids may be in the range of from about 1.0 to about 5.0, preferably in the range of from about 2.5 to about 5Ø Optionally, the ratio of the particle density to the densities of the particle- and/or proppant-free fluids may be in the range of from about 0.2 to about 1.0, preferably about 0.5 to about 1Ø The particles may also be a mixture of particles having a ratio of the particle density to the fluid density in the range of from about 0.2 to about 1.0 and particles-having a ratio of the particle density to the fluid density--in the range of from about 1.0 to about 5Ø The method may further include a step of injecting, between steps (b) and (c), and/or after step (c), a fluid capable of transporting the particles.
Optionally, at least a portion of the particles adheres to one another after placement. At least a portion of the particles may dissolve after the treatment. Optionally, at least a portion of the particles releases acid after the treatment. At least a portion of the particles may release a breaker after the treatment. Optionally, one or more of the fluids contains fibers.
Optionally, one or more of the fluids contains a fluid loss control additive. The steps indicated may be followed by a shut in period.
Brief Description of the Drawings Figure 1 shows the results of a process for placing a particle slug at the bottom of a fracture.
Figure 2 shows the results of a process for placing a particle slug at the top of a fracture.
Figure 3 shows the results of a process for placing a particle slug at the top and at the bottom of a fracture.
Figure 4 shows the results of a process for placing a particle slug that extends deep into a fracture at the bottom.
Figure 5 shows the results of a process for placing a particle slug that extends deep into a fracture at the top.
Figure 6 shows the results of a process for placing a particle slug that extends deep into a fracture both at the bottom and at the top.
Figure 7 shows results calculated with a simulator of a method for placing a particle slug at the bottom of a fracture.
Figure 8 shows results calculated with a simulator of a method for placing an extended particle slug at the bottom of a fracture.
Figure 9 shows results calculated with a simulator of a method for placing extended particle slugs at the bottom and top of a fracture.
Figure 10 shows results calculated with a simulator of a method for placing an extended particle slug at the bottom of a fracture at very low injection rates.
Detailed Description of the Invention Although the following discussion emphasizes conventional hydraulic fracturing, methods of the Invention may be used before or during hydraulic fracturing, acid fracturing, slickwater fracturing, and combined fracturing and gravel packing in a single operation. The invention will be described in terms of treatment of vertical wells, but is equally applicable to wells of any orientation. The invention will be described in terms of vertical fractures in horizontal target zones, but is equally applicable to fractures of any orientation in formations of any orientation. The invention will be described for hydrocarbon production wells, but it is to be understood that the invention may be used for wells for production of other fluids, such as water or carbon dioxide, or, for example, for injection or storage wells.
It should also be understood that throughout this specification, when a concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated. Furthermore, each numerical value should be read once as modified by the term "about" (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context. For example, "a range of from 1 to 10" is to be read as indicating each and every possible number along the continuum between about 1 and about 10. In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to,within the range, it is to be understood that the inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventors have possession of the entire range and all points within the range.
We describe here a method for placing a barrier at the bottom or the top of a hydraulic fracture to control the undesired growth of the fracture height (explained here in terms of a vertical fracture in a horizontal zone). Note that the barrier is a barrier to fluid flow and a barrier to fracture growth. The method is based essentially on the two following phenomena:
the gravitational settling (or rising) of particles in a fluid, and the penetration of a finger of a low-viscosity fluid into a high-viscosity fluid in a slot, for example a fracture, according to the Saffman-Taylor instability mechanism. Note that the displacement of one fluid by another in a narrow vertical slot (for example a fracture in a subterranean formation) gives rise to the development of the Saffman-Taylor instability only in the case in which the displacing fluid is less viscous than the displaced fluid, thereby providing a thin finger of lower-viscosity fluid which penetrates into the higher-viscosity fluid and cuts the latter into two portions, which are then displaced to the top and the bottom of the slot. If the displacing fluid has the same or higher viscosity than the displaced fluid, the flow is stable.
The process of the barrier placement consists of three necessary stages: (i) the injection of a first relatively low-viscosity particle-free fluid, (ii) then the injection of a thickened barrier-particle-laden fluid, and then (iii) injection of a second relatively low-viscosity particle-free fluid. By "particle-free" we mean not containing sufficient particles to contribute significantly to formation of a barrier; we do not mean that the fluid may not contain any particles of any type; for example, a pad fluid may contain fluid loss particles that are not major contributors, for example greater than 20%, to the barrier. The fluids injected before and after the particle-laden slug provide a relatively low-viscosity medium, in which the slug sediments rapidly to the fracture bottom (or rises rapidly to the fracture top). Below, when we describe the first low-viscosity fluid as having a "low-viscosity", we mean that the fluid has a viscosity sufficiently low that the particles will rise or fall through it to the location required in the time allowed by the pumping schedule and any optional shut in.
Additionally, the low-viscosity fluid injected after the slug cuts the highly-viscous particle-laden fluid into two unequal parts according to the Saffman-Taylor instability mechanism, displacing the lower, larger, part of the slug to the fracture bottom, thereby enhancing the sedimentation of a lumped barrier. The lower portion is larger because of gravitational settling of individual proppant particles towards the bottom of the fracture. Below, when we describe the second low-viscosity fluid as having a "low viscosity", we mean that it fingers through the thickened particle-laden fluid under the pumping conditions, and when we describe the particle-laden fluid as "thickened" or "highly-viscous", we mean that the second low-viscosity fluid will finger through it under the pumping conditions. Low-viscosity fluids have been used in the past to provide particle settling or rising in fracturing, but not to cut a particle-laden fracturing fluid into portions for the purpose of forming fluid flow and fracture growth barriers. When a "stretched" barrier is required (a barrier extending farther out into the fracture from the wellbore in which the fracture is being created than would occur without the auxiliary stage), then an auxiliary stage is introduced between the injection of the slug and the injection of the second low-viscosity fluid. The auxiliary stage is the injection of a highly-viscous particle-free fluid. This fluid bulldozes the particle-laden slug along the fracture (at the top, the bottom, or both) thereby providing an extended barrier, which bridges along a greater portion of the fracture. Below, when we describe the auxiliary stage fluid as being "highly-viscous"
we mean that it is sufficiently viscous to be able to push the barrier particles farther into the fracture.
This method and fluid system for barrier placement assisted by gravitational settling or rising and by an unstable fluid-fluid displacement in a hydraulic fracture makes it possible to control the fracture height growth and to prevent the fracture from propagating into the undesired zones located either above or below the target formation. For example the method and fluids allow the operator to keep a fracture in an oil-bearing formation and avoid water- or gas-bearing regions. The process of placing an extended barrier at the top or bottom of a fracture includes four stages of injecting different fluids into the subterranean formation. The stages are as follows: (i) the injection of a pad of a low-viscosity particle-free fluid into a well in order to open and propagate the hydraulic fracture in the subterranean formation, (ii) then the injection of a more viscous particle-laden fluid, (iii) then the injection of a low-viscosity particle-free fluid, and then (iv) the injection of a highly-viscous particle-free fluid. The particle-free pad injected in the first stage provides a low-viscosity medium, in which the slug sediments rapidly to the fracture bottom or rises rapidly to the fracture top.
In such cases the pad fluid must have a lower viscosity than that of the fluid used to place the barrier particles.
(Whenever we say one fluid has a lower (or higher) viscosity than another, we mean at all shear rates.) The pad fluid must have a sufficiently low viscosity to allow the barrier to settle (or rise), but at the same time it must have a sufficiently high viscosity to open and propagate a fracture, so there must be a balance. In cases in which the formation is high permeability, then the pad fluid will commonly have a fairly high viscosity and in such cases the stage or stages after the barrier injection stage must be long enough, or there must be a shut in period, to allow the time necessary for the barrier to rise or fall in a viscous environment.
Suitable viscosities, stage volumes, optional shut in periods, and pumping rates may be calculated by those skilled in fracturing, for example by using one of the many numerical simulators available. A
conventional fracturing treatment may begin right after the end of stage (iv), or optionally the -well may be shut in to allow additional time for the barrier particles to rise or fall to form the barrier(s). The treatment is designed so that the barrier particles form a barrier by the end of the injection of the last stage before initiation of a conventional fracture treatment, or, if shut in is necessary (because of the need for time for settling (rising) or for any other operational reasons), by the end of the shut in period. The barrier is considered to have been formed when flow out of the top or bottom or both the top and bottom of the fracture has been inhibited such that fracture growth past the barrier does not occur.
When the operator desires to place a barrier both at the top and the bottom of the fracture, a different sequence of fluids may be used; in this case the first stage may be a highly-viscous fluid. When the highly-viscous fluid is injected during the first stage, then the finger of the low-viscosity fluid injected during the third stage cuts the slug into two almost equal parts and displaces the lower and the upper parts downwards and upwards, thereby providing the placement of two barriers, one at the top and one at the bottom of the fracture.
The particles constituting the slug, injected in the second stage, when deposited at the fracture bottom or top, bridge at the fracture edge, reduce the pressure applied to the surrounding rock at the fracture edge to below the critical value required for the fracture to propagate into the surrounding rock, and thus stop the fracture growth in the vertical direction.
This particulate material may consist of small rigid or deformable particles of any shape with the density higher or lower than that of any of the injected fluids. (Note that all the fluids ,will typically be water-based and the densities of the fluids will all typically be about the same and about that of water; in this context, when we speak of the density of the fluid, we mean the density of a carrier fluid, not that of a slurry.) The particles may or may not adhere to one another and/or the surrounding rock after placement, may or may not dissolve in the fluid, and may or may not release acid to etch the surrounding formation. This will be discussed further below; these actions may be instigated by the action of a physical trigger (which may for example be closure stress, a temperature increase, a pH change, contact with water, etc.). The low-viscosity particle-free fluid injected at the third stage penetrates into the slug according to the Saffman-Taylor instability mechanism, cuts the slug into two unequal parts, and in the case of heavy barrier particles displaces the lower bigger part of the slug towards the fracture bottom thereby enhancing the sedimentation of the slug.
The following guidelines are followed for a successful barrier placement:
= the flow rate should be the minimum possible, for example as low as about 3.2 m3/min, although this may favor screening out;
= the density of the particles constituting the barrier should be high (for a barrier at the bottom of the fracture) relative to that of the fluid, for example up to about 3600 kg/m3, although this may favor screening out;
= the particle diameter should be approximately that of conventional proppant or smaller to minimize the risk of a screenout;
= the barrier particle concentration in the slug may be as high as practical, for example up to about 1000 kg/m3, to promote efficiency and to promote fast barrier particle settling (rising); the upper limit is governed by equipment limitations and prevention of a screenout (depending upon the other job design parameters);
= the viscosity of the low-viscosity fluid should be as low as possible without promoting a screenout;
= all parameters (for example fluid density and viscosity, barrier particle size and density, stage length (time)) should be selected to optimize barrier placement while minimizing the likelihood of near-wellbore screenout; such decisions may conveniently be made by modeling with a simulator;
= the barrier placement job consists of three or four stages (exemplary amounts of fluids and particles are given in the examples following this section) in the following order (optionally, additional stages may be added, or stages may be divided into sub-stages, for example as shown in the examples); a specific design is determined, for example, from a series of numerical simulations with a fracture simulator:
o a pad of a clean low-viscosity fluid used to create an initial fracture and to provide a low-viscosity medium inside the fracture, in which the barrier particles will settle or rise rapidly; when it is desired to place, two barriers (one at the bottom and one at the top of the fracture), the pad fluid should, on the contrary, be higher-viscosity; when it is necessary for the pad to have higher viscosity (to initiate and propagate a- fracture) than would be desirable for the barrier placement, the pad may contain a breaker, for example a fast-acting breaker; the suitable balance between a viscosity sufficiently high to initiate and propagate a fracture and sufficiently low to allow barrier particle settling(rising) may be determined by numerical simulation; the volume of the pad should be sufficient to create a fracture of desired length;
o a portion of slurry of a diverting particulate material mixed with, for example, a cross-linked gel to transport the particles through the perforations and to place the slug inside the fracture; the particle concentration is high, for example up to about 8 PPA in oilfield units (about 0.96 kg/L); barrier placement will generally lead to increased fracture width and decreased likelihood of screenout in the subsequent fracturing treatment; the volume should be sufficient to create a barrier of the desired length along the fracture;
o an optional portion of a clean highly-viscous fluid, for example a cross-linked gel, to stretch the slug along the fracture, so that it will settle (or rise) and form a barrier bridging along the entire lower (or upper) edge of the fracture;
when a lumped barrier (most of the barrier material near the wellbore) is acceptable, this stage may be omitted; the volume needed is the volume sufficient to push the barrier to the desired location, or to stretch the barrier over a desired distance along the bottom of fracture;
o a portion of a low-viscosity fluid (for example the same as the pad fluid) to penetrate into the more viscous particle-laden fluid according to the Saffman-Taylor instability mechanism and to displace at least the larger lower part of the slug towards the fracture bottom, or, if the particles are less dense than the fluid, to displace at least the larger portion towards the top; if the pad fluid is highly-viscous, then the slug is cut into two almost equal parts displaced upwards and downwards, which results in the placement of two barriers, on the top and the bottom of the fracture, respectively; the volume of clean lower-viscosity fluid is determined by the time needed for the barrier to settle (rise).
Any oilfield fluid may be used for the lower-viscosity and higher-viscosity fluids of the methods of the Invention. The viscosity suitable for a specific job is determined by simulation, for example by comparing and contrasting a series-of simulations.
The fluids may be oil-based or water-based and may be foamed or energized. Most commonly, the fluids are polymer viscosified water based fluids or viscoelastic surfactant (or other non-polymeric viscosifier) viscosified water-based fluids. If made with polymers, a convenient method is to use the same polymer concentration in each fluid but to crosslink the higher-viscosity fluid.
The crosslinking may optionally be delayed; the fluids may optionally contain breakers. The fluids may contain any of the additives normally found in oilfield fluids, such as, but not limited to, iron control agents, clay control agents, stabilizers, demulsifiers, buffers, etc.
Any particles used in the oilfield as a proppant, lost circulation, or fluid loss control additive may be used as the barrier particles. Mixtures of particles may be used. Particularly suitable are those normally used as proppants, for example, sand, ceramics, plant matter, polymer beads, glass, hollow glass microspheres. Other particularly suitable materials are those normally used as fluid loss control agents such as calcium carbonate flakes and polyester flakes, for example polyglycolic acid or polylactic acid flakes. The choice of particle material (density, shape, size) is based primarily on the settling (rising) rate, fracture width, fluid viscosities, and screenout potential. The nature of the particles, and their amount and concentration, are preferably selected so that the barrier formed has a permeability between about 0.0 and about 1.0 Darcy.
At least a portion of the barrier particles may optionally be selected, or treated, so that they adhere to one another after they are placed. For example, there are many resin coated proppants available that have this property. At least a portion of the barrier particles may optionally be slowly soluble (or hydrolysable) in the fracture fluid or the formation fluid or produced so that they survive long enough to prevent fracture height growth but then dissolve (or hydrolyze) so that they no longer inhibit flow into (or out of) the fracture. For example, the barrier should be gone within a week or a month. Optionally, only a portion of the barrier is subsequently removed, by the same mechanism(s) and over the same time scale. This increases the barrier permeability and so increases the fracture conductivity.
Partial or complete removal of the barrier may be initiated by any of a number of triggers, including, by example, closure stress, temperature, pressure, pH change, contact with reservoir fluid, water or another substance, etc. At least a portion of the barrier particles may optionally be an acid-precursor, such as polylactic acid or polyglycolic acid that releases an acid that may etch carbonate formations. The acid may, for example, differentially etch the fracture faces so that they leave a- flow path when the fracture closes, or it may etch cavities into the surrounding formation; either increases the fracture conductivity. The barrier particles may optionally contain an acid in a protective coating that, for example, under pressure, increased temperature, or in the presence of water, releases the acid, for the same purposes. At least a portion of the barrier particles may optionally be or include a breaker for the viscosifier used in the fracture fluid used in the subsequent fracturing treatment; this breaker may be released after the fracturing treatment to help break the fracturing fluid, thereby decreasing its viscosity and providing a more efficient fracture cleanup. The breaker may optionally also be a breaker for the viscosifier(s) used in the fluid(s) used to place the barrier. The barrier particles may be rigid or deformable and may be of any shape.
The method of the Invention may be applied in many different ways. A barrier may be placed at the bottom of a fracture by the sequential injection of a lower-viscosity particle-free pad, then a higher-viscosity particle-laden thickened fluid, and then a lower-viscosity particle-free fluid, into the subterranean formation. The conventional fracturing treatment may begin immediately after the end of the final stage of the barrier placement stage sequence.
Optionally, there may be a shut-in period before commencement of the conventional treatment; the fracture may optionally be allowed to close during this shut-in period. The apparent viscosity of the lower-viscosity fluids should be significantly lower than that of the higher-viscosity fluid at any shear rate. (The lower-viscosity fluids may be the same or different in composition and in rheology.) When the ratio of the particle density to the fluid density ranges from between about 1.0 and about 5.0 (preferably between about 2.5 and about 5.0 to promote settling), this sequential injection of fluids results in the placement of a "lumped" barrier (most of the barrier material is near the wellbore) at the bottom of the fracture as shown in Figure 1, where the wellbore is shown at [1], the fracture is shown at [2], and the barrier is shown at [3]. When the ratio of the particle density to the fluid density ranges from between about 0.2 and about 1.0 (preferably between about 0.5 and about 1.0 to promote rising), this sequential injection of fluids results in the placement of a "lumped"
barrier (most of the barrier material is near the wellbore) at the top of the fracture as shown in Figure 2, where the wellbore is shown at [1], the fracture is shown at [2], and the barrier is shown at [3]. (The wellbore, fracture and barrier(s) are indicated by the same numbers in each of Figures 1-6.) When the viscosities of the lower-viscosity fluid in the pad and the higher viscosity fluid used to inject the barrier particles are the same (including approximately the same), then the method provides the placement of two barriers (two almost equal portions of the initial. particle slug)-one on the top and one on the bottom of the fracture, respectively (as shown in Figure 3). In this case, the key mechanism providing the two slugs on the top and the bottom is the Saffman-Taylor instability, which results in cutting the slug into two portions by the finger of lower-viscosity fluid. These two portions are then displaced towards the top and the bottom of the fracture. The placement of these barriers is enhanced by the phenomenon of the fluid/fluid displacement; gravitational settling alone would not be sufficient. The relative sizes of the top and bottom barriers may be adjusted by adjusting the relative densities of the particles and the fluid, and the relative viscosities of the different fluids.
Barriers may also be placed at both the top and the bottom of the fracture at the same time by the sequential injection of a lower-viscosity particle-free pad, then a higher-viscosity particle-laden thickened fluid, and then a lower-viscosity particle-free fluid, where the particulate material includes a mixture of (a) particles having a ratio of the particle density to the fluid density ranging between about 1.0 and about 5.0 and (b) particles having a ratio of the particle density to the fluid density ranging from about 0.2 and about 1Ø This results in the placement of two lumped particle slugs, one at the top and one at the bottom of the fracture, respectively, as shown in Figure 3.
In order to extend the barrier farther out into the fracture away from the wellbore, to any of the sequences just described an additional stage of a highly-viscous fluid may be added between the stage of barrier particle injection and the subsequent stage of lower-viscosity fluid. The fluid in this additional stage is a particle-free material, for example a cross-linked gel. At any shear rate the viscosity of the fluid used in this stage is lower than, equal to, or slightly higher than that of the fluid used to inject the particles, but it is highly viscous and is more viscous than the subsequent stage of lower-viscosity fluid. This method results in the placement of a stretched particle slug at the bottom of the fracture (Figure 4), a stretched particle slug at the top of the fracture (Figure 5) or stretched particle slugs at the top and bottom of the fracture (Figure 6).
The barrier placement method of the Invention may be applied during a conventional fracturing treatment if the operator determines that undesirable fracture growth is occurring.
The conventional treatment is stopped, with or without fracture closure and/or shut in, the barrier is placed with the various stages as detailed above, the fracture is optionally allowed to close and/or is- optionally shut in, and then the fracture treatment is resumed, optionally with modifications to the original pumping schedule. In such instances it is advantageous to use the same fluids and proppants used in the fracturing treatment for the barrier placement treatment;
concentrations of components (such as viscosifiers, proppant (barrier particles), crosslinkers, and breakers) may differ in some or all the barrier placement stages from those in any of the fracturing treatment stages and still use chemicals and equipment on hand.
Fibers may be added to any of the fluids used in the barrier placement method of the Invention. Fibers in the pad and in the lower-viscosity fluid injected after the barrier particle slug may inhibit settling (or rising) and may not be desirable unless they are needed for some other purpose, for example the breaker or an acid precursor is in the form of fibers. Fibers (or other proppant retention means) in the barrier particle slug may be used to hold the barrier in place during the subsequent fracture treatment, and to adjust the relative rates of barrier particle settling (rising) and barrier particle transport. Fluid loss control additives may be added to any of the stages used for barrier placement; they would be most advantageous in the pad when a large wide fracture is desired.
When the method of the Invention is applied to a vertical fracture (long axis vertical or having a significant vertical component); for example created from a horizontal well, gravity-driven placement of a barrier particle slug results in barrier particle placement at the tip(s) of the fracture, preventing fracture length growth and promoting fracture width growth and keeping the fracture in the formation. The method of the Invention may be applied to fractures in deviated wells. The method of the Invention may be applied in any situation in which a fracture of any orientation has a vertical component and the operator wishes to limit fracture growth upwards or downwards or wishes to create a wide fracture.
The method of the Invention may be used before or during acid fracturing treatments, or fracture treatments with other formation-dissolving fluids. The fluids used in the barrier placement process may or may not contain an acid or formation-dissolving fluid. The method of the Invention may be used before or during a slickwater treatment, provided that the equipment available can create and pump fluids having high particle concentrations and can formulate higher-viscosity fluids. If only slickwater fluids and pump rates can be used, it is still possible to create barriers by the method of the Invention if the pumping times of the barrier particle stage and subsequent stages are long enough to allow sufficient particles to be placed and to allow sufficient particle settling (rising). The method of the Invention may- be used before frac-pack treatments (fracturing and gravel packing in a. single treatment) without deleteriously affecting the frac-pack; normally this would be unnecessary, but it may be done, for example, if the operator plans a fracture treatment and then part way through the treatment changes it to a frac-pack.
The present invention can be further understood from the following examples.
Example 1:
This example demonstrates how the method of the Invention performs under typical field conditions. Table 1 shows the pumping schedule and Figure 1 demonstrates the particle concentration distribution after the end of stage 4, calculated (as in all the examples) using a pseudo 3D fracturing simulator (fracture design, prediction, evaluation and treatment-monitoring program) commercially available under the trade designation FracCADETM from Schlumberger Technology Corporation, Sugar Land, Texas, U. S. A. The density of the barrier particles (called sand in this and the other examples) was equal to 3600 kg/m3 and the particle mean diameter was 0.589 mm (20/40 mesh sand). The "highly-viscous"
fluid parameters were as follows: the power-law exponent was n=0.59 and the consistency was K=0.383 Pas"; the density was that of water, and the apparent viscosity was g=28.1 cP at a shear rate equal to 170 s 1. (The fluid modeled contains 3.6 kg/m3 bromate-crosslinked guar.) The "low-viscosity" fluid modeled contains 3.6 kg/m3 uncrosslinked guar and was assumed to have the same density and rheology as water. These were the high and low viscosity fluids used in each of the examples.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump rate, Volume, Conc., Mass, Volume, Time, m3/ m3 kg/m3 kg m3 min min 1 6.36 Low- 80 - 0 0 80 12.6 visc 2 6.36 High- 10 Sand 958.61 9586 12.7 2.0 visc 3 6.36 Low- 30 - 0 0 30 4.7 visc 4 6.36 High- 100 - 0 0 100 15.7 visc Table 1: Treatment schedule for Example 1 The first stage was a clean pad. The second stage contained the barrier plug;
the third and fourth stages were clean fluid. In this and all the examples, there was no shut-in time; the calculation shows the position of the barrier at the start of the subsequent fracture treatment.
Figure 7 shows the calculated results. A barrier was placed in approximately the near-wellbore half of the fracture, primarily in the near-wellbore third of the fracture and almost all at the bottom. Not shown is that when a similar treatment was modeled except that all four stages used the high-viscosity fluid, the proppant was distributed throughout the fracture with the highest concentration centered (between the top and the bottom) about two thirds of the way to the tip. The barrier particle distribution was in the shape of a horizontal "U" with the open end toward to wellbore; the viscous fluid following the barrier particle slug pushed the slug into the fracture but there was no low-viscosity fluid through which the particles could settle. Also not shown is that when a similar treatment was modeled except that the first stage was the low-viscosity fluid and the last three stages were the high viscosity fluid, a significant portion of the slug formed a barrier at the bottom of the fracture, and most likely, would bridge the lower fracture edge, but there was an upper wing of the deformed slug that had not settled and thus could mix with the conventional proppant in the treatment to follow.
Also not shown is that when the third stage was lower-viscosity fluid and the other three stages were higher-viscosity fluid, the performance was almost as good as the base case, although the barrier had a slightly lower particle concentration and was a little closer to the wellbore. Thus, for a barrier at the bottom, a lower-viscosity first stage was preferable, and additionally a lower-viscosity stage after barrier slug injection (to displace at least a larger part of the slug towards the bottom of the fracture according to the Saffman-Taylor instability mechanism and to promote barrier particle settling as shown in Figure 7 for the design of Table 1) was more preferable. This lower-viscosity stage after the barrier slug injection is kept small to minimize the possibility of a screenout.
Example 2:
The next example illustrates the placement of a barrier stretched along the bottom edge of the fracture. In order to provide an elongated barrier, an auxiliary stage was introduced between pumping the barrier particle slug (Stage 2) and injecting the low-viscosity fluid (Stage 4 in this example). At this point (Stage 3) a small portion of clean cross-linked gel was introduced. The extended job design is presented in Table 2.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump rate, Volume, Conc., Mass, Volume, Time, m3/ min m3 kg/m3 kg m3 min 1 6.36 Low- 80 - 0 0 80 12.6 visc 2 6.36 High- 10 Sand 958.61 9586 12.7 2.0 visc 3 6.36 High- 20 - 0 0 20 3.1 visc 4 6.36 Low- 30 - 0 0 30 4.7 visc 6.36 High- 100 - 0 0 100 15.7 visc Table 2: Treatment schedule for Example 2 The particle concentration distribution calculated for this job design is shown in Figure 8. It can be seen that the small stage of clean viscous fluid pushed a portion of the barrier slug farther into the fracture. This job design was optimized for this effect by running a series of numerical simulations (not shown) in which the amounts of fluids injected in the different stages were varied.
Example 3:
The next example illustrates the effect of the rheology of the fluid injected before the slug on the final pattern inside the fracture. In this case, the pad fluid used was a highly-viscous cross-linked gel. As a result, two barriers were placed, one at the bottom and one at the top of the fracture; The lower-viscosity fluid fingered into the higher-viscosity fluid according to the Saffman-Taylor instability and cut the barrier particle slug into uneven parts;
the larger portion was displaced and then settled towards the bottom and the smaller portion was pushed towards the top. The particles used in this simulation had a mean diameter equal to 0.661 mm and a density of 2540 kg/m3. The results calculated for the particle concentration distribution are summarized in Figure 9, and the pumping schedule is presented in Table 3.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump rate, Volume Conc., Mass, Volume, Time, m3/ min m3 kg/m3 kg m3 min 1 6.36 High- 80 - 0 0 80 12.6 visc 2 6.36 High- 5 Sand 958.61 4793 6.3 1 visc 3 6.36 High- 10 Sand 958.61 9586 12.7 2.0 visc 4 6.36 High- 20 - 0 0 20 3.1 visc 6.36 Low- 30 - 0 0 30 4.7 visc 6 6.36 High- 140 - 0 0 140 22 visc Table 3: Treatment schedule for Example 3 Example 4:
An investigation into the effect of the flow rate on the process of barrier placement showed that the lower the flow rate, the easier it was to place the barrier accurately. In this example, the flow rate was set to 3.2 m3/min, which is near the lowest pumping flow rate possible for most operators' equipment. (Lower flow rates are better and are permissible if the operator's equipment allows.) The pumping schedule and the resulting particle concentration distributions are shown in Table 4 and Figure 10.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump rate, Volume, Conc., Mass, Volume, Time, m3/ min m3 kg/m3 kg m3 min 1 3.2 Low- 80 - 0 0 80 25 visc 2 3.2 High- 10 Sand 958.61 9586 12.7 4 visc 3 3.2 High- 20 - 0 0 20 6.3 visc 4 3.2 Low- 30 - 0 0 30 9.4 visc 5 3.2 High- 100 - 0 0 100 31.3 visc Table 4: Treatment schedule for Example 4 The concentration pattern shown in Figure 10 corresponds to a quite successful placement of a barrier stretched along the fracture, bridging a substantial portion of the lower fracture edge. Again, this pumping schedule was selected from a number of schedules tried.
For example, not shown was a similar simulation in which the fifth stage was 30 instead of 100 m3; more of the barrier material ended up at the top of the fracture and nearer the wellbore on the bottom. Also not shown is that when a treatment following the schedule of Table 4, but with the higher-viscosity fluid used in all stages, was modeled, the barrier was not placed in the bottom, but rather in the middle (vertically) of the fracture, and the fracture height was much greater, especially near the wellbore. Modeling with any of a number of simulators available may be used by one skilled in the art to select a suitable job design for the nature of the strata to be treated and the desired end result and for the available equipment, fluids, and barrier materials. Conventional fracture treatments are designed so that the velocity of longitudinal proppant transport away from the wellbore is much greater than the velocity of proppant settling (or rising). Barrier placement treatment designs are intended to make these rates approximately comparable, and preferably to make settling (rising) take less time than longitudinal transport.
Claims (32)
1. A method for creating a fracture, in a subterranean formation, having a barrier, comprising particles, to fluid flow out of the top or bottom or both the top and bottom of the fracture comprising (a) injecting a pad fluid having a viscosity that allows settling or rising of barrier particles toward the top or bottom to form the barrier, (b) injecting a slurry of the barrier particles in a fluid of a viscosity higher than the pad fluid, said fluid capable of transporting the barrier particles, and (c) injecting a fluid having a lower viscosity than the fluid of step (b) through which the particles may settle or rise to form the barrier.
2. The method of claim 1 wherein the ratio of the particle density to the fluid density is in the range of from about 1.0 to about 5Ø
3. The method of claim 2 wherein the ratio of the particle density to the fluid density is in the range of from about 2.5 to about 5Ø
4. The method of claim 1 wherein the ratio of the particle density to the fluid density is in the range of from about 0.2 to about 1Ø
5. The method of claim 4 wherein the ratio of the particle density to the fluid density is in the range of from about 0.5 to about 1Ø
6. The method of claim 1 wherein the particles are a mixture of particles having a ratio of the particle density to the fluid density in the range of from about 0.2 to about 1.0 and particles having a ratio of the particle density to the fluid density in the range of from about 1.0 to about 5Ø
7. The method of claim 1 further comprising a step of injecting, between steps (b) and (c), a fluid capable of transporting the particles.
8. The method of claim 1 further comprising a step of injecting, after step (c), a fluid capable of transporting the particles.
9. The method of claim 1 wherein at least a portion of the particles adhere to one another after placement.
10. The method of claim 1 wherein at least a portion of the particles dissolve after the treatment.
11. The method of claim 1 wherein at least a portion of the particles release acid after the treatment.
12. The method of claim 1 wherein at least a portion of the particles release a breaker after the treatment.
13. The method of claim 1 wherein one or more of the fluids contains fibers.
14. The method of claim 1 wherein one or more of the fluids contains a fluid loss control additive.
15. The method of claim 1 followed by a shut in period.
16. A method for creating a fracture, in a subterranean formation, having a barrier, comprising particles, to fluid flow out of both the top and bottom of the fracture comprising (a) injecting a pad fluid having a viscosity that does not allow settling or rising of barrier particles toward the top or bottom during the treatment, (b) injecting the barrier particles in a fluid capable of transporting the barrier particles, and (c) injecting a fluid having a lower viscosity than the fluid of step (b) through which the particles may settle or rise to form the barrier.
17. The method of claim 16 wherein the fluids of steps (a) and (b) have the same viscosity.
18. The method of claim 16 wherein all three fluids have the same viscosity.
19. The method of claim 16 wherein the ratio of the particle density to the fluid density is in the range of from about 1.0 to about 5Ø
20. The method of claim 19 wherein the ratio of the particle density to the fluid density is in the range of from about 2.5 to about 5Ø
21. The method of claim 16 wherein the ratio of the particle density to the fluid density is in the range of from about 0.2 to about 1Ø
22 22. The method of claim 21 wherein the ratio of the particle density to the fluid density is in the range of from about 0.5 to about 1Ø
23. The method of claim 16 wherein the particles are a mixture of particles having a ratio of the particle density to the fluid density in the range of from about 0.2 to about 1.0 and particles having a ratio of the particle density to the fluid density in the range of from about 1.0 to about 5Ø
24. The method of claim 16 further comprising a step of injecting, between steps (b) and (c), a fluid capable of transporting the particles.
25. The method of claim 16 further comprising a step of injecting, after step (c), a fluid capable of transporting the particles.
26. The method of claim 16 wherein at least a portion of the particles adhere to one another after placement.
27. The method of claim 16 wherein at least a portion of the particles dissolve after the treatment.
28. The method of claim 16 wherein at least a portion of the particles release acid after the treatment.
29. The method of claim 16 wherein at least a portion of the particles release a breaker after the treatment.
30. The method of claim 16 wherein one or more of the fluids contains fibers.
31. The method of claim 16 wherein one or more of the fluids contains a fluid loss control additive.
32. The method of claim 16 followed by a shut in period.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| PCT/RU2008/000756 WO2010068128A1 (en) | 2008-12-10 | 2008-12-10 | Hydraulic fracture height growth control |
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| CA2746368A1 true CA2746368A1 (en) | 2010-06-17 |
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Family Applications (1)
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|---|---|---|---|
| CA2746368A Abandoned CA2746368A1 (en) | 2008-12-10 | 2008-12-10 | Hydraulic fracture height growth control |
Country Status (3)
| Country | Link |
|---|---|
| US (1) | US20110272159A1 (en) |
| CA (1) | CA2746368A1 (en) |
| WO (1) | WO2010068128A1 (en) |
Families Citing this family (23)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8841914B2 (en) | 2008-04-11 | 2014-09-23 | Baker Hughes Incorporated | Electrolocation apparatus and methods for providing information about one or more subterranean feature |
| US8797037B2 (en) | 2008-04-11 | 2014-08-05 | Baker Hughes Incorporated | Apparatus and methods for providing information about one or more subterranean feature |
| US9328600B2 (en) * | 2010-12-03 | 2016-05-03 | Exxonmobil Upstream Research Company | Double hydraulic fracturing methods |
| US20120193092A1 (en) * | 2011-01-31 | 2012-08-02 | Baker Hughes Incorporated | Apparatus and methods for tracking the location of fracturing fluid in a subterranean formation |
| US20130048282A1 (en) * | 2011-08-23 | 2013-02-28 | David M. Adams | Fracturing Process to Enhance Propping Agent Distribution to Maximize Connectivity Between the Formation and the Wellbore |
| US9850748B2 (en) * | 2012-04-30 | 2017-12-26 | Halliburton Energy Services, Inc. | Propping complex fracture networks in tight formations |
| US9418184B2 (en) * | 2013-07-25 | 2016-08-16 | Halliburton Energy Services, Inc. | Determining flow through a fracture junction in a complex fracture network |
| US9574443B2 (en) * | 2013-09-17 | 2017-02-21 | Halliburton Energy Services, Inc. | Designing an injection treatment for a subterranean region based on stride test data |
| US9500076B2 (en) * | 2013-09-17 | 2016-11-22 | Halliburton Energy Services, Inc. | Injection testing a subterranean region |
| US9702247B2 (en) | 2013-09-17 | 2017-07-11 | Halliburton Energy Services, Inc. | Controlling an injection treatment of a subterranean region based on stride test data |
| WO2015041678A1 (en) * | 2013-09-20 | 2015-03-26 | Halliburton Energy Services, Inc. | Methods for etching fractures and microfractures in shale formations |
| US9797212B2 (en) | 2014-03-31 | 2017-10-24 | Schlumberger Technology Corporation | Method of treating subterranean formation using shrinkable fibers |
| US10655444B2 (en) | 2015-10-22 | 2020-05-19 | Halliburton Energy Services, Inc. | Enhancing propped complex fracture networks in subterranean formations |
| US11767745B2 (en) * | 2016-09-29 | 2023-09-26 | Schlumberger Technology Corporation | Use of energetic events and fluids to fracture near wellbore regions |
| WO2018143918A1 (en) | 2017-01-31 | 2018-08-09 | Halliburton Energy Services, Inc. | Real-time optimization of stimulation treatments for multistage fracture stimulation |
| US20190040305A1 (en) * | 2017-08-01 | 2019-02-07 | Weatherford Technology Holdings, Llc | Fracturing method using a low-viscosity fluid with low proppant settling rate |
| CN107699224B (en) * | 2017-10-10 | 2020-03-27 | 西南石油大学 | Guiding agent for controlling extension height of upper end of hydraulic fracturing crack |
| CN109931045B (en) * | 2017-12-18 | 2021-08-31 | 中国石油化工股份有限公司 | Self-supporting acid fracturing method of double-seam system |
| US11566504B2 (en) | 2019-07-17 | 2023-01-31 | Weatherford Technology Holdings, Llc | Application of elastic fluids in hydraulic fracturing implementing a physics-based analytical tool |
| CN111396018B (en) * | 2020-05-15 | 2022-02-25 | 中国石油天然气集团有限公司 | Fracturing method for improving laying effect of propping agent of heterogeneous reservoir |
| CN112228031A (en) * | 2020-10-14 | 2021-01-15 | 中国石油天然气股份有限公司 | Fracturing method for controlling extending direction of crack |
| CN112431569B (en) * | 2020-10-15 | 2022-12-02 | 中国石油天然气股份有限公司 | Method for preventing crack from extending upwards, high-molecular plugging material and preparation method thereof |
| CN115434659B (en) * | 2021-06-02 | 2024-03-01 | 中国石油天然气集团有限公司 | Technological method for deep fixed-point delivery of hypertonic reservoir plugging agent |
Family Cites Families (10)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4478282A (en) * | 1982-04-07 | 1984-10-23 | The Standard Oil Company | Height control technique in hydraulic fracturing treatments |
| US4509598A (en) * | 1983-03-25 | 1985-04-09 | The Dow Chemical Company | Fracturing fluids containing bouyant inorganic diverting agent and method of use in hydraulic fracturing of subterranean formations |
| SU1682541A1 (en) * | 1989-02-22 | 1991-10-07 | Львовский политехнический институт им.Ленинского комсомола | Method of oil pool development |
| US4887670A (en) * | 1989-04-05 | 1989-12-19 | Halliburton Company | Controlling fracture growth |
| US5159979A (en) * | 1991-10-01 | 1992-11-03 | Mobil Oil Corporation | Method for limiting downward growth of induced hydraulic fractures |
| US6209643B1 (en) * | 1995-03-29 | 2001-04-03 | Halliburton Energy Services, Inc. | Method of controlling particulate flowback in subterranean wells and introducing treatment chemicals |
| US6626241B2 (en) * | 2001-12-06 | 2003-09-30 | Halliburton Energy Services, Inc. | Method of frac packing through existing gravel packed screens |
| US6725930B2 (en) * | 2002-04-19 | 2004-04-27 | Schlumberger Technology Corporation | Conductive proppant and method of hydraulic fracturing using the same |
| US6776235B1 (en) * | 2002-07-23 | 2004-08-17 | Schlumberger Technology Corporation | Hydraulic fracturing method |
| US7213651B2 (en) * | 2004-06-10 | 2007-05-08 | Bj Services Company | Methods and compositions for introducing conductive channels into a hydraulic fracturing treatment |
-
2008
- 2008-12-10 US US12/998,866 patent/US20110272159A1/en not_active Abandoned
- 2008-12-10 CA CA2746368A patent/CA2746368A1/en not_active Abandoned
- 2008-12-10 WO PCT/RU2008/000756 patent/WO2010068128A1/en active Application Filing
Also Published As
| Publication number | Publication date |
|---|---|
| US20110272159A1 (en) | 2011-11-10 |
| WO2010068128A1 (en) | 2010-06-17 |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| FZDE | Discontinued |
Effective date: 20171205 |