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    • 专利摘要:
    method for fracturing multiple zones within a wellbore formed in an underground formation. a method for fracturing multiple zones within a wellbore formed in an underground formation is accomplished by forming direct flow passages in two or more zones within the wellbore that are spaced apart along the length of a portion of the wellbore . the direct flow passages within each zone have different characteristics provided by orienting the direct flow passages in directions in each of the two or more zones relative to a selected direction to provide differences in fracture initiation pressures within each of the two or more zones. a fracturing fluid is introduced into the wellbore in a frac treatment. the fracturing fluid in fracturing treatment is supplied at a pressure above which is above the fracture initiation pressure of one of the two or more zones to facilitate fracturing of said one of the two or more zones while remaining below the fracture initiation pressure of fracture of any other unfractured zones of the two or more zones. the process is repeated for at least one or more unfractured zones of the two or more zones.
    公开号:BR112014002812B1
    申请号:R112014002812-5
    申请日:2012-07-28
    公开日:2021-08-03
    发明作者:Dmitry Ivanovich Potapenko；Bruno Lecerf；Olga Petrovna Alekseenko；Christopher N. Fredd；Elena Nikolaevna Tarasova；Oleg Medvedev；Matthew Robert Gillard
    申请人:Prad Research And Development Limited；
    IPC主号:
    专利说明:

    BACKGROUND
    [001] Statements in this section merely provide background information relating to this disclosure and may not constitute prior art.
    [002] Wellbore treatment methods are often used to increase hydrocarbon production by using a treatment fluid to affect an underground formation in a way that increases the flow of oil or gas from the formation to the wellbore to removal to the surface. The main types of such treatments include fracturing operations, high rate matrix and acid fracturing treatments, matrix acidification and injection of chelating agents. Hydraulic fracturing involves injecting fluids into an underground formation at sufficient pressures to form fractures in the formation, with the fractures increasing the flow from the formation to the wellbore. In chemical stimulation, flowability is improved by using chemicals to alter formation properties, such as increasing effective permeability by dissolving materials in or cauterizing underground formation. A wellbore can be an open hole or a lined hole where a metal tube (liner) is placed in the drilled hole and often cemented in place. In a lined wellbore, casing (and cement if present) is typically drilled at specified locations to allow hydrocarbon flow into the wellbore or to allow treatment fluids to flow from the wellbore into the formation.
    [003] To access hydrocarbon effectively and efficiently, it may be desirable to direct the treatment fluid to multiple target zones of interest in an underground formation. There may be target zones of interest in multiple underground formations or multiple layers in a specific formation that are preferred for treatment. In prior art methods of hydraulic fracture treatments, multiple target zones have typically been treated by treating one zone in the well at a time. These methods typically involved multiple steps of laying a gun down the wellbore to the target zone, drilling the target zone, removing the gun holder, treating the target zone with a hydraulic fracturing fluid, and then isolating the drilled target zone. This process is then subsequently repeated for all target zones of interest until all target zones are addressed. As can be recognized, such methods of treating multiple zones can be highly involved, time-consuming and expensive.
    [004] Therefore, methods of treating multiple zones in an underground formation are desired to overcome these disadvantages. SUMMARY
    [005] A method for fracturing multiple zones within a wellbore formed in an underground formation is performed by performing steps (a) through (d). In (a), direct flow passages are formed in two or more zones within the wellbore that are spaced apart along the length of a portion of the wellbore. The direct flow passages in each zone according to (a) have different characteristics provided by orienting the direct flow passages in directions in each of the two or more zones relative to a selected direction to provide differences in fracture initiation pressures within of each of the two or more zones.
    [006] In (b), a fracturing fluid is introduced into the wellbore in a fracturing treatment and in (c) a fracturing fluid pressure in a fracturing treatment is provided that is above the fracture initiation pressure of one of the two or more zones to facilitate fracturing of said one of the two or more zones. The fracturing fluid pressure in (c) is below the fracture initiation pressure of any other unfractured zones of the two or more zones. Step (d) requires the repetition of (c) for at least one or more unfractured zones of the two or more zones.
    [007] In certain embodiments, the selected direction is a direction of a main stress of the formation surrounding the wellbore. The selected direction can be aligned with or in a plane parallel to a direction of a major stress of the formation surrounding the wellbore. In certain modalities, the selected direction is at least one of a maximum horizontal stress, a vertical stress and a fracture plane.
    [008] In some embodiments, a reactive fluid is injected into at least one zone before fracture initiation occurs in that zone to facilitate reducing fracture initiation pressure. The reactive fluid can be an acid. The wellbore can be cemented using a cement that is substantially soluble in acid.
    [009] Direct flow passages in certain modalities can be formed in each zone using 0° or approximately 180° and phasing in each zone. The direct flow passages of each zone can also lie on a single plane or be located within 1 meter of a single plane. Direct flow passages can be formed by at least one of a perforation, by blasting and by drilling holes in a wellbore casing. Different characteristics of direct flow passages can be provided by wellbore slope in certain cases.
    [0010] The method may further include isolating a fractured zone in accordance with (c) before (d). A degradable material can be used to insulate the fractured zone in many applications. Insulation can also be achieved by the use of at least one of mechanical tools, sealing balls, packers, bridge plugs, direct flow bridge plugs, sand plugs, fibers, particulate material, viscous fluid, foams and combinations thereof.
    [0011] In certain embodiments, two or more zones may be located in a portion of the wellbore that is substantially vertical. In other embodiments, two or more zones are located in a portion of the wellbore that is curved. In some embodiments, two or more zones are located in a portion of the wellbore that is offset from the vertical. In other embodiments, two or more zones may be located in a portion of the wellbore that is substantially horizontal. In yet other embodiments, two or more zones may be located in a portion of the wellbore that is inclined at least 30° from the vertical.
    [0012] In some applications, the direct flow passages in each zone may have a minimum angle that is different by 5° or more than the minimum angle of flow passages in any other of the two or more zones. The direct flow passages in the fractured zone according to step (c) may also be oriented in certain cases at an angle relative to the selected direction that is smaller than the angle of the direct flow passages of any other non-fractured zones of two or more zones. In some embodiments, a straight-flow passage from the unfractured zone of two or more zones subsequently fractured according to (d) may be oriented at an angle relative to the selected direction that is at least 5° smaller than a direct-flow passage of one of the two or more previously fractured zones in (c). At least one of the through-flow passages in the fractured zone according to (c) may be oriented at an angle relative to the selected direction in certain applications that is less than the angle of any through-flow passages relative to the selected direction in any another unfractured zone of two or more fractured zones according to (d).
    [0013] The fractured zone according to (c) can be located towards a wellbore toe position and the fractured zone according to (d) can be located towards a wellbore heel position in certain modalities. In other embodiments, the fractured zone according to step (c) can be located towards a wellbore heel position and the fractured zone according to step (d) can be located towards a position of Wellhole finger.
    [0014] The fracturing fluid of the fracturing treatment can be selected from at least one of a hydraulic fracturing fluid, a reactive fracturing fluid and a slick-water fracturing fluid. The fracturing fluid may also contain at least one of proppant, fine particles, fibers, fluid loss additives, gelling agents and friction reducing agents in certain applications.
    [0015] In certain modalities, fracturing can be performed while being monitored.
    [0016] Each zone can have from 1 to 10 clusters of direct flow passages in some modalities. In certain cases, each through-flow pass cluster can be 0.1 to 200 meters long. BRIEF DESCRIPTION OF THE DRAWINGS
    [0017] For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in combination with the attached figures, in which:
    [0018] Figure 1A is a schematic representation of a cross section of a wellbore showing different stresses surrounding the wellbore and the angle (α) of holes formed in the wellbore in relation to these stresses.
    [0019] Figure 1B is a graph of the angle (α) of perforations relative to a direction of maximum principal stress 01 in the plane perpendicular to the wellbore direction and fracture initiation pressure. Initiation Pressure, FIP).
    [0020] Figure 2 is a graph of the angle between the drilling tunnel of a wellbore and the maximum horizontal stress in a vertical well and the fracture initiation pressure.
    [0021] Figure 3 is a schematic representation of a horizontal section of a drilled coated well showing several holes oriented at different angles.
    [0022] Figure 4A is a schematic representation of a top view of a horizontal well with a curved path showing boreholes oriented at different angles (θ) in relation to maximum and minimum horizontal stresses at the site.
    [0023] Figure 4B is a schematic representation of a side view of a deviated well with an almost vertical finger section showing boreholes oriented at different angles (θ) with respect to maximum (overload) and minimum stresses in place.
    [0024] Figure 4C is a schematic representation of a side view of a diversion well showing boreholes oriented at different angles (θ) in relation to maximum (overload) and minimum stresses in place; and
    [0025] Figure 5 is a schematic representation of a cross-section of a wellbore showing an example of a headland strategy that allows treatment deviation from one zone to the zone, with perforations A1, A2, A3 and A4, being misaligned from the direction of maximum stress or plane that includes the direction of maximum stress at some angle (α) perforations B1, B2...BN...BM being misaligned from the direction of maximum stress at a larger angle. DETAILED DESCRIPTION
    [0026] The following description and examples are presented solely for the purpose of illustrating the different embodiments of the invention and should not be construed as a limitation on the scope and applicability of the invention. While any compositions of the present invention may be described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials. In addition, the composition may also comprise some components other than those already mentioned. While the invention can be described in terms of treating vertical or horizontal wells, it is equally applicable to wells of any orientation. The invention will be described for hydrocarbon production wells, however it should be understood that the invention can be used for wells for the production of other fluids such as water or carbon dioxide, or, for example, for storage or injection wells. It should also be understood that throughout this descriptive report, when a concentration or range of amounts is described as being useful, or appropriate, or similar, it is intended that any and all concentrations or amounts within the range, including end points, should be considered to have been mentioned. Furthermore, each numerical value must be read once as modified by the term "approximately" (unless already expressly so modified) and then read again as not having been modified unless otherwise mentioned in context. For example, "a range from 1 to 10" should be read as indicating each and every possible number along the continuum between approximately 1 and approximately 10. In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or mentioned included in the range, or even when no data point is mentioned included in the range, it is to be understood that the inventors recognize and understand that any and all data points comprised in the range are to be considered to have been specified, and that inventors own the entire range and all the points within the range.
    [0027] The present invention is directed to creating farturas in multiple zones of an underground formation during a fracturing treatment. The method can be used for both coated and uncoated well (open hole) sections. As described here, the fracturing treatment is performed as a single pumping operation and is distinguished from multiple fracturing treatments that can be used to treat different or multiple zones in a formation. As used herein, the term "single pumping operation" is intended to encompass the situation where pumping of a fracturing fluid has started, but no additional drilling equipment (or other equipment) to form openings in the wellbore or subjecting previously created openings for fluid The wellbore is reintroduced into the wellbore or moved to another position to facilitate fracturing treatments after the fracturing fluid has been introduced. In single-pumping operation, pumping rates, pressures, and the character and composition of the fluids pumped can vary and pumping can even be temporarily stopped and restarted to perform fracturing treatment. As used here, this would still constitute a single pumping operation or fracture treatment. Additionally, in certain applications, the one-pumping operation can be conducted while the original drilling equipment is still present in the wellbore.
    [0028] In the present invention, to perform staged treatment of multiple zones in a well during a single frac treatment or pumping operation, differences in fracture initiation pressures of different wellbore zones are used. Differences in fracture initiation pressures for the different zones are created through specific oriented direct flow passages formed in the wellbore. As used herein, the term "direct flow passage(s)" or similar expressions is intended to encompass passages formed in casing and/or wellbore. Commonly, direct flow passages can be formed by barrels that are lowered into the wellbore and that drill through the casing and/or wellbore. As such, the straight-flow passages may be referred to as "cannonade(s)" and the expressions "straight-flow passage(s)", "cannonade(s)", "cannonal channel(s)", "tunnel(s)". is) cannoning” and similar expressions may be used interchangeably herein unless expressly indicated or otherwise evident from its context. Additionally although through flow passages can be formed by employing a grommet, other methods of forming the through flow passages can also be used. These can include blasting, cutting, sawing, drilling, sanding and the like. In certain embodiments, direct flow passages may be formed in the casing on the surface or outside of the wellbore, as described in international publication (PCT application) WO2009/001256A2, which is incorporated herein by reference in its entirety for all purposes . Direct flow passages can also be of different sizes, shapes and configurations. Examples of certain cross-sectional shapes for direct-flow passages include circular, oval, rectangular, polygonal, half-circle, slots, etc., and combinations of these and other shapes. In certain embodiments, the cross-sectional length or longest dimension axis may be oriented parallel or not parallel to the longitudinal axis of the casing or wellbore. The diameter or cross-sectional dimension of direct flow passages or perforations can range from 2 to 40 mm. Direct-flow passages can be from 0.005 to 3 meters in length.
    [0029] By orienting the direct flow passages or perforations in the different zones being treated so that the angles between the perforation channels formed in each zone and a selected direction, heterogeneity in fracture initiation pressure can be obtained. A fracturing fluid is then introduced into the wellbore at a pressure above the fracture initiation pressure of one of the drilled zones to facilitate fracturing of the zone. In the next stage of the fracturing treatment, the fracturing pressure is then increased above the fracturing pressure of the next perforated zone to facilitate fracturing of the next zone. This is repeated until all zones have been fractured. In certain modalities, isolation of the different zones between fracturing stages can be performed.
    [0030] The method can be used in creating multiple fractures in the same formation layer or in creating multiple fractures in a multilayer formation, and can be applied in vertical, horizontal and offset wells. The method can be combined with limited-entry fracturing techniques to facilitate additional fluid diversion in multiple zones at a given injection rate. The method can also be combined with other existing zonal isolation and fluid bypass techniques well known to those skilled in the art.
    [0031] Differences between the principal stresses in a formation facilitate providing for differences in fracture initiation pressure around the wellbore. For example, in vertical wells, anisotropy between horizontal stresses causes additional tensile stress to build up in the zone near the wellbore. As used here, vertical wells are those with a deviation of less than 30° from the vertical. Differences in horizontal stresses in vertical wells result in the fracture initiation pressure being dependent on a position of the fracture initiation point in the wellbore.
    [0032] To further illustrate this, reference is made to figures 1A and 1B, which show a cross section of a wellbore with various stresses shown around the wellbore. In figure 1A, fracture breaking pressure is minimal when the drilling tunnel is aligned in the direction of maximum stress or in a plane that is parallel to the direction of maximum stress (ie, maximum stress = 01 in figures 1A and 1B) . The angle (α) of the drill tunnel deviation from the maximum stress direction causes an increase in the fracture initiation pressure (FIP), as illustrated in Figure 1B.
    [0033] Figure 2 additionally shows the numerically estimated dependencies of the fracture initiation pressure in a vertical well on the angle between the drilling tunnel and the direction of maximum horizontal stress. The magnitude of the calculated increase in fracture initiation pressure caused by the drift of the drilling tunnel is in agreement with experimentally measured values. For purposes of computing fracture initiation pressure, the model described in Cherny et al., “2D Modeling of Hydraulic Fracture Initiation at a Wellbore With or Without Microannulus,” SPE 119352 (2009), which is incorporated herein by reference in full, was used. Three layers near the wellbore were modeled: steel casing, cement and rock. In the calculations, the assumed length of the drilling tunnel was 0.5 m. the annular microspace effect was not taken into account and leakage was neglected. Rock properties were as follows:1. Young Modulus = 20.7GPa. 2. Minimum horizontal voltage = 69Mpa.3. Maximum horizontal stress = 103.5Mpa, which corresponds to a stress anisotropy ratio equal to 1.5.4. Poisson ratio = 0.27. The geometry was as follows: 1. Inner radius of coating = 4.9 cm.5. External radius of coating = 5.6 cm.6. Wellbore radius = 7.8 cm.7. Young's modulus of coating = 200 GPa.8. Young's modulus of cement = 8.28 GPa.
    [0034] Similarly, in ideal horizontal wells (90 degrees) the fracture initiation pressure differences from differently aligned borehole channels are created by the difference between the overload stress and a combination of horizontal stresses (^horizontal min; (^ Such a combination of horizontal stresses depends on the orientation of the lateral section in the formation and turns towards the Horizontal min and the horizontal max when the horizontal section is drilled in the direction of the maximum and minimum horizontal stress, correspondingly. For horizontal wells, the vertical or overload voltage is the highest voltage (ie, overload voltage = d in figures 1A and 1B).
    [0035] Tools and techniques for measuring stress anisotropy are well known in the art. Approaches and practical cases have been discussed, for example, in Oilfield Review, October 1994, p. 37-47, “The promise of elastic anisotropy”. Sonic logging in combination with other logging can identify anisotropic rocks (eg deep shale). The physics used for this type of analysis is based on the phenomena that compression waves move faster in the direction of applied stress. There are two requirements for anisotropy - alignment in the preferred direction and the scale smaller than that of the measurement (here - the wavelength). Thus, sonic anisotropy (rock heterogeneity) can be measured using ultrasound (small scale), sonic (medium scale) and seismic (large scale) waves.
    [0036] In the simplest cases, two types of alignment (horizontal and vertical) can be considered, which produce two types of anisotropy. In the simplest horizontal case, elastic properties vary vertically, but not in layers. This type of rock is called transversely isotropic with the vertical axis of symmetry (transversal isotropic with the vertical axis of symmetry, TIV). The alternative case of the horizontal axis of symmetry is TIH. The two cases of anisotropy can be determined with the DSI Dipole Shear Sonic Imager™ tool, available from Schlumberger Technology Corp., Sugar Land, Texas. The DSI tool triggers sonic shear pulses alternately from two perpendicular transmitters to a set of similarly oriented receivers, and the pulse splits into polarization. At this measurement scale (approximately bore size) the most common evidence for anisotropy of TIV layer formation comes from different P-wave velocities measured in vertical and highly deviated (or horizontal) wells. The same technique is applied for S-wave processing (profiling features Slow shear and Fast shear curves). Field examples of using velocity (elastic) anisotropy information are presented in SPE 110098-MS (Calibrating the Mechanical Properties and In-Situ Stresses Using Acoustic Radical Profiles) and SPE 50993-PA (Predicting Natural or Induced Fracture Azimuths From Shear -Wave Anisotropy).
    [0037] In deviated wellbore holes the drilling guidance effect on fracture initiation pressure is more complex and depends on the anisotropy between all three main stresses. Fracture initiation pressure prediction in this situation is still based on calculation of the stress field around the wellbore in the drilled region, which also requires knowledge of the wellbore orientation in that zone. A comprehensive monograph for hydraulic fracturing initiation from deviated wellbore under arbitrary stress regimes is presented in Hossain et al., SPE 54360 (1999), which is incorporated herein by way of reference.
    [0038] US patent US 4,938,286 discloses a method for hydraulic fracturing simulating a formation penetrated by a horizontal wellbore. The horizontal well hole is drilled on its upper side. The formation is then fractured through the perforations with a fracturing fluid containing low-density proppant. The perforations are then sealed with perforation seals to redirect fluid to the next gap. US patent US 5,360,066 discloses a method for controlling the flow of sand and other solids from a wellbore comprising the steps of a. determine the direction of maximum horizontal stress; and b. drill the wellbore orienting the holes in the direction of maximum horizontal stress. US patent US 5,318,123 discloses a method for optimizing hydraulic fracturing of a well comprising steps of a. determine the fracture propagation direction; B. drill a wellbore in the direction of fracture propagation; ç. pump fracturing fluid to propagate fractures into the formation. The methods disclosed in the cited patents are substantially different from the proposed method of the present invention. To the author's knowledge, the use of guidance drills for sequential fracture treatment diversion between various wellbore zones has not been disclosed to date.
    [0039] Differences in cuff angles in the various zones are selected to provide differences in fracture initiation pressures in the different zones to provide individual and sequential treatment of each zone. The method of establishing the drill angle to provide the desired fracture initiation pressure of the zone to be treated can include mathematical modeling, as described in Cherny et al. (SPE 119352) and Hossain et al. (SPE 54360), discussed earlier. Empirically derived data can also be used to determine the drill angle used in a specific treatment. In such cases, correlations between fracture initiation pressure and perforation angle can be determined by laboratory testing. Examples of such empirically derived methods can be determined by laboratory testing. Examples of such empirically derived methods include those described in Behrmann et al., “Effect of perforations on fracture initiation,” Journal of Petroleum Technology, (May 1991) and Abass et al., “Oriented perforations - a rock mechanics view, SPE 28555 (1994), each of which is incorporated herein by reference in its entirety. In certain cases, specific knowledge of a specific formation gained from experience using formation-oriented drilling systems can provide sufficient information to correlate the head angles with the desired fracture initiation pressures for specific zones in the same or similar formation.
    [0040] After the principal stresses surrounding the wellbore are determined in the zone or zones to be treated, a cannon system can be configured to provide the proper through flow guidance or cannon inlet characteristics. This can be accomplished using guided cannoning techniques. Such technology allows the borehole casing to be cannoned at selected angles towards one of the main stresses. Various methods of orienting oriented drilling tools in wellbore are known. Directed cannon charges in a wellbore can be achieved by mechanical rotary systems, by applying a magnetic positioning device (MPD) or by using gravity-based methods. Appropriate cannoning tools may include pipe-borne cannons (Tubing Conveyed Perforating, TCP) that utilize guide spacers, guided blasting systems, mechanical tools for drilling or cutting casing walls, guided laser systems, etc. Non-limiting examples of guided drilling systems and methods include those described in US patents US 6,173,773 and 6,508,307 and US patent application publication US 2009/0166035 and US2004/0144539, each of which is incorporated. here by way of reference in full. An example of a commercially available oriented gun system is that available as the OrientXact™ gun system, from Schlumberger Technology Corporation, Sugar Land, Texas, which is a pipe-carried oriented gun system.
    [0041] In the present invention, the perforation system provides perforations or direct flow passages near the wellbore. Such a system can provide cannons that penetrate the formation approximately 3 meters, 2 meters, 1 meter or less. The barrels in each zone can use 0° or approximately 180° of load phasing. A cluster of cannons can be provided in each zone with substantially the same orientation and load phasing or the cannons can be oriented with a cannon angle less than ±5° to each other in the same group. The direct flow passage(s) or cannon(s) that is/are oriented at an angle closest to the direction or plane that is parallel to the selected direction of a maximum or main stress may be referred to as the "minimum angle" for that specific group or zone. There may be from 1 to 500 guns provided in each group, more particularly from about 10 to 20. The length of each group of guns may vary from about 0.1 to 200 meters, more particularly from about 0.5 to 5 meters. The distance between groups can range from approximately 5 to 500 meters, more particularly from approximately 10 to 150 meters. Of course, the spacing, number of cannons, etc., will depend on the individual characteristics of each well and the zones being treated.
    [0042] Differences in cannon or cannon angles will typically vary by at least ±5° or ±10° from zone to zone. The minimum angle of each zone may differ from the minimum angle of other zones by 5° or more. This difference in minimum angle can include the differences in minimum angles between a zone and the zone having the next higher fraction initiation pressure. Where the minimum angles of different zones differ by rotation from the minimum angle through a 360° rotation, this would still constitute a difference of 5° or more (ie minimum angle + 360°) even though both zones direct flow passages different ones could have essentially the same orientation. In certain cases the differences in angles from zone to zone may vary from ±15°, ±20°, ±25°, ±30° or more. The difference in headland angles from zone to zone, however, may depend on the type of formation and formation stresses surrounding the wellbore that provide the desired differences in fracture initiation pressure. Differences in fracture initiation pressure, however, will depend on formation characteristics so these pressures should not necessarily be interpreted as limiting the invention. In certain cases where angles of through-flow in each zone may vary within the zone, the angle(s) of through-flow in the zone of the next highest fracture initiation pressure or which is fractured next may( m) have an angle(s) of direct flow passage with respect to the direction or plane that is parallel to the direction of a maximum or main stress that is at least 5° less than at least one direct flow passage of the zone having the next lower fraction initiation pressure or that is previously fractured.
    [0043] Typically, the perforations are oriented so that the perforation zone with the lowest fracture initiation pressure is at a toe position or below the wellbore, with the remaining zones extending toward the heel position, so that the formation is treated finger to heel or from bottom to top of the wellbore. Of course, the pierced zones can be configured so that the lower fracture initiation pressure is located at the heel or top, with the fracturing treatment being carried out heel to toe or top to bottom of the well.
    [0044] To carry out the multizone fracturing treatment according to the invention, the lower hole pressure during treatment is controlled so that it is kept below the fracture initiation pressure of each subsequent zone to be treated. This can be achieved by fracture initiation pressures represented by formula (1) below: FIP1 < FIP2 < ... < FIPN-1 < FIPN (1)
    [0045] where N is the total number of zones being treated in the fracturing operation. In the case of the first zone to be treated, the fracture initiation pressure FIP1 is lower than the fracture initiation pressure in all other zones to be fractured in the frac operation. Introducing fracturing fluids at pressures or rates such that the pressure is at or above FIP1 but below the other fracture initiation pressures of the remaining zones (ie zones 2 to N) facilitates multistage fracturing treatment . Similarly, in the second zone to be treated, pressure is increased at or above the fracture initiation pressure FIP2 of the second zone to be fractured. The fracture initiation pressure for the second zone is less than the fracture initiation pressure for the remaining untreated zones (ie, zones 3 to N). fracturing initiation pressure is sequentially increased for each zone until all zones have been sequentially fractured. In certain cases, fractured areas can be isolated before increasing the fracture pressure to fracture the next area to be fractured. Various isolation techniques can be employed that are well known in the art. This can include the use of various power tools, sealing balls, bypass with particulate material, bridge plugs, direct flow bridge plugs, sand plugs, fibers, particulate material, bypass with viscous fluids and foams, etc., and combinations of these. In other cases, the isolation of the different zones is not used.
    [0046] In certain cases, the fracturing initiation pressure in some or all zones may be artificially decreased prior to fracturing the zones. Pumping acid or reactive chemicals to lower the fracture initiation pressure can be used, as described in SPE 118348 and SPE 114172. Such methods can be used effectively even for substantially inert formations. Acid (eg HCl) can be particularly useful in wells completed using acid soluble cement as described in SPE103232 and SPE114759.
    [0047] Figure 3 shows a horizontal section of a coated well drilled in the direction of maximum horizontal stress in a homogeneous formation with a constant fracture gradient. In the first step, some zones in the well are drilled using oriented drilling technology with approximately 180° of load phasing in each zone. The angle α between the perforation channels and the vertical or plane direction that includes the horizontal section of the wellbore varies from zone to zone, as shown. In this case, the vertical direction represents the greatest major stress or overload that surrounds the wellbore. In the horizontal well section of figure 3, the angle α1 at the well finger section is minimal so that the fracture initiation pressure in that zone is at the lowest level. Angle α is then gradually increased towards the heel. According to figures 1A and 1B, the fracture initiation pressure is thereby gradually increased along the wellbore to the different perforation zones.
    [0048] Further fracturing in the horizontal well section of figure 3 is performed in stages. The first stage is designed to stimulate the finger or farthest wellbore zone with minimal fracture initiation pressure. The pressure during this treatment is maintained at a level below the fracture initiation pressure in the next zone. After stimulation the first zone can be isolated, as with sealing balls while fluid is continuously introduced non-stop. This results in an increase in pressure in the wellbore and initiation of a fracture in the zone located close to the previously treated zone. Additional repetition of the steps described allows selective stimulation of all perforated intervals during a treatment cycle.
    [0049] Figures 4A-4C illustrate other examples of drilling guidelines for multi-stage fracturing treatments in wells with curved trajectories in horizontal or vertical planes. Multiple zones can be located in a long range located in a productive layer. Gap drilling can be performed in one stroke by the use of a gun, such as Guided Pipe Carried Gun (TCP) system that can consist of several load tubes on a carrier. Figure 4A shows a horizontal bypass well with a curved path. Figure 4B shows a deflected well with a curved vertical path. Figure 4C shows a well with a deviating trajectory. Multiple piercing groups can be formed in each of the gaps shown and each gap is fractured in turn. The perforations in each group can be oriented in 180° of phasing with the perforations in each group being at different angles 01...0N up to the maximum tension in place. In Figures 4A-4C, there are noticeable differences between vertical and horizontal stresses as shown.
    [0050] In each case of the modalities of figures 4A-4C, the orientation of the holes in the created geometry will result in the controlled variation of the fracture initiation pressure from zone to zone. In each case, the fracturing treatment consists of N treatment stages with a possible N-1 of isolation stages between the fracturing of each zone. In the first stage of treatment, a fracturing fluid is pumped into the wellbore and the zone with the minimum fracture initiation pressure is stimulated to fracture. The fracturing fluid pressure must be maintained below that of the next lowest fracturing initiation pressure for the remaining unfractured zones. Isolation can be performed to isolate the fractured zone using known isolation techniques such as sealing spheres, bridge plugs, sand plugs, particulate material, fibers, etc. after isolation, pumping is restarted or continued and the next zone with the next lowest fracture initiation pressure is fractured. This zone can then also be isolated. This process is repeated until all zones are subsequently fractured.
    [0051] Figure 5 shows an example of an alternative gunning strategy that can be used to create heterogeneity in fracture initiation pressure in wellbore zones. In this example, each zone has perforations of two types, namely primary: Ai (i = 1...4) and secondary: Bi. (j=0...M), having different orientations in relation to the maximum voltage. Here primary gutters A1, A2, A3 and A4 are offset from the direction of maximum stress at some angle (α) and gutters B1, B2, ... BN, ... BM are offset from the direction of maximum stress at a larger angle. In an embodiment of the present invention, each wellbore zone may have at least one Ai type cannon and one or more Bi type cannon. With such cannons, the orientation fracture initiating pressure in the cannon zone will depend on the angle α and will not depend on the orientation of secondary cannons (Bi). Changing the angle α on a set of cylinder heads in different wellbore zones will allow for different fracture initiation pressure in those zones.
    [0052] Fracture of the different zones can be conducted while being monitored. Various methods to confirm and identify those zones that are actually being treated in multistage treatment can be used. For example, bottom hole pressure data analysis can be used where the bottom hole pressure level is compared to the created fracture initiation pressure distribution in the drilled intervals. Analysis of the bottom hole pressure profile can also facilitate understanding of the created fracture geometry. Real-time microseismic diagnostics can be used where microseismic events generated during fracturing are recorded to provide understanding of the position and geometry of the fractured zone. This method is well known in the art and is widely used in the oil and gas industry. Real-time temperature profiling can also be used. Such methods use distributed temperature detection that indicates which portion of a wellbore is being treated. Such methods are well known to those skilled in the art and can use fiber optics to measure the temperature profile during treatment. Real-time radioactive profiling can be used. This method is based on placing a radioactive sensor in the wellbore before carrying out a treatment and detecting a signal from radioactive indicators added to the treatment fluid during the work. Analysis of low frequency pressure waves (pipe waves) generated and propagated in the wellbore can also be used. Pressure waves are reflected from fractures, wellbore obstacles, completion segments, etc. The decomposition rates and resonant frequencies of forced and free pressure oscillations are used to determine the characteristic impedance and depth of each reflection in the well, after removing resonances caused by known reflectors.
    [0053] Multistage fracturing can be used in different formation fracturing treatments. These include hydraulic fracturing using propellant agents, hydraulic fracturing without using propellant agents, slick-water fracturing and reactive fracturing fluids (eg chelating agents and acid). The fracturing fluids and systems used to perform fracturing treatments are typically aqueous fluids. Aqueous fluids used in the treatment fluid may be fresh water, sea water, salt solutions or brines (eg 1-2% by weight KCl), etc. Emulsion-based or oil-based fluids can also be used.
    [0054] In hydraulic fracturing, aqueous fluids are typically viscosified so that they have sufficient viscosities to load or suspend proppant materials, increase fracture width, prevent fluid leakage, etc. To provide the highest viscosity to aqueous fracturing fluids, hydratable or water-soluble polymers are often added to the fluid. Such polymers may include, but are not limited to, guar gums, high molecular weight polysaccharides composed of galactose and mannose sugars, or guar derivatives such as hydroxypropyl guar (HPG), carboxy methyl guar (CMG), and carboxy methyl hydroxy propyl guar (CMHPG). Cellulose derivatives such as hydroxy ethyl cellulose (HEC) or hydroxy propyl cellulose (HPC) and carboxy methyl hydroxy ethyl cellulose (CMHEC) can also be used. Any useful polymer can be used in cross-linked form, or without cross-linking in linear form. Xanthan, diutan, and seleroglucan, three biopolymers, have been shown to be useful as viscosifying agents. Synthetic polymers such as, but not limited to, polyacrylamide and polyacrylate polymers and copolymers are typically used for high temperature applications. Fluids incorporating the polymer can have any suitable viscosity sufficient to carry out the treatment. Typically, the polymer-containing fluid will have a viscosity value of approximately 50 mPa.s or greater at a shear rate of approximately 100 s-1 at treatment temperature, more typically approximately 75 mPa.s or greater at a shear rate of approximately 100 s-1, and even more typically of approximately 100 Mpa.s or greater at a shear rate of approximately 100 s-1.
    [0055] In some embodiments of the invention, the viscoelastic surfactant (the acronym in English for viscoelastic surfactant, VES) is used as the viscosifying agent for aqueous fluids. The VES can be selected from the group consisting of cationic, anionic, zwitterionic, amphoteric, non-ionic and combinations thereof. Some non-limiting examples are those cited in U.S. Patents 6,435,277 and 6,703,352, each of which is incorporated herein by reference. Viscoelastic surfactants, when used alone or in combination, are capable of forming micelles that form a structure in an aqueous environment that contributes to increased fluid viscosity (also referred to as “viscosifying micelles”). These fluids are normally prepared by mixing in appropriate amounts of appropriate VES to obtain the desired viscosity. The viscosity of VES fluids can be attributed to the three-dimensional structure formed by the components in the fluids. When the concentration of surfactants in a viscoelastic fluid significantly exceeds a critical concentration, and in most cases in the presence of an electrolyte, surfactant molecules aggregate into species as micelles, which can interact to form a network exhibiting elastic and viscous behavior. Fluids that incorporate VES-based viscosifiers can have any appropriate viscosity to carry out the treatment. Typically, the fluid containing VES will have a viscosity value of approximately 50 mPa.s or greater at a shear rate of approximately 100 s-1 at treatment temperature, more typically of approximately 75 mPa.s or greater at a shear rate of approximately 100 s-1, and even more typically of approximately 100 Mpa.s or greater at a shear rate of approximately 100 s-1.
    [0056] Fluids can also contain a gas component. The gas component can be supplied from any suitable gas that forms an energized fluid or foam when introduced into the aqueous medium. See, for example, U.S. Patent 3,937,283 (Blauer et al.), hereafter incorporated by reference. The gas component may comprise a gas selected from nitrogen, air, argon, carbon dioxide, and any mixtures thereof. Particularly useful are nitrogen gas or carbon dioxide components, in any readily available quality. The fluid may contain from approximately 10% to approximately 90% by volume of gas component based on total percentage of fluid volume, more particularly from approximately 20% to approximately 80% by volume of gas component based on total percentage of fluid volume, and more particularly from approximately 30% to approximately 70% gas component volume based on the total fluid volume percentage. It should be noted that the volume percentage presented here for such gases is based on downhole conditions where downhole pressures impact the gas phase volume.
    [0057] In a slick-water fracturing, which is typically used in formations containing “hermetic” or low permeable gas such as tight sand or shale formations, the fluid is a fluid of low viscosity (eg 1-50 mPa s), typically water, this can be combined with a friction reducing agent. Typically, polyacrylamides or guar gum are used as a friction reducing agent. In such treatments, significantly smaller and lighter weight amounts of proppant (eg, 0.012 kg/L to 0.5 kg/L, or 1.5 kg/L) than in conventional viscosified fracturing fluids can be used. The proppant used may have a smaller particle size (eg 0.05mm to 1.5mm, more typically 0.05mm to 1mm) than those used from conventional fracturing treatments used in oil-containing formations . Where used, the proppant can be of a size, quantity and density such that it is efficiently loaded, dispersed and positioned by the treatment fluid in the formed fractures.
    [0058] In hydraulic fracturing applications, an initial pad fluid that does not contain proppant may be initially introduced into the wellbore to initiate fractures in each zone. This is typically followed by a fluid containing proppant to facilitate support of the fractured area after it is fractured. The proppant particles used can be those which are substantially insoluble in the formation fluids. Propant particles carried by the treatment fluid remain in the created fracture, thereby holding the fracture open when the fracturing pressure is released and the well is put into production. Any proppant (gravel) can be used, provided that it is compatible with the base and any materials that promote bonding if the latter are used, the formation, fluid and the desired results of the treatment. Such propants (gravels) can be natural or synthetic, coated or contain chemicals; more than one can be used sequentially or in blends of different sizes or different materials. Propants and cuttings in the same or different wells or treatment may be the same material and/or the same size as each other and the term “propant” is intended to include cuttings in this discussion. Propant is selected based on rock strength, injection pressures, types of injection fluids, or even completion design. Propant materials may include, but are not limited to, sand, sintered bauxite, glass beads, mica, ceramic materials, naturally occurring materials, or similar materials. Propane mixtures can be used as well. Naturally occurring materials can be non-derived and/or unprocessed naturally occurring materials as well as materials based on naturally occurring materials that have been processed and/or derived. Suitable examples of naturally occurring particulate materials for use as propellants include, but are not necessarily limited to: ground shells or nut crushes such as walnut, coconut, pecan, almond, ivory, nut, etc.; ground or crushed seed husks (including fruit pits) of fruit seeds such as plums, olives, peaches, cherries, apricots, etc.; ground or crushed seed husks of other plants such as corn (eg corn cobs or corn kernels), etc.; processed wood materials such as those derived from woods such as oak, North American walnut, walnut, poplar, mahogany, etc. including such woods that have been processed by grinding, chipping, or other form of size degradation, processing, etc. additional information on some of the aforementioned compositions of these can be found in the Encyclopedia of Chemical Technology, edited by Raymond E. Kirk and Donald F. Othmer, third edition, John Wiley & Sons, volume 16, pages 248-273 (entitled “Nuts ”), copyright 1981, which is incorporated herein by reference. In general the proppant used will have an average particle size of approximately 0.05 mm to approximately 5 mm, more particularly, but not limited to typical size ranges of approximately 0.25 - 0.43 mm, 0.43 - 0. 85mm, 0.85 - 1.18mm, 1.18 - 1.70mm, and 1.70 - 2.36mm. Typically the proppant will be present in the carrier fluid at a concentration of approximately 0.12 kg of proppant added in each liter of carrier fluid up to approximately 3 kg of proppant added in each L of carrier fluid, preferably approximately 0.12 kg of proppant added to each liter of carrier fluid up to approximately 1.5 kg of proppant added to each liter of carrier fluid.
    [0059] Other particulate materials can also be used, such as for binding materials, proppant carriers or leak control agents. These can include degradable materials that are intended to degrade after fracture treatment. Degradable particulate materials can include those materials that can be softened, dissolved, reacted or otherwise degraded in well fluids to facilitate their removal. Such materials can be soluble in aqueous fluids or in hydrocarbon fluids. Oil-degradable particulate materials can be used that degrade in the fluids produced. Non-limiting examples of degradable materials may include, without limitation, polyvinyl alcohol, polyethylene terephthalate (PET), polyethylene, dissolvable salts, polysaccharides, waxes, benzoic acid, naphthalene-based materials, magnesium oxide, sodium bicarbonate, sodium carbonate. calcium, sodium chloride, calcium chloride, ammonium sulfate, soluble resins, and the like, and combinations thereof. Particulate material that degrades when mixed with a separate agent that is introduced into the well so that it mixes with and degrades the particulate material can also be used. Degradable particulate materials can also include those that are formed from solid acid precursor materials. Such materials can include polylactic acid (PLA), polyglycolic acid (PGA), carboxylic acid, lactide, glycolide, PLA or PGA copolymers, and the like, and combinations thereof.
    [0060] In many applications, fibers are used as the particulate material, either individually or in combination with other non-fiber particulate materials. Fibers can be degradable as well and be formed from similar degradable materials as those described above. Examples of fiber materials include, but are not necessarily limited to, natural organic fibers, crushed plant materials, synthetic polymer fibers (e.g. non-limiting polyester, polyaramid, polyamide, novoloid or a novoloid type polymer), organic fibers fibrillates, ceramic fibers, inorganic fibers, metal fibers, metal filaments, carbon fibers, glass fibers, ceramic fibers, natural polymer fibers, and any mixtures thereof. Particularly useful fibers are polyester fibers coated as being highly hydrophilic, such as, but not limited to, DACRON® polyethylene terephthalate (PET) fibers from Invista Corp., Wichita, Kans., USA, 67220. Other examples of useful fibers include, but they are not limited to polylactic acid polyester fibers, polyglycolic acid polyester fibers, polyvinyl alcohol fibers and the like.
    [0061] The described thickened or viscosified fluids, with or without a gas component, can also be used in acid fracturing applications, too, in which multiple zones are treated in accordance with the invention. As used herein, acid fracturing can include those fracturing techniques where the treatment fluid contains a forming dissolution material. In such treatments, alternative reactive fluids (aqueous acids, chelators, etc.) with non-reactive fluids (VES fluids, polymer-based fluids) can be used during acid fracturing operations. In carbonate formations, the acid is typically hydrochloric acid, although other acids can be used. In such treatments, fluids are injected at a pressure above the fracture initiation pressure of the specific zone of a carbonate formation (eg limestone and dolomite) being treated. In acid fracturing a proppant cannot be used because the acid differentially cauterizes the fractured formation to create flow paths for forming fluids to flow into the wellbore so that fracture support is not required.
    [0062] Although the invention has only been shown in some of its forms, it should be evident to those skilled in the art that it is not thereby limited, but is susceptible to various changes and modifications without departing from the scope of the invention. Therefore, it is appropriate that the appended claims be interpreted broadly and in a manner compatible with the scope of the invention.
    权利要求:
    Claims (52)
    [0001]
    1. METHOD FOR FRACTURING MULTIPLE ZONES WITHIN A WELL HOLE FORMED IN AN UNDERGROUND FORMATION, the method characterized by comprising: (a) forming direct flow passages in two or more zones within the wellbore that are spaced apart along each other of the length of a portion of the wellbore, the direct flow in each of the two or more passages oriented with respect to a selected direction to provide different fracture initiation pressures within each of the two or more zones;(b) introduce a fracturing fluid in the wellbore in a frac treatment; (c) providing a frac fluid pressure in the frac treatment that is above the fracture initiation pressure of one of the two or more zones to facilitate fracturing of said one of the two or more zones, the fracturing fluid pressure being below the fracture initiation pressure of any other unfractured zones of the two or more zones; and then (d) repeat (c) for at least one or more unfractured zones of the two or more zones.
    [0002]
    2. Method according to claim 1, characterized in that the selected direction is a direction of a main stress of the formation surrounding the wellbore.
    [0003]
    3. Method according to claim 1, characterized in that the selected direction is aligned with or in a plane parallel to a direction of a main stress of the formation surrounding the wellbore.
    [0004]
    4. Method according to claim 1, characterized in that a reactive fluid is injected into at least one zone before the fracture initiation occurs in that zone to facilitate reducing the fracture initiation pressure.
    [0005]
    5. Method according to claim 1, characterized in that the direct flow passages are formed by at least one of a cannon, by blasting and by drilling holes in a wellbore casing.
    [0006]
    The method of claim 1, further comprising isolating at least one previously fractured zone formed in (c) before (d).
    [0007]
    7. Method according to claim 9, characterized in that a degradable material is used to isolate the fractured zone.
    [0008]
    8. Method according to claim 9, characterized in that the insulation is achieved by the use of at least one of mechanical tools, sealing balls, packers, bridge plugs, direct flow bridge plugs, sand plugs , fibers, particulate material, viscous fluid, foams and combinations thereof.
    [0009]
    9. Method according to claim 1, characterized in that the direct flow passages within each zone have a minimum angle that is different by 5° or more from the minimum angle of flow passages of any other of the two or more zones.
    [0010]
    10. Method according to claim 1, characterized in that the fractured zone according to step (c) is located towards a finger position of the wellbore and the fractured zone according to step ( d) is located towards a wellbore heel position.
    [0011]
    11. Method according to claim 1, characterized in that the fractured zone according to step (a) is located towards a wellbore heel position and the fractured zone according to step ( c) is located towards a wellbore finger position.
    [0012]
    12. Method according to claim 1, characterized in that the fracturing fluid is selected from at least one of a hydraulic fracturing fluid, a reactive fracturing fluid and a slick-water fracturing fluid.
    [0013]
    13. Method according to claim 1, characterized in that the fracturing fluid contains at least one of proppant, fine particles, fibers, fluid loss additives, gelling agents and friction reducing agents.
    [0014]
    14. Method according to claim 1, characterized in that the selected direction is at least one of a maximum horizontal stress, a vertical stress and a fracture plane.
    [0015]
    15. Method according to claim 1, characterized in that the fracturing is performed while being monitored.
    [0016]
    16. METHOD FOR FRACTURING MULTIPLE ZONES WITHIN A WELL HOLE FORMED IN AN UNDERGROUND FORMATION, the method characterized by comprising: (a) forming direct flow passages in two or more zones within the wellbore that are spaced apart along each other of the length of a portion of the wellbore, the direct flow passages within each zone having different characteristics provided by orienting the direct flow passages in different directions in each of the zones relative to the main stress of the formation surrounding the wellbore, the direct flow passages within each zone having a minimum angle with respect to the selected direction that is different by 5° or more than the minimum angle of the flow passages with respect to the selected direction of any other of the two or more zones; (b) introducing a fracturing fluid into the wellbore in a frac treatment; (c) provide a fracturing fluid pressure in the fracturing treatment that is above the fracture initiation pressure of one of the two or more zones to facilitate fracturing of said one of the two or more zones, the fracturing fluid pressure being below the fracture initiation pressure of any other unfractured zones of the two or more zones; and then (d) repeating step (c) for at least one or more unfractured zones of the two or more zones.
    [0017]
    17. Method according to claim 16, characterized in that a reactive fluid is injected into at least one zone before the fracture initiation occurs in that zone to facilitate reducing the fracture initiation pressure.
    [0018]
    18. Method according to claim 17, characterized by the fact that the reactive fluid is an acid.
    [0019]
    19. Method according to claim 16, characterized in that the wellbore is cemented using a cement that is substantially soluble in acid.
    [0020]
    20. The method of claim 16, characterized in that direct flow passages are formed in each zone using 0° or 180° phasing in each zone.
    [0021]
    21. Method according to claim 16, characterized in that the direct flow passages are formed by at least one of cannon, by blasting and by drilling holes in a wellbore casing.
    [0022]
    The method of claim 16, further comprising isolating at least one previously fractured zone formed in (c) before proceeding to (d).
    [0023]
    23. Method according to claim 22, characterized in that a degradable material is used to isolate the fractured zone.
    [0024]
    24. Method according to claim 22, characterized in that the insulation is achieved by the use of at least one of mechanical tools, sealing balls, packers, bridge plugs, direct flow bridge plugs, sand plugs , fibers, particulate material, viscous fluid, foams and combinations thereof.
    [0025]
    25. Method according to claim 16, characterized in that the two or more zones are located in a portion of the wellbore that is substantially vertical.
    [0026]
    26. Method according to claim 16, characterized in that the two or more zones are located in a portion of the wellbore that is curved.
    [0027]
    27. METHOD FOR FRACTURING MULTIPLE ZONES WITHIN A WELL HOLE FORMED IN AN UNDERGROUND FORMATION, the method characterized by comprising: (a) forming direct flow passages in two or more zones within the wellbore that are spaced apart along each other of the length of a portion of the wellbore, the direct flow passages within each zone having different characteristics provided by directing the direct flow passages in different directions in each of the zones with respect to a selected direction, the direct flow passages within of each zone having a minimum angle with respect to the selected direction that is greater than 5° or more of the minimum angle of the flow passages with respect to the selected direction of any other of the two or more zones; (b) introducing a fracturing fluid into the wellbore in a frac treatment; (c) provide a frac fluid pressure in the frac treatment that is above the fracture initiation pressure of one of the two or more zones to facilitate fracturing of said one of the two or more zones, the fracturing fluid pressure being below the fracture initiation pressure of any other unfractured zones of the two or more zones; (d) repeat step (c) ) for one or more unfractured zones of the two or more zones; and (e) isolating at least one fractured zone according to (c) before (d).
    [0028]
    28. Method according to claim 27, characterized in that the selected direction is a direction of a main stress of the formation surrounding the wellbore.
    [0029]
    29. Method according to claim 27, characterized in that the selected direction is aligned with or in a plane parallel to a direction of a main stress of the formation surrounding the wellbore.
    [0030]
    30. Method according to claim 27, characterized in that a reactive fluid is injected into at least one zone before the beginning of the fracture occurs in that zone to facilitate reducing the fracture initiation pressure.
    [0031]
    31. Method according to claim 30, characterized in that the reactive fluid is an acid.
    [0032]
    32. Method according to claim 27, characterized in that the wellbore is cemented using a cement that is substantially soluble in acid.
    [0033]
    33. The method of claim 27, characterized in that direct flow passages are formed in each zone using 0° or 180° phasing in each zone.
    [0034]
    34. Method according to claim 27, characterized in that the direct flow passages are formed by at least one cannon, by blasting and by drilling holes in a wellbore casing.
    [0035]
    35. Method according to claim 27, characterized in that a degradable material is used to isolate at least one fractured zone according to (c).
    [0036]
    36. Method according to claim 27, characterized in that the insulation is achieved by the use of at least one of mechanical tools, sealing balls, packers, bridge plugs, direct flow bridge plugs, sand plugs , fibers, particulate material, viscous fluid, foams and combinations thereof.
    [0037]
    37. Method according to claim 27, characterized in that the two or more zones are located in a portion of the wellbore that is substantially vertical.
    [0038]
    38. Method according to claim 27, characterized in that the two or more zones are located in a portion of the wellbore that is curved.
    [0039]
    39. Method according to claim 27, characterized in that the two or more zones are located in a portion of the wellbore that is inclined by at least 30° from the vertical.
    [0040]
    40. Method according to claim 27, characterized in that the two or more zones are located in a portion of the wellbore that is substantially horizontal.
    [0041]
    41. Method according to claim 27, characterized in that the direct flow passages within the fracture zone of (c) are oriented at an angle relative to the selected direction that is less than the angle of the flow passages direct from any other of the unfractured zones of the two or more zones.
    [0042]
    42. Method according to claim 27, characterized in that a direct flow passage from the unfractured zone of the two or more subsequently fractured zones according to (d) is oriented at an angle relative to the selected direction which is at least 5° less than a direct flow passage from one of the two or more previously fractured zones in (c).
    [0043]
    43. Method according to claim 27, characterized in that at least one of the direct flow passages within the fractured zone in (c) is oriented at an angle relative to the selected direction that is less than the angle of any direct flow passes with respect to the selected direction in any other unfractured zones of the two or more fractured zones in (d).
    [0044]
    44. Method according to claim 27, characterized in that the fractured zone according to (c) is located towards a wellbore finger position and the fractured zone according to (d) is located toward a wellbore heel position.
    [0045]
    45. Method according to claim 27, characterized in that the fractured zone according to (c) is located towards a wellbore heel position and the fractured zone according to (d) is located toward a wellbore finger position.
    [0046]
    46. Method according to claim 27, characterized in that the fracturing fluid is selected from at least one of a hydraulic fracturing fluid, a reactive fracturing fluid and a slick-water fracturing fluid.
    [0047]
    47. Method according to claim 27, characterized in that the fracturing fluid contains at least one of proppant, fine particles, fibers, fluid loss additives, gelling agents and friction reducing agents.
    [0048]
    48. Method according to claim 27, characterized in that the selected direction is a maximum main stress direction of the formation surrounding the portion of the wellbore.
    [0049]
    49. Method according to claim 27, characterized in that the different characteristics of the direct flow passages are provided by slope of the wellbore.
    [0050]
    50. Method according to claim 27, characterized in that each zone has from 1 to 10 groupings of direct flow passages.
    [0051]
    51. Method according to claim 50, characterized in that each grouping of direct flow passage has a length of 0.1 to 200 meters.
    [0052]
    52. Method according to claim 27, characterized in that the fracturing is performed while being monitored.
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    同族专利:
    公开号 | 公开日
    MX2014001301A|2014-08-01|
    CN103857877B|2016-06-29|
    BR112014002812A2|2017-03-01|
    AR087457A1|2014-03-26|
    WO2013022627A3|2013-04-25|
    CN103857877A|2014-06-11|
    MX337567B|2016-03-10|
    CA2844110C|2019-10-01|
    RU2014108321A|2015-09-20|
    US20130032350A1|2013-02-07|
    WO2013022627A2|2013-02-14|
    CA2844110A1|2013-02-14|
    US9121272B2|2015-09-01|
    RU2566348C2|2015-10-27|
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    法律状态:
    2018-12-11| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2019-11-05| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2020-12-15| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-03-16| B09Y| Publication of grant cancelled|Free format text: ANULADA A PUBLICACAO CODIGO 9.1 NA RPI NO 2606 DE 15/12/2020 POR TER SIDO INDEVIDA. |
    2021-04-06| B06A| Notification to applicant to reply to the report for non-patentability or inadequacy of the application [chapter 6.1 patent gazette]|
    2021-07-20| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-08-03| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 28/07/2012, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
    申请号 | 申请日 | 专利标题
    US13/204,392|2011-08-05|
    US13/204,392|US9121272B2|2011-08-05|2011-08-05|Method of fracturing multiple zones within a well|
    PCT/US2012/048744|WO2013022627A2|2011-08-05|2012-07-28|Method of fracturing multiple zones within a well|
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