CA2863764A1 - Phased stimulation methods - Google Patents
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- CA2863764A1 CA2863764A1 CA 2863764 CA2863764A CA2863764A1 CA 2863764 A1 CA2863764 A1 CA 2863764A1 CA 2863764 CA2863764 CA 2863764 CA 2863764 A CA2863764 A CA 2863764A CA 2863764 A1 CA2863764 A1 CA 2863764A1
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- 238000000034 method Methods 0.000 title claims abstract description 61
- 230000000638 stimulation Effects 0.000 title claims description 11
- 238000004519 manufacturing process Methods 0.000 claims abstract description 67
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 51
- 239000012530 fluid Substances 0.000 claims abstract description 27
- 230000004936 stimulating effect Effects 0.000 claims abstract description 11
- 238000002955 isolation Methods 0.000 claims description 19
- 238000005755 formation reaction Methods 0.000 description 41
- 229930195733 hydrocarbon Natural products 0.000 description 13
- 150000002430 hydrocarbons Chemical class 0.000 description 13
- 239000004215 Carbon black (E152) Substances 0.000 description 4
- 230000008569 process Effects 0.000 description 4
- 238000005553 drilling Methods 0.000 description 3
- 230000035699 permeability Effects 0.000 description 3
- 230000009467 reduction Effects 0.000 description 3
- 238000013459 approach Methods 0.000 description 2
- 230000008901 benefit Effects 0.000 description 2
- 238000004891 communication Methods 0.000 description 2
- 230000007423 decrease Effects 0.000 description 2
- 239000011159 matrix material Substances 0.000 description 2
- 238000005259 measurement Methods 0.000 description 2
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 2
- 239000011148 porous material Substances 0.000 description 2
- 239000011435 rock Substances 0.000 description 2
- 239000002253 acid Substances 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 239000007789 gas Substances 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 239000003345 natural gas Substances 0.000 description 1
- 239000011368 organic material Substances 0.000 description 1
- 230000037361 pathway Effects 0.000 description 1
- 230000000246 remedial effect Effects 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 238000011282 treatment Methods 0.000 description 1
Classifications
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- 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
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Drilling And Exploitation, And Mining Machines And Methods (AREA)
- Earth Drilling (AREA)
Abstract
A method of stimulating a subterranean formation is provided. The method includes determining a final fracture spacing. The method includes creating a first set of fractures at a first fracture spacing, the first fracture spacing being larger than the final fracture spacing. The method includes allowing production of fluids from the formation through the well bore via the first set of fractures for a period of time. The method includes, after the period of time, creating a second set of fractures. The final fracture spacing is less than or equal to an average fracture spacing between the first set of fractures and the second set of fractures.
Description
PHASED STIMULATION METHODS
FIELD OF THE INVENTION
The present disclosure relates generally to stimulation of subterranean formations and more particularly to a method of phased stimulation.
BACKGROUND
Hydrocarbon (e.g., oil, natural gas, etc.) reservoirs may be found in subterranean formations that have little to no porosity (e.g., shale, tight sandstone etc.). The hydrocarbons may be trapped within fractures and pore spaces of the formation.
Additionally, the hydrocarbons may be adsorbed onto organic material of the shale formation. The rapid development of extracting hydrocarbons from these unconventional reservoirs can be tied to the combination of horizontal drilling and hydraulic fracturing.
Horizontal drilling has allowed for drilling along and within hydrocarbon reservoirs to better capture the hydrocarbons trapped therein. Additionally, more hydrocarbons may be captured by increasing the number of fractures in the formation and/or increasing the size of already present fractures through fracturing or other stimulation.
The spacing between fractures as well as the ability to stimulate the fractures naturally present in the rock may be major factors in the success of horizontal completions in unconventional hydrocarbon reservoirs. Effective placement of fractures in deviated or horizontal wells is challenging. This challenge is highlighted in formations with low permeability. As permeability decreases, smaller spacing is generally necessary to effectively recover hydrocarbons from the formation. However, as the spacing between fractures decreases, the stresses associated with the injection of fluids into the formation to create one fracture is believed to create a "shadow" stress in the formation that negatively influences the placement of the next fracture.
SUMMARY OF THE INVENTION
In one embodiment, a method of stimulating a subterranean formation is provided. The method includes determining a final fracture spacing. The method includes creating a first set of fractures at a first fracture spacing, the first fracture spacing being larger than the final fracture spacing. The method includes allowing production of fluids from the formation through the well bore via the first set of fractures for a period of time.
The method includes, after the period of time, creating a second set of fractures. The final fracture spacing is less than or equal to an average fracture spacing between the first set of fractures and the second set of fractures.
In an embodiment, a method of phased stimulation of a zone in a subterranean formation is provided. The method includes stimulating the zone via a first set of fractures originating at a well bore and having a first fracture spacing. The method includes allowing primary production from the zone via the first set of fractures. The method includes providing isolation between the first set of fractures and the well bore before the primary production reaches a predetermined threshold. The method includes further stimulating the zone via a second set of fractures originating at the wellbore, wherein at least one of the fractures of the second set of fractures lies between adjacent fractures in the first set of fractures. The method includes allowing production from the zone via the second set of fractures. The method includes removing the isolation between the first set of fractures and the well bore thereby allowing secondary production from the zone via the first set of fractures.
BRIEF DESCRIPTION OF THE FIGURES
FIG. 1 is a top view on half length of a hydraulic fracture example illustrating the influence of the stresses from one fracture on the next fracture in accordance with conventional fracture placement.
FIG. 2 is side view of a formation containing a well prior to placement of fractures in accordance with a certain embodiment of the present disclosure.
FIG. 3 is a side view of the formation of FIG. 2 after a first set of fractures has been placed in accordance with a certain embodiment of the present disclosure.
FIG. 4 is a side view of the formation of FIGs. 2 and 3 after a second set of fractures has been placed in accordance with a certain embodiment of the present disclosure.
FIG. 5 is a side view of the formation of FIGs. 2-4 after a third set of fractures has been placed in accordance with a certain embodiment of the present disclosure.
FIG. 6 is a side view of the formation of FIGs. 2-5 after isolation has been removed and the first, second, and third sets of fractures are producing fluid.
FIELD OF THE INVENTION
The present disclosure relates generally to stimulation of subterranean formations and more particularly to a method of phased stimulation.
BACKGROUND
Hydrocarbon (e.g., oil, natural gas, etc.) reservoirs may be found in subterranean formations that have little to no porosity (e.g., shale, tight sandstone etc.). The hydrocarbons may be trapped within fractures and pore spaces of the formation.
Additionally, the hydrocarbons may be adsorbed onto organic material of the shale formation. The rapid development of extracting hydrocarbons from these unconventional reservoirs can be tied to the combination of horizontal drilling and hydraulic fracturing.
Horizontal drilling has allowed for drilling along and within hydrocarbon reservoirs to better capture the hydrocarbons trapped therein. Additionally, more hydrocarbons may be captured by increasing the number of fractures in the formation and/or increasing the size of already present fractures through fracturing or other stimulation.
The spacing between fractures as well as the ability to stimulate the fractures naturally present in the rock may be major factors in the success of horizontal completions in unconventional hydrocarbon reservoirs. Effective placement of fractures in deviated or horizontal wells is challenging. This challenge is highlighted in formations with low permeability. As permeability decreases, smaller spacing is generally necessary to effectively recover hydrocarbons from the formation. However, as the spacing between fractures decreases, the stresses associated with the injection of fluids into the formation to create one fracture is believed to create a "shadow" stress in the formation that negatively influences the placement of the next fracture.
SUMMARY OF THE INVENTION
In one embodiment, a method of stimulating a subterranean formation is provided. The method includes determining a final fracture spacing. The method includes creating a first set of fractures at a first fracture spacing, the first fracture spacing being larger than the final fracture spacing. The method includes allowing production of fluids from the formation through the well bore via the first set of fractures for a period of time.
The method includes, after the period of time, creating a second set of fractures. The final fracture spacing is less than or equal to an average fracture spacing between the first set of fractures and the second set of fractures.
In an embodiment, a method of phased stimulation of a zone in a subterranean formation is provided. The method includes stimulating the zone via a first set of fractures originating at a well bore and having a first fracture spacing. The method includes allowing primary production from the zone via the first set of fractures. The method includes providing isolation between the first set of fractures and the well bore before the primary production reaches a predetermined threshold. The method includes further stimulating the zone via a second set of fractures originating at the wellbore, wherein at least one of the fractures of the second set of fractures lies between adjacent fractures in the first set of fractures. The method includes allowing production from the zone via the second set of fractures. The method includes removing the isolation between the first set of fractures and the well bore thereby allowing secondary production from the zone via the first set of fractures.
BRIEF DESCRIPTION OF THE FIGURES
FIG. 1 is a top view on half length of a hydraulic fracture example illustrating the influence of the stresses from one fracture on the next fracture in accordance with conventional fracture placement.
FIG. 2 is side view of a formation containing a well prior to placement of fractures in accordance with a certain embodiment of the present disclosure.
FIG. 3 is a side view of the formation of FIG. 2 after a first set of fractures has been placed in accordance with a certain embodiment of the present disclosure.
FIG. 4 is a side view of the formation of FIGs. 2 and 3 after a second set of fractures has been placed in accordance with a certain embodiment of the present disclosure.
FIG. 5 is a side view of the formation of FIGs. 2-4 after a third set of fractures has been placed in accordance with a certain embodiment of the present disclosure.
FIG. 6 is a side view of the formation of FIGs. 2-5 after isolation has been removed and the first, second, and third sets of fractures are producing fluid.
DETAILED DESCRIPTION
Referring now to the figures, Figure 1 shows how the influence of the stress from the first (rightmost) fracture is believed to inhibit the formation of the second (second to right) fracture. Depending on the size and placement of the second fracture, the third fracture (third from right) may be influenced by either or both of the first and second fracture stresses. Likewise, fractures may be negatively influenced throughout a zone, even moving beyond a particular stage (e.g., the four leftmost fractures might influence the next stage of four fractures and those fractures might influence the next stage of four fractures).
Thus, the traditional approach has been to either provide larger fracture spacing than otherwise would be desirable, in order to prevent interference from other fractures or provide the desired spacing and accept the effects of the interference. One alternative to these approaches is described in U.S. 2012/0325462, where fractures are initiated in an alternate order than the aforementioned right to left. While U.S. 2012/0325462 claims to provide improvements by negating the directional impact of the stresses, it is believed that the magnitude of the stresses are still problematic and, unlike the present disclosure, U.S.
2012/0325462 does not consider production of formation fluid as a way to alleviate the stresses. Further, the fracture spacings of U.S. 2012/0325462 are in the range of 150 ft to 250 ft and it is believed that the present disclosure would allow for spacings well below 100 ft. Finally, U.S. 2012/0325462 proposes complex fractures which are unnecessary in accordance with the embodiments described below. Specifically, in U.S.
2012/0325462, spacings between fractures must be sufficiently large to provide a stress-free zone in which a complex fracture can be formed. The embodiments described below, on the other hand, do not require such large spacing or complex fractures.
One method of stimulating a subterranean formation 10 having a well bore 12 therein includes (1) determining a threshold stress value indicative of presence of a stress shadow (e.g., by field or other estimations based on formation characteristics), (2) obtaining a formation stress value (e.g., by measurements taken onsite, by field estimations, by calculations, or otherwise), (3) allowing production from the subterranean formation 10 when the stress shadow is present (i.e., when the measured stress value exceeds the threshold stress value), and (4) ceasing production when the stress shadow has dissipated (i.e, when the measured stress value drops below the threshold stress value).
Figures 2-6 illustrate one method of stimulating the subterranean formation 10 having the well bore 12 therein. The well bore 12 provides a pathway for fluids (e.g., hydrocarbons) from a zone 14 to move to the surface 16. Fractures 21-29, originating at the exterior surface of the well bore 12 provide fluid communication between the zone 14 and the well bore 12, allowing the fluids from the zone 14 to exit the subterranean formation 10, move into the well bore 12 and up to the surface 16. As illustrated, the methods describe a horizontal or deviated well bore 12. However, the methods could similarly be used in a vertical well bore.
The first step of the method of Figures 2-6 involves determining a final fracture spacing 18. In Figure 2, the final fracture spacing 18 represents the desired spacing between two adjacent fractures (not yet present in the illustration of Figure 2) after all fractures have been placed (see Figure 6). The desired spacing may be calculated or otherwise determined on the basis of the minimum economic production rate, taking into account formation porosity, hydrocarbon saturation, permeability, and costs associated with completion and production. The final spacing 18 may be an economically optimized fracture spacing and the step of determining the final spacing 18 might involve determining the economically optimized fracture spacing. Such determination might involve calculations of net present value, and accounting for various factors including but not limited to current oil and gas prices, operational costs, and capabilities of the facilities. In some instances, the final fracture spacing 18 might vary along the length of the well bore 12 or even within the zone 14 of interest. However, in the interest of simplicity, the final fracture spacing 18 is illustrated as having a uniform dimension. In some embodiments, the final fracture spacing 18 may be less than 500 ft., less than 300 ft., less than 200 ft., less than 180 ft., less than 170 ft., less than 160 ft., less than 150 ft., less than 140 ft., less than 130 ft., less than 120 ft., less than 110 ft., less than 100 ft., less than 90 ft., less than 80 ft., less than 70 ft., less than 60 ft., less than 50 ft., less than 40 ft., less than 30 ft., or even less than 20 ft.
Referring now to Figure 3, a first set of fractures 21, 22, 23 are created at a first fracture spacing 30. The first fracture spacing 30 is larger than the final fracture spacing 18.
In this illustration, the first fracture spacing 30 is approximately four times the final fracture spacing 18. In embodiments with two sets of fractures, the first fracture spacing 30 may be about twice the final fracture spacing 18. In embodiments with more than three sets of fractures, the first fracture spacing 30 may be more than four times the final fracture spacing 18. After the first set of fractures 21, 22, 23 are created, hydrocarbons or other fluid 32 from the formation 10 are produced through the well bore 12 via the first set of fractures 21, 22, 23 for a period of time. The period of time might be determined based on providing sufficient time to permit the relief of stress created by the first set of fractures 21, 22, 23.
The production of fluids 32 is believed to relieve the pore pressure thus relieving the stress in the rock over time. By allowing fluid 32 to leave the formation 10, it is thought that the stresses caused by fracturing may be alleviated in the region around such fractures. Such reduction in stresses may allow for a superior fracture to be created between existing fractures, as compared to fractures created without allowing for such stress relief Thus, production of fluids 32 may be permitted until a predetermined threshold is reached. In one example, the predetermined threshold may be a time of production from the formation 10. While allowing for a large time to pass might provide for more stress relief, it is thought that the period of time for production between formation of the first set of fractures 21, 22, 23 and formation of the second set of fractures 24, 25 may be relatively short. Such period of time might be less than a year, from 6 months to a year, from 1 to 6 months, from 1 week to 1 month, or from 1 hour to 1 week. In some instances, the period of time might be as small as a few days or even within a few hours.
An alternate predetermined threshold may be a percentage of a maximum projected production from the formation 10. While allowing for a large percentage of the maximum projected production might provide for more stress relief, it is thought that the production between formation of the first set of fractures 21, 22, 23 and formation of the second set of fractures 24, 25 may be relatively small. Such production might be less than 50% of the maximum projected production, less than 25% of the maximum projected production, less than 5% of the maximum projected production, or less than 1% of the maximum projected production. In some instances, the production may be as small as a tenths of a percent or even a few hundredths of a percent. Other alternatives to time and production volumes may be used in the embodiments described, so long as some method of feedback on whether sufficient relief of the stress caused by a particular set of fractures has occurred via production.
Once the stress created by the first set of fractures 21, 22, 23 has been relieved, the production of fluid 32 from the formation 10 via the first set of fractures 21, 22, 23 may be stopped by plugging the fractures 21, 22, 23, or otherwise providing isolation between the first set of fractures 21, 22, 23 and the well bore 12. Such isolation may be provided through any of a number of methods. For example, as illustrated in Figure 4, tubing 38 may be run in the casing 40 lining the well bore 12. The tubing 38 may have external packers 42 used for isolation. Alternative means of isolation include external casing packers, production liners, expandables, coiled tubing via sleeve that opens and closes via ball drop, hydraulics, or otherwise, chemical isolation, or any number of other methods of isolating fractures.
Referring now to Figure 4, once the stress created by the first set of fractures 21, 22, 23 has been released via production of fluid 32, a second set of fractures 24, 25 is created. It is believed that the reduction in fluid 32 in the formation 10 will allow placement of the second set of fractures 24, 25 between (e.g., in the middle of) the first set of fractures 21, 22, 23 without significant resistance. An average fracture spacing 34 between the first set of fractures 21, 22, 23 and the second set of fractures 24, 25 is equal to or greater than the final fracture spacing 18. Stated otherwise, the final fracture spacing 18 is less than or equal to the average fracture spacing 34 between adjacent fractures in the set of fractures including the first set of fractures 21, 22, 23 and the second set of fractures 24, 25.
As illustrated in Figure 4, the average fracture spacing 34 is about twice the final fracture spacing 18. However, in some embodiments, two sets of fractures may be sufficient. In those embodiments, the average fracture spacing 34 may be equal to the final fracture spacing 18. Thus, the first fracture spacing 30 might be double the final fracture spacing 18 when two sets of fractures or sufficient, and the first fracture spacing 30 will be more than double the final fracture spacing 18 in embodiments where more than two sets of fractures are utilized. If two sets of fractures are sufficient, isolation of the first set of fractures 21, 22, 23 may be removed and production of formation fluid 32 may proceed through both the first and second sets of fractures 21, 22, 23, 24, 25. If further fractures are desired, isolation of the first set of fractures 21, 22, 23 may remain. After the second set of fractures 24, 25 are created, hydrocarbons or other fluid 32 from the formation 10 are produced through the well bore 12 via the second set of fractures 24, 25 for a second period of time.
The second period of time might be determined based on providing sufficient time to permit the relief of stress created by the second set of fractures 24, 25. Such period of time might be less than a year. For example, the second period of time might be anywhere between 1 and 6 months. In some instances, the second period of time might be as small as a few days or even a few hours. Once the stress created by the second set of fractures 24, 25 has been relieved, the production of fluid 32 from the formation 10 via the second set of fractures 24, 25 may be stopped by plugging the fractures 24, 25, or otherwise providing isolation between the second set of fractures 24, 25 and the well bore 12.
Referring now to Figure 5, once the stress created by the second set of fractures 24, 25 has been released via production of fluid 32, a third set of fractures 26, 27, 28, 29 is created. An average fracture spacing 36 between the first set of fractures 21, 22, 23, the second set of fractures 24, 25, and the third set of fractures 26, 27, 28, 29 is equal to or greater than the final fracture spacing 18. Stated otherwise, the final fracture spacing 18 is less than or equal to the average fracture spacing 36 between adjacent fractures in the set of fractures including the first set of fractures 21, 22, 23, the second set of fractures 24, 25, and the third set of fractures 26, 27, 28, 29.
As illustrated in Figure 5, the average fracture spacing 36 is approximately equal to the final fracture spacing 18. However, if the process were to be repeated in additional iterations, the final fracture spacing 18 might be smaller than the average fracture spacing 36. Once all iterations are complete, all isolation (e.g., the tubing 38 and external packers 42) may be removed to allow for production of fluid 32 through all fractures 21-29, as shown in Figure 6.
A method of phased stimulation of the zone 14 in the subterranean formation 10 can also be described with respect to Figures 2-6. First, the zone 14 is stimulated via the first set of fractures 21, 22, 23 originating at the well bore 12 and having the first fracture spacing 30. Such stimulation may be in the form of hydraulic fracturing, acid fracturing, matrix stimulation, and the like. Next, primary production of fluid 32 is allowed from the zone 14 via the first set of fractures 21, 22, 23 until a predetermined threshold is reached.
The predetermined threshold may represent a value indicating a stress relief level has been reached. As described above, the predetermined threshold may be a time of production from the zone or the predetermined threshold may be a percentage of a maximum projected production from the zone. Additionally, other measurements may provide an indication that desirable stress relief has occurred. For example, the predetermined threshold may use feedback in the form of pressure levels, temperatures, produced fluid volumes, flow back fluid volumes, etc. for an indication that suitable stress reduction has occurred. Then, isolation is provided between the first set of fractures and the well bore 12.
The zone 14 is further stimulated via the second set of fractures 24, 25 originating at the wellbore 12. At least one of the fractures 24, 25 of the second set of fractures 24, 25 lies between adjacent fractures of the first set of fractures 21, 22, 23. As illustrated, second set fracture 24 lies between adjacent first set fractures 21 and 22 and second set fracture 25 lies between adjacent first set fractures 22 and 23. Next, fluid 32 is allowed to be produced from the zone 14 via the second set of fractures 24, 25. Then, the isolation between the first set of fractures 21, 22, 23 and the well bore 12 is removed, allowing secondary production from the zone 14 via the first set of fractures 21, 22, 23.
The primary production from the zone 14 via the first set of fractures 21, 22, is less than the production from zone 14 via both the first and second sets of fractures 21-25. Likewise, if a third set of fractures 26-29 is provided, the production from the combined first second and third set of fractures is greater than the production from the first and second sets of fractures. Thus, the primary production from the zone 14 is less than a maximum production from the zone 14. Further, the primary production from the zone 14 may be less than a maximum economical production from the zone. Such maximum economical production from the zone 14 might be less than the maximum production available from the zone 14, but might represent the most profitable amount of production when accounting for costs involved. Generally, the primary production from the zone 14 will be less than the maximum economical production. However, it is thought that the sacrifice of maximum economical production in the primary production is outweighed by the benefit provided by superior communication with the zone 14 via the second set of fractures 24, 25, the optional third set of fractures 26-29, and any additional iterations provided by repeating the process.
Similarly, after the processes described herein, any of the fractures may be re-stimulated in a secondary or remedial operation. In such a process, a set of fractures may be created, stimulated, and may produce before being isolated while another set of fractures is stimulated. Then, both sets of fractures may produce for some time before either or both sets of fractures is re-stimulated and may produce once again.
Furthermore, methods analogous to those above could be used for operations involving other formation treatments. For example, matrix stimulation may benefit from methods such as those described herein.
Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments, configurations, materials, and methods without departing from their scope. Accordingly, the scope of the claims and their functional equivalents should not be limited by the particular embodiments described and illustrated, as these are merely exemplary in nature and elements described separately may be optionally combined.
Referring now to the figures, Figure 1 shows how the influence of the stress from the first (rightmost) fracture is believed to inhibit the formation of the second (second to right) fracture. Depending on the size and placement of the second fracture, the third fracture (third from right) may be influenced by either or both of the first and second fracture stresses. Likewise, fractures may be negatively influenced throughout a zone, even moving beyond a particular stage (e.g., the four leftmost fractures might influence the next stage of four fractures and those fractures might influence the next stage of four fractures).
Thus, the traditional approach has been to either provide larger fracture spacing than otherwise would be desirable, in order to prevent interference from other fractures or provide the desired spacing and accept the effects of the interference. One alternative to these approaches is described in U.S. 2012/0325462, where fractures are initiated in an alternate order than the aforementioned right to left. While U.S. 2012/0325462 claims to provide improvements by negating the directional impact of the stresses, it is believed that the magnitude of the stresses are still problematic and, unlike the present disclosure, U.S.
2012/0325462 does not consider production of formation fluid as a way to alleviate the stresses. Further, the fracture spacings of U.S. 2012/0325462 are in the range of 150 ft to 250 ft and it is believed that the present disclosure would allow for spacings well below 100 ft. Finally, U.S. 2012/0325462 proposes complex fractures which are unnecessary in accordance with the embodiments described below. Specifically, in U.S.
2012/0325462, spacings between fractures must be sufficiently large to provide a stress-free zone in which a complex fracture can be formed. The embodiments described below, on the other hand, do not require such large spacing or complex fractures.
One method of stimulating a subterranean formation 10 having a well bore 12 therein includes (1) determining a threshold stress value indicative of presence of a stress shadow (e.g., by field or other estimations based on formation characteristics), (2) obtaining a formation stress value (e.g., by measurements taken onsite, by field estimations, by calculations, or otherwise), (3) allowing production from the subterranean formation 10 when the stress shadow is present (i.e., when the measured stress value exceeds the threshold stress value), and (4) ceasing production when the stress shadow has dissipated (i.e, when the measured stress value drops below the threshold stress value).
Figures 2-6 illustrate one method of stimulating the subterranean formation 10 having the well bore 12 therein. The well bore 12 provides a pathway for fluids (e.g., hydrocarbons) from a zone 14 to move to the surface 16. Fractures 21-29, originating at the exterior surface of the well bore 12 provide fluid communication between the zone 14 and the well bore 12, allowing the fluids from the zone 14 to exit the subterranean formation 10, move into the well bore 12 and up to the surface 16. As illustrated, the methods describe a horizontal or deviated well bore 12. However, the methods could similarly be used in a vertical well bore.
The first step of the method of Figures 2-6 involves determining a final fracture spacing 18. In Figure 2, the final fracture spacing 18 represents the desired spacing between two adjacent fractures (not yet present in the illustration of Figure 2) after all fractures have been placed (see Figure 6). The desired spacing may be calculated or otherwise determined on the basis of the minimum economic production rate, taking into account formation porosity, hydrocarbon saturation, permeability, and costs associated with completion and production. The final spacing 18 may be an economically optimized fracture spacing and the step of determining the final spacing 18 might involve determining the economically optimized fracture spacing. Such determination might involve calculations of net present value, and accounting for various factors including but not limited to current oil and gas prices, operational costs, and capabilities of the facilities. In some instances, the final fracture spacing 18 might vary along the length of the well bore 12 or even within the zone 14 of interest. However, in the interest of simplicity, the final fracture spacing 18 is illustrated as having a uniform dimension. In some embodiments, the final fracture spacing 18 may be less than 500 ft., less than 300 ft., less than 200 ft., less than 180 ft., less than 170 ft., less than 160 ft., less than 150 ft., less than 140 ft., less than 130 ft., less than 120 ft., less than 110 ft., less than 100 ft., less than 90 ft., less than 80 ft., less than 70 ft., less than 60 ft., less than 50 ft., less than 40 ft., less than 30 ft., or even less than 20 ft.
Referring now to Figure 3, a first set of fractures 21, 22, 23 are created at a first fracture spacing 30. The first fracture spacing 30 is larger than the final fracture spacing 18.
In this illustration, the first fracture spacing 30 is approximately four times the final fracture spacing 18. In embodiments with two sets of fractures, the first fracture spacing 30 may be about twice the final fracture spacing 18. In embodiments with more than three sets of fractures, the first fracture spacing 30 may be more than four times the final fracture spacing 18. After the first set of fractures 21, 22, 23 are created, hydrocarbons or other fluid 32 from the formation 10 are produced through the well bore 12 via the first set of fractures 21, 22, 23 for a period of time. The period of time might be determined based on providing sufficient time to permit the relief of stress created by the first set of fractures 21, 22, 23.
The production of fluids 32 is believed to relieve the pore pressure thus relieving the stress in the rock over time. By allowing fluid 32 to leave the formation 10, it is thought that the stresses caused by fracturing may be alleviated in the region around such fractures. Such reduction in stresses may allow for a superior fracture to be created between existing fractures, as compared to fractures created without allowing for such stress relief Thus, production of fluids 32 may be permitted until a predetermined threshold is reached. In one example, the predetermined threshold may be a time of production from the formation 10. While allowing for a large time to pass might provide for more stress relief, it is thought that the period of time for production between formation of the first set of fractures 21, 22, 23 and formation of the second set of fractures 24, 25 may be relatively short. Such period of time might be less than a year, from 6 months to a year, from 1 to 6 months, from 1 week to 1 month, or from 1 hour to 1 week. In some instances, the period of time might be as small as a few days or even within a few hours.
An alternate predetermined threshold may be a percentage of a maximum projected production from the formation 10. While allowing for a large percentage of the maximum projected production might provide for more stress relief, it is thought that the production between formation of the first set of fractures 21, 22, 23 and formation of the second set of fractures 24, 25 may be relatively small. Such production might be less than 50% of the maximum projected production, less than 25% of the maximum projected production, less than 5% of the maximum projected production, or less than 1% of the maximum projected production. In some instances, the production may be as small as a tenths of a percent or even a few hundredths of a percent. Other alternatives to time and production volumes may be used in the embodiments described, so long as some method of feedback on whether sufficient relief of the stress caused by a particular set of fractures has occurred via production.
Once the stress created by the first set of fractures 21, 22, 23 has been relieved, the production of fluid 32 from the formation 10 via the first set of fractures 21, 22, 23 may be stopped by plugging the fractures 21, 22, 23, or otherwise providing isolation between the first set of fractures 21, 22, 23 and the well bore 12. Such isolation may be provided through any of a number of methods. For example, as illustrated in Figure 4, tubing 38 may be run in the casing 40 lining the well bore 12. The tubing 38 may have external packers 42 used for isolation. Alternative means of isolation include external casing packers, production liners, expandables, coiled tubing via sleeve that opens and closes via ball drop, hydraulics, or otherwise, chemical isolation, or any number of other methods of isolating fractures.
Referring now to Figure 4, once the stress created by the first set of fractures 21, 22, 23 has been released via production of fluid 32, a second set of fractures 24, 25 is created. It is believed that the reduction in fluid 32 in the formation 10 will allow placement of the second set of fractures 24, 25 between (e.g., in the middle of) the first set of fractures 21, 22, 23 without significant resistance. An average fracture spacing 34 between the first set of fractures 21, 22, 23 and the second set of fractures 24, 25 is equal to or greater than the final fracture spacing 18. Stated otherwise, the final fracture spacing 18 is less than or equal to the average fracture spacing 34 between adjacent fractures in the set of fractures including the first set of fractures 21, 22, 23 and the second set of fractures 24, 25.
As illustrated in Figure 4, the average fracture spacing 34 is about twice the final fracture spacing 18. However, in some embodiments, two sets of fractures may be sufficient. In those embodiments, the average fracture spacing 34 may be equal to the final fracture spacing 18. Thus, the first fracture spacing 30 might be double the final fracture spacing 18 when two sets of fractures or sufficient, and the first fracture spacing 30 will be more than double the final fracture spacing 18 in embodiments where more than two sets of fractures are utilized. If two sets of fractures are sufficient, isolation of the first set of fractures 21, 22, 23 may be removed and production of formation fluid 32 may proceed through both the first and second sets of fractures 21, 22, 23, 24, 25. If further fractures are desired, isolation of the first set of fractures 21, 22, 23 may remain. After the second set of fractures 24, 25 are created, hydrocarbons or other fluid 32 from the formation 10 are produced through the well bore 12 via the second set of fractures 24, 25 for a second period of time.
The second period of time might be determined based on providing sufficient time to permit the relief of stress created by the second set of fractures 24, 25. Such period of time might be less than a year. For example, the second period of time might be anywhere between 1 and 6 months. In some instances, the second period of time might be as small as a few days or even a few hours. Once the stress created by the second set of fractures 24, 25 has been relieved, the production of fluid 32 from the formation 10 via the second set of fractures 24, 25 may be stopped by plugging the fractures 24, 25, or otherwise providing isolation between the second set of fractures 24, 25 and the well bore 12.
Referring now to Figure 5, once the stress created by the second set of fractures 24, 25 has been released via production of fluid 32, a third set of fractures 26, 27, 28, 29 is created. An average fracture spacing 36 between the first set of fractures 21, 22, 23, the second set of fractures 24, 25, and the third set of fractures 26, 27, 28, 29 is equal to or greater than the final fracture spacing 18. Stated otherwise, the final fracture spacing 18 is less than or equal to the average fracture spacing 36 between adjacent fractures in the set of fractures including the first set of fractures 21, 22, 23, the second set of fractures 24, 25, and the third set of fractures 26, 27, 28, 29.
As illustrated in Figure 5, the average fracture spacing 36 is approximately equal to the final fracture spacing 18. However, if the process were to be repeated in additional iterations, the final fracture spacing 18 might be smaller than the average fracture spacing 36. Once all iterations are complete, all isolation (e.g., the tubing 38 and external packers 42) may be removed to allow for production of fluid 32 through all fractures 21-29, as shown in Figure 6.
A method of phased stimulation of the zone 14 in the subterranean formation 10 can also be described with respect to Figures 2-6. First, the zone 14 is stimulated via the first set of fractures 21, 22, 23 originating at the well bore 12 and having the first fracture spacing 30. Such stimulation may be in the form of hydraulic fracturing, acid fracturing, matrix stimulation, and the like. Next, primary production of fluid 32 is allowed from the zone 14 via the first set of fractures 21, 22, 23 until a predetermined threshold is reached.
The predetermined threshold may represent a value indicating a stress relief level has been reached. As described above, the predetermined threshold may be a time of production from the zone or the predetermined threshold may be a percentage of a maximum projected production from the zone. Additionally, other measurements may provide an indication that desirable stress relief has occurred. For example, the predetermined threshold may use feedback in the form of pressure levels, temperatures, produced fluid volumes, flow back fluid volumes, etc. for an indication that suitable stress reduction has occurred. Then, isolation is provided between the first set of fractures and the well bore 12.
The zone 14 is further stimulated via the second set of fractures 24, 25 originating at the wellbore 12. At least one of the fractures 24, 25 of the second set of fractures 24, 25 lies between adjacent fractures of the first set of fractures 21, 22, 23. As illustrated, second set fracture 24 lies between adjacent first set fractures 21 and 22 and second set fracture 25 lies between adjacent first set fractures 22 and 23. Next, fluid 32 is allowed to be produced from the zone 14 via the second set of fractures 24, 25. Then, the isolation between the first set of fractures 21, 22, 23 and the well bore 12 is removed, allowing secondary production from the zone 14 via the first set of fractures 21, 22, 23.
The primary production from the zone 14 via the first set of fractures 21, 22, is less than the production from zone 14 via both the first and second sets of fractures 21-25. Likewise, if a third set of fractures 26-29 is provided, the production from the combined first second and third set of fractures is greater than the production from the first and second sets of fractures. Thus, the primary production from the zone 14 is less than a maximum production from the zone 14. Further, the primary production from the zone 14 may be less than a maximum economical production from the zone. Such maximum economical production from the zone 14 might be less than the maximum production available from the zone 14, but might represent the most profitable amount of production when accounting for costs involved. Generally, the primary production from the zone 14 will be less than the maximum economical production. However, it is thought that the sacrifice of maximum economical production in the primary production is outweighed by the benefit provided by superior communication with the zone 14 via the second set of fractures 24, 25, the optional third set of fractures 26-29, and any additional iterations provided by repeating the process.
Similarly, after the processes described herein, any of the fractures may be re-stimulated in a secondary or remedial operation. In such a process, a set of fractures may be created, stimulated, and may produce before being isolated while another set of fractures is stimulated. Then, both sets of fractures may produce for some time before either or both sets of fractures is re-stimulated and may produce once again.
Furthermore, methods analogous to those above could be used for operations involving other formation treatments. For example, matrix stimulation may benefit from methods such as those described herein.
Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments, configurations, materials, and methods without departing from their scope. Accordingly, the scope of the claims and their functional equivalents should not be limited by the particular embodiments described and illustrated, as these are merely exemplary in nature and elements described separately may be optionally combined.
Claims (23)
1. A method of stimulating a subterranean formation having a well bore therein, the method comprising:
determining a final fracture spacing;
creating a first set of fractures at a first fracture spacing, the first fracture spacing being larger than the final fracture spacing;
allowing production of fluids from the formation through the well bore via the first set of fractures for a period of time;
after the period of time, creating a second set of fractures;
wherein the final fracture spacing is less than or equal to an average fracture spacing between the first set of fractures and the second set of fractures.
determining a final fracture spacing;
creating a first set of fractures at a first fracture spacing, the first fracture spacing being larger than the final fracture spacing;
allowing production of fluids from the formation through the well bore via the first set of fractures for a period of time;
after the period of time, creating a second set of fractures;
wherein the final fracture spacing is less than or equal to an average fracture spacing between the first set of fractures and the second set of fractures.
2. The method of claim 1, wherein the first fracture spacing is at least double the final fracture spacing.
3. The method of claim 1, wherein the final fracture spacing comprises an economically optimized fracture spacing, and wherein the step of determining the final fracture spacing comprises determining the economically optimized fracture spacing.
4. The method of claim 1, wherein the period of time comprises sufficient time to permit the relief of stress created by the first set of fractures.
5. The method of claim 1, wherein the period of time comprises less than one year.
6. The method of claim 5, wherein the period of time comprises from 1 month to 6 months.
7. The method of claim 5, wherein the period of time comprises from 1 week to 1 month.
8. The method of claim 5, wherein the period of time comprises from 1 hour to 1 week.
9. The method of claim 1, further comprising stopping production of fluids from the first set of fractures prior to creating the second set of fractures.
10. The method of claim 1, further comprising:
allowing production of fluids from the formation through the well bore via the second set of fractures for a second period of time;
after the second period of time, creating a third set of fractures;
wherein the final fracture spacing is less than or equal to an average fracture spacing between the first set of fractures, the second set of fractures, and the third set of fractures.
allowing production of fluids from the formation through the well bore via the second set of fractures for a second period of time;
after the second period of time, creating a third set of fractures;
wherein the final fracture spacing is less than or equal to an average fracture spacing between the first set of fractures, the second set of fractures, and the third set of fractures.
11. A method of phased stimulation of a zone in a subterranean formation, the method comprising:
stimulating the zone via a first set of fractures originating at a well bore and having a first fracture spacing;
allowing primary production from the zone via the first set of fractures;
providing isolation between the first set of fractures and the well bore before the primary production reaches a predetermined threshold;
further stimulating the zone via a second set of fractures originating at the wellbore, wherein at least one of the fractures of the second set of fractures lies between adjacent fractures in the first set of fractures;
allowing production from the zone via the second set of fractures; and removing the isolation between the first set of fractures and the well bore thereby allowing secondary production from the zone via the first set of fractures.
stimulating the zone via a first set of fractures originating at a well bore and having a first fracture spacing;
allowing primary production from the zone via the first set of fractures;
providing isolation between the first set of fractures and the well bore before the primary production reaches a predetermined threshold;
further stimulating the zone via a second set of fractures originating at the wellbore, wherein at least one of the fractures of the second set of fractures lies between adjacent fractures in the first set of fractures;
allowing production from the zone via the second set of fractures; and removing the isolation between the first set of fractures and the well bore thereby allowing secondary production from the zone via the first set of fractures.
12. The method of claim 11, wherein the predetermined threshold comprises a percentage of a maximum projected production from the zone.
13. The method of claim 12, wherein the percentage is no more than 50%.
14. The method of claim 13, wherein the percentage is no more than 25%.
15. The method of claim 14, wherein the percentage is no more than 5%.
16. The method of claim 11, wherein the predetermined threshold comprises a time of production from the zone.
17. The method of claim 16, wherein the time of production is no more than 1 year.
18. The method of claim 11, wherein the first set of fractures and the second set of fractures have an average fracture spacing and wherein the first fracture spacing is at least twice the average fracture spacing.
19. The method of claim 11, wherein the first fracture spacing is at least four times a final fracture spacing.
20. The method of claim 11, wherein the step of providing isolation comprises running tubing with external packers into the well bore.
21. The method of claim 11, further comprising re-stimulating the first set of fractures.
22. A method comprising:
(a) determining a threshold stress value indicative of presence of a stress shadow;
(b) obtaining a formation stress value;
(c) allowing production when the formation stress value exceeds the threshold stress value; and (d) ceasing production when the formation stress value drops below the threshold stress value.
(a) determining a threshold stress value indicative of presence of a stress shadow;
(b) obtaining a formation stress value;
(c) allowing production when the formation stress value exceeds the threshold stress value; and (d) ceasing production when the formation stress value drops below the threshold stress value.
23. The method of claim 22 further comprising:
before step (c), stimulating a zone in a subterranean formation via a first set of fractures originating at a well bore;
providing isolation between the first set of fractures and the well bore before the production reaches the threshold stress value;
further stimulating the zone via a second set of fractures originating at the wellbore, wherein at least one of the fractures of the second set of fractures lies between adjacent fractures in the first set of fractures;
allowing production from the zone via the second set of fractures; and removing the isolation between the first set of fractures and the well bore thereby allowing secondary production from the zone via the first set of fractures.
before step (c), stimulating a zone in a subterranean formation via a first set of fractures originating at a well bore;
providing isolation between the first set of fractures and the well bore before the production reaches the threshold stress value;
further stimulating the zone via a second set of fractures originating at the wellbore, wherein at least one of the fractures of the second set of fractures lies between adjacent fractures in the first set of fractures;
allowing production from the zone via the second set of fractures; and removing the isolation between the first set of fractures and the well bore thereby allowing secondary production from the zone via the first set of fractures.
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|---|---|---|---|
| US201361879886P | 2013-09-19 | 2013-09-19 | |
| US61/879,886 | 2013-09-19 |
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| CA2863764A1 true CA2863764A1 (en) | 2015-03-19 |
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| CA 2863764 Abandoned CA2863764A1 (en) | 2013-09-19 | 2014-09-17 | Phased stimulation methods |
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| US (1) | US20150075784A1 (en) |
| CN (1) | CN104453822A (en) |
| CA (1) | CA2863764A1 (en) |
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10012064B2 (en) | 2015-04-09 | 2018-07-03 | Highlands Natural Resources, Plc | Gas diverter for well and reservoir stimulation |
| US10344204B2 (en) | 2015-04-09 | 2019-07-09 | Diversion Technologies, LLC | Gas diverter for well and reservoir stimulation |
| US10982520B2 (en) | 2016-04-27 | 2021-04-20 | Highland Natural Resources, PLC | Gas diverter for well and reservoir stimulation |
Families Citing this family (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| AR104396A1 (en) * | 2015-04-24 | 2017-07-19 | W D Von Gonten Laboratories Llc | SIDE POSITIONING AND COMPLETE DESIGN FOR IMPROVED WELL PERFORMANCE OF UNCONVENTIONAL RESERVES |
| US20190063186A1 (en) | 2016-03-17 | 2019-02-28 | Shell Oil Company | Single entry fracturing process |
| CN106194141A (en) * | 2016-08-19 | 2016-12-07 | 中国石油天然气股份有限公司 | The process formed based on seam net under volume fracturing |
| AU2017386376A1 (en) | 2016-12-29 | 2019-07-04 | Shell Internationale Research Maatschappij B.V. | Fracturing a formation with mortar slurry |
Family Cites Families (9)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US20070215345A1 (en) * | 2006-03-14 | 2007-09-20 | Theodore Lafferty | Method And Apparatus For Hydraulic Fracturing And Monitoring |
| US7934553B2 (en) * | 2008-04-21 | 2011-05-03 | Schlumberger Technology Corporation | Method for controlling placement and flow at multiple gravel pack zones in a wellbore |
| US8210257B2 (en) * | 2010-03-01 | 2012-07-03 | Halliburton Energy Services Inc. | Fracturing a stress-altered subterranean formation |
| US20130220604A1 (en) * | 2010-10-20 | 2013-08-29 | Abdel Wadood M. El-Rabaa | Methods For Establishing A Subsurface Fracture Network |
| CA2852881A1 (en) * | 2011-06-24 | 2012-12-27 | Board Of Regents, The University Of Texas System | Method for determining spacing of hydraulic fractures in a rock formation |
| US8967262B2 (en) * | 2011-09-14 | 2015-03-03 | Baker Hughes Incorporated | Method for determining fracture spacing and well fracturing using the method |
| AU2012332270A1 (en) * | 2011-11-04 | 2014-05-29 | Schlumberger Technology B.V. | Modeling of interaction of hydraulic fractures in complex fracture networks |
| CN102606124B (en) * | 2012-03-16 | 2015-07-29 | 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 | The synchronous volume fracturing technology of dual horizontal well segmentation many bunches |
| CN103015955B (en) * | 2012-12-28 | 2015-06-24 | 中国石油集团渤海钻探工程有限公司 | Open-hole horizontal well multi-cluster sliding sleeve staged fracturing string and fracturing method thereof |
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2014
- 2014-09-17 CA CA 2863764 patent/CA2863764A1/en not_active Abandoned
- 2014-09-17 US US14/488,733 patent/US20150075784A1/en not_active Abandoned
- 2014-09-19 CN CN201410482904.2A patent/CN104453822A/en active Pending
Cited By (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10012064B2 (en) | 2015-04-09 | 2018-07-03 | Highlands Natural Resources, Plc | Gas diverter for well and reservoir stimulation |
| US10344204B2 (en) | 2015-04-09 | 2019-07-09 | Diversion Technologies, LLC | Gas diverter for well and reservoir stimulation |
| US10385258B2 (en) | 2015-04-09 | 2019-08-20 | Highlands Natural Resources, Plc | Gas diverter for well and reservoir stimulation |
| US10385257B2 (en) | 2015-04-09 | 2019-08-20 | Highands Natural Resources, PLC | Gas diverter for well and reservoir stimulation |
| US10982520B2 (en) | 2016-04-27 | 2021-04-20 | Highland Natural Resources, PLC | Gas diverter for well and reservoir stimulation |
Also Published As
| Publication number | Publication date |
|---|---|
| US20150075784A1 (en) | 2015-03-19 |
| CN104453822A (en) | 2015-03-25 |
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