STRENGTHENING FRACTURE TIPS FOR PRECISION FRACTURING

Abstract

A method of fracturing a reservoir wherein the main fracture stimulation treatment is preceded by depositing non dissolving solids into fracture tips where excessive downward or upward fracture growth is not desired, thereby controlling fracture geometry. The method thereby increases production of a fluid, such as water, oil or gas, from said reservoir, and avoids fracture propagation out of the pay-zone into undesirable zones.

Claims

1. A method of stimulating a reservoir for increased production of hydrocarbons, said method comprising: a) injecting a fracture fluid into a stage of a well in a reservoir to initiate one or more fractures in said stage; b) determine a fracture extension rate and a primary fracture geometry and identifying one or more fracture tip(s) that require strengthening; c) injecting a first tip strengthening fluid containing a first non-dissolving solid into said stage at a first rate such that a slope of a log-log plot of net pressure versus time is positive and said one or more fracture tip(s) are strengthened by depositing said first solid into said one or more fracture tip(s); d) optionally repeating step c) with a second tip strengthening fluid containing a second non-dissolving solid that is larger than said first non-dissolving solid; e) injecting a main treatment injection fluid at a second rate that does not exceed said first rate once it is determined from injection pressure diagnostics that said one or more fracture tips are strengthened and fracture vertical growth is contained during said injecting; f) repeating steps a-e) for subsequent stages of said well; and g) producing hydrocarbons from said well.

2. The method of claim 1, wherein step d) is performed.

3. The method of claim 1, wherein step d) is omitted and instead said second tip strengthening fluid is combined with said main treatment injection fluid.

4. The method of claim 1, wherein step c) and d) are combined and said first and second solids are in a 60/40 to 40/60 ratio.

5. The method of claim 1, wherein step c) and d) are combined and said first and second solids are in a 50/50 ratio.

6. The method of claim 1, said main treatment comprising a first pad injection followed by a proppant injection and a final flush injection.

7. The method of claim 1, wherein said first solid is 40/70 US mesh sand or 30/50 US mesh sand.

8. The method of claim 1, wherein said second solid is 100 US mesh sand.

9. The method of claim 1, wherein 100 US mesh sand is pumped with said main treatment at 0.5 lbm/gal concentration.

10. The method of claim 1, wherein i) said one or more fracture tips are predominantly downward growing fracture tips and said first and second solids are heavier than said injection fluid and sink, or wherein ii) said one or more fracture tips are predominantly upward growing fracture tips and said first and second solids are lighter than said injection fluid and float or are neutral buoyant, or iii) both i) and ii).

11. The method of claim 1, where a flush fluid is injected after each of steps c) and optional d) and e).

12. The method of claim 1, wherein said method includes simulating fracture geometry in a model reservoir having characteristics of said reservoir to identify said one or more fracture tip(s) that require strengthening.

13. The method of claim 12, wherein solid settling is simulated in said model reservoir.

14. A method of stimulating a reservoir for increased production of hydrocarbon; said method comprising: a) simulating fracture geometry in a model reservoir having characteristics of a reservoir to identify said one or more simulated fracture tip(s) that require strengthening; b) simulating solid settling into said one or more simulated fracture tip(s) in said model reservoir; c) repeated steps a and b as needed to select a first tip strengthening fluid containing a first solid, and optionally a second tip strengthening fluid containing a second solid larger than said first solid; d) injecting a fracture fluid into a stage of a well in said reservoir to initiate one or more fractures in said stage; e) injecting said first tip strengthening fluid containing said first solid into said stage at a first rate such that a slope of a log-log plot of net pressure versus time is positive and said one or more fracture tip(s) are strengthened by depositing said first solid into said one or more fracture tip(s); f) optionally repeating step e) with said second tip strengthening fluid containing said second non-dissolving solid that is larger than said first non-dissolving solid; g) injecting a main treatment injection fluid at a second rate that does not exceed said first rate; h) repeating steps d-g) for subsequent stages of said well; and i) producing hydrocarbons from said well.

15. The method of claim 14, wherein said one or more simulated fracture tips are predominantly downward growing fracture tips and said first and second solids are denser than said injection fluid and sink.

16. The method of claim 14, wherein said one or more simulated fracture tips are predominantly upward growing fracture tips and said first and second solids are less dense than said injection fluid and float or are neutral buoyant.

17. The method of claim 14, wherein said first and second solids are a mix of dense solids that sink and less dense solids that float or are neutral buoyant.

18. The method of claim 14, wherein step f) is performed.

19. The method of claim 14, wherein step f) is omitted and instead said second tip strengthening fluid is combined with said main treatment injection fluid.

20. The method of claim 14, wherein step e) and f) are combined and said first and second solids are in a 60/40 to 40/60 ratio.

21. An improved method of fracturing a reservoir for increased production of hydrocarbon, said method comprising injecting a pad into a well in a reservoir to create fractures, injecting proppant into said well and said fractures, and then producing hydrocarbon from said well, the improvement comprising: a) simulating fracture geometry in a model reservoir having characteristics of said reservoir to identify said one or more simulated fracture tip(s) that require strengthening; b) simulating solid settling into said one or more simulated fracture tip(s) in said model reservoir; c) repeated steps a and b as needed to select a first tip strengthening fluid containing a first solid, and optionally a second tip strengthening fluid containing a second solid larger than said first solid; d) injecting a fracture fluid into a well in said reservoir to initiate one or more fractures; e) injecting said first tip strengthening fluid into said well at a first rate such that a slope of a log-log plot of net pressure versus time is positive and said one or more fracture tip(s) are strengthened by depositing said first solid into said one or more fracture tip(s) and optionally repeating with said second tip strengthening fluid; f) subsequently injecting a pad into said reservoir to create further fractures; g) injecting proppant into said fractures; and h) thereafter producing hydrocarbon from said well.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0094] FIG. 1: (prior art) Hydraulic fracturing of a reservoir. Allows more gas or oil to reach the well for production.

[0095] FIG. 2: (prior art) Well bore contact with various fracture types. Longitudinal open-hole (top), longitudinal cemented (center), and transverse fractures (bottom).

[0096] FIG. 3A-B: Fracture distance versus net pressure mapping. Graphs prepared using a simulator and a model that comprises a coal bed methane reservoir of permeability of 0.12 md, expected fracture conductivity of nearly 1,750 md-ft, pay zone between 3,325 and 3,375 ft (1,014.7 and 1,029.0 m) and high mobile water saturation zone below 3,425 ft (1,044 m). FIG. 3A is net pressure in psi on the x axis versus distance in feet from the fracture initiation point (0) on the y axis. The circle (top line) and squares (bottom line) indicating the upper and lower tips of the fracture, respectively. The middle of the fracture is shown by triangles (middle line). FIG. 3B is stress distribution of the formation as a function of depth. Stresses are indicated by the circles with a range of psi shown, and the star indicates a perforation cluster. In FIG. 3A, the star denotes the distance of the high stress member from the center of the perforation and aligns with the depth position in FIG. 3B. The payzone and high water saturation region are highlighted by top and bottom boxes, respectively.

[0097] FIG. 4A-B: Simulation shows possible downward growth of fracture into unwanted zones. FIG. 4A is stress in psi versus true vertical depth (“TVD”) in meters with the black line indicating formation stresses in psi and the colors showing various layer types. These are yellow, red, purple and gray for clean-sandstone, dirty-sandstone, siltstone and shale respectively. FIG. 4B is fracture penetration in meters versus TVD wherein the colors represent proppant coverage in lb/ft2. The high water saturation zone is shown by the blue box.

[0098] FIG. 5A-B: Simulation depicting proppant settling at the bottom of the fracture. FIG. 5A is the modeled stress distribution of the various layers in the formation and FIG. 5B is fracture half-length showing proppant coverage. In FIG. 5, the simulation shows higher concentrations of proppant depicted by blue color and equivalent to nearly 0.2 lbm/ft.sub.2 based on the scale on right Y-axis, at the bottom tip of the fracture. The arrows inside the fracture show the direction and magnitude of fluid velocity vector that can be scaled based on scale of “0.419 m/s” shown at the bottom of the proppant coverage scale. The fracture half-length is limited to 100 m.

[0099] FIG. 6A-B: Simulation depicting proppant settling at the bottom of the fracture. FIG. 6A is the modeled stress distribution of the various layers in the formation and FIG. 6B is fracture half-length showing proppant coverage. This plot shows that after strengthening the bottom tip of the fracture, the fracture can now be extended to the desired fracture half-length, and it will not grow into the high water saturation layers below thus helping to meet the objective of the fracture simulation treatment.

DETAILED DESCRIPTION

[0100] In order to obtain proof of concept for the methods, we performed simulations of a model coal bed methane gas well with a low permeability of 0.12 mD and expected fracture conductivity of nearly 1,750 mD-ft. Given these constraints, a propped fracture half-length of nearly 300 meters is desirable if a dimensionless fracture conductivity of 15 is targeted for optimal well performance. The objective of the treatment was to limit the fracture growth within the pay zone between 3,325 and 3,375 ft (1,014.7 and 1,029.0 m) and fractures must be prevented from entering the high mobile water saturation zone below 3,425 ft (1,044 m).

[0101] The gridded numerical model was run in a fully 3-dimensional mode and took into account a 2-dimensional fluid flow inside the fracture, which accounts for proppant settling mechanism while also accounting for leakoff of fluid into the formation, which is a critical input in calculation of fracture geometry.

[0102] Simulations were performed with a fluid of small viscosity of up to 12 cP and injection rates of nearly 8 bbl/min.

[0103] Following are the steps used in our proof-of-concept work, wherein we first simulated fracture geometry under a more traditional injection profile, and then tested one embodiment of the inventive profile. Once an injection profile is optimized by simulator, it can then be applied with the field.

[0104] Determine fracture vertical growth profile. The plot of distance versus net pressure in FIG. 3A is generated using the technique discussed in Pandey and Rasouli (2021), where the apparent fracture toughness was input based on the model developed to calculate the same with the help of predicted fluid velocity. The distribution of in situ stresses in the model formation did not favor a well contained fracture due to the presence of low-stressed members below the depth of 3,395 ft, as shown in the right plot of FIG. 3B.

[0105] FIG. 3A confirms that if the net pressure during the treatment (defined as fracture pressure minus in situ stress) exceeds 350 psi, the bottom stress barrier at this depth is liable to give in. As a result, the fracture can migrate downwards, as shown by the location bottom tip of the fracture in FIG. 3A. The points in 3A denote the expected top, middle and bottom tips of the fracture. As can be seen, initially the top and bottom of the fractures remained confined to a total height of a mere few feet if the net pressures are limited to 225 psi. Once the net pressures exceed 225 psi, the fracture appears to grow in downward direction, nearly 60 ft below the initiation point and with further increases in net pressure, tends to grow vertically in both the directions, as shown by upper and lower tip location. The depth and distances are both highlighted by a star and the payzone and the high water saturation region, are highlighted by top and bottom boxes, respectively.

[0106] Simulate base fracture treatment to obtain fracture geometry. The fracture geometry plot generated by a gridded numerical fracture simulator for a typical pump schedule is shown in FIG. 4. The plot of FIG. 4A shows typical output from a fracture simulator where one of the 2 equally sized fracture wings (bi-wing fracture) is illustrated with for a given fracture property along the vertical height and half-length of the fracture. The track on the left shows stress distribution in the formation as a function of depth, and the various colors represent various layer lithological types described above. The right portion of the plot shows the extent of fracture extension and height growth, with the various colors depicting the contour of proppant coverage inside the fracture with the units of lbm/ft.sup.2. The small arrow shows the velocity vectors associated with fluid movements inside the fracture. The vectors can be scaled from the scale shown on the bottom of the right legend. The same implies for FIG. 4B.

[0107] A crosslinked frac fluid of 20 lbm/Mgal concentration was used in the simulation and the injection rates were limited to 12.0 bbl/min to ensure that net pressures were under control and excessive height growth avoided. For a payzone of nearly 40 ft (12.2 m) the total proppant designed was 145,000 lbm reaching up to a maximum concentration of 8.0 lbm/gal to generate the desired conductivity.

[0108] As expected, the simulation confirms that a downward fracture growth is possible, despite our viscosity and rate precautions, since the bottom barrier is not sufficiently strong to contain the fracture. The downward fracture growth results in the fracture contacting non-pay rock and considerable placement of proppant in regions that will not contribute to production. Also, the penetration of the fracture in rocks with high mobile-water saturation below 1,044 m (3,425 ft) may also make the well more prone to water production.

[0109] Since the typical frack injection profile was clearly not optimized for our model reservoir, we next simulated a frack technique wherein fracture tips were strengthened with solid material, thus restraining fracture growth, before a similar main fracking plan was implemented.

[0110] Employ the Specialized Pumping Technique to Halt Downward Fracture Growth.

[0111] To arrest fracture growth in downward direction (as needed for this exemplary reservoir), we simulated the same model well using one example of the inventive injection profile (see below). Where successful in the simulation, the same steps are to be followed in a reservoir having the same parameters that were simulated in the successful model.

[0112] Preferably, bottomhole pressure data is either obtained with the help of downhole gauges or with the help of calculated bottomhole pressures and used to control the rates of injection and thus pressures to achieve our tip strengthening goals.

[0113] In general, the procedure laid out below outlines the process of strengthening the blade-like edge of the entire fracture and concentrated at the fracture tips with preparatory steps shown below. Once this action is done, the actual planned fracking treatment, termed as “main treatment” will be pumped with an intention to fracture stimulate the well. The observations of rate and pressure made during the fracture tip strengthening process will influence the main treatment design.

[0114] 1) Breakdown the formation at a low injection rate not exceeding 5.0 bbl/min (0.8 m.sub.3/min), pump-in additional 10 bbl (1.59 m.sup.3) and shut-in the well to monitor the pressure decline to identify the closure pressure (Pc). The injection fluid should be a linear gel (non-crosslinked fluid) of small polymer loading such as 10 to 15 lbm/Mgal with viscosity in the range of 10 to 13 cP.

[0115] 2) Once Pc is determined, conduct a step rate test (“SRT”) with 15 lbm/Mgal (or thereabouts) linear gel or the type/polymer loading mentioned in step 1 to identify the fracture extension rate. Limit the maximum rate during the SRT to not more than twice the injection rate or 8.0 bbl/min (1.27 m3/min). Shut-in the well to obtain closure pressure and identify any change from previous value.

[0116] 3) Conduct a dedicated calibration injection test at the maximum rate during Step 2. Identify injection pressure profile i.e., the slope of net pressure versus time in log-log plot to determine geometry—whether the fracture is extending or increasing in height or if it is a radial fracture. Determine fracture closure pressure Pc from pressure fall-off after shut-in of injection test to determine the net pressure gain, formation leakoff, Young's Modulus, and fluid efficiency. Care must be taken to conduct this test with a linear gel of 10 to 15 lbm/Mgal specified above to limit the net pressures.

[0117] 4) Analyze the bottomhole injection pressures in Step 3 to determine the primary geometry and perform a pressure fall-off test to determine if fracture height growth was observed, which should generally be the case if a lack of barrier is suspected.

[0118] 5) Conduct a sand settling test with 100, 40/70 and 30/50 U.S. Mesh at 0.25 and 0.5 lbm/gal concentration in 10 lbm/Mgal and 15 lbm/Mgal linear gel fluids. Note down the settling times and select the fluid/sand concentration combination that results in faster setting for first cycle of fracture containment mentioned in step 6) below.

[0119] 6) Inject the fracture containment treatment using the combination identified in step 5). This will consist of low viscosity fluid, such as 15 lbm/Mgal linear gel with breakers where the total injection volume does not exceed 50% of the planned pad volume of the main treatment which is the actual fracture stimulation treatment planned for the well (see 0092). We used the following schedule (Table 2), wherein our tests showed that 40/70 U.S. mesh or 30/50 U.S. mesh may be pumped, but the data in FIG. 5 was generated with 100 mesh in small concentrations of 0.5 lbm/gal.

[0120] The slurry (fluid+solids) laden fluid must be flushed into the formation with the same linear gel, but over-flushing must be avoided. A freeze protect fluid may be pumped as the end of flush if the wells are in colder regions.

TABLE-US-00004 TABLE 2 Pump Schedule for Fracture Containment Treatment - Part I. SI = Shut in Rate Step Name (bbl/min) Volume Solid Solid Conc. 1 Linear Gel 6.0 15% Pad None None 2 Linear Gel 6.0 35% Pad 40/70 0.5 PPA mesh 3 Flush/SI 0 Wellbore None None

[0121] 7) Shut-in the well and again monitor the decline in pressure. The low viscosity fluid will allow quick settling of proppant and facilitate forming a proppant pack at the bottom edge of the fracture as shown in FIG. 5B. Continue to monitor the pressure until a closure is observed.

[0122] In our simulated model, downward growth was the problem, so we selected sands of 2.65 specific gravity to strengthen the bottom fracture barrier, or any specific gravity sufficient to allow the proppant to sink in the injection fluid being used. However, if the upward growth was problematic, neutrally buoyant or light weight proppant (such that the proppant tends to float in the injection fluid) may be pumped so strengthen upwardly growing fracture tips.

[0123] Pressure should be monitored closely during the injection period particularly when proppant is being in pumped. Where a ⅛ to ¼ slope can be identified in a log-log plot of net pressure versus time, there is sufficient indication that the fracture is now bound. If the slope is near zero or trending in the negative direction, the injection rate is reduced until a positive slope is observed.

[0124] 8) Optionally repeat the fracture containment treatment shown in Step 5, but replace the 30/50 or 40/70 U.S. mesh sand with 100 mesh sand as follows (Table 3).

TABLE-US-00005 TABLE 3 Pump Schedule for Fracture Containment Treatment - Part II. Rate Step Name (bbl/min) Volume Solid Solid Conc. 1 Linear Gel 6.0 15% Pad None None 2 Linear Gel 6.0 35% Pad 100 mesh 0.5 PPA 3 Flush/SI 0 Wellbore None None

[0125] 9) Shut-in the well and again monitor the decline in pressure. The 100-mesh sand will settle to the bottom of the fracture and consolidate the pack, especially when the actual hydraulic fracture stimulation is pumped after these preparatory fracture tip strengthening injection sequences. The 2-step fracture containment treatment (step 5 and step 7) offer double consolidation of the pack.

[0126] 10) Pump the designed fracture stimulation treatment at controlled injection rates, especially in pad stage, so that the fracture remains confined. In the pad stage of the treatment, the injection rates must not increase the rates at which the fracture containment treatments were pumped. The pad may consist of low gel loading cross linked fluid such as 20 lbm/Mgal borate cross linked fluid used in the simulation of example case and hence will be prone to generating net pressures. Use plots such as shown in FIG. 3A as guidelines to limit net pressures while constantly monitoring them.

[0127] If the fracture containment is successful, the final fracture geometry may be similar to the illustration shown in the simulations results shown in FIG. 6.

[0128] The advantages of the new method may include one or more of the following in any combination(s) thereof: [0129] Allow more precise placement of fractures. [0130] Improve the probability of placing optimal fractures with desired length and fracture conductivity and within the payzone. [0131] Prevent fractures from growing out of the payzone, especially into unwanted formations. [0132] Improve overall well performance.

[0133] The following references are incorporated by reference in their entirety for all purposes. [0134] PANDEY, V. J; AGREDA, A. J. (2014) New fracture-stimulation designs and completion techniques result in better performance of shallow Chittim ranch wells. SPE Prod & Oper 29 (4): 288-309. SPE-147389-PA. http://dx.doi.org/10.2118/147389-PA [0135] PANDEY, V. J.; RASOULI, V. (2021) Vertical growth of hydraulic fractures in layered formations. Presented at The Virtual SPE Hydraulic Fracturing Technology Conference, 4-6 May. SPE-204155-MS. dx.doi.org/10.2118/204155-MS. [0136] PANDEY, V. J.; RASOULI, V. (2021) A semi-analytical model for estimation of hydraulic fracture height growth calibrated with field data. J. Pet. Sci. and Eng. Volume 202, July 2021, 108503. doi.org/10.1016/j.petro1.2021.108503 [0137] PANDEY, V. J.; RASOULI, V. (2021) Fracture height growth prediction using fluid velocity based apparent fracture toughness model. Rock Mech. Rock Engg. J. doi. org/10.1007/s00603-021-02489-w. [0138] PANDEY, V. J.; FLOTTMANN, T. (2015) Applications of geomechanics to hydraulic fracturing: case studies from coal stimulations. Presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 3-5 February. SPE-173378-MS. doi.org/10.2118/173378-MS, [0139] MEYER B. R., BAZAN, L. W.; JACOT, H.; LATTIBEAUDIERE, M. G. (2010) Optimization of multiple transverse hydraulic fractures in horizontal wellbores. Presented at the SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania SPE-131732-MS. [0140] YU, W.; SEPEHRNOORI, K (2013) Optimization of multiple hydraulically fractured horizontal wells in unconventional gas reservoirs. J. Petrol. Eng. Article ID 151898, available online at hindawi.com/journals/jpe/2013/151898/. [0141] Step Rate Test (SRT) Guidelines—Texas, at rrc.texas.gov/oil-and-gas/publications-and-notices/manuals/injection-disposal-well-manual/summary-of-standards-and-procedures/technical-review/step-rate-test-guidelines/ [0142] Step Rate Test Procedure, at epa.gov/sites/default/files/documents/INFO-StepRateTest.pdf. [0143] UIC pressure falloff testing guideline at epa.gov/sites/default/files/2015-07/documents/guideline.pdf.