HYDRAULIC INTEGRITY ANALYSIS

Abstract

An economical process in which cement sheath integrity, perforation cluster spacing and frac plug integrity can be assessed for every frac stage, potentially leading to improvements in stimulation, completion, cementing and drilling practices. It is based on analyzing wellbore pressure responses occurring at key segments of the wireline pump-down and perforating operation and correlating the results among multiple frac stages and wells in a field or play. A special requirement is that the frac ball (ball check) is inserted in the frac plug and pumped to seat prior to performing perforating operations. A complementary benefit of this process is that selectively establishing injectivity in the most distant perforation cluster can be used to establish inhibited HCl acid (wireline acid) coverage across all perforation intervals for uniform reduction in near-wellbore tortuosity.

Claims

1. A process for testing a well bore in a hydrocarbon reservoir where the process comprises: a. providing a well bore in a hydrocarbon reservoir; b. run in the well bore with wireline and bottomhole assembly (BHA) consisting of a frac plug, a setting tool, multiple perforating guns and a casing collar locator, with the frac ball (ball check) preinstalled in the frac plug until said BHA reaches the build section of the well; c. initiate pumping water into the well at a rate of 5-15 bbl/min (0.79-2.4 m.sup.3/min) to drag the BHA to the desired location in the lateral; d. shut down to obtain an instantaneous shut in pressure (ISIP) and 3 to 5 minutes of shut-in pressure for establishing a pump-down pressure-falloff trend line; e. activate the setting tool to set the frac plug; f. move wireline up the well to place the gun string at the first perforating location; g. pump at 1-2 bbl/min (0.16-0.32 m.sup.3/min) to seat the frac ball in the frac plug, wherein seating said frac ball isolates previously treated intervals and forms a closed wellbore chamber from the frac plug to surface treating lines; h. pressure the wellbore to at least 1000 psi (6.9 MPa) above the pump-down shut-in pressure; i. close a plug valve in the surface treating line to isolate the pumping equipment and optional safety relief valve during this pressure test; j. monitor pressure for 3 to 5 minutes to check for pressure-tightness of the closed wellbore chamber; k. check for indications of fluid bleed-back and make adjustments if necessary to achieve a leak-tight seal; l. maintaining pressure, selectively perforate the first (toe-ward) cluster interval only and observe pressure falloff response for 3 to 5 minutes; m. evaluate for communication with or isolation from the previously treated intervals; n. move wireline up the well to locate the BHA away from the perforations; o. reopen the plug valve; p. inject into the first cluster at an injection rate of 2 bbl/min (0.32 m.sup.3/min) until treating pressure stabilizes or breaks back; q. increase the injection rate to 5-6 bbl/min (0.79-0.95 m.sup.3/min), continuing to pump until pressure re-stabilizes; r. pump for at least an additional minute; s. shut down to obtain instantaneous shut in pressure (ISIP) and evaluate pressure falloff response for 3-5 minutes; t. repeat steps (j) through (s) until all perforating guns have been discharged; u. discontinue injection after perforating is complete; and v. retrieve wireline, setting tool and spent guns and prepare the well for the next frac stage; w. repeat steps (b) through (v) until all frac stages have been completed; and x. produce hydrocarbons from said treated well bore.

2. The method according to claim 1, wherein said bridge plug is selected from a solid bridge plug, a composite bridge plug, a poppet-type frac plug, a poppet-type frac plug comprising a pre-installed check device, and a retrievable bridge plug.

3. The method according to claim 1, where step (s) includes evaluating for indication of communication with or isolation from the previously treated intervals.

4. The method according to claim 1, wherein inhibited HCl acid is used in conjunction with the pump-down process of step (q) to extend the fluid injection until the wireline acid arrives at the open perforation cluster, then discontinuing injection.

5. The method according to claim 1, wherein wireline acid is spotted across one or more perforations.

6. The method according to claim 1, wherein the injection rate of step (q) is increased to maintain the flow velocity through each perforation.

7. The method according to claim 1, wherein an optimized automated hydraulic integrity system is used to adjust integrity analysis parameters in real-time.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0025] The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee. A more complete understanding of the present invention and benefits thereof may be acquired by referring to the follow description taken in conjunction with the accompanying drawings.

[0026] FIG. 1 demonstrates the plug-and-perf method of stimulating multiple intervals in a horizontal well.

[0027] FIG. 2 shows a longitudinal starter fracture, which increases the breadth of fracturing along the lateral.

[0028] FIG. 3 shows a rate/pressure plot of a pump-down diagnostics operation.

[0029] FIG. 4 shows the a.) frac ball (ball check) being pre-installed in the frac plug and b.) bottomhole assembly.

[0030] FIG. 5 demonstrates a typical DFIT pressure profile via toe initiation valve in a cemented horizontal well.

[0031] FIG. 6 is an example of isolation from previously treated intervals.

[0032] FIG. 7 is an example of water hammer oscillations following perforating.

[0033] FIG. 8 is an example of water hammer oscillations during the shut-in period following the pump-down event.

[0034] FIG. 9 is an example of communication to previously treated intervals.

[0035] FIG. 10 is an example of sustained ball seat failure following the perforating event.

[0036] FIG. 11 is another example of sustained ball seat failure following the perforating event.

[0037] FIG. 12 demonstrates failure of frac plug during the injectivity test.

[0038] FIG. 13 shows a leak detected during the system pressure test.

[0039] FIG. 14 is an example of frac plug failure and wireline tension increase during injectivity test.

[0040] FIG. 15 tracks the incremental time to perform pump-down diagnostics.

[0041] FIG. 16 shows separation from the pump-down pressure-falloff line for a Baltic Basin case study.

[0042] FIG. 17 provides rate and treating pressure behavior during injectivity tests for a Baltic Basin case study.

[0043] FIG. 18 shows cement coverage as measured by Radial Bond Tool, in lateral section covered by fracturing stages 4-5.

[0044] FIG. 19 is a summary of pump-down diagnostics results on 27 wells.

[0045] FIG. 20 shows pressure isolation between stages as a function of cluster spacing distance.

[0046] FIG. 21 is an example of typical pressure behavior during pump-down diagnostics on a fracturing stage at 35 ft (10.7 m) cluster spacing.

[0047] FIG. 22 is an example of typical pressure behavior during pump-down diagnostics on a fracturing stage at 25 ft (7.6 m) cluster spacing.

[0048] FIG. 23 is an example of typical pressure behavior during pump-down diagnostics on a fracturing stage at 15 ft (4.6 m) cluster spacing.

[0049] FIG. 24 compares cumulative distributions of distance between the 1st perforation cluster (toe side) and closest casing collar or centralizer location for cases of good and poor isolation.

[0050] FIG. 25 is a scatter plot showing a comparison of well productivity against percent of fracturing stages with good pressure isolation. Each point represents a well that was completed using 15 ft (4.5 m) cluster spacing.

DETAILED DESCRIPTION

[0051] Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.

[0052] The general procedure for a pump-down diagnostic test is outlined below and depicted in the rate-pressure treatment chart shown in FIG. 3: [0053] 1. Run in the well with wireline and bottomhole assembly (BHA) consisting of frac plug, setting tool, multiple perforating guns and casing collar locator, with the frac ball (ball check) preinstalled in the frac plug (FIGS. 4a and 4b). Optionally, a solid bridge plug (of any material composition, including composite type) or poppet-type frac plug (featuring a pre-installed check device) can be used in lieu of a ball-check type frac plug. [0054] 2. When wireline reaches the build section of the well, initiate pumping water into the well at a rate of 5-15 bbl/min (0.79-2.4 m.sup.3/min) to drag the BHA to the desired location in the lateral (i.e., pump-down process). During the pump-down, wellbore fluid is entering previously treated perforation clusters. [0055] 3. Shut down to obtain an instantaneous shut-in pressure (ISIP) and 3 to 5 minutes of shut-in pressure for establishing a pump-down pressure-falloff trend line. [0056] 4. Following this brief shut-in period, activate the setting tool to set the frac plug. Then move wireline up the well to place the gun string at the first perforating location, which is the perforation cluster closest to the toe of the well. [0057] 5. Pump at 1-2 bbl/min (0.16-0.32 m.sup.3/min) to seat the frac ball (ball check) in the frac plug, isolating the previously treated intervals and forming a closed wellbore chamber from the frac plug to surface treating lines (or simply set one of the alternative wellbore-plugging devices noted previously). [0058] 6. Pressure the wellbore to at least 1000 psi (6.9 MPa) above the pump-down shut-in pressure. Then close a plug valve in the surface treating line to isolate the pumping equipment and safety relief valve (if applicable) during this pressure test. This will prevent potential bleed-back of fluid at the surface to enable selective evaluation of frac plug pressure integrity. Also monitor the wireline lubricator seal throughout the process to check for indications of fluid bleed-back and make adjustments if necessary to achieve a leak-tight seal. [0059] 7. Monitor pressure for 3 to 5 minutes to check for pressure-tightness of the closed wellbore chamber. [0060] 8. Maintaining pressure, selectively perforate the first (toe-ward) cluster interval only and observe pressure falloff response for 3 to 5 minutes, evaluating for communication with or isolation from the previously treated intervals. Then move wireline up the well to locate the BHA away from the perforations. [0061] 9. Reopen the plug valve. Inject into the first cluster at an injection rate of 2 bbl/min (0.32 m.sup.3/min) until treating pressure stabilizes or breaks back. Then increase the injection rate to 5-6 bbl/min (0.79-0.95 m.sup.3/min), continuing to pump until pressure re-stabilizes. Pump for at least an additional minute. Note: when using inhibited HCl acid (wireline acid) in conjunction with the pump-down process, extend the fluid injection until the wireline acid arrives at the open perforation cluster, then discontinue injection. Doing this will result in the acid being spotted across all subsequent perforation cluster locations, for more uniform reduction of near-wellbore tortuosity among the newly perforated clusters during acid displacement. [0062] 10. Shut down to obtain ISIP and evaluate pressure falloff response for 3-5 minutes, once again evaluating for indication of communication with or isolation from the previously treated intervals. [0063] 11. Perforate the remaining clusters, re-establishing injection at 2 bbl/min (0.32 m.sup.3/min) while perforating. Note: if wireline acid was spotted across perforations, it can optionally be displaced from the wellbore after perforating all clusters—if casing corrosion is a concern. Injection rate can be increased at this time. [0064] 12. Discontinue injection after perforating (and acid displacement if implemented) is complete; retrieve wireline, setting tool and spent guns and prepare the well for the next fracturing stage.
During the pump-down diagnostic process, surface pressure, injection rate and wireline data should be recorded to file at a fixed increment of 1 second. Pressure gauge resolution of 0.1 psi (689 Pa) or better is required.

[0065] The primary objectives of performing pump-down diagnostics are to evaluate the sealing characteristics of the frac plug, the capacity of the cement sheath to provide isolation from the previously treated intervals in the wellbore, and the impact of cluster spacing on treatment isolation. Secondary objectives include: ability to spot inhibited HCl acid (wireline acid) across the entire perforated interval, evaluation the components of pressure drop in the wellbore system including friction across the bottomhole assembly (BHA) during the pump-down operation for identification of restrictions in the wellbore, comparing pump-down ISIP, leak-off characteristics and water hammer responses among frac stages for assessing in-situ stress and near-wellbore fracture conductivity and locating areas of reservoir pressure depletion and enhanced permeability. For a variation of the last secondary objective, see Roark et al 2017.

[0066] The following examples of certain embodiments of the invention are given. Each example is provided by way of explanation of the invention, one of many embodiments of the invention, and the following examples should not be read to limit, or define, the scope of the invention.

Example 1: Diagnostic Signatures

[0067] Diagnostic fracture injection tests (DFIT's) conducted from a single initiation site near the toe of cased/cemented horizontal wells are characterized by an elevated instantaneous shut-in pressure (ISIP) followed by steep pressure falloff after shut-in. An example of a horizontal-well DFIT is exhibited in FIG. 5. The unstable pressure behavior indicates the existence of a tortuous, narrow flow path (longitudinal starter fracture) connecting the wellbore to a primary transverse fracture (Cramer and Nguyen 2013, McClure et al 2019). In this case, the friction pressure due to near-wellbore tortuosity=7615 psi (52.5 MPa) [unadjusted ISIP]−6742 psi (46.5 MPa) [adjusted ISIP]=873 psi (6.1 MPa). This DFIT exemplifies a cement-bonded interval in isolation from previously treated intervals (it is the only open interval in the well). It serves as a guidepost for pressure behavior attributable to interval isolation from previously treated intervals during pump-down diagnostic perforating and injectivity testing events.

[0068] The rate-pressure record of a pump-down diagnostic sequence conducted after the second fracturing stage on a well in the Baltic Basin is shown in FIG. 6. Perforation clusters in the well were uniformly spaced at 32.8 ft (10 m) intervals. A pump-down pressure-falloff trend line (green dashed line) was constructed for comparison to pressure responses of the closed-chamber perforating event and subsequent injectivity test. Pressure dropped modestly upon perforating, maintaining a level at least 600 psi (4.1 MPa) above the pump-down trend line.

[0069] The increase in surface pressure during the post-perforating shut-in period is the result of fluid expansion due to thermal recovery from wellbore cooling. The cooling resulted from the large volume of water injected during previous treatment stages. The pressure buildup indicates that closed-chamber conditions prevailed due to excellent wellbore tubular integrity and effective sealing from previously treated intervals by the frac plug. It also indicates that minimal if any fluid is leaving the wellbore due to lack of behind-pipe communication to previous intervals and the extremely low permeability of the contacted reservoir rock.

[0070] An oscillatory pressure signature (known as a water hammer) was observed upon perforating. It was generated by the gun detonation shockwave in a wellbore system lacking the ability to discharge fluid through the new perforations. This led to a strong change in momentum of the detonation pulse which favored the formation of the water hammer (Nguyen et al. 2021). A distinguishing characteristic is that the frequency of water hammer oscillations in this closed-chamber environment (see FIG. 7) was twice the frequency of water hammer oscillations produced following the end of the pump-down (see FIG. 8), since wellbore fluid during the pump-down injection was injected into a large hydraulic fracture system of constant-pressure conditions that was created during the previous treatment (Holzhausen and Gooch 1985). The oscillation decay rate was lower for the perforating event since friction is less when the travel path of the water hammer pulse is limited to the closed chamber wellbore.

[0071] A rate of 6 bbl/min (0.95 m.sup.3/min) was achieved during the injectivity test, with a tortuous near-wellbore flow restriction indicated by the very high surface treating pressure. When this characteristic is combined with the high, unstable ISIP and significant separation of shut-in pressure from the pump-down pressure-falloff trend line [˜1700 psi (˜11.7 MPa)], the injectivity test pressure response resembles a toe DFIT, providing strong indication that the new treatment interval is completely isolated from the previously treated intervals and that cement sheath quality is adequate in this part of the lateral.

[0072] The rate-pressure record of a pump-down diagnostic testing sequence conducted after the tenth fracturing stage on the same Baltic Basin well is shown in FIG. 9. A pump-down pressure-falloff trend line (green dashed line) was constructed for comparison to pressure responses corresponding to the closed-chamber perforating event and subsequent injectivity test. Pressure dropped rapidly upon perforating, to the same level and trend as the pump-down trend line, indicating the newly perforated interval was in communication with the previously treated intervals. A rate of 6 bbl/min (0.95 m.sup.3/min) was achieved during the injectivity test, with a high surface treating pressure indicating a tortuous flow restriction, but at a much lower magnitude than the previous example, i.e., 6800 psi (46.9 MPa) vs 8800 psi (60.7 MPa). The ISIP was high and unstable, again indicating an annular flow restriction. But pressure rapidly dropped to the same level and trend as the pumpdown trend line during shut in, confirming the diagnosis of communication with the previously treated interval(s) and suggesting that cement sheath quality is inadequate in this part of the lateral.

[0073] The rate-pressure record of a pump-down diagnostic testing sequence done in a well in south Texas is shown in FIG. 10. The single perforation cluster consisted of three 0.40 in diameter entry holes. Communication to previously treated intervals is indicated by rapid decreases in pressure to the pump-down pressure-falloff trend line following both the perforating event and injectivity test. But the observations that follow led to the conclusion that the main communication pathway was through the frac plug opening due to problems with the frac ball staying on the frac plug seat.

[0074] An abnormally high injection rate [over 8 bbl/min (1.3 m.sup.3/min)] was required to seat the ball for performing the pre-perforating closed chamber pressure test, indicating a defect in the ball or its seat. Surface treating pressure was very low throughout the injectivity test with total friction pressure of 210 psi (1.4 MPa), well less than the predicted friction pressure for injecting through three 0.40 in (10.2 mm) entry holes [495 psi (3.41 MPa)] but slightly greater than the predicted friction for injecting through an 1 in. (25.4 mm) opening in the frac plug [100 psi (0.69 MPa)].

[0075] Water hammer events were exhibited when pumping was ended following the injectivity test and the injection during perforating the remaining clusters. In this case, the water hammer oscillations appeared to be of the same frequency as the water hammer oscillations following the pump-down, another indication of strong connection to the hydraulic fracture system associated with previously treated intervals. Water hammer events associated with large conductive hydraulic fracture systems are indicative of through-pipe communication, since behind-pipe channels usually have some degree of flow-path restriction or tortuosity. Tortuosity results in the buildup of back pressure in the casing during injection, leading to restricted, slowly declining flow through the perforations after surface shut in, which suppresses water hammer development.

[0076] The rate-pressure record of a pump-down diagnostic testing sequence conducted in an offsetting well in south Texas is shown in FIG. 11. The pressure signatures were very similar to the previous case with the exception that the frac ball was easily seated using the normal injection rate [2 bbl/min (0.32 m.sup.3/min)] and a pressure buildup trend developed during the pressure test, indicating that closed-chamber conditions prevailed due to excellent tubular and wellhead integrity and effective sealing from previously treated intervals by the frac plug.

[0077] The rapid drop in pressure to the pump-down pressure-falloff trend line following the perforating event coupled with a water hammer oscillatory pulse indicated the frac ball instantly fell off seat or broke apart upon perforating. This enabled the decompressing wellbore fluid to surge through the unplugged opening in the frac plug, inducing a brief but strong rate pulse into a previously treated interval and causing a water hammer after the rate pulse terminated.

[0078] Subsequent activities exhibited an identical pattern to the previous test with no evidence that the frac ball reseated. Surface treating pressure was very low throughout the injectivity test with total friction pressure of 210 psi (1.4 MPa), well less than the predicted friction pressure for injecting through three 0.40 in (10.2 mm) perforations [605 psi (4.2 MPa)] but slightly greater than the predicted friction for injecting through an 1 in. (25.4 mm) opening in the frac plug [123 psi (0.85 MPa)].

[0079] The rate-pressure record of a pump-down diagnostic testing sequence conducted on a different treatment stage on the same well as above is shown in FIG. 12. Surface pressure during the post-perforating shut in period remained well above the pump-down pressure-falloff trend line, indicating isolation from previously treated intervals. During the early part of the injection test, pressure climbed sharply indicating sustained isolation but it dropped sharply as 9400 psi (64.8 MPa) was exceeded, resulting in a strong water hammer with the same implications as noted in the previous example but with one exception. In this case, the total friction pressure at the end of the injectivity test was 84 psi (0.57 MPa), less than the predicted friction for injecting through a 1 in. (25.4 mm) opening in the frac plug [100 psi (0.69 MPa)]. The reduced friction relative to the other cases combined with the sharp pressure break is indicative of destruction of the frac plug or mobilization of it past previously treated intervals.

[0080] Cases of direct communication through the wellbore due to an unseated frac ball or failed frac plug have been infrequently observed in pump-down diagnostics testing. These examples are included to show potential situations that could be encountered which could give misleading results in terms of measuring cement containment between stages.

[0081] The pressure test and perforating portion of pump-down diagnostics testing on another horizontal well in south Texas is shown in FIG. 13. Although the testing indicated isolation of the newly perforated interval from the previous frac stage, pressure declined throughout the pressure test indicating a leak in the system. A similar leak was indicated for the eight stages in the well that were evaluated with this process even though isolation from the previously treated intervals was indicated in all tests. Although the leak source may have the frac plug, the possibility exists that the pressure loss resulted from an upstream leak, in the casing string or more likely at the surface through pumping equipment or wireline lubricator. To achieve the proper diagnosis, it is important to eliminate surface bleed back and conduct a properly executed and documented pressure test of the casing and wellhead prior to pump-down activities.

[0082] Due to pre-installation of the frac ball in the frac plug, a complete perforation gun misfire following setting of the frac plug will result in a job delay, since the ability to do another pump-down is lost once frac plug is set. In those cases, an additional perforating gun run must be made to complete the perforating process by using a wireline tractor or coiled tubing. Using a perforating system featuring addressable-switch gun firing significantly reduces the chance of total misfire, since a gun that fails to detonate can be bypassed and the next gun in sequence can be fired. When using perforating systems with a diode-switch firing mechanism, any misfire in the gun sequence prevents firing of additional guns and forces premature retrieval of the BHA.

[0083] Another potential risk is failure to achieve injectivity into any perforation cluster without spotting HCl acid. This would require a coiled tubing run to spot and inject acid into the perforations. This is a very rare occurrence when tubulars and wellhead with high pressure ratings are used. To access this risk, prior treatments in the region should be researched to assess the potential for injectivity problems.

[0084] An infrequent problem with pump-down diagnostic injectivity testing was experienced in an early application and exhibited in FIG. 14. The sudden failure and mobilization of the frac plug down the lateral during the pump-down injectivity test exposed previously treated intervals, resulting in a pressure decline of 3637 psi (25.1 MPa) within a 2-second period. The calculated fluid expansion in the wellbore due to the sudden pressure loss was 2.77 bbl (0.44 m.sup.3) [i.e., 83 bbl/min (13.2 m.sup.3/min)]. When the fluid-expansion pulse was added to the surface injection rate of 10 bbl/min (1.6 m.sup.3/min), the downhole flow rate was calculated to be 93 bbl/min (14.8 m.sup.3/min) during that 2-second interval. The wireline tension increased from 1499 lbf (680 kg) to 4481 lbf (2033 kg) because of the flow surge. The increased wireline tension led to the BHA parting from the wireline at the weak point, necessitating a remedial effort to recover the perforating guns. A failed pressure test was a prelude to this event, indicating a pre-existing problem with the frac plug. In subsequent applications, reductions in injection rate and pressure differential across the frac plug were invoked upon a failed pump-down diagnostic pressure test or the injectivity test was bypassed altogether.

[0085] Time is money. The primary cost of performing pump-down diagnostics is the incremental time required to perform the work. Incremental time is calculated by determining the elapsed time between the start of the frac plug pressure test and the end of the injectivity pressure-falloff period. The incremental time required for a pump-down diagnostics project performed in south Texas is shown in FIG. 15. The statistical calculations on the incremental time follow—mean=12 minutes, 51 seconds; median=13 minutes, 51 seconds; standard deviation=57 seconds. When performed on a multi-well zipper fracturing project with a dedicated pump-down crew, there is often no additional time required to perform pump-down diagnostics since pump-down operations on one well can be performed while stimulating the offset well.

Example 2: Case Study—Baltic Basin

[0086] This case study is based on a horizontal well completed in the Ordovician Sasino formation in the Baltic Basin of northcentral Poland. The well was drilled to a true vertical depth of 9269 ft (2825.2 m) and had 4910 ft (1497 m) of lateral coverage within the Sasino interval. The casing long-string cement job design specified mixing and pumping 50 bbls (7.9 m.sup.3) of 15.0 lb/gal (1.80 kg/L) weighted spacer and 425 bbls (67.6 m.sup.3) of 16.0 lb/gal (1.92 kg/L) Class G cement, to be displaced with 3 bbls (0.5 m.sup.3) of weighted spacer and 343 bbls (54.5 m.sup.3) of 2% KCl water at a rate of 6 bbl/min (0.95 m.sup.3/min). Fluids and cement slurry were mixed and pumped as per plan. However, the top cementing plug failed to launch during job execution, leading to severe channeling within the lateral part of the wellbore as the lighter, lower viscosity displacement fluid fingered through and migrated above the denser, more viscous spacer and cement. This channeling phenomenon was evidenced by a leaking shoe joint and layer of set cement in the bottom part of the lateral which necessitated extensive cleanout work prior to doing the fracturing treatments. The plug-and perf treatment process was combined with limited entry treatment methods in performing 25 frac stages with 6 perforation clusters per frac stage. Clusters were spaced at 32.8 ft (10 m) intervals, which was well beyond the expected breath of the longitudinal starter fracture and associated transverse fractures. Pump-down diagnostics were performed during all 24 pump-downs. Rate/pressure plots for two of these pump-down diagnostic tests were previously shown in FIGS. 6 and 9. Pressure integrity tests and general pressure behavior during the diagnostic sequences indicated that the frac plug effectively isolated the wellbore from previously treated intervals in all cases. Yet as indicated in FIG. 16, there were numerous instances of rapid pressure decline to the pump-down pressure-falloff trend line following perforating and injectivity testing (i.e., zero pressure difference, indicated by a null value in the bar chart) in the toe-ward half of the well (stages 1-12). This behavior is indicative of annular communication to the previously treated intervals. It is attributable to inadequate cement sheath quality given the relatively wide spacing between perforation clusters (outside the breath of the longitudinal fracture component) and corroborates the diagnosis of channeling by the displacement water. Very good isolation from the previously treated intervals was exhibited in the 10 of 12 stages in the up-hole portion of the lateral, as evidenced by substantial positive pressure difference when compared to the pump-down pressure-falloff trend line following perforating and injectivity testing. This finding indicated that the channeling phenomenon was limited to the trailing part of the cement slurry.

[0087] Treating pressure tended to be much higher during the injection tests in fracturing stages demonstrating behind-pipe isolation from the previous treated intervals. This relationship is exhibited in FIG. 17. These injections had characteristics resembling the completely isolated toe-sleeve DFIT shown in FIG. 5. The average injection rate and maximum surface treating pressure for frac stages exhibiting isolation were 4.0 bbl/min (0.64 m.sup.3/min) and 8133 psi (56.1 MPa), respectively. The average injection rate and maximum surface treating pressure for frac stages exhibiting communication to the previous frac stage were 5.3 bbl/min (0.79 m.sup.3/min) and 6549 psi (45.2 MPa), respectively.

[0088] Incremental time for doing the diagnostic testing was calculated by determining the elapsed time between the beginning of the frac plug pressure test and the end of the injectivity pressure-falloff period. Here are the statistical calculations on incremental time for the 24 stages: mean=19 minutes; median=16 minutes; mode=16 minutes; minimum=13 minutes; maximum=34 minutes.

[0089] Cement quality in the annular gap between casing and drilled hole was evaluated prior to the fracturing treatments with an acoustic radial bond tool. Log results for a lateral section near the toe of the well, from 4200-4260 m (13,780-13,976 ft) measured depth are shown in FIG. 18. Although the log interpretation indicated excellent cement sheath quality, pump-down diagnostic testing indicated strong communication to the previous treated interval within this same interval, which is reasonable given the evidence of severe channeling of cement with displacement fluid. At least in this case, pump-down diagnostics provided a more accurate means of assessing cement sheath quality than the cement evaluation tool.

Example 3: Case Study—South Texas

[0090] Using the method listed in previous sections of the paper, pump-down diagnostics were performed on 27 horizontal wells drilled in a south Texas reservoir. Interpretable data was collected on a total of 304 stages for determining if there was pressure isolation from the previous stage.

[0091] Analysis of pressure responses. A summary of the testing outcomes for all wells is shown in FIG. 19. Results were widely variable, as positive indication of pressure isolation ranged from 0-100% of the evaluated stages per well. This chart also indicated that for many stages, pressure isolation was indeterminant (i.e., stage outcomes indicated as maybe) as pressure was only slightly delayed in declining to the pump-down trend line yet elevated surface pressure was observed during injectivity testing which indicated significant near-wellbore tortuosity. This behavior implied limited communication to the previously treated intervals and that a cement sheath was present and offering some resistance to behind-pipe flow.

[0092] The variable that had the strongest correlation with indicated pressure isolation between stages was cluster spacing. Stages that implemented wider cluster spacing had a higher likelihood of exhibiting good pressure isolation between stages. This relationship is illustrated in FIG. 20. For the wells in this study, cluster spacing was considered to be equal to the distance between the perforation closest to the heel of the well of the prior stage and the perforation closest to the toe of the well of the tested stage.

[0093] It is notable that abundant data was available for cases with 15 ft (4.6 m) cluster spacing (256 stages), less data was available for cases with 25 ft (7.6 m) cluster spacing (43 stages), and even less data was available for cases with 35 ft (10.7 m) cluster spacing (5 stages). However, stages with wider cluster spacing regularly had much larger surface pressure separations from the pump-down pressure-falloff trend line following the injectivity test, which supports the notion of cluster spacing being a dominant factor in pressure isolation between stages. The examples shown in FIGS. 21 through 23 are from the study area and represent pressure behavior for various cluster spacings.

[0094] To further evaluate the impact of cement quality on isolation characteristics, treatment isolation was correlated with the distance between the tested perforation cluster and the closest casing collar or centralizer. In a horizontal wellbore, the casing string tends to lay on the low side of the wellbore. A casing centralizer or casing collar with its larger OD forms an external upset that helps support the string and increases clearance on the low side, improving cement quality along the corresponding lateral interval (Haut and Crook 1979). Treatment isolation as a function of the distance between tested perforation clusters and the closest casing collar or centralizer is shown in FIG. 24. The pump-down diagnostic test results are categorized into good isolation and poor isolation groups. The calculated distance for both groups exhibits a similar trend on the cumulative distribution plot. This indicates mechanisms other than cement quality may be affecting treatment isolation among perforation clusters or intervals. A likely influencing mechanism is the breadth of the longitudinal starter fractures as noted in the Introduction section and depicted in FIG. 2. At some point, cluster spacing is going to fall within the range of hydraulic fracturing activity dictated by the longitudinal fracturing component, greatly increasing the frequency of communication between fracturing stages.

[0095] Well production analysis. Of the wells completed with 15 ft (4.6 m) cluster spacing, 16 wells have been on production for a minimum of 9 months and were compared against expected productivity, i.e., mass production rate divided by calculated reservoir pressure drawdown. The findings are shown in FIG. 25, indicating there is no correlation between well productivity and the degree of inter-stage pressure isolation as determined from pump-down diagnostics testing. The metric for expected well productivity was based on historical productivity of nearby wells with similar completion designs in the same geological area and was normalized for the lateral length. The underperformance of wells that are below 80% of expected productivity is believed to be caused by depletion from nearby parent wells. An extended zone of fracturing along the lateral for individual perforation clusters could result from the presence of pre-existing fractures and is a possible explanation for higher performing wells that show poor inter-stage isolation.

[0096] Despite these findings, when treatments are confined to targeted perforations and even better, targeted perforation clusters, the created far-field transverse fractures along the lateral will be more uniform in extent and distribution. Reservoir simulations indicate that hydraulic fracture uniformity leads to more uniform drainage of reservoir rock and superior long-term field economics. Short-term production results do not always capture the negative effects of irregular fracture coverage, especially when observations are limited to a small set of wells. For the South Texas case study wells, 15 ft cluster spacing may be too close to prevent inter-stage communication during the subsequent high-volume fracturing treatments, even when a high-quality cement sheath is present. Determining volume-dependent inter-stage communication tendencies is not within the scope of pump-down diagnostics testing.

Example 4: Automated Hydraulic Integrity Analysis

[0097] By developing a model of previous integrity analyses along with real-time data, an automated hydraulic integrity system can be deployed to 1.) generate a pump-down trend line and compute the amount of separation between that trend line and post-perforation and injectivity-test pressure responses and 2.) calculate the periodicity and decay rate of water hammer oscillations. This information is then processed using an algorithm routine to determine the existence or absence of inside-pipe and behind-pipe isolation of the new treatment stage from previously treated intervals. This same automated system can process databased operational data to dramatically reduce the time required to analyze historical pump-down data.

[0098] Pump-down diagnostics provide a means of checking if communication is occurring between a just-perforated fracturing stage and previously treated intervals, which can serve as a key performance indicator for treatment control and cement sheath integrity. For moderate perforation cluster spacing (e.g., 33 ft (10 m) between clusters), pump-down diagnostics have been shown to provide a more reliable diagnosis of cement sheath quality along the lateral than cement bond log evaluation. For close perforation cluster spacing (e.g., 15 ft (4.6 m) between clusters), pump-down diagnostic results for stage isolation may be more affected by the breadth of the longitudinal starter fracture and associated hydraulic fracturing activity than by the cement sheath quality. The timing and oscillatory frequency of water hammer events observed during pump-down diagnostic operations offer additional clues to the nature of inter-stage communication. Pump-down diagnostics are time efficient and economical, typically requiring about 15 minutes per frac stage. Pump-down diagnostics risk factors can be effectively mitigated by using an addressable-switch select-fire perforating system, applying area experience to assess fracture initiation behavior in the absence of spotting HCl, and modifying or foregoing the injectivity test if the frac plug fails the pressure test.

[0099] In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as a additional embodiments of the present invention.

[0100] Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.

REFERENCES

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