Method and apparatus for automated pressure integrity testing (APIT)

Abstract

A method of conducting a pressure integrity test for an underground formation includes: whilst fluid is supplied to and/or released and returned from the underground formation under pressure, using an automated monitoring and supervisory system to: monitor the pressure of the fluid being supplied to and/or returned from the underground formation in real-time, monitor a volume of the fluid that is supplied to and/or returned from the underground formation in real-time, determine one or more relationship(s) for the monitored pressure and the monitored volume as the pressure and the volume vary relative to each other and/or with time during the real-time monitoring thereof, and analyze the monitored pressure and volume data using the one or more relationship(s) either in real-time or after completion of the pressure integrity test in order to provide information and/or warnings concerning at least one parameter relating to the underground formation.

Claims

1. A method of conducting a pressure integrity test for an underground formation whilst fluid is supplied to and then released and returned from the underground formation under pressure, the method comprising: using an automated monitoring and supervisory system to monitor the pressure of the fluid that is being supplied to and returned from the underground formation in real-time; using the automated monitoring and supervisory system to monitor a volume of the fluid that is being supplied to and returned from the underground formation in real-time; using the automated monitoring and supervisory system to determine one or more relationship(s) for the monitored pressure and for the monitored volume in real-time as the pressure and the volume vary relative to each other and/or with time during the real-time monitoring thereof; and using the automated monitoring and supervisory system to analyze the monitored pressure and volume data using the one or more relationship(s) in real-time in order to provide information and/or warnings in real-time, wherein the information and/or warnings concern one or more of: parameters relating to the underground formation, performance of the pressure integrity test during testing, an outcome of the pressure integrity test, quality of the monitored pressure and volume data, or test metrics; wherein the method is used after fluid has been supplied to the underground formation under pressure and whilst the fluid pressure is being released and fluid is returned from the underground formation, the pressure and the volume of the returned fluid is monitored in real-time, and the step of analyzing involves determining expected pressure and volume values based on a hydrostatic approximation of the pressure inside the underground formation and comparing the real-time monitored values to the expected values.

2. The method of claim 1, wherein a volume sensor is configured to allow for measurements in steps of 5 liters or less.

3. The method of claim 1, wherein a pressure sensor is located top-side at a point where the pressure is equivalent to, or has a known relationship to, the pressure at the point of entry of the fluid into the underground formation.

4. The method of claim 3, wherein the pressure sensor has a resolution of 0.5 MPa or lower.

5. The method of claim 4, wherein the pressure sensor has a pressure rating or 5000 psi or lower, and is isolatable or removable to allow for high pressure use of the automated monitoring and supervisory system during normal use, and measurement of pressure with the pressure sensor if the pressure integrity test is a lower pressure integrity test.

6. The method of claim 1, wherein a pressure sensor and a volume sensor are able to operate at a sampling rate of 5 seconds or less.

7. The method of claim 1, wherein the method is used during supplying of the fluid to the underground formation and the step of analyzing involves a real-time step of, during the pressure integrity test and whilst the fluid is being supplied to the underground formation, calculating a forecast that predicts future values of the pressure and the volume for a look-ahead time period and determining if the future values will cross outside of an envelope defining allowable pressure and volume values.

8. The method of claim 7, wherein the step of calculating the forecast uses at least one relationship determined in connection with the monitored pressure and volume data, and the at least one relationship is determined based on a set sample size for recent sampling points.

9. The method of claim 8, wherein the step of calculating the forecast is based on looking back over the monitored pressure and volume data for a time period equivalent to the look-ahead time period.

10. The method of claim 1, wherein the step of analyzing involves a real-time step of, during the pressure integrity test and whilst the fluid is being supplied to the underground formation, gathering information relating to quality of data available for monitoring the pressure and/or the volume, assessing the information relating to the quality of the data including determining potential quality of interpretation of the data, and providing an indication of quality of results of the pressure integrity test based on the information relating to the quality of the data.

11. The method of claim 10, wherein the information relating to the quality of the data includes one or more factors of sampling intervals, availability of volumetric flowback data, availability of downhole data in addition to topside data, whether the data is digital or analog, linearity of pump-in compliance, magnitude of the pump-in compliance, number of pump-in cycles, and/or fracture closure pressures determined using different methods and/or in different test cycles, wherein the indication of the quality of the results of the pressure integrity test is a ranking based on the one or more factors.

12. The method of claim 11, wherein factors that might result in a first, lowest ranking include one or more of: unusable data, non-linear pump-in compliance and/or fracture closure pressure values determined based on top side measurements having greater than 0.1 SG between maximum and minimum values.

13. The method of claim 12, wherein a second ranking higher than the first ranking is assigned if none of the factors for the first ranking are present but the information relating to the quality of the data indicates one or more of: a sampling rate for topside data being too high, the pump-in compliance being excessively high, and/or fracture closure pressure values determined based on downhole measurements having greater than 0.1 SG between maximum and minimum values.

14. The method of claim 13, wherein a third ranking higher than the second ranking is assigned if none of the factors required for the second ranking are present but the information relating to the quality of the data indicates one or more of: an absence of downhole data, a sampling rate for downhole data being too high, an absence of volumetric flow-back data, pump-in compliance being more than 1.5 times the expected value, a failure to have a minimum number of pump in cycles, fracture closure pressure values having greater than 0.05 SG difference, total flowback volume being less than 50% and/or closed fracture compliance being in excess of twice the expected fracture compliance.

15. The method of claim 14, wherein a fourth ranking higher than the third ranking is assigned if none of the factors required for the third ranking are present but the information relating to the quality of the data indicates one or more of: topside data sampling rate exceeding 1 second, downhole sampling rate exceeding 2 seconds, volumetric flowback sampling rate being above two seconds, pump-in compliance being more than 1.25 times the expected value, closed fracture compliance being more than 1.75 times the expected value, total flowback volume being less than 70%, and/or a failure for all fracture closure pressure interpretations to be within 0.02 SG.

16. The method of claim 15, wherein a fifth ranking higher than the fourth ranking is assigned if none of the factors required for the first ranking to the fourth ranking are present.

17. A computer program product comprising instructions that, when executed, cause a data processing apparatus to operate an automated monitoring and supervisory system whilst fluid is supplied to and/or released and returned from an underground formation under pressure, the automated monitoring and supervisory system being operated in accordance with the method of claim 1.

18. An automated monitoring and supervisory system for conducting a pressure integrity test for an underground formation, the automated monitoring and supervisory system being configured to operate in accordance with the method of claim 1.

19. The method of claim 1, wherein a volume sensor is configured to allow for measurements in steps of 2 liters or less.

20. The method of claim 1, wherein the test metrics include at least one of leakage rate, trapped air, unstable pump rate, plugged choke, system compliance, or surface pressure and surface volume.

21. A method of conducting a pressure integrity test for an underground formation whilst fluid is supplied to and/or released and returned from the underground formation under pressure, the method comprising: using an automated monitoring and supervisory system to monitor the pressure of the fluid that is being supplied to and/or returned from the underground formation in real-time; using the automated monitoring and supervisory system to monitor a volume of the fluid that is being supplied to and/or returned from the underground formation in real-time with a volume sensor capable of measuring the volume of the fluid in steps of 10 liters or less and with a sampling rate of 5 seconds or below; using the automated monitoring and supervisory system to determine one or more relationship(s) for the monitored pressure and for the monitored volume as the pressure and the volume vary relative to each other and/or with time during the real-time monitoring thereof; and using the automated monitoring and supervisory system to analyze the monitored pressure and volume data using the one or more relationship(s) either in real-time or after completion of the pressure integrity test in order to provide information and/or warnings concerning one or more of: parameters relating to the underground formation, performance of the pressure integrity test during testing, an outcome of the pressure integrity test, quality of the monitored pressure and volume data, or test metrics; wherein the method is used after fluid has been supplied to the underground formation under pressure and whilst the fluid pressure is being released and fluid is returned from the underground formation, the pressure and the volume of the returned fluid is monitored in real-time, and the step of analyzing involves determining expected pressure and volume values based on a hydrostatic approximation of the pressure inside the underground formation and comparing the real-time monitored values to the expected values.

22. The method of claim 21, wherein the step of analyzing involving determining a fracture closure pressure based on the monitored pressure and the monitored volume.

23. The method of claim 22, wherein the monitored pressure and volume data are used to find a system stiffness for a reaction of the underground formation to the pressure integrity test, and to identify a point when a change in stiffness indicates opening or closing of a fracture.

24. The method of claim 23, wherein the fracture closure pressure is determined by analysis of a plot of pressure against volume as the fluid is supplied to the underground formation.

25. The method of claim 23, wherein the fracture closure pressure is determined by analysis of a plot of a square root of pressure against time as the fluid is supplied to the underground formation.

26. The method of claim 23, wherein both of a plot of pressure against volume and a plot of square root of pressure against time are used to find values for the fracture closure pressure, and the fracture closure pressure values are compared.

27. The method of claim 23, wherein multiple cycles of supplying and releasing fluid to/from the underground formation are carried out, with values for the fracture closure pressure being determined from two or more of the multiple cycles, and the fracture closure pressure values for different cycles being compared.

28. The method of claim 21, wherein the test metrics include at least one of leakage rate, trapped air, unstable pump rate, plugged choke, system compliance, or surface pressure and surface volume.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) Certain preferred embodiments of the invention will be described below by way of example only and with reference to the accompanying drawings in which:

(2) FIG. 1 shows a physical overview of an automated pressure integrity testing system;

(3) FIG. 2 is a plot of pressure against time during three cycles in an XLOT test;

(4) FIG. 3 shows pressure against a volume plotted for the same test;

(5) FIGS. 4 and 5 include more detail for the 1.sup.st cycle in the test of FIG. 2;

(6) FIGS. 6 and 7 show more detail for the 2.sup.nd cycle in the test of FIG. 2;

(7) FIGS. 8 and 9 show more detail for the 3.sup.rd cycle in the test of FIG. 2;

(8) FIGS. 10 and 11 illustrate plots used for determining the fracture closure pressure during the 1.sup.st cycle;

(9) FIGS. 12 and 13 show similar plots relating to fracture closure pressure for the 2.sup.nd cycle; and

(10) FIGS. 14 and 15 show similar plots relating to fracture closure pressure for the 3.sup.rd cycle.

DETAILED DESCRIPTION OF THE INVENTION

(11) The example embodiment is a new supervisory system providing real-time test analysis and automated result interpretation from pressure integrity tests, leak-off tests and extended leak-off tests. The system provides Automated Pressure Integrity Tests (APIT) as distinct from the manual tests used in the prior art. Based on a minimum of preconfigured user input, the system covers all test phases, from pressurization, fracture propagation to shut-in and flowback. Rather than relying on computationally intensive modelling of downhole physics, we apply regression techniques to relate surface pressure to injected fluid volume, shut-in duration and volume or time in flowback.

(12) In summary, system compliance and fluid leakage rates are determined prior to leak-off using a non-linear regression model. The calibrated model is then used to generate prediction intervals for detecting leak-off and fracture pressures. Extended leak-off test interpretation is based on the system stiffness approach, in which fracture closure is associated with a reduction in system compliance. We apply change-point regression to determine the fracture closure pressure during shut-in and during flowback. The supervisory system identifies unexpected test behavior and triggers warnings by continuously evaluating key test metrics such as leakage rate, system compliance and surface pressure during each test phase.

(13) Low-pass filtering combined with regression techniques ensure that the system is capable of analyzing field tests of variable quality and with noisy surface sensor measurements. The performance of test is assessed based on historical tests that are representative of the variation in possible pressure-volume behaviors and with typical noise levels on input sensor signals. The system of the example embodiment provides more reliable determination of leak-off and fracture pressures, fracture propagation and fracture closure pressures than manual techniques used in the prior art. The addition of real-time supervisory functionality in addition to standardization of test interpretation and analysis are immediate benefits of implementing this system. In addition, all data can be stored for future analysis and audit, as well as for use in improving and optimizing the operation of the supervisory system itself.

(14) Various abbreviations are used herein as set out below:

(15) TABLE-US-00001 Term Definition APIT Automated Pressure Integrity Tests FIT Formation Integrity Test PIT Pressure Integrity Test LOT leak off test XLOT Extended leak-off test LCM lost Circulation Material MODU Mobile Offshore Drilling Unit NCS Norwegian Continental Shelf BOP Blow out preventer PLC Programmable Logic Computer PSV Pressure Safety Valve PWD Pressure While Drilling TBD To be decided TS Technical sidetrack GS Geological sidetrack P&A Plug and abandon FBP Formation Breakdown Pressure FCP Fracture Closure Pressure EMW Equivalent Mud Weight FPP Fracture Propagation Pressure FRP Fracture Re-opening Pressure ISIP Instantaneous shut-in Pressure TVD True vertical depth

(16) As noted above, existing pressure integrity tests involve a manual procedure for operating the pumps and chokes as well as manual interpretation of the test results. The high dependency on manual processes also results in a low consistency and repeatability of tests. In addition to that, the industry needs a standardized and sustainable robust workflow system to meet the challenges of data logging, data storage and reporting.

(17) The APIT system described herein makes a step-change for pressure integrity tests, leak-off tests and extended leak-off tests to enable increased use of drilling automation to allow for faster drilling with less trouble & cost. This new supervisory system provides real-time test analysis and improved automatic results interpretation of PIT, LOT and XLOT. The functionality of APIT system could perform pressure tests for qualification of formation as barrier in P & A operations and may be used in mini-frac application for openhole dual packer testing. The solutions of APIT system are reliable and orientation & structure of the GUI will be user friendly. The system automates and improves on the existing processes, and executes, interprets and stores the data the same way every time. Thus, the APIT system provides the operator with a familiar result for a familiar testing regime, but does so with improved speed, accuracy and reliability as well as providing additional capabilities not possible with the prior art, including real-time analysis, real-time quality reports, on-going warnings or ‘flags’ relating to problems or failures during testing, and test metrics provided automatically and in real-time.

(18) The main steps of the existing PIT, LOT and XLOT test procedures are summarized below. A typical PIT or LOT is conducted by drilling out a few meters of new formation below the last set casing, closing the well, and pressurizing the well up to a predetermined target test pressure (for PIT) or until a deviation from a nearly linear pressure-volume curve is observed (for LOT). A representative PIT or LOT procedure is as follows:

(19) 1. Drill out casing shoe and cement and clean rat hole

(20) 2. If using lost circulation material (LCM): Drill approximately 1 meter new formation Place lost circulation material (LCM) from bottom hole and into casing/liner Pressurize the LCM pill and hold for 15 minutes

(21) 3. Wash to bottom and drill approximately 3 meters new formation Circulate clean and condition mud

(22) 4. Pull up into casing string and close BOP. Line up to pump down drill string or kill/choke line. Conduct a pressure test of the surface equipment. Check any leaking

(23) 5. Pump to reference pressure

(24) 6. Pump into well with constant rate to: PIT: Predetermined target test pressure LOT: Observed leak-off point

(25) 7. Shut-in the well and monitor pressure for at least 15 minutes

(26) 8. Bleed off to reference pressure

(27) The test is sometimes carried out with LCM that extends from the casing or liner and 1 meter down. This serves the main purpose of sealing off the formation-cement-casing interface to avoid fluid losses into permeable formations above.

(28) An XLOT follows the same initial steps as above, but now a sizable fracture should be propagated into the formation and away from the immediate stress concentration region surrounding the wellbore. Rather than pumping to target test pressure (PIT) or leak-off (LOT), more fluid is pumped and usually two pressurization and de-pressurization cycles are performed:

(29) 6. Pump with constant rate to formation breakdown (FBP)

(30) 7. Pump an additional ˜1 m.sup.3 fluid to propagate the fracture into virgin formation

(31) 8. Shut-in the well for a predefined duration, typically 10-15 minutes for the first XLOT test cycle

(32) 9. Flowback to the surface over a fixed choke opening until pressure reaches reference pressure

(33) 10. Shut-in well and monitor for rebound pressure and fluid flow from fracture for 5 minutes

(34) 11. Repeat test with or without a shut-in period

(35) The cement service company is normally not directly involved in designing the formation integrity test, but they are provided with work instructions for the steps above. Work instructions are typically more detailed for XLOTs than for PIT and LOT. It is common that an XLOT procedure is reviewed by the company organization, both onshore and offshore. Cement service provider personnel will then be involved to agree on how to line up the cement unit for the upcoming test.

(36) A person from the cement service provider will operate the cement unit during the test, while a company representative, such as a geologist, observe. The cement unit operator will act on the orders of the company representative during the tests. On newer level B cement units, the test results are logged digitally and displayed on a computer screen as the test progresses. On older level A cement units, test results are manually read by the operators and plotted by hand on a sheet of paper.

(37) After the test is completed, a preliminary test evaluation is performed on the basis of the surface measurements from the cement unit. The best available data are to be used for the final test evaluation, which is normally performed onshore using downhole memory data from bottom-hole assembly tools. This data is usually available after tripping out of the hole. While the surface pressure measurement is influenced by the PVT behavior of the drilling fluid, casing and formation expansion as well as fluid viscoelasticity; memory data provide direct measurements of the downhole pressure at the casing shoe at high temporal resolution. Downhole data are thus clearly superior when it comes to accurate determination of minimum principal in-situ stress and other test pressures.

(38) The proposed APIT system will follow a similar workflow to the existing tests and its functionalities will work on the basis of the surface measurements (pressure, fluid volume) from the cement unit. The surface sensors should be able to produce sufficient accuracy, as explained above, to allow for high quality test results to be produced. In some cases this may require additional or upgraded sensors. Existing installations may often not have sufficient monitoring capabilities, in particular for volume measurements.

(39) The APIT system of the example described below uses a cement unit that can be operated remotely i.e. so called level B units or B type units. This is not essential since the A type unit can also be used, but the level B unit is the most attractive candidates for implementation on the APIT system in view of the additional synergistic advantages of having remote operation for the cement unit in conjunction with automatic monitoring of the pressure integrity tests. Consequently, the discussion in the ensuing sections will focus primarily on level B units.

(40) There are two primary types of cement units, type A and type B, that differ mainly by how they are operated. There are currently no industry-standard definitions, but Halliburton suggests the following category definitions: Level A: Pressure testing and pumping from a safe area using a touch screen Level B: Remote controlled unit Level C: Remote control from off-site location (another rig or from onshore)

(41) Here, a level A unit represents a pressure testing facility meeting the minimum regulatory requirements for offshore drilling units. A typical level A unit on the Norwegian Continental Shelf (NCS) dates from the late 1980s or early 1990s. These units are operated mechanically, by air and by hydraulics. A level B cement unit is distinguished from level A by a remote control system, making it operable from a control room on the same installation.

(42) A third level, a level C is used in the Statoil system to identify units that can potentially be operated from onshore. A network link to onshore is thus the only difference between a level B and a level C unit, which implies that level B units rather easily can be extended to level C functionality. The Valhall injection platform is currently the only installation with an operable level C unit.

(43) TABLE-US-00002 TABLE 1 Cement unit overview for Statoil fixed installations. Installation name Cement unit level Oseberg B Level B Oseberg Ø Level B Crane Level B Gullfaks A Level B Gullfaks B Level B Snorre A Level B Statfjord A Old level A or level B* Statfjord B Old level A or level B* Statfjord C Old level A or level B* Heidrun Level B (new in 2016) *Statoil has upgraded the original level A cement units installed on the Statfjørd installations.

(44) The two-level unit categorization (level A and level B) should be applicable for other cement unit providers and other operators as well.

(45) The proposed APIT system takes real-time pressure and volume measurements obtained at a surface location whilst fluid is being supplied to or released from and returned from the formation. The APIT system is a computational software based system which performs real-time test analysis and automated result interpretation of FIT/LOT/XLO. This system includes a hydrostatic model, parameters estimation model, statistical approach, regression & curve fitting techniques and combines all these elements into a supervisory control system to automatically execute formation integrity tests. Based on the model assumptions and operator inputs it gives output to the existing cementing unit based on measurements and anticipated pressure build-up behavior.

(46) The model is based on surface pump pressure measurements to measurements of injected fluid volume, and fitting the model to test observations by calibrating regression parameters corresponding to fluid compressibility, air trapped, casing and open-hole expansion and pressure-driven filtration losses to the formation.

(47) The methods require fewer configuration data and can be based on time-resolved surface measurements of cement pump, pressure and displacement tank volume. Test interpretation and safeguarding with the APIT system can be based on these methods, which provide consistent evaluation of test results by using pre-defined confidence levels for hypothesis testing of statistical significance.

(48) The algorithms in APIT system are relatively simple and it is anticipated that the system can be seamlessly implemented into the existing cement unit control system and data logging system. This is perceived to be a positive aspect of the system, as the implementation and use of the system will involve minor changes on the hardware side and not have substantial influence on work procedures associated with preparing the unit for pressure integrity tests.

(49) The physical elements of the example APIT system correspond generally to a conventional level B cement unit, with some notable modifications and new minimum requirements. FIG. 1 shows an overview of an example APIT system. As is typical in the prior art displacement tanks 32 are coupled to a cement pump 12 that is arranged to provide cement to the underground formation 42 in a standard fashion. Normal monitoring and control systems 14 can be present, and they are augmented by the APIT system 26. As well as the addition of new software/monitoring elements the APIT system also necessitates the need for suitable volume and pressure measurements. A preferred minimum capability for volume measurement is real-time measurement in 10 liter steps and a preferred minimum capability for the pressure measurement is a resolution of 0.5 bar, with both pressure and volume measurements being able to be sampled at a sampling rate of 1 or 2 seconds, or less. In the example the volume measurement takes place at the displacement tanks 32 via level sensors 28. The pressure measurement can be in the flow line between the cement pump 12 and the underground formation 42 and in this case uses a pressure sensor 36. A density meter 34 is also present. The various sensors 28, 34, 36 provide readings to the level B control system 14, and this passes sensor data 16 to the APIT system 26.

(50) An additional requirement for the cementing unit for best operation of the APIT system is that there should be a shut-in valve 22 in addition to the flowback choke valve 24 that is typically present. The APIT system 26 interacts with the existing remote and local operator stations 14 (for example a conventional level B type system) by receiving the sensor data 16 and returning, in real-time, advisory messages, warnings and safety triggers via communication channel 18. The APIT system will further provide automatic test interpretation and generate test reports including test metrics and an indication of the quality of the test data and of the interpretation thereof. In addition to the real-time monitor data for volume and pressure the APIT system is further provided with parameters including well geometry, compress ability of the fluid, temperature, casing shoe test data and water depth, and configuration data such as a setting for target pressure and a prediction or expected prognosis relating to the test result. The APIT system 26 and the local control system 14 can be coupled via a communication link 38 to an onshore operations center 40.

(51) In the example of FIG. 1 the underground formation 42 is connected to the cement pump 12 via a stand pipe manifold at the drill floor 20 and via a choke kill line 44, with these connections being made in conventional fashion. The underground formation 42 is a wellbore with a blow-out protector 46, which is closed during the pressure integrity testing, and beneath which there are conventional casing 48 and cement 50 layers. A possible fracture 52 is indicated.

(52) The structure and orientation of the APIT system was designed based on following functionalities: Hydrostatic model—this model is required for setting the system tolerance limit of APIT system. State detection model—it is needed for calibration and to detect different phases of FIT/LOT/XLOT followed by pressure-volume curves. Regression model—Statistical approach to calculate fitting parameters for state detection model. Contingency estimators—detection of unexpected events (trapped air. cement channel, casing expansion, casing shoe leakage, etc.). Control panel—for system in automation mode. Qualification of formation as barrier-Assessment of the minimum principal stress.

(53) Test pressures such as leak-off pressure, formation breakdown pressure and fracture closure pressure are identified automatically by well-known statistical methods; e.g.; change point regression techniques and dynamic search for straight lines and quadratic curves.

(54) The functionalities of APIT system have been calibrated against field test data to confirm that the APIT system works in field applications. FIGS. 2 to 15 show an example of the output of the APIT system based on real test data.

(55) In this example the test configuration was as set out in the table below.

(56) TABLE-US-00003 TABLE 2 Wellbore data and system configuration Parameter Value Rig Test Rig Date of test Oct. 10, 2010 Test type XLOT Well ABC123 Wellbore RT-MSL RT-cement unit TVD Casing section [in] 8 1/2 Casing depth TVD RT [m] 1650.0 Casing depth MD RT [m] Downhole sensor depth TVD RT [m] Well inclination [deg] Well azimuth [deg] Installation type floater Bottom hole TVD [m] 1650.0 Water depth [m] Total system volume [m3] 171.0 Pressure sensor depth [m] 39 Data type downhole Data time step duration [sec] 2 Reference pressure [bar] 210 Injection rate [l/min] 100.0 Flowback choke opening [%] Expected formation closure pressure [bar] 35.08 Volume to inject after formation breakdown [I] 1000 Drilling fluid type WBM Drilling fluid density [sg] 1.250 Casing test compliance [l/bar/100 m3] 6.0 Rig specific friction pressure gradient [bar/m] Estimated hydrostatic BHP [bar] 197.5 Use LCM

(57) In this table the blank fields indicate data/parameters that could optionally be supplied and might be used by the APIT system, but were not used in the example.

(58) The test was carried out in a generally conventional fashion for XLOT, with the addition of the automated supervisory system. The monitored pressure and volume, as recorded in real-time, are shown in FIGS. 2 to 15.

(59) FIG. 2 shows pressure against time for extended leak off test having typical characteristics. The test starts with a basic test in order to estimate the fracture pressure of the open hole section and test the integrity of the cement. Pump in continues until first the leak off pressure and then the formation breakdown pressure is reached. After the formation breakdown pressure pumping continues but the fracture volume tends to increase faster than the fluid pump in rate, which results in a distinct and rapid pressure decline stop the pressure then stabilizes at the fracture propagation pressure, which corresponds to the balance between fracture volume generation and the fluid pumping rate. Pumping is then stopped, and the pressure is equal to the instantaneous shut-in pressure.

(60) At the end of the shut-in phase, the pressure should stabilize, indicating pressure integrity at the casing shoe and of the formation. The APIT system will issue a message in the shut-in period when the system has found a stabilized pressure. The check for whether the pressure is stable is divided into three parts:

(61) 1. Is the pressure decrease the last 10 minutes less than 2% of the downhole pressure?

(62) If the pressure decrease the last 10 minutes is less than 2% of the downhole pressure (p.sub.dh):
p(t−10)−p(t)<0.02p.sub.dh,

(63) the message ‘Pressure decrease is less than 2% of BHP during the last 10 minutes’ is issued.

(64) 2. Is pressure decline rate less than the maximum limit?

(65) We fit the measurements to Δp(t)=at+b, where t is the time since shut-in. The decline rate (a) is compared to a maximum decline rate, a.sub.max (bar/min):

(66) $a_{\max} = \frac{φ_{\max}}{V_{0} C},$

(67) where φ.sub.max is the maximum allowable volume flux (default is 2 l/min), V.sub.0 is the system volume and c is the system compliance determined from the pump-in phase. If the pressure decline rate is less than the maximum pressure decline rate (a<a.sub.max) for 60 seconds, the message ‘The volume loss rate is less than 2 l/min’ is issued.

(68) 3. Is the pressure decline rate decreasing?

(69) The pressure measurements from the last 6 minutes are divided into 3 intervals, where each interval is 2 minutes:
p.sub.1=[p(t−6):p(t−4)],p.sub.2=[p(t−4):p(t−2)]
and
p.sub.3=[p(t−2):p(t)]
The pressure decline rate, a, is estimated for each interval: a.sub.1, a.sub.2 and a.sub.3, using the same regression method and formula as in 2. The pressure decline rate is decreasing if a.sub.3<a.sub.2 and a.sub.2<a.sub.1.

(70) The pressure is defined as stable if the criteria (points 1-3) are met:

(71) $p (t - 10) - p (t) < 0.02 p_{dh}$ $a < a_{\max}$ $a_{3} < a_{2} and a_{2} < a_{1}$

(72) If the system defines the pressure as stable, the stable shut-in pressure, p.sub.SIP, is set to the value of the pressure measurement 10 minutes before the pressure is declared as stable.
p.sub.SIP=p(t−10)

(73) During the first cycle a fixed shut-in period is taken before the well is flowed back. During shut-in the system pressure will gradually decrease due to fluid losses through the fracture faces depending on the duration of the shut-in period drilling fluid filtration properties and formation permeability the fracture might close during shut-in or it can remain open. In this example the fracture remains open. After shut-in, the pressure is bled off, typically through a choke valve with a fixed opening. As noted above, the fracture closure pressure is associated with an increase in system stiffness and a change in slope in a pressure and volume plot. If the flowback is through a choke with a fixed opening then a plot of pressure (or square root of pressure) as a function of time will also show a change in slope. Determining fracture closure pressure in this way is illustrated below with reference to FIGS. 10 through 15.

(74) A second cycle is typically performed shortly after the first cycle. Pump in commences again and the pressure increases steeply. Due to compressive stresses in the rock the fracture will remain closed until the pressure reaches a fracture reopening pressure. The fracture reopening pressure should not exceed the fracture initiation pressure of the first cycle. If it does then an alert may be raised. Depending on drilling fluid type and the properties of drilling fluid the fracture reopening pressure may be slightly higher than the fracture closure pressure. Following the fracture reopening pressure the pump in continues but the pressure within the system stays generally unchanged due to continued opening of the existing fracture stop there can be a shut-in period after the pump in, and then after that the pressure is bled off in the same way as for the first cycle.

(75) A third cycle is then carried out in a similar manner to the second cycle. It should be noted that in some cases, if the data produced by the second cycle and the first cycle is good and consistent, then the third cycle may not be necessary. One of the advantages of the proposed automated system is that the analysis of the first and second cycle can occur in real time, just as soon as the cycle has been sufficiently completed, and the system can then automatically propose whether or not a third cycle is necessary, either due to discrepancies in the original data, or to provide additional confidence for a particular scenario.

(76) FIG. 3 shows a plot of pressure against volume for the same three cycles as those shown in the pressure and time plot of FIG. 2. Of course, the various pressure against volume plots are overlaid, since volume is supplied and released during the three cycles. So that the various features of the three cycles can be more clearly seen, especially in relation to the plots of pressure against volume, then separate plots for each cycle are shown in FIGS. 4 through 9, again in both pressure against time and pressure against volume form. These plots, and the processing of the data relating to these plots, are discussed below with reference to the APIT system.

(77) During pump in as the pressure and the volume increases then an envelope is set with an upper and lower threshold as shown in FIG. 5 in relation to the first cycle. A similar set of thresholds is present in FIG. 7 and FIG. 9 in relation to the second and the third cycles. The APIT system continually monitors pressure and volume as they are measured in real-time and fits a curve to recent points enabling a forecast to be made looking ahead in time. If the forecast indicates that the pressure and volume data will exceed the envelope by crossing the opera lower threshold then the test can be stopped, since this indicates a bad test. This process can be considered roughly analogous to a manual process in which the operator may watch pressure and volume values as a test progresses, and effectively guess when they might exceed the allowable envelope. However, the automated process is considerably more accurate and reliable, and can operate with a finer degree of decision-making than a manual process. This means that during the pump in phase of this type of test the automated system can ensure that whilst any test that exceeds the set limits is stopped, there is minimal risk of a false alarm and a test being stopped when in fact it could have been allowed to continue.

(78) The automated system may also automatically take note of and record metrics such as fracture initiation pressure and fracture propagation pressure, and so on. The determination of fracture propagation pressure in particular can be more effectively done with an automated system that monitors volume as well as pressure in real-time, since by curve fitting and regression it is possible to more reliably and accurately detect the stabilization of pressure that indicates the fracture propagation pressure.

(79) These metrics can be determined automatically during multiple cycles of a single test and compared immediately by the automated system. Hence, it is possible to check if, for example, fracture propagation pressure as indicated by the second cycle of this type of test is sufficiently similar to fracture propagation pressure as indicated by the first cycle. This can provide a way to determine whether or not a third cycle is required. If the first two tests give identical or very similar results then one might have the confidence to avoid the time and expense of a third cycle of the test.

(80) When the fluid is released and returned from the formation then a similar process of continuous real-time monitoring and analysis is carried out. During this part of the cycle the fracture closure pressure is often of most interest. The fracture closure pressure can be determined by fitting two straight lines to the curve during flowback as shown in FIGS. 5, 7 and 9, and as illustrated in greater detail in FIGS. 11, 13 and 15. A point of intersection of the two straight lines is identified, and this allows a value for the fracture closure pressure to be obtained. Once again, values between different cycles of the same test can be determined immediately and compared to check whether or not a third or subsequent cycle is required. In addition, since there is no need for analysis after testing has been completed then a report relating to the test can be produced immediately upon completion of the test by the automated system including details of the fracture closure pressure as well as a degree of confidence in the test result, which might perhaps be determined based on similarity of results between different cycles, or a comparison of topside and downhole data and so on. A further discussion of on-going and real-time assessment of the quality of the test is set out below.

(81) As noted above, the fracture closure pressure can also be determined based on a plot of the square root of pressure against time. Again this is done by fitting two straight lines to the plot and finding the intersection of the lines. FIGS. 10, 12 and 14 show examples of this. The automated system allows for this to be done in real time just as soon as the data is available. The fracture closure pressure determined using this technique can be compared with the fracture closure pressure determined using the plot of pressure against volume. This allows for another data point and another comparison to check the quality of the text and ensure confidence in the results. Again this can be done in real-time.

(82) Parameters determined by the APIT system during the tests illustrated in the Figures are shown in Table 3 below.

(83) TABLE-US-00004 TABLE 3 Test results Parameters-Test results Cycle 1 Cycle 2 Cycle 3 Estimated fluid compressibility 5.8 6.1 5.7 [l/bar/100 m.sup.3] Estimated fluid leak coefficient 0.1 0.0 0.1 [1/min/bar] Measured system compliance pump-in 6.7 6.1 6.1 [l/bar/100 m.sup.3] Measured system compliance flowback 6.6 7.8 8.2 [l/bar/100 m.sup.3] Measured Friction pressure loss [bar] 0.7 0.7 0.8 Measured Pump-in volume [I] 2410 1516 1080 Measured Flowback volume [I] 524 910 856 Estimated Leak-off pressure [bar] N/A N/A N/A Estimated Fracture reopening N/A 258.1 258.2 pressure [bar] Estimated Formation breakdown 324.2 N/A N/A pressure [bar] Estimated Fracture propagation 258.1 258.8 260.1 pressure [bar] Estimated Fracture closure N/A N/A N/A pressure shut-in (sqrt(t)-p) [bar] Estimated Fracture closure 237.2 242.9 241.0 pressure flowback (t-sqrt(p)) [bar] Estimated Fracture closure 236.2 242.4 240.7 pressure flowback (v-p) [bar] Estimated Fracture closure N/A N/A N/A pressure shut-in (sqrt(t)-p) [g/cm.sup.3] Estimated Fracture closure 1.465 1.501 1.489 pressure flowback (t-sqrt(p)) [g/cm.sup.3] Estimated Fracture closure 1.459 1.498 1.487 pressure flowback (v-p) [g/cm.sup.3]

(84) In this table the “N/A” indicates data/parameters that could be determined by the APIT system, but were not found in this example or not applicable for the respective cycle.

(85) As well as an analysis of the tests and on-going alerts as discussed above there are also numerous other notifications and alerts that can be made by the APIT system. For this example the table below lists all the info messages, warnings and alarms issued while running the APIT supervisory system. A triangle symbol ({circumflex over ( )}) is used for warnings/alerts and a circle symbol (∘) is used for interpreted values; i.e. LOP, FPP, FCP, FRP etc.

(86) TABLE-US-00005 TABLE 4 APIT system outputs. Time Pressure Volume Test [min] [bar] [liters] phase Info/warning/alarm message Symbol 0.4 210.1 35.7 Pump-in Forcing analysis to start at 210.1 bar .sup.∧ 1.5 220.6 140.0 Pump-in Prediction intervals established .sup.∧ 1.5 220.6 140.0 Pump-in Crossed min volume line .sup.∧ 13.5 322.3 1330.0 Pump-in Deviation from linear trend 14.0 324.2 1380.0 Pump-in Deviation from linear trend identified as ○ formation breakdown. FBP is 324.2 bar, no leak-off point identified 22.9 257.8 2390.0 Pump-in Injected volume has reached 1000 liters 23.4 258.1 2420.0 Pump-in Stable pressure last 250 liters, average ○ FPP is 258.1 bar 23.4 257.3 2420.0 Pump-in Going to shut-in phase 37.8 252.2 2434.3 Shut-in Pressure decrease is less than 2.0 % of BHP during the last 10 minutes 38.5 252.1 2435.7 Shut-in The volume loss rate is less than 2.0 liters/min 38.5 252.1 2435.7 Shut-in Stable shut-in pressure is 253.8 bar 38.9 252.1 2434.3 Shut-in Fracture closure pressure is not identified in shut-in phase 38.9 252.1 2434.3 Shut-in Going to flowback phase 42.6 237.2 2200.0 Flowback Fracture closure pressure is 237.2 bar ○ (time-square root of pressure analysis) 42.9 236.2 2185.7 Flowback Fracture closure pressure is 236.2 bar ○ (volume-pressure analysis) 48.7 212.1 1910.0 Flowback The difference in FCP from pressure- volume and time-square root of pressure analysis is −1.1 bar 48.7 212.1 1910.0 Flowback The system stiffness in pump-in and flowback after closed fracture is similar (pump-in compliance: 6.7, flowback compliance: 6.6) 48.7 212.1 1910.0 Flowback The flowback volume is 524 liters and the pump-in volume is 2410 liters. The flowback volume is 22 % of the pump-in volume 48.7 212.1 1910.0 Flowback Shutting in 48.8 210.8 0.0 Flowback Starting XLOT cycle 2 48.8 210.8 0.0 Flowback Pump pressure higher than maximum .sup.∧ allowable pressure 48.8 210.8 0.0 Pump-in Forcing analysis to start at 210.8 bar .sup.∧ 49.9 220.9 120.0 Pump-in Prediction intervals established .sup.∧ 50.6 228.4 180.0 Pump-in Crossed min volume line .sup.∧ 54.3 258.1 510.0 Pump-in Deviation from linear trend identified as ○ fracture reopening. FRP is 258.1 bar 66.3 258.8 1505.7 Pump-in Stable pressure last 800 liters, average ○ FPP is 258.8 bar 66.3 259.3 1505.7 Pump-in The difference in fracture propagation pressure between cycle 1 and 2 is 0.7 bar 66.3 259.3 1505.7 Pump-in Going to shut-in phase 67.3 257.7 1500.0 Shut-in Going to flowback phase 73.7 242.9 1060.0 Flowback Fracture closure pressure is 242.9 bar ○ (time-square root of pressure analysis) 73.9 242.4 1040.0 Flowback Fracture closure pressure is 242.4 bar ○ (volume-pressure analysis) 82.9 210.7 590.0 Flowback The difference in FCP from pressure- volume and time-square root of pressure analysis is −0.5 bar 82.9 210.7 590.0 Flowback The system stiffness in pump-in and flowback after closed fracture is similar (pump-in compliance: 6.1, flowback compliance: 7.8) 82.9 210.7 590.0 Flowback The flowback volume is 910 liters and the pump-in volume is 1516 liters. The flowback volume is 60 % of the pump-in volume 82.9 210.7 590.0 Flowback Shutting in 83.0 210.8 4.3 Rebound Starting XLOT cycle 3 83.0 210.8 4.3 Rebound Pump pressure higher than maximum .sup.∧ allowable pressure 83.0 210.8 4.3 Pump-in Forcing analysis to start at 210.8 bar .sup.∧ 84.1 221.4 120.0 Pump-in Prediction intervals established .sup.∧ 84.2 222.1 114.3 Pump-in Crossed min volume line .sup.∧ 88.0 258.2 504.3 Pump-in Deviation from linear trend identified as ○ fracture reopening. FRP is 258.2 bar 93.8 260.1 1074.3 Pump-in Stable pressure last 300 liters, average ○ FPP is 260.1 bar 93.8 260.6 1074.3 Pump-in The difference in fracture propagation pressure between cycle 1 and 3 is 2.0 bar 93.8 260.6 1074.3 Pump-in The difference in fracture propagation pressure between cycle 2 and 3 is 1.3 bar 93.8 260.6 1074.3 Pump-in Going to shut-in phase 94.7 258.6 1080.0 Shut-in Going to flowback phase 100.4 241.0 664.3 Flowback Fracture closure pressure is 241.0 bar ○ (time-square root of pressure analysis) 109.0 210.8 224.3 Flowback The difference in fracture closure pressure between cycle 1 and cycle 3 is 3.8 bar (time-square root of pressure analysis) 109.0 210.8 224.3 Flowback The difference in fracture closure pressure between cycle 2 and cycle 3 is 1.9 bar (time-square root of pressure analysis) 100.5 240.7 653.0 Flowback Fracture closure pressure is 240.7 bar ○ (volume-pressure analysis) 109.0 210.8 224.3 Flowback The difference in FCP from pressure- volume and time-square root of pressure analysis is −0.4 bar 109.0 210.8 224.3 Flowback The system stiffness in pump-in and flowback after closed fracture is similar (pump-in compliance: 6.1, flowback compliance: 8.2) 109.0 210.8 224.3 Flowback The flowback volume is 856 liters and the pump-in volume is 1080 liters. The flowback volume is 79 % of the pump-in volume 109.0 210.8 224.3 Flowback Total flowback volume is 45.7% of total pump-in volume 109.0 210.8 224.3 Flowback Shutting in 109.0 210.8 224.3 Flowback The data quality is Excellent (5). 109.0 210.8 224.3 Flowback The Shmin quality is Average (3). Total flowback volume is less than 50% of total pump-in volume 109.0 210.8 224.3 Flowback The overall test quality is Good (4). Total flowback volume is less than 70% of total pump-in volume

(87) It will be appreciated that the APIT system can provide a large amount of information that it is not possible to obtain using the prior art integrity tests where analysis and interpretation is done manually. This is a significant advantage of the APIT system, which is achieved by gathering both pressure and volume data in real-time and by performing an analysis as the data is gathered and in an automated fashion.

(88) The APIT system of course also be used to automatically derive any other test metrics that may be required, and it can repeat any analysis done in the prior art either in the same way, after the test, or generally in a quicker fashion during the test, including providing results that may impact on whether or not future cycles of the test are carried out or whether the test might be stopped on grounds of bad data, for example.

(89) The following Tables 5-10 list various messages providing information, warnings or alarms that may be issued by the proposed system. The system may thus be arranged to provide one of more of the listed messages in the specified phase, and preferably it is arranged to use all of the listed messages.

(90) TABLE-US-00006 TABLE 5 Info, warning or alarm message in the pressurization phase (pump-in) Message Classification Description Crossed Warning Pressure/volume curve falls outside max/min the area spanned by the minimum volume line line Δp = (cV.sub.0).sup.−1ΔV = C.sub.min.sup.−1ΔV and the maximum line Δp = C.sub.min.sup.−1ΔV. ΔV.sub.i = V.sub.i − V.sub.1 and Δp.sub.i = p.sub.i − p.sub.1 Unstable Warning 10 subsequent volume pump rate measurements are outside the prediction interval, [V.sub.min,V,.sub.max] Fluid leak Warning Volume estimated using regression coefficient above model with leak coefficient, Δ{circumflex over (V)}.sub.leak, is tolerance limit higher than 25% of the volume estimated using regression model without leak coefficient, ΔV.sub.no leak, for 15 subsequent measurements Pressure Warning 6 subsequent volume measurements less than are higher than what is predicted predicted, when the pressure is lower than 30% possible of the target test pressure for PIT, or leakage 30% of the expected LOP for LOT/XLOT tests. Pressure Warning 6 subsequent volume measurements less than are higher than what is predicted predicted, when the pressure is higher than possible 30% of the target test pressure for PIT. leak-off. Stop test? Deviation from Info 6 subsequent volume measurements linear trend are higher than what is predicted identified when the pressure is higher than as leak-off. 30% of expected LOP LOP is X bar for LOT/XLOT tests. Pressure higher Warning 30 subsequent volume than predicted measurements are lower than the predicted volume Pressure Alarm Measured pressure is higher than the higher than maximum allowable test pressure. maximum allowable test pressure

(91) TABLE-US-00007 TABLE 6 Info, warning or alarm messages in the shut-in phase (PIT) Classifi- Message cation Description Pressure decrease is Info The pressure decrease the last 10 less than 2% of BHP minutes is less than 2% of the bottom hole pressure. The volume loss rate Info The slope of the pressure vs. time curve is less than 2 liters/ is less than the upper tolerance criterion, min $a_{\max} . Default value is a_{\max} = \frac{φ_{\max}}{V_{0} C},$ where φ.sub.max = 2 liters/min. The volume loss rate Warning Issued if the above alarm (Table 5) is is more than 2 liters/ issued and the slope of the pressure vs. min time curve is higher than the upper tolerance criterion, a.sub.max at a later time. Stable shut-in Info This message is issued if the 3 criteria pressure is X bar for stable pressure is fulfilled: criteria for volume loss rate, criteria for pressure drop last 10 minutes, and the pressure decline rate must be decreasing Pre-defined shut-in Info This message is issued if the pre-defined time reached. shut-in time is reached and the pressure Consider to extend has not stabilized. the shut-in phase Pre-defined shut-in Info This message is issued if the pre-defined time reached shut-in time is reached and the pressure has stabilized. Shut-in complete. Info When the choke is opened for flowback, Pressure decrease the pressure decrease since the initial since ISIP is X bar shut-in pressure is calculated.

(92) TABLE-US-00008 TABLE 7 Info, warning, or alarm messages in the fracture propagation phase Message Classification Description Pressure higher than Alarm The measured pressure is maximum allowable higher than the maximum test pressure allowable test pressure. Injected volume Warning The total injected volume has reached has reached the configured maximum limit maximum volume, i.e. the tank volume Injected volume has Info The specified volume to inject reached target volume after leak-off or formation breakdown is reached Stable pressure last Info The fracture propagation pressure X liters. Average is estimated to the average FPP is Y bar of the pressure readings in the stable pressure region. Increasing pressure Info The pressure is increasing in last X liters, average the fracture propagation phase pressure is Y bar Decreasing pressure Info Where pressure is linearly last X liters, average (stably) decreasing. pressure is Y bar

(93) TABLE-US-00009 TABLE 8 Info, warning or alarm messages in the shut-in phase (XLOT) Classifi- Message cation Description Pressure decrease is Info The pressure decrease the last 10 less than 2% of BHP minutes is less than 2% of the bottom hole pressure. The volume loss rate Info The slope of the pressure vs. time curve is less than 2 liters/ is less than the upper tolerance criterion, min $a_{\max} . Default value is a_{\max} = \frac{φ_{\max}}{V_{0} C},$ where φ.sub.max = 2 liter/min. The volume loss rate Warning Issued if the above alarm (table-7) is is more than 2 liters/ issued and the slope of the pressure vs. min time curve is higher than the upper tolerance criterion, a.sub.max at a later time. Stable shut-in Info This message is issued if the 3 criteria pressure is X bar for stable pressure are fulfilled: criteria for volume loss rate, criteria for pressure drop last 10 minutes, and the pressure decline rate must be decreasing Pre-defined shut-in Info This message is issued if the pre-defined time reached. shut-in time is reached and the pressure Consider to extend has not stabilized. the shut-in phase Pre-defined shut-in Info This message is issued if the pre-defined time reached shut-in time is reached and the pressure has stabilized. Going to flowback Info This message is issued when the choke is opened for flowback Fracture closure Info Issued if the dynamic search for FCP in pressure candidate the shut-in phase detects an FCP is X bar. Identified candidate in shut-in phase

(94) TABLE-US-00010 TABLE 10 Info, warning or alarm messages in the rebound phase (XLOT) Message Classification Description Pre-defined rebound Info The pre-defined rebound time is reached time is reached Final rebound Info The final pressure in the pressure is X bar rebound shut-in phase is given as output

(95) TABLE-US-00011 TABLE 9 Info, warning or alarm messages in the flowback phase (XLOT) Message Classification Description Fracture closure Info Fracture closure pressure is pressure is X bar identified using the gpressure (√ pressure-time vs. time analysis analysis) Fracture closure Info Fracture closure pressure is pressure is X bar identified using the pressure (pressure-volume vs. volume analysis analysis) The compliance Info The slope of the in pump-in and pressure vs. volume curve flowback after closed in the flowback phase fracture is similar is less than two times the slope in the pump-in phase The complianc Info The slope of the in pump-in and pressure vs. volume curve flowback after closed in the flowback phase fracture is not similar is higher than two times the slope in the pump-in phase The flowback volume is Info At the end of the flowback X liters, and the pump- period, the flowback volume in volume is X liters, is calculated and compared The flowback volume is to the pump-in volume. X% of the pump-in volume

(96) In connection with the input data and the quality of interpretation of the data the APIT system includes further capabilities for providing an indication of the quality of the test. It does this by continually assessing parameters relating to the data in real-time. In one example of a process of this type the APIT system may provide a ranking based on the scheme set out in Table 11 below. The data quality is ranked from 1 to 5, with one being worthless and 5 being excellent. If all of the criteria are met then the data quality is deemed to be excellent

(97) TABLE-US-00012 TABLE 11 Data quality test Quality ranking if Criteria criteria not met Is the data usable for 1. Fail/Worthless interpretation? Is the sampling rate 2. Poor topside downhole less than 5 seconds? Is there downhole data? 3. Average Is both topside and 3. Average downhole data available? Are both topside and 3. Average downhole sampling rates below 5 seconds? Is volumetric flowback 3. Average data available? Is the topside data 4. Good sampling rate below 1 second? Is the downhole 4. Good sampling rate below 2 seconds? Is a volumetric flowback 4. Good data sampling rate below 2 seconds?

(98) Other factors may also be considered along with those tabulated above. By way of example, factors that might result in a ranking of 1 (i.e. worthless/fail) may include non-linear pump in compliance and/or fracture closure pressure values determined based on top side measurements having greater than 0.1 SG between maximum and minimum values. If those requirements are passed then factors that might result in a ranking of 2 could include the pump in compliance being excessively high, for example more than twice the expected value and/or fracture closure pressure values determined based on downhole measurements having greater than 0.1 SG between maximum and minimum values. If those requirements are passed then factors that might result in a ranking of 3 could include pump in compliance being more than 1.5 times the expected value, a failure to have a minimum number of pump in cycles (for example at least two pump in cycles), fracture closure pressure values having greater than 0.05 SG difference, total flowback volume being less than 50% and/or the closed fracture compliance being in excess of twice the expected fracture compliance. If those requirements are passed then factors that might result in a ranking of 4 could include pump in compliance being more than 1.25 times the expected value, closed fracture compliance being more than 1.75 times the expected value, total flowback volume being less than 70%, and a failure for all fracture closure pressure interpretations to be within 0.02 SG. If all these factors are passed then the quality would be ranked as excellent.

(99) It will be appreciated that alternative quality test criteria could be set, and the ranking system could of course be adjusted to suit individual operators and particular requirements. A significant advantage arises with the APIT system since it can provide a quality ranking both during conducting a test and also immediately when a test is completed. The operator may set a minimum ranking for a test to be allowed to continue, so that if any criteria is failed indicating, for example, a ranking of 3 or below and the test is stopped and repeated with improvements made to increase the quality of the test. The operator may allow tests to continue despite a low ranking, but then assign less importance or lesser certainty to the results of those tests, and perhaps allocate resources to repeating those tests of the lowest quality from a given sequence or series of testing.

(100) Various benefits of introducing the proposed new system for supervisory and automation functionalities for the formations integrity tests (e.g. PIT, LOT, XLOT) are as follows: the system analyses test data using statistical methods that provide clear and quantitative information regarding observed and predicted behavior. This can be of great value for the users of the system, since identification of test pressures such as leak-off and fracture closure pressures will now be based on statistical data analyses rather than subjective evaluations. The system will improve the consistency of the test by providing users with online result analysis and safeguarding functionalities and repeatability of test. Supervisory and automatic safeguarding functionalities can have a positive impact on safety and provide early-detection of unexpected system behavior, such as non-linear pressure behavior during pump-in (e.g. caused by large permeability losses to formation or through channels in the cement), or unexpected change in system stiffnesses between two subsequent XLOT cycles. The system stores test result with system configuration parameters in a predefined data format. Standardization of test reporting will facilitate our understanding of hydraulic fracturing, fracture propagation and fracture closure processes since result databases lend themselves to data mining methods, and systematic parameter studies.

(101) The proposed APIT system hence provides real-time supervisory functionality during a pressure integrity tests, and can extended to automatically control the cement pump and flowback choke when run in automation mode. The system configuration should not require expert knowledge, nor should the system require significant changes to operational procedures or hardware modifications. Test report generation can be handled in conjunction with the existing logging system.

(102) Primary purposes of conducting formation integrity tests while drilling include verification of fracture pressure in the new formation, verification of the cement integrity at the casing shoe, and, in the case of XLOTs, also measuring the magnitude of the minimum principal stress at the test depth. Test results and their interpretation can have a large impact on the drilling operation, such as motivating remedial cementing operations or adjusting the mass density of the drilling fluid in order to reduce risk of fracturing the formation. XLOT stress measurements are important both for verifying fracture and collapse pressure limits, but also when it comes to planning to permanently abandon a well. In such a case, well barriers must be placed so that the potential internal pressure is lower than the fracture pressure or the minimum principal stress of the formation.

(103) The APIT system can represent a step-change in terms of standardizing the formation integrity test execution and interpretation. The system will generate valuable test metrics for the operator during the test, as well as clear indications concerning unexpected test behavior. This will provide important decision-support for the operator during the test, improve the overall quality of formation integrity tests and reduce the number of required test repetitions due to poor quality results and also reduce the total time of test execution at the installation. The APIT system will automatically process the test data, identify characteristic test pressures, as well as provide test quality indicators. It is therefore also expected that the system will improve the quality of the initial test interpretation, and reduce the time required for test interpretation.

(104) As part of the pump-in analysis, the system evaluates fluid compressibility, casing expansion and potential permeability losses, where losses may be to the formation or through the cement at the casing shoe. This information is displayed during the test and may be saved to the test report generated by the system. This can be of value e.g. in determining whether to perform remedial cement operations or not. These aspects of the system can increase the overall test efficiency and reduce the non-drilling time in the operation.

(105) The APIT system may also have positive risk-reducing effects for the formation integrity test operation and for the subsequent wellbore section drilling operation. The system can be developed with a number of safeguards that would aid the operator in unexpected behavior detection, such as sudden and uncontrolled influx into the well during shut-in or unexpected reduction in system compliance during pump-in. Early detection of unexpected behavior can thus reduce the risk associated with the test, and make it easier to treat undesired situations. The system should improve quality and reliability of the formation integrity test, as well as facilitating standardization of test execution. The resulting improved reliability and accuracy can therefore also reduce the risk for serious well control incidents during drilling of the next wellbore section, especially risks associated with unintentionally fracturing the well (and thereby experiencing lost circulation incidents that could lead to kicks) or hole collapse (that may lead to mechanically stuck pipe situations or tight hole). Such well control incidents may have significant consequences for personnel, the environment and assets.

(106) Digitization and standardization of formation integrity test results can be useful for strengthening our understanding of hydraulic fracturing/qualification of formation as barrier/mini-frac for openhole dual packer test and be valuable for developing test interpretation techniques when e.g. XLOTs are conducted in complex stress regimes and in formations with natural and conductive fractures.

(107) Specific advantages from the APIT system will include: Fewer failed tests.fwdarw.spend less time on field tests through better execution (statistics based on field data) Improved efficiency in test execution.fwdarw.todays time spread, expected time spared where automation offer typically 1 sigma variance less dependent on operator competence.fwdarw.test will be executed on less time, as the operator learning curve is not necessary Better data quality.fwdarw.less time spent on interpretation simplified drillers/operational geology/rock mechanics tasks.fwdarw.speed requires simplicity Fewer drilling process errors A more systematic (automated) and hence repeatable process, with readily comparable results in different installations due to the use of a common automated system. less manual work.fwdarw.more systematic and automated workflow less dependence on operator competence.fwdarw.not dependent on learning curve, advisory teaching tool safer and more accessible data storage Better precision of the process control less formation damage during testing due to improved process precision.fwdarw.reduces probability for subsequent drilling errors, like loss (investigate number of losses after FIT, compared to average population), Reduced wellbore integrity problems early detection of unexpected behavior during testing Fewer planning errors due to improved test data quality Consistent testing, data collection and data reporting.fwdarw.better basis for data interpretation preparing for future electronic workflow Better data quality, better interpretation with less errors.fwdarw.more accurately defined drilling window and improve drilling plan, reduce risk well control incidents during drilling of next section developing improved test interpretation techniques in complex stress-regimes simplified drillers/operational geology/rock mechanics tasks and improved reliability of testing automatic safeguarding against unwanted/uncontrolled loss will help avoid unwanted incidents and human operational error resulting well control incidents and unwanted formation damage reduced risk of unwanted losses to formation will result in less contamination of drilling fluid and produced reservoir fluid when starting production, leading to reduced dumped fluids

(108) Thus, the APIT system consists of a simpler hydraulic model that is evaluated by regression methods, as well as statistical and curve fitting techniques for the different test phases. These elements are integrated into a supervisory control system. The system provides real-time execution and automatic visualization and quantitative interpretation of FITs, LOTs, and XLOTs.

(109) The real-time APIT system has proven to be reliable and ensures complete automation of the pressure testing sequence through execution, interpretation and data storage consistently. This advanced system can be adapted into a stand-alone tool for assisting a cement control system operator or it can be integrated into other technology through a drilling control system.

(110) The results obtained from the APIT system have proven to be reliable, consistent and easily accessible as it adopts a user friendly GUI system. The calibrated pressure integrity tests results attained through the APIT system are easily downloadable, standardized and assimilated into official databases in a time efficient manner. The benefits for Operators implementing this technology are linked to: Time and cost savings Accurate and reliable test results without unnecessary repetitions of tests Improved drilling operational efficiency Reduction in formation damage Integrated component towards drilling automation strategy

(111) Automated FIT/LOT/XLOT testing is a much safer and efficient pressure testing alternative to the current manual counterpart, which improves overall drilling performance.

Method and apparatus for automated pressure integrity testing (APIT)

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E21B47/117

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E21B49/008

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E21B47/06

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E21B47/06

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E21B47/117

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E21B49/00

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Abstract

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Description