Title:
METHOD AND APPARATUS FOR RESERVOIR TESTING AND MONITORING
Kind Code:
A1


Abstract:
An apparatus may include a tubular, a first isolator connected to the tubular and configured to engage an interior surface of the wellbore, a first pressure gauge connected to the tubular and configured to take multiple pressure readings over a period of time, and a first perforation gun connected to the tubular without compromising the communication of fluid through an inner flow channel of the tubular. A method may include placing the apparatus in a wellbore, and actuating the isolator to provide isolation of a first zone in a formation. The method may include activating the perforation gun to provide fluid communication between an annulus of the wellbore and the zone in the formation. The method may include allowing the pressure gauge to take a plurality of pressure readings over a period of time. Based on the pressure readings, the method may include determining a formation characteristic.



Inventors:
Fair, Phillip Scott (Houston, TX, US)
Dombrowski, Robert James (Houston, TX, US)
Fonseca Ocampos, Ernesto Rafael (Houston, TX, US)
Reynolds, Alan Clifford (Windsor, VA, US)
Huynh, Darren (Calgary, CA)
Zhan, Lang (Pearland, TX, US)
Langille, David Lindsay Alexander (Calgary, CA)
Dumont, Wayne L. (Airdrie, CA)
Application Number:
14/638337
Publication Date:
09/10/2015
Filing Date:
03/04/2015
Assignee:
SHELL OIL COMPANY
Primary Class:
Other Classes:
166/55.1, 166/250.17
International Classes:
E21B49/08; E21B33/124; E21B34/12; E21B43/116; E21B43/14; E21B47/06; E21B47/12
View Patent Images:
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Primary Examiner:
RO, YONG-SUK
Attorney, Agent or Firm:
SHELL OIL COMPANY (HOUSTON, TX, US)
Claims:
We claim:

1. An apparatus for testing or monitoring a wellbore penetrating a reservoir in a subterranean formation, the apparatus comprising: a. a tubular; b. an isolator connected to the tubular and configured to engage an interior surface of the wellbore; c. a pressure gauge connected to the tubular and configured to take multiple pressure readings over a period of time; and d. a perforation gun.

2. The apparatus of claim 1, wherein the tubular is configured to maintain continuity of an inner flow channel therein.

3. The apparatus of claim 1, wherein the perforation gun is connected and parallel to the tubular without compromising the communication of fluid through an inner flow channel of the tubular, and wherein the perforation gun is connected to the tubular via a connector such that a centerline of the perforation gun does not align with a centerline of the apparatus.

4. The apparatus of claim 1, wherein the perforation gun comprises at least one tubular puncher configured to puncture a canister of the perforation gun without puncturing casing present in the wellbore.

5. The apparatus of claim 1, wherein the perforation gun comprises a sliding sleeve valve.

6. The apparatus of claim 5, wherein the perforation gun comprises a tubular.

7. The apparatus of claim 1, further comprising at least one additional perforation gun.

8. The apparatus of claim 1, wherein the pressure gauge is connected to a tubing encapsulated conductor or tubing encapsulated cable (TEC) so as to provide real time data reading on a surface device.

9. The apparatus of claim 7, wherein the perforation guns are arranged in parallel.

10. The apparatus of claim 7, wherein the perforation guns are arranged in series.

11. The apparatus of claim 1, further comprising: a. an additional tubular; b. an additional isolator connected to the additional tubular and configured to engage the interior surface of the wellbore; c. an additional pressure gauge connected to the additional tubular and configured to take multiple pressure readings over a period of time; and d. an additional perforation gun.

12. The apparatus of claim 1, wherein an inner flow channel of the tubular is blocked by a bottom cap.

13. A method comprising: a. in a wellbore, placing an apparatus comprising a tubular, a first isolator connected to the tubular and configured to engage an interior surface of the wellbore, a first pressure gauge connected to the tubular and configured to take multiple pressure readings over a period of time, and a first perforation gun connected to the tubular without compromising the communication of fluid through an inner flow channel of the tubular; b. actuating the isolator to provide isolation of a first zone in a formation; c. activating the perforation gun to provide fluid communication between an annulus of the wellbore and the zone in the formation; d. allowing the pressure gauge to take a plurality of pressure readings over a period of time; and e. based on the pressure readings, determining a formation characteristic.

14. The method of claim 13, wherein the step of actuating the isolator comprises hydraulically actuating the isolator.

15. The method of claim 13, wherein the isolator comprises a packer and wherein the apparatus further comprises a second packer connected to the tubular and configured to engage the interior surface of the wellbore, a second pressure gauge connected to the tubular and configured to take multiple pressure readings over a period of time, and a second perforation gun connected and parallel to the tubular without compromising the communication of fluid through the inner flow channel, the method further comprising: a. actuating the second packer to provide isolation of a second zone in the formation; b. activating the second perforation gun to provide fluid communication between the annulus of the wellbore and the second zone in the formation; and c. allowing the second pressure gauge to take a plurality of pressure readings over a period of time.

16. The method of claim 15, wherein the perforating guns are activated at substantially the same time.

17. The method of claim 15, wherein the perforating guns are activated at substantially different times.

18. The method of claim 13, wherein determining a formation characteristic comprises determining permeability of the formation.

19. A method comprising: a. in a cased and perforated wellbore, placing an apparatus comprising a tubular, a first isolator connected to the tubular and configured to engage an interior surface of the casing, a first pressure gauge connected to the tubular and configured to take multiple pressure readings over a period of time, and a first perforation gun connected and parallel to the tubular without compromising the communication of fluid through an inner flow channel of the tubular; b. actuating the isolator to provide isolation of a zone in a formation; c. activating the perforation gun to provide fluid communication among the zone in the formation, an interval isolated opposite the zone, and an interior volume of a canister of the perforation gun; d. allowing the pressure gauge to take a plurality of pressure readings over a period of time; and e. based on the pressure readings, determining a formation characteristic.

20. The method of claim 19, wherein the isolator comprises a packer and wherein the apparatus further comprises a second packer connected to the tubular and configured to engage the interior surface of the casing, a second pressure gauge connected to the tubular and configured to take multiple pressure readings over a period of time, and a second perforation gun connected and parallel to the tubular without compromising the communication of fluid through the inner flow channel, the method further comprising: a. actuating the second packer to provide isolation of a second zone in the formation; b. activating the second perforation gun to provide fluid communication among the second zone in the formation, an interval isolated opposite the second zone, and an interior volume of a canister of the second perforation gun; and c. allowing the second pressure gauge to take a plurality of pressure readings over a period of time.

Description:

RELATED PATENTS

This application claims priority to U.S. provisional patent application No. 61/948,968, filed on Mar. 6, 2014, the contents of which is incorporated herein by reference.

FIELD OF THE INVENTION

The invention relates to a method and apparatus for reservoir testing and monitoring.

BACKGROUND

In hydrocarbon exploration and production, a formation of interest is identified and a wellbore is drilled from the ground (onshore operations) or seabed (offshore operations) in a generally downward direction to penetrate the formation. Once the wellbore has been drilled, casing is frequently lowered into the hole and cemented in place through known but evolving methods. Once the casing is secured, a tool known as a perforating gun may be lowered into the casing and charges may be set off at the perforating gun to perforate or punch holes through the casing such that the hydrocarbons in the formation can ingress through the perforations and move up through the interior of tubing and/or the casing to the surface for consumption. Various stimulation techniques, such as hydraulic fracturing, are commonly used to enhance the flow of hydrocarbons.

In newer methods, the wellbore may not be substantially perpendicular to the surface (known as a “vertical” well), but may start vertical and then deviate to a skewed angle or even become substantially parallel to the surface (known as a “horizontal” well). In some cases, the wellbore may even turn back upward (known as an “inverted” well) or otherwise snake in another direction. The purpose of such deviation from traditional vertical wells is to place the wellbore in a position to closely align with the sections or “zones” of the formation thought to have best access to desirable hydrocarbons. Accordingly, the wellbore may penetrate multiple zones in a “multi-zone” well.

In order to extract the hydrocarbons economically, thought and planning often goes into various treatments or “completions” of the well. Part of the planning involves monitoring and testing the well. In particular, some tests involve ascertaining permeability of the various zones in the well so as to optimize production. A highly permeable zone is one from which hydrocarbons flow more freely than a comparatively less permeable zone. Wells placed in the more permeable zones are more productive.

Conventional permeability assessments rely on core measurements taken along sections of the wellbore and analyzed in a laboratory. However, in relatively impermeable or “tight” formations, the permeability values obtained from the laboratory often do not represent the actual results in reservoirs for several reasons. Specifically, scalability of laboratory results often lead to significant uncertainties; measurement conditions can be substantially different from actual reservoir conditions and users may not have the ability to account for the contribution from natural fractures to permeability can lead to orders of magnitude errors. Understanding the contribution of natural fractures may therefore be useful. In-situ down-hole measurements are used for obtaining formation permeability estimations.

Conventional hydrocarbon reservoirs have relatively high permeability, meaning that hydrocarbons can flow more readily from the rock of the formation into the casing. In those reservoirs, multi-zone well testing is usually carried out with a production logging tool positioned sequentially at multiple locations corresponding to the various zones of the reservoir. The logging tool is lowered into the wellbore on a wire or other tether called a work string or “tool string” to a first location corresponding to the bottom zone. The logging tool, which includes spinner(s) to measure flow rate, pressure and temperature sensors, density sensor, electrical probes, etc., may be positioned just above the bottom zone. When the well condition is changed, the tool measures flow rates, pressure, temperature, phase hold ups, etc. Such readings can be used to infer formation properties, such as permeability of the zone before the process is repeated at a second location corresponding to a second zone, etc. In this manner, the bottom zone formation properties may be obtained from the first test, the properties of the second zone may be estimated based on first and second tests, and other zones may be tested sequentially. Thus, for high permeability reservoirs, accurate and useful readings can be taken quickly. However, such testing may not work as well for unconventional reservoirs having relatively low permeability because the low permeability would result in a much longer time for each of the readings causing undesirable delay in the process. For ultra-low permeability, the time necessary may be prohibitively long. Thus, for unconventional reservoirs, different methods to conduct multi-zone well testing are generally utilized. Two common techniques for multi-zone formation property monitoring and testing in unconventional reservoirs include an external-to-casing method, and an internal-to-casing method.

The external-to-casing method of formation property monitoring and testing uses multiple integrated perforating gun/gauge devices mounted outside the casing before the casing is cemented in place. The devices are cemented outside casing at multiple locations along a vertical, deviated or horizontal portion of the wellbore. Pressure measurements from the gauges can be sent to surface through wired or wireless telemetry or stored locally for later retrieval. The devices are described more completely in SPE 102745 and in EP1945905. A diagram of an integrated perforating gun/gauge device is shown in FIG. 1 and an application of the device is illustrated in FIG. 2. These external-to-casing devices are primarily used to monitor reservoir pressure over a long period. There are several limitations in using these external-to-casing methods. First, the integrated devices must be run into the well along with casing installation and are thus only applicable in a newly drilled wellbore. Second, because the integrated devices are cemented in place in the gap between the outside of the casing and the inside of the wellbore, they must generally be small in order to fit without being damaged. Third, the final test locations need to be fully understood and identified before running the casing because once installed they cannot, typically, be re-positioned. Finally, the external-to-casing devices may affect the cement job quality because the cement between the casing and the wellbore may not flow around the devices completely, leading to voids or other areas of non-uniform cement placement, which may lead to unreliable test results due to poor cement isolations and well integrity concerns

The internal-to-casing method of formation property monitoring and testing is a preferred approach in many situations for unconventional reservoirs. As with the external-to-casing method the internal-to-casing method is used to monitor reservoir pressure for a long period. The bottom zone is perforated first. Then, packer plug, pressure gauge(s) and wireless telemetry are positioned inside the casing at the location adjacent to the bottom zone of the formation for which reservoir monitoring is desired. After the packer is set, the bottom zone can be monitored independently from the zones above. Subsequently, these procedures are repeated for each of the above zones. Alternatively, all zones may be perforated first. Then, multiple packers, pressure gauges and wired or wireless data transmission means may be run in the well with a tubing conveyance. After packers are set to isolate all targeted zones, pressure gauges within the isolated wellbore intervals can monitor the reservoir pressure in the corresponding zones. No matter which of the above two methods is used, essentially, the internal-to-casing system for each zone is placed after perforating has occurred. In other words, the perforating and reservoir monitoring tool installation for each zone are separate operations. Completion of multiple zones can be time consuming For example, as outlined in SPE 102745. The devices used in the internal-to-casing method do not include any means to create a pressure transient for permeability estimation. Such internal-to-casing systems are primarily used for reservoir monitoring purposes, not for reservoir property estimation or reservoir testing. Therefore, there is a need to improve the internal-to-casing system for including both reservoir monitoring and testing functionalities.

SUMMARY OF THE INVENTION

In accordance with one aspect of the present disclosure, an apparatus for testing or monitoring a wellbore penetrating a reservoir in a subterranean formation includes a tubular, an isolator, a pressure gauge, and a perforation gun. The isolator may be connected to the tubular and configured to engage an interior surface of the wellbore. The pressure gauge may be connected to the tubular and configured to take multiple pressure readings over a period of time.

In accordance with an aspect of the present disclosure, a method includes placing an apparatus in a wellbore. The apparatus may include a tubular, a first isolator connected to the tubular and configured to engage an interior surface of the wellbore, a first pressure gauge connected to the tubular and configured to take multiple pressure readings over a period of time, and a first perforation gun connected to the tubular without compromising the communication of fluid through an inner flow channel of the tubular. The method may also include actuating the isolator to provide isolation of a first zone in a formation. The method may include activating the perforation gun to provide fluid communication between an annulus of the wellbore and the zone in the formation. The method may include allowing the pressure gauge to take a plurality of pressure readings over a period of time. Based on the pressure readings, the method may include determining a formation characteristic.

In accordance with an aspect of the present disclosure, a method includes placing an apparatus in a cased and perforated wellbore. The apparatus may include a tubular, a first isolator connected to the tubular and configured to engage an interior surface of the casing, a first pressure gauge connected to the tubular and configured to take multiple pressure readings over a period of time, and a first perforation gun connected and parallel to the tubular without compromising the communication of fluid through an inner flow channel of the tubular. The method may include actuating the isolator to provide isolation of a zone in a formation. The method may also include activating the perforation gun to provide fluid communication among the zone in the formation, an interval isolated opposite the zone, and an interior volume of a canister of the perforation gun. The method may include allowing the pressure gauge to take a plurality of pressure readings over a period of time. Based on the pressure readings, the method may include determining a formation characteristic.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a side cross sectional view of an apparatus in accordance with certain aspects of the present disclosure.

FIG. 2 is a side cross sectional view of an apparatus having skewed connectors in accordance with certain aspects of the present disclosure.

FIG. 3 is a top cross sectional view of an apparatus in accordance with certain aspects of the present disclosure.

FIG. 4 is a top cross sectional view of an apparatus having skewed connectors in accordance with certain aspects of the present disclosure.

FIG. 5 is a side cross sectional view of an apparatus having two perforating guns in accordance with certain aspects of the present disclosure.

FIG. 6 is a side cross sectional view of an apparatus having four perforating guns in accordance with certain aspects of the present disclosure.

DETAILED DESCRIPTION

The apparatus and methods disclosed may lessen some of the limitations of the existing internal-to-casing methods of formation property monitoring and testing with respect to in-situ, multi-zone permeability measurements and/or formation pressure monitoring.

A new system combines the internal-to-casing method with hydraulically activated perforating guns so that a perforating inflow test is possible at each zone after that zone has been closed off or “isolated” from other zones using devices called packers. The pressure gauges and a perforating gun are lowered into the wellbore as part of a tool string. The pressure gauges are configured to take readings in the area between the tool string and the interior of the casing, called the “annulus.” FIG. 3 shows the schematics of an exemplary apparatus 10. Multiple such apparatus 10 may be connected together for multi-zone applications. A multi-zone perforating inflow test might be possible with such apparatus. The apparatus 10, useful for formation monitoring and testing, includes a tubular 12, a packer 14, a by-pass sub 14a, a pressure gauge 16, and a perforating gun 18. The packer 14, pressure gauge 16 and perforating gun 18 may be connected to the tubular 12 such that they do not interrupt the continuity of an inner flow channel of the tubular 12. Previous techniques included guns below tubing that broke the flow channel, rendering operation in multiple zones unsatisfactory. In the apparatus 10, the continuity of the inner flow channel of the tubular 12 may be maintained. Thus, the perforating gun 18 may be connected to the tubular 12 without interrupting or compromising the communication or continuity of fluid flow through the inner flow channel of the tubular 12.

In use, the apparatus 10 is lowered into a wellbore 20 having a casing 22 secured in place by cement 24. The apparatus 10 is lowered from the surface of the earth to the formation 26 while remaining connected to the surface via a long connector in the form of tubing or other tensile connection. Together, the apparatus 10 and that connection, along with any other tools connected thereto, are referred to as the tool string. As described below in further detail, the tool string is placed at a desired location and the packer 14 engages an interior surface 28 of the casing before the perforating gun 18 is activated and measurements are provided by the pressure gauge 16.

In addition to providing actuating functionality, the tubular 12 may provide structure to the apparatus 10 as it is lowered into the wellbore 20. The tubular 12 may be stiff enough to handle the rebound of the perforating gun 18 but flexible enough to be run into the wellbore 20. The tubular 12 may have a bottom cap 48 (illustrated in FIG. 8) to allow for fluid in the tubular 12 to be isolated from fluid outside the tubular 12. In other words, the inner flow channel through the tubular 12 may be blocked by the bottom cap 48. Thus, when the packer 14, perforating gun 18 or other tools are in communication with the tubular 12, pressure inside the tubular 12 may be used to actuate the various tools. Multiple apparatus 10 may be connected together while the inner flow channel of the tubular 12 is still maintained, which allows operating perforating guns at multiple locations in the tool string. Thus, a tool string may be configured to monitor or test multiple zones simultaneously. In such a configuration, the apparatus may include at least one additional tubular, an additional packer connected to the additional tubular and configured to engage the interior surface of the casing; an additional pressure gauge connected to the additional tubular and configured to take multiple pressure readings over a period of time; and an additional perforation gun. The by-pass sub 14a may also be an important component in the tool assembly, allowing electrical cable to be run from outside the tubular 12 to inside the tubular and packer 14 and eliminating the use of feed-through packer and reducing the risks of ineffective packer isolation due to micro-annulus caused by the cable feed-through.

The packer 14 may be connected to the tubular 12 and configured to engage an interior surface of the casing 22, known as being “set.” Generally, when multiple packers 14 are present, the lowest is set first and the others are set in turn, however, all packers 14 may be set simultaneously or in any other order. Pressure may be equalized between the packers 14 if desired.

Once the packers 14 are set, the pressure gauges 16, also connected to the tubular 12 and ported to annulus 36, may take a baseline measurement in annulus 36 prior to the actuation of the perforating gun 18 and then can take additional measurements to determine the speed and magnitude of pressure changes. The pressure gauges 16 may be configured to take multiple pressure readings over any period of time and may report those readings via tubing encapsulated conductor or tubing encapsulated cable (TEC) 17, wireless communication or otherwise. Connection of the pressure gauges 16 via TEC 17 may provide for real time data reading on a surface device.

A first embodiment is illustrated in FIG. 4. In this embodiment, connectors 30 (illustrated as skewed in this particular embodiment) are provided to link a portion of the tubular 12 on which the perforating gun 18 or other testing devices (not shown) are mounted, such that the tubular 12 and perforating gun 18 is in a balanced position, thus maintaining the apparatus 10 on a center line of the packer 14, as shown in FIG. 4. Thus, a centerline of a perforation gun 18 may not align with a centerline of the apparatus 10. The use of one or more connectors 30 may mitigate the packer integrity issues noted with respect to conventional methods. Additionally or alternatively, the use of one or more connectors 30 may improve a seal between the packer 14 and the interior surface 28 of the casing 22 during the test.

A second embodiment is illustrated in FIG. 5. In this embodiment, two perforating guns 18 are illustrated in parallel. Alternate embodiments, described below, provide for perforating guns 18 in series. Additionally, other variants of parallel and/or series may be used. The perforating guns 18 may be mounted on the tubular 12 independently or jointly. The perforating guns 18 may be in the form of canisters each having an interior volume. The interior volume of the perforating guns 18 may be sized as appropriate to generate sufficient pressure transient for permeability estimation. As illustrated, the perforating guns 18 have no fluid communication between one another. Alternatively, fluid communication may be provided between the interior volumes of the perforating guns 18, e.g., a flow tube or other flow channel may connect the interior volumes of the perforating guns 18.

Referring back to FIG. 4, the perforating gun or guns 18 have at least one firing head 32 connected thereto. At least one perforating charge may be detonated by the firing head 32, which may be activated through pressurizing the tubular 12 to break a rupture disc (not shown). In some embodiments, multiple rupture discs may be used to activate multiple firing heads for detonating multiple charges in multiple perforating guns 18. The charges at different perforating guns 18 may be detonated at substantially the same time or substantially at different times by using multiple activation levels for the multiple rupture discs.

Referring back to FIG. 5, the detonation of the charges of the perforating guns 18 will create perforations 34 that puncture or perforate the casing 22 and the cement 24 and extend into the formation 26. While one perforating gun 18 is functional, multiple perforating guns 18 may provide advantages. For example, multiple perforating guns 18 may provide more communication between the interior of the casing 22 and the formation 26 via a larger number of perforations 34. Alternatively or additionally, multiple perforating guns 18 may provide a larger overall interior volume of the perforating guns 18, allowing for a larger pressure differential between the interior of the casing 22 and the formation 26. This may lead to a stronger pressure transient signal, which, in turn, may result in better formation permeability estimation.

Referring now to FIG. 6, more than two perforating guns 18, which are parallel to tubular 12, may be used in the pressure monitoring and testing tool string. While the number and configuration of the perforating guns 18 may be limited by the space inside the casing 22, any number of perforating guns 18 may be used. For example, FIG. 6 shows a configuration of four perforating guns 18. Such configuration may be used to provide more balanced phasing angles in the azimuth of the wellbore 20. Phasing angles refer to the directions of perforations. For example, FIG. 5 shows unbalanced perforation phasing angles because all are on the right side while FIG. 6 shows balanced perforation phasing angles because perforations are placed substantially uniformly around the periphery of the wellbore.

Referring back to FIG. 4, in another embodiment, at least one perforating gun 18 is loaded with at least one tubular puncher (not shown) configured to puncture the canister of the perforation gun 18 without puncturing the casing 22 and without puncturing the tubular 12. This configuration may be useful when the perforations 34 are already present at desired depths with desired perforated interval lengths using suitable perforating guns, e.g., perforating guns 18. Pressure in an annulus 36 formed between the apparatus 10 and the interior surface 28 of the casing 22 may be in equilibrium because the communication between the formation 26 and the wellbore 20 was established before the apparatus 10 is run into the wellbore. After the apparatus 10 is positioned at the desired location, the packer 14 is actuated to isolate the desired wellbore interval (corresponding to the desired zone). In some instances packers 14 may be present on both sides of the perforating gun 18 and may both be actuated to provide the isolation. Once the desired interval is isolated, the tubular puncher may be actuated or fired by activating the rupture disc. This allows for the interior volume of the canister of the perforating gun 18 to be exposed to the contents of the annulus 36. Therefore, a pressure pulse may be created by the pressure differential between the interior volume of the canister of the perforating gun 18 and the formation 26 because the pressure inside the canister, after a certain duration of the charge detonation, may be designed to be significantly different from (i.e., either higher or lower) that of the fluid in the formation 26. This pressure pulse may propagate into the formation 26 and be used to estimate formation properties. Such a configuration may provide several advantages. First, because the perforating operation is separated from the testing operation, the perforated locations, perforated interval lengths, and choice of size of the perforating guns used in perforating jobs may be far more flexible. Larger perforated intervals and larger perforating charges may be used without deference to gun shock damage to the apparatus 10 and without space constraints when running perforating guns 18 mounted on the tubular 12. Second, because only tubular punchers are used in the perforating guns 18 run with the pressure gauge 16 and the explosive loads in tubular punchers are usually small in comparison with the conventional similar size deep penetration charges, the gun shock created from tubular punchers may be much smaller. Third, a tubular puncher can create a much larger hole in the wall of the canister of the perforating gun 18 compared to a similar deep penetration charge. This may allow further reduction in the number of tubular punchers used in the operation, further minimizing the possible gun shock damage to the apparatus 10.

Note that the previously described embodiments may be combined. In particular, a multi-gun configuration may be used on a tool string that is connected using the skewed connectors 30. Furthermore, one more of the perforating guns 18 may be loaded with only tubular punchers, or only standard charges, or both tubular punchers and standard formation penetration charges. These charges may be detonated by a single firing head or multiple firing heads at substantially the same time or at substantially different times.

Referring now to FIG. 7, in another embodiment, the firing head and charge loaded perforating guns 18 are replaced with a hydraulically activated sliding sleeve valve 38 and a blank tubular or a blank gun carrier 40 without loading any perforating charges or tubular punchers. In this configuration, the casing is also perforated at the desired depths with desired perforated interval lengths using the desired perforating guns prior to the apparatus 10 being run into the casing 22. The pressure in annulus 36 and the formation 26 may be in equilibrium by virtue of the perforations 34 present before the apparatus 10 is utilized. Therefore, when the interior volume of the canister is exposed by opening of the sliding sleeve valve 38, a pressure pulse may be created by the pressure differential between the interior volume of the canister and the formation 26 because the pressure of the interior volume of the canister may be designed to be significantly different from (i.e., either higher or lower) that of the fluid in the formation 26. Such a configuration may provide several advantages. First, the perforating operation may be separated from the testing operation. Thus, the perforated locations, perforated interval lengths, and choices of the gun sizes used in perforating jobs may be much more flexible. Larger perforated intervals and larger guns may be used without the concerns of gun shock damage to the apparatus 10 and without the space constraints when running the tubular mounted guns. Second, because no perforating charge or tubular puncher is used in the apparatus 10, the gun shock damage to the apparatus, including the pressure gauge 16, may be completely eliminated. Third, because the sliding sleeve valve 38 is used to open the interior volume of the canister to fluid from the formation 26, the pressure inside the blank gun carrier 40 can be much lower at the beginning of the test than that of perforating guns loaded with deep penetration charges or tubular punchers. Explosives used in deep penetration charges and tubular punchers typically generate significantly higher than atmospheric pressure inside the canister right at the time of the detonation. This gun pressure will generally decrease as the temperature of the gases created during the detonation decreases. This process may take minutes to hours depending on the guns and charges used. Thus, very early pressure data after charge detonation may not be used in in-situ permeability estimation for the tool string combining the testing and perforating functions. The sliding sleeve valve 38 and blank gun carrier 40 may eliminate the issue of pressure peaks and significant decay times, making the pressure transient data higher quality and interpretable data available from the very beginning of the test.

Note that the previously described embodiments may be combined. In particular, one or more perforating guns 18 and/or blank gun carriers 40 may connect to the sliding sleeve valve 38. In addition, one or more perforating guns 18 and/or blank gun carriers 40 may be loaded with at least one standard formation penetration charge, or at least one tubular puncher or at least one standard charge and one tubular puncher.

The figures are used for illustration purposes only. Multiples of the disclosed apparatus 10 may be installed on a single tool string for multi-zone formation property monitoring and testing. If multiple devices are used in a single tool string, a TEC (not shown) and the tubular 12 may run through the entire string connecting to multiple pressure gauges 16 in multiple wellbore intervals for data acquisitions. Such configuration may utilize multiple packers 14 and multiple perforating guns 18 as is evident from this disclosure.

In yet another embodiment, the rupture discs used to activate the perforating firing heads 32 or sliding sleeve valves 38 may have multiple levels of threshold such that (a) different perforating firing heads 32 and/or sliding sleeve valves 38 in a single isolated wellbore interval may be activated at different times using the different rupture disc activation levels; (b) perforating firing heads 32 and/or sliding sleeve valves 38 at different wellbore intervals in different zones of the formation 26 may be activated at different times using the different rupture disc activation levels.

The canister of the perforating gun 18 (or corresponding feature of an alternate embodiment) may be sufficiently long to have a desired interior volume for a particular test interval although number of formation penetration charges or tubular punchers installed in the canister may be small. The canister, blank tubular or gun length may also be sufficiently long to give a desired interior volume for an impulse test. Furthermore, the canister, gun carriers and/or blank tubular/guns at different zones may have different lengths in order to accommodate the desired formation fluid produced volumes at different tested zones. Additionally, multiple perforating charges may be assembled to shoot at a single direction or pathway to increase the open areas on gun carriers and casing as well as better penetration and communication between the annulus 36 and the formation 26.

While pressure gauges 16 are described, other sensors, such as chemical sensors, electrical sensors, optical sensors, mechanical sensors, etc. may be used independently or jointly in the tool string to measure one or multiple fluid or formation properties during the test. While the illustrations depict a vertical well, the apparatus 10 and methods described herein may be useful in deviated, horizontal or other well configurations.

Referring now to FIG. 8, multiple zones 42, 44 may be the targets of a test using one of the above described apparatus 10. A bottom plug 46 may be installed to isolate the annulus 36 into a bottom section 54, which is below the corresponding targeted zones 42 and 44, and an upper section which is opposite to the targeted zones 42 and 44. If the wellbore 20 does not extend below the first zone 44, the bottom plug 46 may be omitted. Once the bottom plug 46 has been placed, the apparatus 10 is run into the annulus 36. As illustrated in FIG. 8, the apparatus includes two packers 14, two pressure gauges 16, and two perforating guns 18. When the apparatus 10 is positioned at the targeted location, the packers 14 may be set by pressurizing the tubular 12, pressurizing the casing 22, pushing/rotating through mechanical means, or any combination of these operations. Once the packers 14 are set, the upper section of the wellbore 20 above the bottom plug 46 may be isolated into two intervals 50 and 52. One interval 52 corresponding to the first zone 44 is isolated by a packer 14 at one end and by the bottom plug 46 at the other end. The other interval 50 corresponding to the second zone 42 is isolated by packers 14 at both ends. If a third packer (not shown) is installed below the bottom perforating gun 18 in the tool string, the bottom plug 46 may again be omitted because the three packers may isolate the wellbore into two independent chambers corresponding to the zones 42, 44. The fluid in the tubular 12 may then be further pressurized, such that the rupture discs ported thereto burst, thus activating the firing heads 32, which, in turn, detonate the perforating charges and tubular punchers. The perforations 34 in the first zone 44 establish fluid communication among the formation 26, the interval 52 isolated opposite the first zone 44, and the interior volume of the canister of the perforating gun 18, while sealing means in the firing head 32 maintain hydraulic isolation among the tubular 12, the interval 52, and the formation 26. Because the pressure inside the perforating gun 18 is much different from the first zone 44 of the formation 26, a pressure pulse is created. This pressure pulse propagates into the first zone 44 of the formation 26 and induces flow transport between the first zone 44 and the interior volume of the canister, which generates pressure transient that is recorded by the pressure gauge 16 in the interval 52. This pressure transient can be used to estimate formation properties near the perforations 34 in the first zone 44. Similarly, the perforations 34 adjacent to the portion of the annulus adjacent to the second zone 42 establish fluid communication between the formation 26 and the interval 50 isolated opposite the second zone 42. Similarly, additional zones may be isolated and tested in a similar manner. Once a number of pressure readings have been provided by pressure gauge 16 over a period of time, those readings can be compared to determine a rate of change, a magnitude of change, or both. From that information, a formation characteristic may be determined For example, permeability may be determined by comparing such pressure readings. A fast change in pressure readings would likely be indicative of a highly permeable formation and a slow change would likely be indicative of a low permeability formation.

The apparatus 10 and methods disclosed in this document are believed to provide at least some of the following improvements over the internal-to-casing method. First, using the connectors 30 to link a portion of the tubular 12 on which the perforating guns 18 or other devices are mounted may balance the apparatus 10, allowing the packers 14 to be maintained in alignment with a centerline of the tool string, resulting in better packer integrity and sealing when the packers 14 are set in the well. Second, using multiple perforating guns 18 that are parallel to the tubular 12 and are mounted on the tubular 12 separately or jointly may improve the phasing angles of the perforations 34, increase the perforation areas on the casing 22, increase the flow contact areas of the perforations 34 in the formation 26, and increase the total interior volume of the canister of the perforating guns 18 such that a stronger pressure pulse (either higher or lower than the formation pressure) can be achieved. Thus, the methods and apparatus may alleviate possible problems of insufficient pressure pulse magnitude and insufficient flow areas.

Third, multiple systems may be deployed in a single tool string allowing for testing and monitoring for multiple zones. Fourth, the placement of perforations may be far more flexible than the existing single run, internal-to-casing pressure monitoring/testing system. Fifth, testing an existing perforated well may be possible with the apparatus 10 and methods described herein.

The apparatus 10 and methods may also mitigate or even eliminate the effect of the charge detonation shock on the tool string in some embodiments.

While the description above refers to a cased wellbore, in some embodiments, the casing may be absent such that the elements engage an interior surface of the uncased wellbore. Thus, engagement of the inner surface of the wellbore may either be engagement of the casing (i.e., indirect engagement of the inner surface of the wellbore), or direct engagement of the wellbore.

Further, while the description above refers to packers using mechanical setting means, other isolators may be used. For example, swellable packers that use chemical means to engage an elastomer with the surface of the wellbore may also be utilized. Thus, the isolator may be a packer, as described, or any other device suitable for providing separation or isolation between different areas.

While the description above uses hydraulic actuation to operate packers, perforating guns and sliding sleeve valves, other actuation means may also be applicable. Specifically, packers, perforating guns and sliding sleeve valves can be activated by electrical signals through wired or wireless telemetry. In some variations, packers, perforating guns and sliding sleeves may be activated through the combination of hydraulic and electrical actuations.

Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments, configurations, materials, and methods without departing from their scope. Accordingly, the scope of the claims and their functional equivalents should not be limited by the particular embodiments described and illustrated, as these are merely exemplary in nature and elements described separately may be optionally combined.