US20150198015A1

US20150198015A1 - Method Of Utilizing Subterranean Formation Data For Improving Treatment Operations

Info

Publication number: US20150198015A1
Application number: US14/670,226
Authority: US
Inventors: Wesley da Silva Barreto; Nicolas Orban; Jan Jacobsen
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2010-12-20
Filing date: 2015-03-26
Publication date: 2015-07-16
Also published as: WO2012087864A8; MX2013007039A; WO2012087864A2; WO2012087864A3

Abstract

Disclosed is a method in which subterranean formation data such as, but not limited to, pressure, mobility or permeability data is acquired while drilling and stored. The data is utilized to improve the design, the progress, and the evaluation of a subsequent wellbore treatment. The wellbore treatment may be conducted and monitored utilizing fiber optic enabled coiled tubing or the like.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of co-pending U.S. patent application Ser. No. 13/996,514, filed Dec. 19, 2011, which is a 371 of International Application No. PCT/US11/65720, filed Dec. 19, 2011, which claims benefit of U.S. Provisional Patent Application Ser. No. 61/424,766, filed Dec. 20, 2010. Each of the aforementioned related patent applications is herein incorporated by reference in its entirety.

BACKGROUND

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
The present disclosure is related to wellsite equipment and methods of use thereof, for example surface and downhole equipment used to develop and/or produce an oilfield.
A wellbore may be formed by drilling into a subterranean formation containing a fluid or region of interest. Data may be acquired during the drilling operation as part of oilfield services including, but not limited to, logging while drilling (LWD) services, measuring while drilling (MWD) services, and/or formation pressure while drilling (FPWD) services.
The life of the wellbore may subsequently include treatment operations, for example aimed at stimulating production of hydrocarbon fluids.
It remains desirable to provide improvements in oilfield surface and downhole equipment and/or oilfield services.

SUMMARY

In an embodiment of a method usable in an oilfield, a wellbore is drilled into a subterranean formation, data related to the subterranean formation is acquired while drilling and stored, and a profile related to a property of the subterranean formation is calculated utilizing the acquired data. A treatment operation is performed in the wellbore. Data related to the treatment operation is measured and compared to the profile. The treatment operation is improved based on the comparison.
In another embodiment of a method usable in an oilfield, a wellbore is drilled into a subterranean formation, pressure data related to the subterranean formation is acquired while drilling and stored, and information about the heterogeneity of the subterranean formation in terms of transmissibility is estimated utilizing the pressure data. A treatment operation is designed utilizing the estimated heterogeneity. The treatment operation is performed in the wellbore.
In an embodiment, the data acquired comprises formation permeability data and/or fluid mobility data. In an embodiment, the data is acquired with a logging while drilling tool and/or a formation pressure while drilling tool having an extendable sample probe. In an embodiment, the data related to the treatment operation comprises a remaining damage of the subterranean formation causing a skin effect. In an embodiment, calculating a profile comprises utilizing the acquired data to calculate an expected injection/production profile at an end of the treatment operation. In an embodiment, performing a treatment operation comprises one of selecting an acid type and selecting a volume of acid utilizing the acquired data and selecting may be based on information about the heterogeneity of the subterranean formation in terms of transmissibility. In an embodiment, improving comprises adjusting treatment fluid delivery based on the comparison of the measured data to the profile.
In an embodiment, performing a treatment operation comprises performing a matrix acidizing operation and/or performing an operation with fiber optic enabled coiled tubing and measuring may comprise measuring with the fiber optic enabled coiled tubing and/or performing distributed temperature sensing (DTS) with the fiber optic enabled coiled tubing. In an embodiment, acquiring comprises acquiring one of formation permeability data and fluid mobility data, and the method may further comprise evaluating the treatment operation by comparing DTS data with the one of permeability data and fluid mobility data. The method may further comprise gathering production data from the wellbore and comparing the production data with one of the permeability data, the fluid mobility data, and the DTS data.
In an embodiment, the method may further comprise evaluating the treatment operation using the profile and evaluating may comprise comparing DTS data and production data.
In an embodiment, a method usable in an oilfield comprises drilling a wellbore into a subterranean formation, acquiring and storing pressure data related to the subterranean formation while drilling, estimating information about the heterogeneity of the subterranean formation in terms of transmissibility utilizing the acquired data, designing a treatment operation utilizing the estimated heterogeneity, and performing the treatment operation in the wellbore. In an embodiment, selecting comprises one of selecting an acid type and selecting a volume of acid. In an embodiment, the method further comprises calculating a profile related to permeability of the subterranean formation utilizing the acquired data.

BRIEF DESCRIPTION OF THE DRAWINGS

The features and advantages of the present disclosure will be better understood by reference to the following detailed description when considered in conjunction with the accompanying drawings wherein:

FIG. 1 is a schematic view of an embodiment of an apparatus for performing a treatment operation of a subterranean formation in accordance with the present disclosure;

FIGS. 2A and 2B are schematic views of an embodiment of a fiber optic enabled coiled tubing in accordance with the present disclosure; and

FIG. 3 is a flowchart of an example portion of a method of utilizing subterranean formation data for subsequent treatment operation according to the present disclosure.

DETAILED DESCRIPTION

Indication of permeability heterogeneity of subterranean formations—the quality of variation in rock properties with location in a reservoir or subterranean formations—would allow efficient selection of fluid systems and volumes to be used during stimulation treatments of a wellbore drilled in the subterranean formations. When fluid mobility data (and formation permeability data) are computed from formation pressure data measured while drilling the subterranean formations, the fluid mobility data (and formation permeability data) may be a good estimation of the flow properties of virgin or undamaged subterranean formation and may thus be used to indicate permeability heterogeneity of the subterranean formations.
Further, prediction of post-treatment injectivity/productivity profiles would allow pro-active improvement of the delivery of the fluid systems during the stimulation treatment of the wellbore, for example by adapting the schedule of chemical diversion and matrix acidizing performed with coiled tubing in carbonate formations. In hydrocarbon reservoirs where fluid mobility data (and formation permeability data) computed from formation pressure data acquired while drilling are well correlated to post-treatment injectivity/productivity profiles measured with production logging tools (PLT), for example in some carbonate formations, the fluid mobility data (and formation permeability data) may also be used to predict injectivity/productivity profiles expected after formation damage is removed by the wellbore stimulation treatment (i.e., post-treatment injectivity/productivity profiles).
The present disclosure describes a method of utilizing subterranean formation data for improving treatment operations. The method may comprise acquiring pressure data while drilling with a formation pressure while drilling tool, for example the StethoScope tool, a mark of Schlumberger Technology Corporation. The method may further comprise computing fluid mobility data (and formation permeability data) from the pressure data. The fluid mobility data (and formation permeability data) derived from formation pressure data acquired while drilling may be utilized for improving the efficiency of consequent wellbore treatments or treatment operations performed with coiled tubing, for example as part of ACTive service, a service mark of Schlumberger Technology corporation. The fluid mobility data (and formation permeability data) may be useful in the planning stages of a chemical diversion to be performed prior to matrix acidizing stimulation, because formation heterogeneity may be a deciding factor in determining the fluid volumes required for chemical diversion. The fluid mobility data (and formation permeability data) may additionally be useful during performing the matrix acidizing stimulation with fiber optic enabled coiled tubing, because comparison between actual injection/production profiles computed from distributed temperature surveys (DTS) and the predicted post-treatment injection/production profiles may provide information about the effectiveness of the matrix acidizing stimulation as well as information about potential remaining damage potentially causing skin effect.
The heterogeneity indication and the post-treatment profile prediction could alternatively be obtained from open hole log data (e.g., nuclear magnetic resonance log data). Open hole logs provide information about porosity and fluid saturations, and there have been many attempts at correlating porosity (and fluid saturations) with formation permeability (and fluid mobility). But these correlations may fail in some hydrocarbon reservoir rocks, for example in carbonate formations. In contrast to open hole log data, formation pressure data acquired while drilling a subterranean wellbore may provide relatively more reliable values of formation permeability (and fluid mobility).
As shown at 300 in FIG. 3, a drilling operation is performed, during which time, such as when drilling is momentarily stopped, formation pressure data is acquired and stored. That is, a formation pressure while drilling (FPWD) tool is used to perform subterranean formation drawdowns or pretests at locations along a wellbore drilled into the subterranean formation. Those skilled in the art will appreciate that other data may be acquired while drilling including, but not limited to, by logging while drilling (LWD) tools and/or services, measuring while drilling (MWD) tools and/or services, and the like.
In an embodiment, the FPWD tool may comprise a sample probe to draw fluid from the subterranean formation in order to determine various properties of the subterranean formation. The sample probe may be extendable with appropriate actuators in order to establish a fluid communication between the FPWD tool and the subterranean formation. The FPWD tool may comprise suitable sensors, such as a pressure sensor, for determining the properties of the subterranean formation. The FPWD tool may also comprise a suitable hydraulic assembly—including conduits, drawdown piston(s), and valve connections therebetween—in order to perform one or more drawdowns or pretests. One example implementation of such a probe and hydraulic assembly is shown in U.S. Pat. No. 5,233,866, the disclosure of which is incorporated by reference herein in its entirety.
Fluid mobility values—mobility of a fluid is the ratio of formation permeability in millidarcies or and to the fluid viscosity in centipoise or cp—may be computed from data acquired by the FPWD tool and stored by the FPWD tool at 300. When formation pressure data are measured while drilling before significant subterranean formation damage occurs, or in absence of skin effect, the data computed therefrom, including fluid mobility values, is a good estimation of the flow properties of virgin or undamaged subterranean formation.
The formation pressure data acquired and stored at 300 may allow a user to calculate a zero skin fluid mobility profile (and a zero skin formation permeability profile). The calculated zero skin mobility and/or permeability profile may then be used as a baseline representative of the property of virgin or undamaged subterranean formation in the planning stages of a wellbore treatment, as discussed in more detail below.
Further, the formation pressure while drilling data may be used to calculate a zero skin injection/production data for the wellbore. The calculated zero skin injection/production data may then allow evaluation and/or pro-active improvement of the efficiency of the wellbore treatment, as discussed in more detail below. For example, using the mobility values determined previously, a post-treatment cumulative injection/production capacitance curve may be predicted by summing the product of the mobility values by the spacing between the locations along the wellbore at which formation pressure measurements have been performed. The predicted post-treatment cumulative injection/production capacitance curve may be used as a baseline representative of a cumulative injection/production capacitance curve that would be computed from measurements obtained post-treatment with a production logging tool (PLT).
After drilling the wellbore, formation damage may develop and may cause a skin effect that is detrimental to the production of hydrocarbon fluids. As shown at 400 in FIG. 3, a treatment operation may be designed utilizing the data acquired and stored at 300, such as the calculated zero skin fluid mobility profile (and formation permeability profile). In one example, data variations in the zero skin formation permeability profile indicate the heterogeneity of the subterranean formation in terms of fluid transmissibility, which may be subsequently utilized in the design stage of fluid diversion to be conducted prior to a stimulation treatment, such as matrix acidizing. Indication about the heterogeneity of the subterranean formation in terms of fluid transmissibility may be useful in the planning stages of a wellbore treatment operation, as the amount of formation heterogeneity may be a deciding factor in determining the fluid volumes and/or the fluid viscosities required for chemical diversion or the like, as will be appreciated by those skilled in the art.
Thus, the acquired and stored formation pressure data may be used to compute, for example, heterogeneity properties of the subterranean formation which may in turn allow for the selection of the type and volume of treatment fluid, such as, for example, diverter-acid fluid selection (e.g., based on diverter-acid fluid viscosity) and diverter-acid fluid volumes (e.g., based on the extend of high permeability zones along the wellbore) for use in stimulating a carbonate formation.
In addition, a provisional matrix acidizing schedule may be designed, based for example on past experience of subterranean formation damage, as will be appreciated by those skilled in the art.
As shown at 500 in FIG. 3, a treatment operation is conducted in a subterranean well, for example using coiled tubing services or operations. The treatment operation may have been designed at 400.
Referring to FIG. 1, there is shown a schematic illustration of equipment, and in particular surface equipment, used in providing coiled tubing services or operations in the subterranean well. The coiled tubing equipment may be provided to a well site using a truck 101, skid, or trailer. Truck 101 carries a tubing reel 103 that holds, spooled up thereon, a quantity of coiled tubing 105. One end of the coiled tubing 105 terminates at the center axis of reel 103 in a reel plumbing apparatus 123 that enables fluids to be pumped into the coiled tubing 105 while permitting the reel to rotate. The other end of coiled tubing 105 is placed into wellbore 121 by injector head 107 via gooseneck 109. Injector head 107 injects the coiled tubing 105 into wellbore 121 through the various surface well control hardware, such as blow out preventer stack 111 and master control valve 113. Coiled tubing 105 may convey one or more tools or sensors 117 at its downhole end.
Coiled tubing truck 101 may be some other mobile-coiled tubing unit or a permanently installed structure at the wellsite. The coiled tubing truck 101 (or alternative) also carries some surface control equipment 119, which may comprises a computer. Surface control equipment 119 is connected to injector head 107 and reel 103 and is used to control the injection of coiled tubing 105 into wellbore 121. Control equipment 119 is also useful for controlling operation of tools and sensors 117 and for collecting any data transmitted to from the tools and sensors 117 to the surface. Monitoring equipment may also be provided together with control equipment 119 or separately. The connection between coiled tubing 105 and monitoring equipment and or control equipment 119 may be a physical connection as with communication lines, or it may be a virtual connection through wireless transmission or known communications protocols such as TCP/IP. In this manner, it is possible for monitoring equipment to be located at some distance away from the wellbore. Furthermore, the monitoring equipment may in turn be used to transmit the received signals to offsite locations.
Turning to FIGS. 2A and 2B, there is shown cross-sectional views of coiled tubing apparatus 200 according to the present disclosure. The coiled tubing apparatus 200 includes a coiled tubing string 105, a fiber optic tether 211 (comprising in the embodiment shown of an outer protective tube 203 and one or more optical fiber 201), a surface termination 301, downhole termination 207, and a surface pressure bulkhead 213. Surface pressure bulkhead 213 is mounted in coiled tubing reel 103 shown in FIG. 1 and is used to seal fiber optic tether 211 within coiled tubing string 105 thereby preventing release of treating fluid and pressure while providing access to optical fiber 201. Downhole termination 207 provides both physical and optical connections between optical fiber 201 and one or more optical tools or sensors 209. Optical tools or sensors 209 may be the tools or sensors 117 of the coiled tubing operation shown in FIG. 1, may be a component thereof, or provide functionality independent of the tools and sensors 117 that perform the coiled tubing operations.
During the treatment, the coiled tubing string 105 is injected into the wellbore and a treatment fluid flows from the surface through the interior 215 of the coiled tubing string 105 and into the wellbore 121. As will be appreciated by those skilled in the art, fiber optic enabled measurements, such as profiling with distributed temperature surveys (DTS), allows for injection profiles to be produced during the coiled tubing treatment. Fluid placement within the wellbore 121 may be improved and/or optimized utilizing measurements enabled by the fiber optic tether 211 disposed within the coiled tubing string 105, as discussed in more detail below.
Referring back to the method shown in FIG. 3, the treatment performed at 500 may include pro-active improvement of the fluid systems and fluid delivery with coiled tubing based on formation pressure data previously acquired in the subterranean well. For example, the zero skin injection/production data calculated at 300 may be used as a baseline to predict a post-treatment cumulative injection/production capacitance curve. The distributed temperature surveys (DTS) obtained with fiber optic in coiled tubing may be used to iteratively determine updated cumulative injection/production capacitance curves. The updated cumulative injection/production capacitance curves may be compared to the predicted post-treatment cumulative injection/production capacitance curve. Pro-active improvement of the fluid systems and fluid delivery may be based on this comparison.
In an embodiment of the treatment performed at 500, by reducing or stopping the stimulation treatment in zones of the subterranean wellbore where the updated cumulative injection/production capacitance curve matches the predicted post-treatment cumulative injection/production capacitance curve, over-stimulation may be reduced or avoided in these zones. Thus, fluid placement may be improved.
In another embodiment of the treatment performed at 500, by increasing the stimulation treatment in zones of the subterranean wellbore where both the updated cumulative injection/production capacitance curve does not match the predicted post-treatment cumulative injection/production capacitance curve and the zone transmissibility is still too low, under-stimulation may be reduced or avoided in these zones. For example, thief zones (other subterranean formation zones into which stimulation fluids may be lost) may prevent further stimulation in the mismatch zones. An operator may decide to inject chemical diversion fluid prior to resume injection of stimulation fluid. Thus, fluid treatment schedule may be improved.
At 600, a post-treatment evaluation may be performed. The post-treatment evaluation may include an indication of the agreement between the actual cumulative injection/production capacitance curve achieved at the end of the treatment performed at 500 and the predicted post-treatment cumulative injection/production capacitance curve. The indication of agreement may provide information about the effectiveness of the stimulation treatment. The post-treatment evaluation may comprise performing a mini fall-off pressure analysis with pressure data recorded and transmitted while the coiled tubing is still in the well. The mini fall-off pressure analysis may provide information about remaining damage type, as will be appreciated by those skilled in the art. The post-treatment evaluation may also comprise utilizing the actual cumulative injection/production capacitance curve achieved at the end of the treatment performed at 500 to evaluate completion integrity, for example to detect leaks through casing tubular.
After the treatments performed at 500 and the evaluations performed at 600 are completed, the wellbore may be set up for producing or extracting hydrocarbon fluids therefrom. At various later points in time, perhaps even months or years, a production logging tool (PLT) or the like may be utilized to gather data from the produced fluids. The data gathered with the PLT during production may be utilized to compute a PLT profile. The PLT profile may be evaluated in order to, for example, monitor the extent and/or type of the subterranean formation damage by comparing the PLT profile to a corresponding profile computed from at least one of the subterranean formation data obtained at 300, the treatment data obtained at 500, and/or the post-treatment evaluation obtained at 600.
The preceding description has been presented with reference to particular embodiments. Persons skilled in the art and technology to which this disclosure pertains will appreciate that alterations and changes in the described structures and methods of operation can be practiced without meaningfully departing from the principle, and scope of this description. Accordingly, the foregoing description should not be read as pertaining (oily to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.

Claims

What is claimed is:

1. A method usable in an oilfield, comprising:

drilling a wellbore into a subterranean formation;

acquiring and storing data related to the subterranean formation while drilling;

calculating a profile related to a property of the subterranean formation utilizing the acquired data;

performing a treatment operation in the wellbore;

measuring data related to the treatment operation;

comparing the measured data to the profile; and

improving the treatment operation based on the comparison.

2. The method of claim 1 wherein acquiring comprises acquiring one of formation permeability data and fluid mobility data.

3. The method of claim 1 further comprising acquiring data with a logging while drilling tool.

4. The method of claim 1 wherein acquiring comprises acquiring data with a formation pressure while drilling tool having an extendable sample probe.

5. The method of claim 1 wherein the data related to the treatment operation comprises a remaining damage of the subterranean formation causing a skin effect.

6. The method of claim 1 wherein calculating a profile comprises utilizing the acquired data to calculate an expected injection/production profile at an end of the treatment operation.

7. The method of claim 1 wherein performing comprises one of selecting an acid type and selecting a volume of acid utilizing the acquired data.

8. The method of claim 7 wherein selecting is based on information about the heterogeneity of the subterranean formation in terms of transmissibility.

9. The method of claim 1 wherein improving comprises adjusting treatment fluid delivery based on the comparison of the measured data to the profile.

10. The method of claim 1 wherein performing comprises performing a matrix acidizing operation.

11. The method of claim 1 wherein performing comprises performing an operation with fiber optic enabled coiled tubing.

12. The method of claim 11 wherein measuring comprises measuring with the fiber optic enabled coiled tubing.

13. The method of claim 11 wherein measuring comprises performing distributed temperature sensing (DTS) with the fiber optic enabled coiled tubing.

14. The method of claim 11 wherein acquiring comprises acquiring one of formation permeability data and fluid mobility data, the method further comprising evaluating the treatment operation by comparing DTS data with the one of permeability data and fluid mobility data.

15. The method of claim 14 further comprising gathering production data from the wellbore and comparing the production data with one of the permeability data, the fluid mobility data, and the DTS data.

16. The method of claim 1 further comprising evaluating the treatment operation using the profile.

17. The method of claim 16 wherein evaluating comprises comparing DTS data and production data.

18. A method usable in an oilfield, comprising:

drilling a wellbore into a subterranean formation;

acquiring and storing pressure data related to the subterranean formation while drilling;

estimating information about the heterogeneity of the subterranean formation in terms of transmissibility utilizing the acquired data;

designing a treatment operation utilizing the estimated heterogeneity; and

performing the treatment operation in the wellbore.

19. The method of claim 18 wherein selecting comprises one of selecting an acid type and selecting a volume of acid.

20. The method of claim 18 further comprising calculating a profile related to permeability of the subterranean formation utilizing the acquired data.