The present disclosure relates to methods, apparatus and systems for formation fluid sampling in wellbores.
During oil and gas drilling operations, after a borehole is drilled, formation evaluations are performed to measure and analyze the properties of the formation fluid therein, including assessing a quantity and producibility of fluids (e.g., oil) therein. Formation evaluations can be used to determine various actions, such as the viability of a formation for production, as well as which interval(s) of a wellbore should be targeted for production purposes.
In some wells, the ability to obtain a representative sample of formation fluid for evaluation is challenging, such as in low-permeability formations in wells that are drilled with water-based mud (WBM), including those with severe skin damage. Such wells are not uncommon in, for example, the north slope of Alaska.
One embodiment of the present disclosure includes a method for sampling fluid from a subterranean formation that is intersected by a wellbore. The method includes isolating a section of the wellbore with a fluid tester. The fluid tester includes an inlet. Isolating the section of the wellbore with the fluid tester includes providing a space between the inlet of the fluid tester and the subterranean formation. The method includes pumping a fluid mixture from the subterranean formation into the wellbore and into the inlet of the fluid tester. During the pumping, the fluid mixture enters the space and at least partially separates within the space into at least two phases. The at least two phases include a hydrocarbon-based phase and a water-based phase. When the hydrocarbon-based and water-based phases enter the inlet of the fluid tester, the method includes pumping a sample of at least a portion of the hydrocarbon-based phase with a first pump from the fluid tester inlet to a sample chamber and using a second pump to pump a remainder of fluid from the fluid tester inlet into the wellbore. The second pump exhibits a higher pump rate than a pump rate of the first pump. The method includes testing a hydrocarbon content of the sample.
Another embodiment of the present disclosure includes a method for sampling fluid from a subterranean formation that is intersected by a wellbore. The method includes performing an initial draw-down at a target interval in the wellbore, including pumping fluid from the subterranean formation using a first fluid tester. The method includes isolating the target interval of the wellbore with a second fluid tester that includes an inlet. A dead volume is present between the inlet of the second fluid tester and the subterranean formation. The method includes pumping a fluid mixture from the subterranean formation into the dead space and into the inlet of the second fluid tester. During the pumping, the fluid mixture at least partially separates within the dead space into at least two phases, including a hydrocarbon-based phase and a water-based phase. The method includes pumping a sample of at least a portion of the hydrocarbon-based phase with a first pump from the inlet of the second fluid tester to a sample chamber, and using a second pump to pump a remainder of fluid from the inlet of the second fluid tester into the wellbore. The second pump exhibits a higher pump rate than a pump rate of the first pump. The method includes testing the sample to determine a hydrocarbon content of the sample.
Another embodiment of the present disclosure includes a method for sampling fluid from a subterranean formation that is intersected by a wellbore. The method includes: a) performing an initial draw-down at a first target interval in the wellbore, including pumping fluid from the subterranean formation using a first fluid tester; b) isolating the first target interval of the wellbore with a second fluid tester; c) pumping a fluid mixture from the subterranean formation and into a dead space between the subterranean formation and an inlet of the second fluid tester, wherein, during a residence time within the dead space, the fluid mixture containing mud and hydrocarbon separates into at least two phases that include a water-based phase and a hydrocarbon-based phase; d) pumping a first sample of the hydrocarbon-based phase into a sample chamber while pumping a remainder of the fluid into the wellbore; e) testing the first sample to determine a hydrocarbon content of the first sample; f) repeating steps ‘a’ through ‘e’ at a second target interval in the wellbore to determine a hydrocarbon content of a second sample; and g) comparing the hydrocarbon content of the first sample with the hydrocarbon content of the second sample.
So that the manner in which the features of the apparatus, systems and methods of the present disclosure may be understood in more detail, a more particular description is provided with reference to the embodiments thereof which are illustrated in the appended drawings that form a part of this specification. It is to be noted, however, that the drawings illustrate only various exemplary embodiments and are therefore not to be considered limiting of the disclosed concepts as it may include other effective embodiments as well.
Methods, apparatus, and systems according to present disclosure will now be described more fully with reference to the accompanying drawings, which illustrate various exemplary embodiments.
The present disclosure includes methods, apparatus and systems for formation fluid sampling in wellbores. In some embodiments, the methods, apparatus and systems disclosed herein provide for the segregation of formation fluid from, for example, mud filtrate, providing for relatively high-quality formation fluid samples. In some such embodiments, the methods, apparatus and systems disclosed herein exploit gravity and residence time within the wellbore to segregate formation fluid from other fluids. After the formation fluid has been segregated, the methods, apparatus and systems disclosed herein provide for the selective collection of samples of the formation fluid from the well, such as by selectively pumping the formation fluid and other fluids in different directions. For example, the formation fluid may be pumped upwards, towards the opening of the wellbore, while the other fluids are pumped downwards, deeper into the wellbore. The methods, apparatus and systems disclosed herein include procedures, techniques, and hardware used to segregate and collect such formation fluid samples.
Certain embodiments of the disclosure include methods for sampling formation fluid in wellbores. In some such embodiments, the methods include sampling formation fluid in wellbores having been drilled with water-based mud (WBM), also referred to as water mud. Water-based mud is a drilling fluid (mud) that includes water as the major liquid phase thereof, and as the wetting (external) phase thereof. Water-based muds can include fresh WBM, seawater WBD, lime mud, low-solids mud, low-solids/nondispersed mud (i.e., low-solids mud with no clay deflocculant chemical), potassium, and silicate. In some embodiments, the methods, apparatus and systems disclosed herein include downhole fluid segregation to collect relatively high-quality formation fluid samples with wireline formation testers in wells that have been drilled with WBM and have relatively severe skin damage. As would be understood by one skilled in the art, “skin” is a dimensionless factor calculated to determine the production efficiency of a well by comparing actual conditions with theoretical or ideal conditions, where a positive skin value indicates some damage or influences that are impairing well productivity and a negative skin value indicates enhanced productivity, typically resulting from stimulation. Also, one skilled in the art would understand that “damage”, as used with respect to “skin”, refers to natural or induced production impairments that can develop in the reservoir, the near-wellbore area, the perforations, the gravel-pack completion or the production pipelines, such as the tubing. The methods disclosed herein are not limited to being used in the specific types of wells discussed herein (e.g., wells drilled with WBM), and may be used for the sampling of formation fluids in other types of wells.
The formations that may be sampled using the methods disclosed herein include relatively low-permeability formations (i.e., formations that do not readily transmit fluids, such as shales and siltstones). One exemplary region in which the methods, apparatus, and systems disclosed herein may be applied is the north slope of Alaska. However, the methods disclosed herein are not limited to being used in these particular formations, and may be used in other formations for the sampling of formation fluids.
One exemplary embodiment of the method disclosed herein will be descried with reference to
With reference to
With reference to
With reference to
While the initial draw down of formation fluid is described as being performed with a 3D radial probe, the methods disclosed herein are not limited to use of a 3D radial probe and may use other probes or tools capable of drawing in formation fluid towards and/or into a wellbore.
Without being bound by theory, it is believed that the initial drawing in of formation fluid 116 towards and/or into wellbore 102 avoids or mitigates an unfavorable mobility ratio that would, in the absence of this initial drawing of formation fluid 116, result in only invasion fluid (injectant) being moved while subsequently pumping to collect samples. The “mobility ratio” refers to the mobility of an injectant divided by the mobility of fluid the injectant is displacing, such as oil. Therefore, it is believed that this initial drawing in of formation fluid 116 towards and/or into wellbore 102 helps to ensure that oil is being subsequently sampled, rather than other fluids.
With reference to
In
After the residence time has passed a sample of formation fluid 116 may be taken. In some embodiments, the sample of formation fluid 116 is taken via during a rate-controlled pumping period. In some such embodiments, the pumping includes using a simultaneous two-pump technique to collect the segregated formation fluid and discard the mud filtrate. With reference to
While the hydrocarbon is pumped via pump 307 upwards, at least some of the hydrocarbon may still be pumped downwards along with the WBM filtrate 117.
After and/or coincident with the collection and/or the pumping of formation fluid 116 into sampling recipients 119, formation fluid 116 may be tested. For example, formation fluid 116 may be tested to determine the hydrocarbon content thereof (e.g., a weight percentage or volume percentage). In some embodiments, the testing includes spectroscopy, such as fluorescence spectroscopy. Formation fluid 116 may be tested in real-time, simultaneously while the formation fluid 116 is being pumped and/or collected. For example, formation fluid 116 may be tested using a downhole fluid analyzer, such as Schlumberger's InSitu Fluid Analyzer real-time downhole fluid analysis (DFA) system, which integrates various sensors making quantitative fluid properties measurements to provide a comprehensive characterization of formation fluid 116 at reservoir conditions. In some such embodiments, both fluid streams flowing upward (fluid stream 311 in
Without being bound by theory, it is believed that the combination of tool inlets (i.e., the inlets of probe 112 and that of packer 118) used in the present method, both with dead volume (i.e., packer 118) and without dead volume (i.e., probe 112), can assist to displace the mud filtrate 117, bring the target phase (formation fluid 116) closer to the wellbore 102, and allow for collection of relatively high-quality samples after the formation fluid 116 is segregated via the action of gravity at the wellbore 102. Furthermore, it is believed that, with the packer 118 set at the target interval, the cleanup period that the annular space between the packer 118 and the wellbore 102 (i.e., the space defined by isolated wellbore section 122) provides a sufficient residence time to both phases of the fluid therein, such that the isolated wellbore section 122 acts as a segregation chamber for the fluid. “Cleanup” refers to a period when fluids are coming out of the formation and into the wellbore. During this time, the skin effect changes, such that well test results may reflect temporary obstructions to flow that will not be present in later tests.
The ability to segregate the WBM from the formation fluid provides for more accurate determinations of the fluid contents of the wellbore and intervals thereof. More accurate determinations of the fluid contents provide for the ability to determine which wellbores and which intervals thereof are more viable for hydrocarbon production. The present disclosure provides for the use of downhole residence time, using a wellbore coupled with dual pump action, to separate hydrocarbons from WBM filtrate through a single probe inlet. Without being bound by theory, it is believed that embodiments of the sampling techniques disclosed herein, including those using current formation tester capabilities, are capable of collecting relatively high-quality samples in wells where such high-quality sample collection has previously been thought to be challenging or impossible. Formation testers include tools run on wireline to obtain fluid samples and measure formation pressures. Formation testers are sometimes referred to as wireline formation testers. Formation testers include tool run on an electric logging cable that push probes into the formation, which then allows production into a closed chamber. While formation fluid is discussed herein as including oil, formation fluid may include any fluid that occurs in the pores of a rock, including oil, natural gas and water.
While the methods disclosed herein have been described with reference to obtaining and analyzing fluid samples in wells drilled using WBM, the methods disclosed herein are not limited to such wells. For example, in some embodiments the methods disclosed herein are used in wells drilled with oil-based mud. Oil-based mud is an invert-emulsion mud, or an emulsion whose continuous phase is oil. In such embodiments, the same method and procedure nay be implemented to obtain and test samples of fluid, with the exception that the fluid flowing downwards (e.g., fluid stream 313 in
The methods, apparatus, and systems disclosed herein may be used to collect samples of formation fluid. In certain applications, the methods, apparatus, and systems disclosed herein may be used to collect fluid samples in wells in relatively low-permeability formations that have been drilled with WBM, including those with severe skin damage. For example, the methods, apparatus, and systems disclosed herein may be used to collect samples of formation fluid form wells on the north slope of Alaska.
In some embodiments, fluid sampling method disclosed herein may be used to assess the quantity and producibility of fluids from a reservoir. Information obtained from such fluid sampling methods may be used to guide wellsite decisions, such as placement of perforations and hydraulic fracture stages, and reservoir development and production planning.
In some embodiments, the fluid samples taken in accordance with the present disclosure, such that the fluid has a residence time within an isolated dead volume prior to sampling, exhibit an increase in hydrocarbon fraction, relative to the hydrocarbon fraction in samples taken without providing a residence time to the fluid within an isolated dead volume prior to sampling. In some such embodiments, the hydrocarbon fraction of the fluid samples is increased from a percentage that is less than 50%, or less than 40%, or less than 30%, or less than 20%, or less than 10%, or 5% or less to a percentage that is at least 50%, at least 60%, or least 70%, at least 80%, at least 90%, or at least 95% (where each % is a weight percent, wt. %). In some embodiments, the hydrocarbon fraction of a fluid sample is increased by a factor of 20. That is, the measured hydrocarbon percentage of a fluid may be 4.5 wt. % when using a probe that has no dead volume, but the measured hydrocarbon percentage measured of the same fluid may be 90 wt. % when subsequently using a probe with dead volume that provides residence time to the fluid prior to sampling. In some such embodiments, the hydrocarbon fraction of the fluid samples is increased by a factor of 20, 18, 15, 12, 10, 8, 5, or 2. In one example, a maximum hydrocarbon fraction in a fluid sample may be 5 wt. % when using probes that have no dead volume, whereas, samples from the same well may have hydrocarbon fractions increased to 90 wt. % by subsequently using probes with dead volume that provide residence time to the fluids prior to sampling with the pumps.
The following is one example of application of the fluid sampling method disclosed herein. However, the fluid sampling method is not limited to this particular application or these particular results.
A study was performed to assess the downhole fluid segregation and sampling methods disclosed herein. A wellbore was pumped at one interval using a Saturn 3D radial probe with no dead volume, and the maximum hydrocarbon fraction observed in the fluid samples obtained by the probe was 5 wt. % of sample. A hydrocarbon fraction of 5 wt. % is suboptimal for the sample volumes. A straddle packer was then set immediately after use of the probe, at the same depth with the wellbore. The cleanup period demonstrated that the annular space between the tool (the straddle packer) and the wellbore was providing a residence time to both phases on the fluid therein. Thus, the annular space between the tool (the straddle packer) and the wellbore was acting as a segregation chamber for the fluid therein. Lab results confirmed that the fluid samples collected without residence time contained 95 wt. % WBM filtrate, while the bottles (samples) collected with the proposed technique, utilizing the residence time, contained 90 wt. % hydrocarbon. Thus, the methods disclosed herein may be used to collect relatively high-quality fluid samples with wireline formation testers in wells drilled with WBM having severe skin damage.
Certain, non-limiting, embodiments will now be set forth.
Embodiment 1. A method for sampling fluid from a subterranean formation that is intersected by a wellbore, the method comprising: isolating a section of the wellbore with a fluid tester, the fluid tester including an inlet, wherein isolating the section of the wellbore with the fluid tester includes providing a space between the inlet of the fluid tester and the subterranean formation; pumping a fluid mixture from the subterranean formation into the wellbore and into the inlet of the fluid tester, wherein during the pumping the fluid mixture enters the space and at least partially separates within the space into at least two phases, the at least two phases including a hydrocarbon-based phase and a water-based phase; when the hydrocarbon-based and water-based phases enter the inlet of the fluid tester, pumping a sample of at least a portion of the hydrocarbon-based phase with a first pump from the fluid tester inlet to a sample chamber and using a second pump to pump a remainder of fluid from the fluid tester inlet into the wellbore, wherein the second pump exhibits a higher pump rate than a pump rate of the first pump; and testing a hydrocarbon content of the sample.
Embodiment 2. The method of embodiment 1, wherein the fluid tester comprises a straddle packer having expandable members and the inlet is positioned between the expandable members, wherein isolating the section of the wellbore comprises expanding the expandable members of the straddle packer, and, when the expandable members are expanded, a dead volume between the inlet of the straddle packer and the subterranean formation defines the space.
Embodiment 3. The method of embodiment 1 or 2, wherein the straddle packer includes a single inlet.
Embodiment 4. The method of any of embodiments 1 to 3, further comprising, prior to isolating the section of the wellbore with the fluid tester, pumping fluid from the subterranean formation at the section of the wellbore using an initial fluid tester having an inlet.
Embodiment 5. The method of embodiment 4, wherein the initial fluid tester comprises a 3D radial probe.
Embodiment 6. The method of embodiment 4 or 5, wherein there is no dead volume between the inlet of the initial fluid tester and the subterranean formation during the pumping.
Embodiment 7. The method of any of embodiments 4 to 6, wherein a hydrocarbon content of fluid pumped by the initial fluid tester is less than 50 weight percent.
Embodiment 8. The method of any of embodiments 1 to 7, wherein the sample is pumped upwards towards a surface of the wellbore and the remainder of fluid is pumped downwards into the wellbore.
Embodiment 9. The method of any of embodiments 1 to 8, wherein a hydrocarbon content of the sample is at least 50%.
Embodiment 10. The method of any of embodiments 1 to 9, wherein a hydrocarbon content of the sample is at least 90%.
Embodiment 11. The method of any of embodiments 1 to 10, wherein the space acts as a segregation chamber such that the fluid mixture separates therein via gravity, immiscibility between hydrocarbon and water, density differentials between hydrocarbon and water, or combinations thereof.
Embodiment 12. The method of any of embodiments 1 to 11, wherein the sample is skimmed from a top of fluid entering the fluid tester and pumped via the first pump.
Embodiment 13. The method of any of embodiments 1 to 12, wherein the pump rate of the second pump is at least 2 times greater than the pump rate of the first pump.
Embodiment 14. The method of any of embodiments 1 to 13, wherein the pump rate of the second pump is at least 5 times greater than the pump rate of the first pump.
Embodiment 15. The method of any of embodiments 1 to 14, wherein the pumping of the first pump and the pumping of the second pump are performed simultaneously.
Embodiment 16. The method of any of embodiments 1 to 15, wherein testing the hydrocarbon content of the sample comprises performing spectroscopy on the sample.
Embodiment 17. The method of any of embodiments 1 to 16, wherein the testing of the hydrocarbon content of the sample is performed simultaneously while pumping.
Embodiment 18. The method of any of embodiments 1 to 17, wherein the fluid mixture comprises hydrocarbon and water-based mud.
Embodiment 19. The method of any of embodiments 1 to 18, wherein the wellbore is a wellbore having been drilled with water-based mud.
Embodiment 20. The method of any of embodiments 1 to 19, wherein the wellbore is a wellbore exhibiting skin damage.
Embodiment 21. The method of any of embodiments 4 to 20, the initial fluid tester is a wireline formation tester.
Embodiment 22. The method of any of embodiments 1 to 21, wherein the subterranean formation is a low-permeability formation.
Embodiment 23. The method of any of embodiments 4 to 22, wherein the initial fluid tester pumps fluid in the subterranean formation to bring hydrocarbons in the subterranean formation within or into closer proximity to the wellbore.
Embodiment 24. The method of any of embodiments 1 to 23, wherein the residence time is coincident with a cleanup period wherein fluid enters the wellbore from the subterranean formation.
Embodiment 25. The method of any of embodiments 1 to 7, 9 to 17 and 20 to 24, wherein the sample is pumped downward towards a surface of the wellbore and the remainder of fluid is pumped upwards into the wellbore.
Embodiment 26. The method of any of embodiments 1 to 7 and 9 to 19 and 20 to 25, wherein the fluid mixture comprises hydrocarbon and oil-based mud.
Embodiment 27. The method of any of embodiments 1 to 7 and 9 to 19 and 20 to 26, wherein the wellbore is a wellbore having been drilled with oil-based mud.
Embodiment 28. A method for sampling fluid from a subterranean formation that is intersected by a wellbore, the method comprising: performing an initial draw-down at a target interval in the wellbore, including pumping fluid from the subterranean formation using a first fluid tester; isolating the target interval of the wellbore with a second fluid tester, the fluid tester including an inlet, wherein a dead volume is present between the inlet of the second fluid tester and the subterranean formation; pumping a fluid mixture from the subterranean formation into the dead space and into the inlet of the second fluid tester, wherein during the pumping the fluid mixture at least partially separates within the dead space into at least two phases, the at least two phases including a hydrocarbon-based phase and a water-based phase; pumping a sample of at least a portion of the hydrocarbon-based phase with a first pump from the inlet of the second fluid tester to a sample chamber and using a second pump to pump a remainder of fluid from the inlet of the second fluid tester into the wellbore, wherein the second pump exhibits a higher pump rate than a pump rate of the first pump; and testing the sample to determine a hydrocarbon content of the sample.
Embodiment 29. A method for sampling fluid from a subterranean formation that is intersected by a wellbore, the method comprising: a) performing an initial draw-down at a first target interval in the wellbore, including pumping fluid from the subterranean formation using a first fluid tester; b) isolating the first target interval of the wellbore with a second fluid tester; c) pumping a fluid mixture from the subterranean formation and into a dead space between the subterranean formation and an inlet of the second fluid tester, wherein, during a residence time within the dead space, the fluid mixture containing mud and hydrocarbon separates into at least two phases that include a water-based phase and a hydrocarbon-based phase; d) pumping a first sample of the hydrocarbon-based phase into a sample chamber while pumping a remainder of the fluid into the wellbore; e) testing the first sample to determine a hydrocarbon content of the first sample; f) repeating steps ‘a’ through ‘e’ at a second target interval in the wellbore to determine a hydrocarbon content of a second sample; and g) comparing the hydrocarbon content of the first sample with the hydrocarbon content of the second sample.
Embodiment 30. The method of embodiment 29, further comprising: h) determining which of the first or second target intervals to produce hydrocarbons from based on the comparison between the hydrocarbon content of the first sample and the second sample.
Although the present embodiments and advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the disclosure. Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the processes, machines, manufactures, apparatus, systems, compositions of matter, means, methods and steps described in the specification. As one of ordinary skill in the art will readily appreciate from the disclosure, processes, machines, manufactures, apparatus, systems, compositions of matter, means, methods, or steps, presently existing or later to be developed that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein may be utilized according to the present disclosure. Accordingly, the appended claims are intended to include within their scope such processes, machines, manufactures, apparatus, systems, compositions of matter, means, methods, or steps.
This application claims the benefit of U.S. Provisional Application No. 62/908,958, filed Oct. 1, 2019, the disclosure of which is incorporated herein by reference in its entirety.
Filing Document | Filing Date | Country | Kind |
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PCT/US2020/053740 | 10/1/2020 | WO |
Number | Date | Country | |
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62908958 | Oct 2019 | US |