METHOD TO PERFORM RAPID FORMATION FLUID ANALYSIS
A method for determining a property of a formation is described herein. The method includes positioning a wellbore tool at a location within a wellbore. A formation fluid is withdrawn from the formation using the wellbore tool. The formation fluid is passed through a flow line within the wellbore tool and a formation fluid sample is extracted from the flow line. The method further includes analyzing the formation fluid sample within the wellbore tool to determine a property of the formation fluid sample. The analysis is performed by excluding mud filtrate contamination within the flow line.
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This disclosure relates to fluid analysis, and more particularly to formation fluid analysis.
BACKGROUNDWireline logging is used in the oil and gas field industry to investigate and determine properties of hydrocarbon reservoir formations. A wireline logging operation begins by lowering a wireline tool into a wellbore that traverses a formation. The wireline tool includes a probe for extracting formation fluid from the formation and pumping the formation fluid into the wireline tool. In one example, this formation fluid is then optically analyzed to determine a chemical composition for the fluid. This data provides valuable information about the hydrocarbon reservoir formation that can be used later in completing and producing the well.
The optical analysis is performed using a “clean” formation fluid, which may take a great deal of time to obtain due to mud filtrate contamination within the formation. The mud filtrate contamination comes from drilling mud within the wellbore. The drilling mud can be oil-based or water-based. In many cases, the drilling mud penetrates a distance into the wellbore and contaminates the formation fluid. This mud filtrate contamination can invalidate an optical analysis. For example, oil-based mud filtrate within the sample can cause inflated values of lumped alkanes with carbon numbers equal to or greater than six (e.g., C6+ fraction). Furthermore, mud filtrate within the sample can cause optical scattering from mud particulates and emulsions (e.g., oil/water mixtures), which can also invalidate an optical analysis.
To obtain a clean sample for analysis, the wireline tool continuously extracts formation fluid from the formation and pumps the formation fluid through the tool. Eventually, due to the limited penetration distance of the drilling mud into the formation, the formation fluid entering the wireline tool will “clean up” and will no longer contain a substantial amount of mud filtrate. The analysis can then be performed on this “clean” sample of formation fluid. The cleanup time may vary between an hour and 24 hours. The total cleanup time is compounded when cleanup is repeated at multiple sampling locations within the formation. These extended cleanup times make wireline logging operations time consuming. In some cases, such as wireline logging operation performed on offshore rigs, the extended cleanup times make wireline logging operations prohibitively expensive.
SUMMARYThis summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
Illustrative embodiments are directed to a method for determining a property of a formation. The method includes positioning a wellbore tool at a location within a wellbore. A formation fluid is withdrawn from the formation using the wellbore tool. The formation fluid is passed through a flow line within the wellbore tool and a formation fluid sample is extracted from the flow line. The method further includes analyzing the formation fluid sample within the wellbore tool to determine a property of the formation fluid sample. The analysis is performed by excluding mud filtrate contamination within the flow line. Thus, in some cases, the analysis is performed before the formation fluid within the flow line has “cleaned up” and while there is still substantial mud filtrate contamination within the flow line.
Various embodiments are also directed to another method for determining a property of a formation contaminated with water-based mud filtrate. In this method, a wellbore tool is positioned at a location within a wellbore and a formation fluid is withdrawn from the formation using the wellbore tool. The formation fluid is passed through a flow line within the wellbore tool and a formation fluid sample is extracted from the flow line. Water is removed from the formation fluid sample using a membrane and the formation fluid sample is analyzed within the wellbore tool to determine a property of the formation fluid sample.
Further illustrative embodiments are also directed to another method for determining a property of a formation contaminated with oil-based mud filtrate. The method includes positioning a wellbore tool at a location within a wellbore and withdrawing a formation fluid from the formation using the wellbore tool. The formation fluid is passed through a flow line within the wellbore tool and a formation fluid sample is extracted from the flow line. The method also includes identifying a number of chemical components within the formation fluid sample using gas chromatography. Chemical components that appear or may appear within the oil-based mud filtrate are excluded from consideration. A remaining set of chemical components from the number of chemical components is used to determine a property of the formation fluid sample.
Those skilled in the art should more fully appreciate advantages of various embodiments of the present disclosure from the following “Description of Illustrative Embodiments,” discussed with reference to the drawings summarized immediately below.
Illustrative embodiments of the disclosure are directed to a method for determining a property of a formation. The method includes positioning a wellbore tool at a location within a wellbore. The tool withdraws the formation fluid from the formation at the location. The formation fluid passes through a flow line within the wellbore tool and a formation fluid sample is extracted from the flow line. The method further includes performing an analysis of the formation fluid sample within the wellbore tool by excluding mud filtrate contamination within the flow line. In contrast to past methods, the analysis can be performed before mud filtrate contamination within the flow line has cleaned up. In this manner, embodiments described herein perform a “rapid” formation fluid analysis and avoid extended clean up times and increase efficiency of wireline logging, logging-while-drilling (LWD), and other operations. Details of various embodiments are discussed below.
The wireline tool 102 also includes a fluid analyzer module 210 for analyzing at least a portion of the fluid in the flow line 204. This fluid analyzer module 210 is further described below. After the fluid analysis module 210, the formation fluid may be pumped out of the flow line 204 and into the wellbore 104 through a port 212. Some of the formation fluid may also be passed to a fluid collection module 214 that includes chambers for collecting fluid samples and retaining samples of the formation fluid for subsequent transport and testing at the surface (e.g., at a testing facility or laboratory).
In some embodiments, a pump or a piston (not shown) can be used to extract the formation fluid sample from the main flow line 204 and pass the formation fluid through the membrane 306. In various embodiments, the membrane 306 separates water from the formation fluid sample as the sample is being extracted from the main flow line 304. Also, in some embodiments, the membrane 306 is disposed before the valve 304. Once the formation fluid sample passes the membrane 306, the sample flows into a fluid analyzer 308 that analyzes the sample to determine at least one property of the fluid sample. The fluid analyzer 308 is in electronic communication with the surface equipment 112 through, for example, a telemetry module (not shown) and the cable 108. Accordingly, the data produced by the fluid analyzer 308 can be communicated to the surface for further processing by processing system.
The fluid analyzer 308 can include a number of different devices and systems that analyze the formation fluid sample. For example, in one embodiment, the fluid analyzer 308 includes a spectrometer that uses light to determine a composition of the formation fluid sample. The spectrometer can determine an individual fraction of methane (C1), an individual fraction of ethane (C2), a lumped fraction of alkanes with carbon numbers of three, four, and five (C3-C5), and a lumped fraction of alkanes with a carbon number equal to or greater than six (C6+). An example of such a spectrometer is described in U.S. Pat. No. 4,994,671 issued on Feb. 19, 1991 and U.S. Patent Application Publication No. 2010/0265492 published on Oct. 21, 2012. Each of these references is hereby incorporated by reference, in their entireties, herein. In another embodiment, the fluid analyzer 308 includes a gas chromatograph that determines a composition of the formation fluid. In one embodiment, the gas chromatograph determines an individual fraction for each alkane within a range of carbon numbers from one to 25 (C1-C25). Examples of such gas chromatographs are described in U.S. Pat. No. 8,028,562 issued on Oct. 4, 2011 and U.S. Pat. No. 7,384,453 issued on Jun. 10, 2008. Each of these references is hereby incorporated by reference, in their entireties, herein. The fluid analyzer 308 may also include a mass spectrometer, a visible absorption spectrometer, an infrared absorption spectrometer, a fluorescence spectrometer, a resistivity sensor, a pressure sensor, a temperature sensor, a densitometer and/or a viscometer. The fluid analyzer 308 may also include combinations of such devices and systems. For example, the fluid analyzer module 210 may include a spectrometer followed by a gas chromatograph as described in, for example, U.S. Pat. No. 7,637,151 issued on Dec. 29, 2009 and U.S. patent application Ser. No. 13/249,535 filed on Sep. 30, 2011. Each of these references is hereby incorporated by reference, in their entireties, herein.
In this specific embodiment, the fluid analyzer module 210 further includes a spectrometer 315 followed by a densitometer 317 and a viscometer 319. Such an arrangement will provide both a chemical composition for the fluid sample and also physical characteristics for the fluid sample (e.g., density and viscosity). As explained above, other combinations of devices and systems that analyze the formation fluid sample are also possible.
In
At process 408, the analysis of the formation fluid is performed by excluding the mud filtrate contamination within the flow line (e.g., the main flow line 204). As explained above, when the wellbore tool withdraws formation fluid from the formation, the fluid initially includes mud filtrate contamination. Reference number 216 within
The rapid formation fluid analysis method can be applied to formations that are contaminated by oil-based drilling muds or water-based drilling muds. For example,
As explained above, chemical components can be excluded from consideration based upon the composition of the oil-based drilling mud. In some cases, the chemical composition of the drilling mud is known and those specific chemical components that constitute the oil-based drilling mud are excluded from consideration. To this end, the chemical composition of certain types of drilling muds can be obtained from a database that includes various types of drilling muds and their chemical components. Also, the drilling mud can be analyzed at a surface location using gas chromatography to determine its chemical components. In one example, C13 and C15-C18 are known chemical components of the drilling mud and those chemical components are excluded from consideration.
In some embodiments, when the specific chemical components of the drilling mud are unknown, a broader range of chemical components can be excluded from consideration. In one example, chemical components with carbon numbers between C8 and C20 are excluded because drilling muds generally include chemical components with carbon numbers between C8 and C20. Oil-based drilling muds are often made from diesel, a distillation fraction or synthetic oil. Such oil-based muds have a limited carbon number range. Typically, the lowest carbon number observed is C10 or C11, but some diesel and distillation based muds will start at C8 or C9. Other oil-based muds, such as synthetic oil-based muds, are much more monodisperse and have a higher carbon number anywhere from C12 to C16. The highest carbon number in an oil-based drilling mud is more variable and ranges from C14, for some lighter muds, to C29, for some of the distillate-based muds. Generally, the end point for carbon numbers is between C16 and C20. Accordingly, on the higher end, there are small concentrations of components above the C20 endpoint within drilling muds and, at the lower end, there are very small concentrations of components below C8.
The method 500 of
The heavier individual fractions (e.g., C21+) including biomarkers that remain for consideration can also provide valuable information about the properties of the formation. For example, biomarkers can be used to determine properties of the formation. Biomarkers are complex organic compounds that are disposed in sediments, rocks, and crude oils and show little or no change in chemical structure from their original parent organic molecules, which were part of living organisms. Biomarkers can be used to determine the history of the oil within the formation. In particular, biomarkers can be used to identify oil-oil and oil-source rock correlations and thermal maturity. Ptystane and phytane are acyclic isoprenoid biomarkers that elute around C17 and C18. Other biomarkers will elute between C24 and C36, such as hopanes, which elute around C27 to C29. Further details about how biomarkers can be used to determine properties of formation are described in Peters et al., The Biomarker Guide, Vol. 2, pp. 473-640, 645-703 (2007).
The rapid formation fluid analysis method can also be applied to formations that are contaminated by water-based drilling muds. For example,
As explained above, the membrane removes water filtrate from the formation fluid sample and improves the accuracy of the fluid analyzer. In various embodiments, the purpose of performing the fluid analysis on the formation fluid is to determine the chemical components of the hydrocarbon fraction within the formation fluid sample (e.g., the C1, C2, lumped C3-C5, and lumped C6+ fractions). The presence of water within the sample can adversely impact this analysis. For example, when performing an optical analysis using a spectrometer, the water within the sample scatters the light signal from the spectrometer and generates artifacts within the detected light signal. In other systems, software can be used to remove these artifacts. In some cases, however, the water fraction and the hydrocarbon fraction can create an emulsion. Emulsions that appear within the flow line may be difficult to cleanup even with extended cleanup times and the artifacts they generate in detected light signals can be very difficult to remove. In various embodiments, the membrane advantageously separates the water fraction from the hydrocarbon fraction. In this manner, the optical analysis can be performed on a single phase hydrocarbon sample without interference from other phases (e.g., a water fraction).
Illustrative embodiments of the rapid formation analysis method can be used to reliably produce a formation fluid sample that accurately represents the original hydrocarbon fraction within the formation.
Various embodiments of the rapid formation analysis method can be used to accurately detect and analyze the hydrocarbon fraction of formation fluids.
Various embodiments of the rapid formation analysis method can also be used to accurately determine a fluid color for hydrocarbon fractions within formation fluids. The fluid color of a formation fluid is used for fluid typing (e.g., determining the presence of water, gas, condensate, light oil, medium oil, and/or heavy oil). In another example, the fluid color is used to quantify the oil-based mud filtrate contamination within the formation fluid. Fluid color measurements may be influenced by the presence of water (e.g., from a water-based mud filtrate).
With respect to water-based drilling muds, the rapid formation fluid analysis method is not limited to any particular type of fluid analysis technique. Optically analyzing formation fluid samples using a spectrometer is one example. In other embodiments, gas chromatography can be used to determine the individual C1 to C25 fractions of the formation fluid sample. For example, in one specific embodiment, the fluid analyzer module, as shown in
The rapid formation analysis method can be implemented a number of different ways in order to increase the efficiency of logging operations and provide valuable information about the formation. In one example, a wireline tool performs a rapid formation fluid analysis at a plurality of sampling locations within the wellbore. In so doing, the logging operation avoids cleanup time at each sampling location, while also providing valuable information about the formation at each location. More specifically, the rapid formation analysis provides a partial chemical composition of the formation fluid at each of the sampling locations. Such a partial chemical composition indicates the presence of different types of hydrocarbons within the formation and shows how those types of hydrocarbons change between the different sampling locations. In one example, the C1, C2, lumped C3-C5, and lumped C6+ fractions from an optical analysis can be used for fluid typing and determining connectivity within the formation. In another example, the lighter individual hydrocarbon fractions (e.g., C1-C7) from a gas chromatography analysis can be used to determine the source of the hydrocarbons within the formation, the maturity of the hydrocarbons, the biodegradation of the hydrocarbons, the fractionation of the hydrocarbons, the water washing of the hydrocarbons, and thermochemical sulfate reduction of the hydrocarbons.
In various embodiments, the partial chemical compositions at each of the sampling locations are compared against each other to determine other properties of the formation, such as connectivity within the formation. By using ratios of certain chemical components at the sampling locations, a comparison can be made between different sampling locations to determine whether the sampling locations are connected. For example, the ratio between heptane and methylcyclohexane can be used to determine connectivity. In another specific example, a ratio between heptane and a total amount of dimethylcyclopentanes (or an individual amount of a dimethylcyclopentane) can be used to determine connectivity. Sampling locations with similar chemical compositions are likely connected. Such comparisons can be made (1) between one or more sampling locations within the same wellbore, (2) between one or more sampling locations within different wellbores of the same multilateral well, and (3) between one or more sampling locations within different wells.
In some embodiments, the rapid formation analysis method can be used to determine whether to perform a more comprehensive analysis of the formation at a sampling location. In such embodiments, the wireline tool performs a comprehensive analysis of the formation at a first sampling location. In one example, the comprehensive analysis includes analyzing an uncontaminated fluid sample. To this end, the wellbore tool withdraws the formation fluid from the formation and pumps the formation fluid through the flow line until the formation fluid within the flow line is uncontaminated by mud filtrate. In one specific example, the flow line is the main flow line represented by reference number 204 in
The more comprehensive analysis of the formation fluid at the first sampling location can provide additional information, such as a water fraction for the formation fluid or more complete chemical composition identification (e.g., a complete set of individual fractions for C1 to C25). As explained above, however, the disadvantage of this more comprehensive analysis is the additional clean up time. The rapid formation analysis method can be applied at the next sampling location to increase the efficiency of the logging operation. For example, the wellbore tool is moved to a second sampling location and the rapid formation analysis method is performed to determine a partial chemical composition of the formation fluid. By comparing the partial chemical composition at the second sampling location to the more complete chemical composition at the first sampling location, the connectivity between the sampling locations can be determined. If there is no connectivity between the two sampling locations, then a more comprehensive analysis at the second sampling location can be performed (e.g., an analysis of an uncontaminated formation fluid). If there is connectivity between the two sampling locations, then a determination that the two sampling locations have similar formation properties can be made and the wellbore tool does not perform a more comprehensive analysis at the second sampling location. Instead, the wellbore tool moves on to analyze the formation at a third sampling location. This process can be repeated iteratively. In this manner, the rapid formation analysis method can be used to avoid acquisition of redundant data at multiple sampling locations, which, in turn, also increases logging efficiency.
Illustrative embodiments of the present disclosure are not limited to wireline logging operations, such as the ones shown in
Some of the processes described herein, such as (1) determining a property of the formation fluid sample, (2) determining a property of a formation, (3) excluding chemical components that constitute oil-based mud filtrate, (4) using a set of remaining chemical components to determine a property of a formation fluid sample, (5) determining whether to perform an analysis of an uncontaminated formation fluid using a property of a formation fluid sample, and (6) comparing a property of a formation fluid sample at a first location to a property of a second formation fluid sample at a second location, can be performed by a processing system.
In one specific embodiment, the processing system is located at the well site as part of the surface equipment (e.g., the truck 112 in
The term “processing system” should not be construed to limit the embodiments disclosed herein to any particular device type or system. In one embodiment, the processing system includes a computer system. The computer system may be a laptop computer, a desktop computer, or a mainframe computer. The computer system may include a graphical user interface (GUI) so that a user can interact with the computer system. The computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, or general purpose computer) for executing any of the methods and processes described above (e.g. processes (1)-(6)).
The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device. This memory may be used to store, for example, data from the wellbore tool.
Some of the methods and processes described above, including processes (1)-(6), as listed above, can be implemented as computer program logic for use with the computer processor. The computer program logic may be embodied in various forms, including a source code form or a computer executable form. Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language or a high-level language such as C, C++ or JAVA). Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor. The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).
Additionally, the processing system may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)). Any of the methods and processes described above can be implemented using such logic devices.
Although several example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the scope of this disclosure. Accordingly, all such modifications are intended to be included within the scope of this disclosure.
Claims
1. A method for determining a property of a formation, the method comprising:
- positioning a tool at a first location within a wellbore;
- withdrawing a formation fluid from the formation at the first location using the tool, wherein the formation fluid passes through a flow line within the tool;
- extracting a formation fluid sample from the flow line; and
- analyzing the formation fluid sample within the tool by excluding mud filtrate contamination within the flow line.
2. The method according to claim 1, wherein analyzing comprises:
- removing water from the formation fluid sample by passing the formation fluid sample through a membrane when the mud filtrate is a water-based mud filtrate.
3. The method according to claim 2, wherein the analysis of the formation fluid sample is selected from the group consisting of: gas chromatography, mass spectroscopy, visible absorption spectroscopy, infrared absorption spectroscopy, fluorescence detection, resistivity measurements, pressure measurements, density measurements, viscosity measurements, temperature measurements, and a combination thereof.
4. The method according to claim 1, wherein the analyzing comprises:
- analyzing the formation fluid sample using gas chromatography when the mud filtrate is an oil-based mud filtrate.
5. The method according to claim 4, wherein analyzing comprises:
- identifying a plurality chemical components within the formation fluid sample;
- excluding chemical components that comprise the oil-based mud filtrate; and
- determining the property of the formation fluid sample.
6. The method according to claim 5, wherein at least one chemical component with a carbon number between 8 and 20 is excluded from consideration.
7. The method according to claim 5, further comprising:
- using a known chemical composition of the mud filtrate to exclude chemical components that comprise the oil-based mud filtrate.
8. The method according to claim 1, further comprising:
- using the property of the formation fluid sample to determine whether to perform an analysis of an uncontaminated formation fluid within the flow line.
9. The method according to claim 8, wherein the analysis of the uncontaminated formation fluid comprises:
- withdrawing the formation fluid from the formation and pumping the formation fluid through the flow line until the formation fluid within the flow line is uncontaminated by mud filtrate; and
- performing an analysis of the uncontaminated formation fluid within the tool.
10. The method according to claim 8, wherein the analysis of the uncontaminated formation fluid comprises:
- withdrawing the formation fluid from the formation and pumping the formation fluid through the flow line until the formation fluid within the flow line is uncontaminated by mud filtrate; and
- extracting an uncontaminated formation fluid sample from the flow line;
- transporting the uncontaminated formation fluid sample for surface analysis.
11. The method according to claim 1, further comprising:
- comparing the property of the formation fluid sample at the first location to a property of a second formation fluid sample at a second location within the wellbore; and
- using the comparison to determine whether to perform an analysis of an uncontaminated formation fluid at the first location.
12. The method according to claim 1, further comprising:
- comparing the property of the formation fluid sample at the first location within the wellbore to a property of a second formation fluid sample at a second location; and
- using the comparison to determine a property of the formation.
13. The method according to claim 12, wherein the second location is a location selected from the group consisting of: a location within the wellbore, a location within a second wellbore of a second well and a location within a second wellbore within a multilateral well.
14. The method according to claim 1, wherein the property of the formation fluid sample is a chemical composition for the formation fluid sample and analyzing the formation fluid sample comprises determining the chemical composition for the formation fluid sample.
15. The method according to claim 1, wherein the property of the formation fluid sample is selected from the group consisting of: bubble point, dew point, asphaltene onset pressure, density, viscosity, pressure, temperature, and a combination thereof.
16. The method according to claim 1, wherein the property of the formation fluid sample is used to determine the property of the formation.
17. The method according to claim 16, wherein the property of the formation is selected from the group consisting of: connectivity, water washing, biodegradation and a combination thereof.
18. A method for determining a property of a formation, the method comprising:
- positioning a tool at a location within a wellbore;
- withdrawing a formation fluid from the formation at the location using the tool, wherein the formation fluid passes through a flow line within the tool;
- extracting a formation fluid sample from the flow line;
- removing water from the formation fluid sample using a membrane; and
- analyzing the formation fluid sample within the wellbore tool to determine a property of the formation fluid sample.
19. The method of claim 18, wherein the property of the formation fluid sample is a chemical composition for the formation fluid sample and analyzing the formation fluid sample comprises determining the chemical composition for the formation fluid sample.
20. A method for determining a property of a formation, the method comprising:
- positioning a wellbore tool at a location within a wellbore;
- withdrawing a formation fluid from the formation at the location using the wellbore tool, wherein the formation fluid passes through a flow line within the wellbore tool;
- extracting a formation fluid sample from the flow line;
- identifying a plurality of chemical components within the formation fluid sample using gas chromatography;
- excluding chemical components that comprise an oil-based mud filtrate; and
- determining the property of the formation fluid sample.
Type: Application
Filed: Mar 14, 2013
Publication Date: Sep 18, 2014
Applicant: SCHLUMBERGER TECHNOLOGY CORPORATION (SUGAR LAND, TX)
Inventors: RONALD E.G. VAN HAL (WATERTOWN, MA), JEFFREY CRANK (WALPOLE, MA), ROBERT J. SCHROEDER (NEWTON, CT), MARTIN E. POITZSCH (DERRY, NH), DAN EUGENE ANGELESCU (NOISY LE GRAND)
Application Number: 13/829,710
International Classification: E21B 49/08 (20060101);