US20140260586A1

US20140260586A1 - Method to perform rapid formation fluid analysis

Info

Publication number: US20140260586A1
Application number: US13/829,710
Authority: US
Inventors: Ronald E.G. Van Hal; Jeffrey Crank; Robert J. Schroeder; Martin E. Poitzsch; Dan Eugene Angelescu
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2013-03-14
Filing date: 2013-03-14
Publication date: 2014-09-18
Also published as: GB2528190A; BR112015022106A2; WO2014159496A1; NO20151108A1; GB201515089D0

Abstract

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 A formation fluid is withdrawn from the formation using the wellbore tool.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.

Description

TECHNICAL FIELD

This disclosure relates to fluid analysis, and more particularly to formation fluid analysis.

BACKGROUND

Wireline 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.

SUMMARY

This 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.

BRIEF DESCRIPTION OF THE DRAWINGS

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.

FIG. 1 shows a wireline logging system at a well site in accordance with one embodiment of the present disclosure;

FIG. 2 shows a wireline tool in accordance with one embodiment of the present disclosure;

FIG. 3A shows a fluid analyzer module in accordance with one embodiment of the present disclosure;

FIG. 3B shows a fluid analyzer module in accordance with another embodiment of the present disclosure;

FIG. 4 shows a method for determining a property of a formation in accordance with one embodiment of the present disclosure;

FIG. 5 shows a method for determining a property of a formation contaminated with an oil-based mud filtrate in accordance with one embodiment of the present disclosure;

FIG. 6A shows (i) a reference chromatogram that was obtained by analyzing a formation fluid sample and (ii) a contaminated chromatogram that was obtained by analyzing the same formation fluid sample contaminated with an oil-based mud filtrate in accordance with one embodiment of the present disclosure;

FIG. 6B shows a more detailed view of the chromatograms of FIG. 6A.

FIG. 7 shows a method for determining a property of a formation that is contaminated by a water-based mud filtrate in accordance with one embodiment of the present disclosure;

FIG. 8 shows a plot that was generated by optically analyzing a formation fluid sample that was separated using a membrane in accordance with one embodiment of the present disclosure;

FIG. 9 shows an original oil sample, an emulsion of the original oil sample and water, and a sample after the emulsion has been passed through a membrane in accordance with one embodiment of the present disclosure;

FIG. 10 shows a wireline log that was obtained using a rapid formation fluid analysis method in accordance with one embodiment of the present disclosure;

FIG. 11 shows a concurrent wireline log that was obtained using a conventional fluid analysis system;

FIG. 12 shows a plot that was obtained using a rapid formation fluid analysis method in accordance with one embodiment of the present disclosure;

FIG. 13 shows optical spectra for a set of single phase fluids; and

FIG. 14 shows one potential spectrum generated from a 50 percent oil and water mixture.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

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.
FIG. 1 shows one example of a wireline logging system 100 at a well site. Such a wireline logging system 100 can be used to implement a rapid formation fluid analysis. In this example, a wireline tool 102 is lowered into a wellbore 104 that traverses a formation 106 using a cable 108 and a winch 110. The wireline tool 102 is lowered down into the wellbore 104 and makes a number of measurements of the adjacent formation 106 at a plurality of sampling locations along the wellbore 104. The data from these measurements is communicated through the cable 108 to surface equipment 112, which may include a processing system for storing and processing the data obtained by the wireline tool 102. The surface equipment 112 includes a truck that supports the wireline tool 102. In other embodiments, the surface equipment may be located in other locations, such as within a cabin on an off-shore platform.
FIG. 2 shows a more detailed view of the wireline tool 102. The wireline tool includes 102 a selectively extendable fluid admitting assembly (e.g., probe) 202. This assembly 202 extends into the formation 106 and withdraws formation fluid from the formation 116 (e.g., samples the formation). The fluid flows through the assembly 202 and into a main flow line 204 within a housing 206 of the tool 102. A pump module 207 is used to withdraw the formation fluid from the formation 106 and pass the fluid through the flow line 204. The wireline tool 102 may include a selectively extendable tool anchoring member 208 that is arranged to press the probe 202 assembly against the formation 106.
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).
FIG. 3A shows a more detailed view of a fluid analyzer module 210. As shown in FIG. 3A, the fluid analyzer module 210 includes a secondary flow line 302 (e.g., a channel) that is coupled through a valve 304 to the main flow line 204. The valve 304 selectively passes a sample of formation fluid into the secondary flow line 302. The secondary flow line 302 also includes a membrane 306 to separate water from the formation fluid sample (e.g., a hydrophobic membrane). Such a membrane is described in U.S. Pat. No. 7,575,681 issued on Aug. 18, 2009 and U.S. Pat. No. 8,262,909 issued on Sep. 11, 2012. Each of these references is hereby incorporated by reference in their entireties.
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.
FIG. 3B shows a fluid analyzer module 210 in accordance with another embodiment of the present disclosure. In this embodiment, a bypass flow line 301 is coupled to the main flow line 204 through a first valve 305. The first valve 305 selectively passes formation fluid from the main flow line 204 into the bypass flow line 301. A secondary flow line 307 (e.g., a channel) is coupled through a second valve 309 (e.g., an entrance valve) to the bypass flow line 301. The second valve 309 selectively passes a sample of formation fluid into the secondary flow line 307. The fluid analyzer module 204 includes a membrane 311 to separate water from the formation fluid sample (e.g., a hydrophobic membrane). In this embodiment, the membrane 311 is disposed before the second valve 309. The fluid analyzer module 210 also includes a third valve 313 (e.g., an exit valve) between the secondary flow line 307 and the bypass flow line 301. The second valve 309 and the third valve 313 can be used to isolate the formation fluid sample within the secondary flow line 307. After analysis, the formation fluid sample can pass to the bypass flow line 301 through the third valve 313.
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 FIG. 3B, the fluid analyzer module 210 also includes a pressure unit 321 for changing the pressure within the fluid sample and a pressure sensor 323 that monitors the pressure of the fluid sample within the secondary flow channel 307. In one specific embodiment, the pressure unit 321 is a piston that is in communication with the secondary flow line 307 and that expands the volume of the fluid sample to decrease the pressure of the sample. As explained above, the second valve 309 and the third valve 313 can be used to isolate the formation fluid sample within the secondary flow line 307. Also, in some embodiments, the pressure unit 321 can be used to extract the formation fluid sample from the bypass flow line 301 by changing the pressure within the secondary flow line 307. The pressure sensor 323 is used to monitor the pressure of the fluid sample within the secondary flow line 307. The pressure sensor 323 can be a strain gauge or a resonating pressure gauge. By changing the pressure of the fluid sample, the fluid analyzer module 210 can make measurements related to phase transitions of the fluid sample (e.g., bubble point or asphaltene onset pressure measurements). Further details of devices and systems that analyze the formation fluid sample are also provided in U.S. Provisional Patent Application Ser. No. 61/______ entitled “Pressure Volume Temperature System” and filed on Mar. 14, 2013 (Attorney Docket No. IS13.3119-US-PSP), which is hereby incorporated by reference, in its entirety, herein.
FIG. 4 shows a method 400 for determining a property of a formation in accordance with one embodiment of the present disclosure. As shown at process 402, the method 400 includes positioning a wellbore tool at a first location within a wellbore. In some embodiments, this wellbore tool is the wireline tool 102, as shown in FIG. 2. However, in various other embodiments, the wellbore tool can also be a logging-while-drilling tool. Once positioned adjacent to a location-of-interest within the formation, at process 404, the wellbore tool withdraws the formation fluid from the formation (e.g., samples the formation). The wellbore tool can use a selectively extendable fluid admitting assembly 202, as shown in FIG. 2, to withdraw the formation fluid from the formation. The formation fluid then passes through a main flow line within the wellbore tool. In some embodiments, the formation fluid is pumped through the main flow line using the pump module 207. At process 406, a formation fluid sample is extracted from the main flow line. In one example, as shown in FIG. 3, the valve 304 is open between the main flow line 204 and the secondary flow line 302 so that a formation fluid sample passes into the secondary flow line of the fluid analyzer module 210. In other embodiments, the formation fluid sample is extracted from a different flow line, such as bypass flow line 301. At process 408, an analysis of the formation fluid sample is performed within the wellbore tool to determine a property of the formation fluid sample. This analysis is performed by, for example, the fluid analyzer module 210, as shown in FIGS. 2 and 3.
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 FIG. 2 shows mud filtrate contamination within the formation 106. According to past methods, the wellbore tool continues to withdraw and pump formation fluid out of the formation until the fluid within the main flow line has “cleaned up.” One measure for determining whether the formation fluid has cleaned up is the stability of the ratio of formation water to oil within the flow line. After the formation fluid has cleaned up, the clean formation fluid can be analyzed. Thus, in the past, the approach to formation fluid analysis was dependent on clean formation fluid within the flow line. In contrast, the rapid formation fluid analysis method described herein performs an analysis of the formation fluid independent of mud filtrate contamination within the flow line by excluding the mud filtrate contamination within the flow line. The analysis can be performed before the formation fluid within the main flow line has “cleaned up” and while there is still substantial mud filtrate contamination. Substantial mud filtrate contamination can range between 5 percent and 99 percent of the fluid within the main flow line. Accordingly, embodiments of the rapid formation fluid analysis method avoid long cleanup times and reduce costs associated with wireline and LWD logging operations, Various embodiments also facilitate wireline and LWD logging measurements that would otherwise be prohibitively expensive or pose an excessive risk for “sticking” the wellbore logging system against the wellbore wall.
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, FIG. 5 shows a method 500 for determining a property of a formation that is contaminated by an oil-based mud filtrate. The method 500 of FIG. 5 includes positioning a wellbore tool at a first location within a wellbore 502, withdrawing a formation fluid from the formation and passing the formation fluid through a flow line within the tool 504, and extracting a formation fluid sample from the flow line 506. The method 500 further includes identifying a plurality of chemical components within the formation fluid sample using gas chromatography 508. In this embodiment, the fluid analyzer module includes a gas chromatograph that determines the chemical composition of the fluid sample. In one particular embodiment, the chromatograph determines the individual chemical components of the fluid sample from C₁to C₂₅. At process 510, chemical components that constitute the oil-based mud filtrate are excluded from consideration. In one specific example, one or more chemical components with carbon numbers between C₈and C₂₀are excluded from consideration. At process 512, the remaining set of chemical components (e.g., C₁-C₇and C₂₁₊) is used to determine the property of the formation. In this manner, the method analyzes the formation fluid sample independently of oil-based mud filtrate contamination within the flow line. Those chemical components that make up the mud filtrate are not used in the analysis and thus do not invalidate or adversely impact the analysis.
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, C₁₃and C₁₅-C₁₈are known chemical components of the drilling mud and those chemical components are excluded from consideration.
FIG. 6A shows a “contaminated” chromatogram 602 that was obtained by analyzing a formation fluid sample contaminated with an oil-based mud filtrate. In this case, the formation fluid sample included 50 percent contamination with an oil-based mud filtrate. The oil-based mud filtrate included chemical components with carbon numbers between C₁₅to C₁₈and those components are represented as enlarged peaks within the chromatogram. Per process 510 of FIG. 5, the C₁₅to C₁₈chemical components and representative peaks are removed from consideration and not used to determine the properties of the fluid sample. FIG. 6A also shows a reference chromatogram 604 that was obtained by analyzing a formation fluid sample that was uncontaminated by the oil-based mud filtrate. The enlarged peaks representative of the oil-based mud filtrate do not appear within the reference chromatogram 604.
FIG. 6B shows a more detailed view of the chromatograms 602, 604 of FIG. 6A. In particular, FIG. 6B shows the representative peaks of components with carbon numbers from C₁to C₇. The representative peaks within the contaminated chromatogram 602 match the representative peaks within the reference chromatogram 604. The peaks within the contaminated chromatogram 602 are smaller than the representative peaks within the reference chromatogram 604 due to the smaller quantity of original formation fluid in the contaminated chromatogram. As explained above, the contaminated sample included 50 percent contamination from oil-based mud filtrate. FIGS. 6A and 6B show that the representative peaks from C₁to C₇within the contaminated chromatogram 602 can be reliably used to determine a property of the formation fluid sample because they match the representative peaks within the reference chromatogram 604. More specifically, the representative peaks from C₁to C₁₄and the representative peaks greater than C₁₈can be used to determine a property of the formation fluid sample because those areas of the chromatogram were not affected by the oil-based mud filtrate.
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 C₈and C₂₀are excluded because drilling muds generally include chemical components with carbon numbers between C₈and 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 C₁₀or C₁₁, but some diesel and distillation based muds will start at C₈or C₉. Other oil-based muds, such as synthetic oil-based muds, are much more monodisperse and have a higher carbon number anywhere from C₁₂to 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 C₁₆and C₂₀. Accordingly, on the higher end, there are small concentrations of components above the C₂₀endpoint within drilling muds and, at the lower end, there are very small concentrations of components below C₈.
The method 500 of FIG. 5 will provide a partial chemical composition of the formation fluid within the formation (e.g., individual C₁-C₇and C₂₁₊ fractions). In turn, this chemical composition information can be used to determine a property of the formation (e.g., a hydrocarbon reservoir). In one example, the partial chemical composition itself is a property of the formation and provides information about the different types of hydrocarbons present within the formation. The partial chemical composition can also be used to determine other properties of the formation. For example, the lighter individual hydrocarbon fractions (e.g., C₁-C₇) that remain for consideration can provide valuable information about the properties of the formation. Specifically, C₇isomers are separated using gas chromatography and the C₇isomer ratio 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/or thermochemical sulfate reduction of the hydrocarbons, as described in, for example, Peters et al., The Biomarker Guide, Vol. 1, pp. 162-190 (2007). In particular, a decreased ratio of toluene over n-heptane indicates water washing and proximity of a water zone. An increase of the cyclopentanes over n-heptane indicates biodegradation. In another example, the chemical components from C₁to C₅can be used to determine wetness ratios, balance ratios, and character ratios as described in Haworth et al., Interpretation of Hydrocarbon Shows Using Light (C₁-C₅) Hydrocarbon Gases From Mud Log Data, AAPG Vol. 69, pp. 1305-1310 (1985). In yet another example, the ratios between the C₁, C₂, C₃and C₄components (e.g., elevated (C₁) levels in particular) can be used to determine the presence of secondary charging or biodegradation.
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 C₁₇and C₁₈. Other biomarkers will elute between C₂₄and C₃₆, such as hopanes, which elute around C₂₇to 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, FIG. 7 shows a method 700 for determining a property of a formation that is contaminated by a water-based mud filtrate. The method 700 of FIG. 7 includes positioning a wellbore tool at a first location within a wellbore 702, withdrawing a formation fluid from the formation and passing the formation fluid through a flow line within the wellbore tool 704, and extracting a formation fluid sample from the flow line 706 (e.g. the main flow line 204 or bypass flow line 301). At process 708, the method 700 further includes removing water from the formation fluid sample by passing the formation fluid sample through a membrane. This membrane may be a hydrophobic membrane that separates a water fraction from an oil fraction, such as the membrane 306 shown in FIG. 3. Furthermore, processes 706 and 708 may happen simultaneously. Then, at process 710, the formation fluid sample is analyzed within the wellbore tool to determine a property of the formation. In one example of the method, the fluid analyzer is a spectrometer and the analyzing process 710 is performed to measure the C₁, C₂, lumped C₃-C₅, and lumped C₆₊ fractions within the formation fluid sample. This analysis is performed independently of water-based mud filtrate contamination within the flow line because the membrane removes the water before the formation fluid sample enters the fluid analyzer. Accordingly, the method can analyze the formation fluid sample before the water filtrate within the flow line has cleaned up.
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. FIG. 8 shows a plot 806 that was generated by optically analyzing a formation fluid sample that was separated using the membrane. In particular, three different plots are shown within FIG. 8. Plot 802 represents the optical spectrum for a heavy oil and plot 804 shows the optical spectrum produced by an emulsion of water and the same heavy oil. As the plots show, the water has a substantial impact on the optical diffraction of the sample and many optical characteristics of the original crude oil are lost. Plot 806 shows the optical spectrum produced by the separated heavy oil. To produce plot 806, the emulsion of water and the heavy oil was passed through the membrane and then optically analyzed. Plot 806 is nearly identical to the plot 802 produced by the original heavy oil. FIG. 8 shows that the membrane can be reliably used to remove the water fraction and to produce a formation fluid sample that accurately represents the original hydrocarbon fraction within the formation.
FIG. 9 shows a series of oils samples. Sample 902 is an original oil sample, sample 904 is an emulsion of the original oil sample and water and sample 906 represents a sample after the emulsion has been passed through the membrane. FIG. 9 shows how a membrane can be used to return a formation fluid sample to a state 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. FIG. 10 shows a wireline log 1000 that was obtained using a rapid formation fluid analysis method. In particular, the log 1000 in FIG. 10 was obtained using a spectrometer disposed behind a hydrophobic membrane. FIG. 11 shows a concurrent wireline log 1100 that was obtained using a spectrometer-based conventional fluid analysis system. A comparison between FIGS. 10 and 11 shows the ability of the membrane to produce a stable optical measurement. The wireline log 1100 in FIG. 11 shows a live plot of oil and water fractions. Reference number 1102 refers to areas with large fluctuations of water and reference number 1104 refers to areas with large fluctuations in oil. In some cases, the conventional fluid analysis system yields data where the oil and water fraction add up to greater than one. This means that the data in these areas in the log 1100 is generally not reliable. Reference number 1106 refers to such areas on the wireline log 1100. Such areas 1106 are an indication of very high optical scattering due to mud filtrate inside the flow line. In contrast, the wireline log 1000 in FIG. 10 shows a wireline log 1000 that was obtained using a 4 channel spectrometer disposed behind a hydrophobic membrane. The wireline log includes plots 1002, 1004, 1006, 1008 for each channel of the spectrometer. As shown by the plots, even when the conventional system fails to detect oil (e.g., around time mark 1071.0 on the wireline log 1100), the 4 channel spectrometer records a signal that can be used to determine the composition of the oil. This comparison shows that the combination of the membrane and spectrometer can detect much smaller optical oil signatures, as compared to the conventional system. FIG. 10 further shows that the oil signal is stable for the next 1.8 hours, whereas the conventional system shows heavy fluctuation of oil and water.
FIG. 12 shows another example of how the rapid formation analysis method can be used to accurately detect and analyze the hydrocarbon fraction of formation fluids. In this example, the rapid formation fluid analysis method was implemented by a wireline tool with a selectively extendable fluid admitting assembly (e.g., probe). In particular, three different plots are shown within FIG. 12. Plot 1202 represents an optical spectrum generated by a spectrometer that was located near the probe of the wireline tool before a pump (e.g., after probe 202 and before pump module 207 in FIG. 2). The spectrometer before the pump analyzes an initial formation fluid that is free of a water/oil emulsion. Accordingly, plot 1202 has a low optical density baseline with no evidence of optical scattering. The second plot 1204 represents an optical spectrum generated by a second spectrometer that is disposed further downstream after the pump within the wireline tool (e.g., after pump module 207 in FIG. 2). This second spectrometer produces a large increase in optical scattering because the pump churns up oil and water within the formation fluid and produces a highly scattering emulsion. Plot 1206 represents an optical spectrum generated by a third spectrometer that was also located after the pump (e.g., after pump module 207 in FIG. 2). This third spectrometer, however, was disposed after a hydrophobic membrane that removed water from the formation fluid sample. As shown by plot 1206, the rapid formation analysis method accurately reproduces the optical spectrum 1202 generated by the initial emulsion-free formation fluid.
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). FIG. 13 shows optical spectra for a set of single phase fluids, such as water, heavy oil, medium oil, etc. The optical spectrum that results from a mixture of oil and water depends on (1) the oil and water fraction and (2) how the fluids mix together. FIG. 14 shows one potential spectrum generated from a 50 percent oil and water mixture. The mixture had a multi-phase flow with slugs of oil and slugs of water (e.g., a “sluggy” flow). As compared with FIG. 13, the oil color is affected dramatically by the presence of water. In particular, the methane absorption peak (C₁) is quite weak and can be masked in the presence of water. By applying the rapid formation analysis method, the water can be removed from the formation fluid and a more accurate color of the formation fluid can be obtained.
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 C₁to C₂₅fractions of the formation fluid sample. For example, in one specific embodiment, the fluid analyzer module, as shown in FIG. 3, includes a gas chromatograph. This fluid analyzer configuration can be used to analyze formation fluid contaminated with both water-based mud filtrates and oil-based mud filtrates. When analyzing a formation fluid with water based contamination, the hydrophobic membrane removes the water from the formation fluid and the gas chromatograph analyzes the formation fluid sample to determine the individual C₁to C₂₅fractions within the formation fluid sample. In the case when the mud filtrate is an oil-based mud filtrate, the gas chromatograph analyzes the formation fluid sample to determine the individual C₁to C₂₅fractions within the formation fluid sample and the chemical components that constitute the oil-based mud filtrate are excluded from consideration. In this case, although the hydrophobic membrane does not prevent oil-based mud filtrate from passing to the gas chromatograph, the membrane does advantageously protect the gas chromatograph from water, which can damage stationary phases within the gas chromatograph. In yet further embodiments, one of mass spectroscopy, visible absorption spectroscopy, infrared absorption spectroscopy, fluorescence detection, bubble point measurements, dew point measurements, asphaltene onset pressure measurements, resistivity measurements, fluid pressure measurements, fluid density measurements, fluid viscosity measurements, and fluid temperature measurements can also be used to analyze the formation fluid sample. Combinations of such techniques may also be used.
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 FIG. 2. Once the formation fluid is uncontaminated, the analysis of the formation fluid is performed. The analysis of the uncontaminated formation fluid can be performed within the main flow line or the uncontaminated formation fluid can be extracted from the main flow line into a secondary flow line and analyzed within the secondary channel. In another example, the comprehensive analysis includes extracting an uncontaminated formation fluid sample from the flow line and then transporting the uncontaminated formation fluid sample for surface analysis.
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 C₁to 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 FIGS. 1-3. For example, the embodiments described herein can also be used with any suitable means of conveyance, such coiled tubing. Furthermore, various embodiments of the present disclosure may also be applied in logging-while-drilling (LWD) operations, sampling-while-drilling operations, measuring-while-drilling operations or any other operation where sampling of the formation is performed.
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 FIG. 1). The processes are performed at the well site using the processing system within the truck. In other embodiments, however, the processes may be performed at a location that is remote from the well site, such as an office building or a laboratory.
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

What is claimed is:

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:

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.