BACKGROUND
TECHNICAL FIELD
The present disclosure generally relates to downhole tools and in particular to systems and methods for downhole fluid sampling.
BACKGROUND INFORMATION
Oil and gas wells have been drilled at depths ranging from a few thousand feet to as deep as five miles. A large portion of the current drilling activity involves directional drilling that includes drilling boreholes deviated from vertical by a few degrees to horizontal boreholes to increase the hydrocarbon production from earth formations.
Information about the subterranean formations traversed by the borehole may be obtained by any number of techniques. Techniques used to obtain formation information include obtaining one or more core samples of the subterranean formations and obtaining fluid samples produced from the subterranean formations these samplings are collectively referred to herein as formation sampling. Modern fluid sampling includes various downhole tests and sometimes fluid samples are retrieved for surface laboratory testing.
Typical downhole fluids can include drilling fluids, return fluids, and production fluids containing one or more hydrocarbons. Downhole fluids, depending on composition, temperature, and pressure, can be viscous and/or adhesive in nature. For example, production hydrocarbons can include one or more viscous and/or adhesive asphaltenic compounds, each having twenty or more carbon atoms. Surface-based fluid analyses and downhole fluid analysis are often affected due to the inability to properly purge downhole fluid samples from test cells and from instrument sensors. Fluid buildup on downhole instrument sensors can undesirably increase response time and may cause an unwanted offset in signal response.
SUMMARY
The following presents a general summary of several aspects of the disclosure in order to provide a basic understanding of at least some aspects of the disclosure. This summary is not an extensive overview of the disclosure. It is not intended to identify key or critical elements of the disclosure or to delineate the scope of the claims. The following summary merely presents some concepts of the disclosure in a general form as a prelude to the more detailed description that follows.
Disclosed is an apparatus for sampling a downhole fluid. The apparatus can include a tool having at least one surface element wetted by a downhole fluid, and the at least one surface element may include a fluid-repellant material disposed on a substrate for repelling some or all of the downhole fluid wetting the at least one surface element.
An exemplary method for sampling a downhole fluid includes wetting at least one surface element of a tool with a downhole fluid the at least one surface element comprising a fluid-repellant material disposed on a substrate. The method may further include repelling some or all of the downhole fluid from the at least one surface element.
An exemplary method for manufacturing an apparatus for sampling a downhole fluid includes disposing a fluid-repellant material on a substrate to form a surface element. The manufacturing method further includes forming at least a portion of a downhole fluid sampling tool using the surface element, the surface element being wettable by a downhole fluid during operation of the downhole fluid sampling tool.
BRIEF DESCRIPTION OF THE DRAWINGS
For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the several non-limiting embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:
FIG. 1 schematically represents a non-limiting example of an illustrative tool for conducting a downhole operation according to one or more embodiments of the disclosure;
FIG. 2 shows a cross-sectional view of an exemplary surface element according to one or more embodiments of the disclosure;
FIG. 3 depicts a non-limiting example of an illustrative device cross section showing a surface element having a coated substrate according to one or more embodiments of the disclosure;
FIG. 4 is a non-limiting elevation view of an exemplary well logging apparatus according to several embodiments of the disclosure; and
FIG. 5 is a non-limiting elevation view of an exemplary simultaneous drilling and logging system that incorporates several aspects of the disclosure.
DESCRIPTION OF EXEMPLARY EMBODIMENTS
FIG. 1 schematically represents a non-limiting example of an illustrative tool 100 for conducting a fluid sampling operation according to one or more embodiments of the disclosure. The tool 100 may be disposed within or about a carrier 134. The carrier 134 may be a surface-located carrier or may be used for transporting the tool 100 into a well borehole. The tool 100 may include any number of devices for conducting downhole operations. The tool devices shown in the example of FIG. 1 include a spectrometer 104, and a sensor test section including sensors 118, 120, 122, 124, and a sensor interface 138 and one or more sample chambers 116. A downhole computing device 128 having a processor 130 and a data storage unit 132 is shown coupled to the spectrometer 104 and to the sensor section via a communications bus 136. Information processed in the computing device 128 may be transmitted via the bus 136 to other devices including, but not limited to, controllers, loggers, transmitters, or any combination thereof. The communication bus 136 can include one or more optical and/or one or more electrical cables as desired for a particular tool configuration. These and similar devices may be used for sampling and testing downhole fluids sampled by the tool 100.
In the non-limiting example of FIG. 1, a pump 142 is in fluid communication with fluid conduits 112 and one or more ports 102 for permitting downhole fluids to flow into the tool 100 and through, into, and/or around the one or more devices disposed within the carrier 134. Sampled downhole fluids may be expelled from the tool 100 via one or more outlet ports 114 positioned as desired on the carrier 134 and in fluid communication with the fluid conduits 112. The downhole fluids may include, but are not limited to, polar and non-polar drilling fluids, return fluids, and/or formation fluids. The downhole fluids may include one or more hydrocarbon species containing twenty or more carbon atoms, for example asphaltenes having one or more viscous, high molecular weight hydrocarbons. These highly viscous, and often adhesive, downhole fluids may tend to buildup on wetted surface elements 200 of downhole and/or uphole devices and on the surface elements 300 of other devices that contact the downhole fluids during sampling or testing. Several exemplary downhole devices such as the spectrometer 104, sensors 118, 120, 122, 124 and/or fluid sample chambers 136 include respective surface elements 200, 300 that will contact downhole fluid as depicted in the exemplary embodiment of FIG. 1.
Still referring to FIG. 1, the downhole fluid may flow through fluid conduits 112, to the spectrometer 104. An exemplary spectrometer 104 may include a light source 106, a sample region 108, and one or more detectors 110, 111 for measuring the optical properties of downhole fluid within a fluid sample region 108. The fluid sample region 108 includes a surface element 200 in contact with fluid in the fluid sample region 108. The downhole fluid may be conveyed via the fluid conduits 112 to a valve 144 that may be actuated to convey the downhole fluid to a test section where a sensor interface 106 may be coupled to sensors, such as the sensors 118, 120, 122, and 124 mentioned above that have respective surface elements 300 contacting the downhole fluid flowing in the test section. The sensors 118, 120, 122, 124 may include any number of sensor types. For example, sensors in the test section may include a temperature sensor 118, a pressure sensor 120, a stress sensor 122, a distance sensor 124 as shown or any other sensor type that may be useful in estimating downhole fluid properties. The exemplary temperature sensor 118 can include at least one temperature sensitive device, for example a thermocouple, thermistor, resistance temperature detectors (RTD), or any combination of one or more devices, suitable for converting the temperature of the fluid flowing past the sensor into one or more signals. The pressure sensor 120 can include at least one pressure sensitive device, for example a mechanical deflection sensor, strain gauge, piezoresistive semiconductor sensor, micro-electromechanical system (MEMS) sensor, vibrating element sensor, variable capacitance sensor, or any combination thereof. The one or more stress sensors 122 can include one or more acceleration and/or vibration sensors. Downhole fluid may be expelled before or after entering the test section or may be retained for later testing.
In some embodiments, the valve 144 may be actuated to expel the downhole fluid from the tool via an outlet port 114 positioned upstream of the test section. The downhole fluid may be further conveyed via the fluid conduits 112 to an outlet port 114 downstream of the test section or may be directed via a valve 146 to the sampling chamber 116. In some embodiments, the sampling chamber may be flushed using another valve 148 and outlet port positioned downstream of the sampling chamber 116. The sampling chamber 116 may include a surface element 200 that is in contact with fluid in the sampling chamber 116. The several surface elements 200, 300 are further described below with reference to FIGS. 2 and 3.
FIG. 2 shows a cross-sectional view of an exemplary surface element 200 according to one or more embodiments of the disclosure. A surface element 200 according to several exemplary embodiments includes a substrate 210 with a surface portion 205 comprising a fluid-repellent material 220. The surface portion 205 may be chemically and/or mechanically bonded to the substrate 210. The fluid-repellent material 220 may be selected to prevent the buildup and/or adhesion of the downhole fluid 215 to the surface portion 205, thereby improving the flow of the downhole fluid 215 past or along the coated substrate 210. The fluid-repellent material 220 can include, but is not limited to, polytetrafluoroethylene (PTFE) compounds, fluorocarbon resins, fluoropolymers, silicone polymers, mixtures thereof and/or combinations thereof. The fluid-repellent material 220 can be applied to the substrate during or after fabrication of the wetted surfaces in both the tool 100 and the carrier 134 thereby providing a fluid-repellent surface portion 205 on the wetted surfaces. The fluid-repellent material 220 can be applied as a liquid, solid, or gas through any deposition process amenable to providing a continuous, non-porous coating on the selected wetted surfaces within the carrier 134. For example, the fluid-repellent material 220 can be applied to the substrate 210 using application techniques including, but not limited to, powder coating, spraying, immersion, electrostatic precipitation or deposition, gas phase condensation, or any combination thereof. The surface element 200 may be incorporated as a portion of any number of the fluid-contacting surfaces described above and shown in FIG. 1. In some examples, the surface element 200 may form a portion of a sensor that contacts downhole fluids as described below with reference to FIG. 3.
FIG. 3 depicts a non-limiting example of an illustrative device cross section 300 showing a surface element 200 having a coated substrate 210 according to one or more embodiments of the disclosure. The substrate 210 can include any wetted internal or external surface disposed in, on, or about the tool 100 and/or carrier 134. The exemplary view of FIG. 3 shows one or more sensors 305 disposed on the substrate 210. The sensors 305 can be in fluid and/or electrical communication with other elements, components and/or devices within the carrier 134 via one or more electrical conductors and/or fluid conduits shown schematically at 310. The sensors 305 may include, but are not limited to, one or more pressure sensors, temperature sensors, optical sensors, fluorescence sensors, flow rate sensors, viscosity sensors, or any combination thereof. The sensors 305 can include one or more wavelength specific light generators and/or receivers. Where the one or more sensors 305 include optical devices such as optical sensors, wavelength specific light generators and/or receivers, the fluid-repellent material 205 disposed on or about the sensor 305 can be translucent and/or transparent to one or more selected light frequencies generated and/or received by the one or more sensors 305. The several sensor embodiments may be incorporated into a tool 100 for sampling downhole fluids as described above and shown in FIG. 1, and as mentioned, the tool may 100 a surface tool or a downhole tool. Downhole tools may be conveyed via wireline or drill string as described below.
FIG. 4 shows a non-limiting example of a well logging apparatus 400 according to several embodiments of the disclosure. The well logging apparatus 400 is shown disposed in a well borehole 402 penetrating one or more formations 404 for making measurements of properties of the formations 404. The borehole 402 is typically filled and/or pressurized with drilling fluid to prevent formation fluid influx.
A tool string 406 can be lowered into the well borehole 402 using one or more cables 408 that can be spooled and unspooled using a winch or drum 410. At least one of the cables 408 can be an armored communications cable containing one or more communications buses 136. The tool string 406 can be in two-way communication with surface equipment 412 using the communications cable 136, containing one or more optical fibers and/or electrical conductors, within the armored communications cable 408. As depicted in FIG. 4, the tool string 406 can include one or more tools 100 as described in detail with respect to FIG. 1 above. The tool string 406 can preferably be centered within the well borehole 402 using one or more centralizers 422a, 422b attached to the tool string 406 at axially distant locations. The centralizers 422a, 422b can be of types well known in the art, such as bowsprings.
The surface equipment 412 can include one or more telemetry systems 414 for communicating control signals and data to the tool string 406 and one or more computers 416. The computer 416 can include one or more recorders 418 for storing, plotting, and/or recording data acquired using the one or more downhole tools 100 and transmitted via the communications bus 136 to the surface equipment 412. Circuitry for controlling and operating the one or more tools 100 can be located within the tool string 406, for example within one or more electronics cartridges 424. The circuitry can be connected to the one or more tools 100 using one or more connectors 426. In several embodiments, the tool 100 can incorporate one or more high-gain semiconductor devices such as one or more of the devices described herein with respect to FIG. 1, FIG. 2, and/or FIG. 3.
FIG. 5 is an elevation view of a simultaneous drilling and logging system 500 that may incorporate non-limiting embodiments of the disclosure. A well borehole 502 can be drilled into the earth under control of surface equipment including a drilling rig 506. In accordance with a conventional arrangement, rig 506 includes a drill string 514. The drill string 514 can be a coiled tube, jointed pipes or wired pipes as well known by those skilled in the art. In one example, a bottom hole assembly (“BHA”) 550 may include one or more tools 100 such as one or more of the devices described herein with respect to FIG. 1, FIG. 2, and/or FIG. 3.
While-drilling tools will typically include a drilling fluid 526 circulated from a mud pit 528 through one or more mud pumps 530, past one or more desurgers 532, and through one or more mud supply lines 534. The drilling fluid 526 can flow through a longitudinal central bore in the drill string 514 exiting through one or more jets (not shown) disposed about the lower face of a drill bit 524. Return fluid containing drilling mud, cuttings and formation fluid can be returned to the surface via the annular region 538 that exists between the outer surface of the drill string 514 and the inner surface of the borehole 502. Return fluid exiting the annular region 538 can be directed via line 542 to the mud pit 528 for analysis, recovery, recycle and/or disposal.
The system as depicted in FIG. 5 can use any conventional telemetry methods and devices for communication between the surface and one or more downhole components and/or tools 100. In the embodiment shown mud pulse telemetry techniques can be used to communicate data from downhole to the surface during drilling operations. A surface controller 548 can be used for processing commands and other information used in the drilling operations.
In one or more embodiments, a downhole drill motor 536 can be included in the drill string 514 for rotating the drill bit 524. In several embodiments, the while-drilling tool 100 can incorporate one or more high-gain semiconductor devices such as any of the devices described herein and shown in FIGS. 1 through 3.
A telemetry system 552 may be located in a suitable location on the drill string 514 such as above the tool 100. The telemetry system 552 may be used to transmit and/or receive commands and/or data to the surface controller 548 using mud pulse telemetry or by other communication techniques known in the art. For example, acoustic pipe telemetry and/or wired pipe telemetry may be used.
The surface controller 548 can include one or more data processing systems, one or more data storage systems, one or more data recording systems, one or more data handling peripherals, or any combination thereof. The surface controller 548 can also respond to user commands entered through a suitable man-machine interface, such as a keyboard. In one non-limiting embodiment, the BHA 550 can incorporate various aspects of the disclosure, including, but not limited to, sensors and logging-while-drilling (LWD) devices to provide information about the formation, downhole drilling parameters and the mud motor.
Several operational examples will now be described with reference to the several exemplary embodiments described above and shown in FIGS. 1-5. In one or more exemplary embodiments, the illustrative tool 100 as depicted in FIG. 1 can be deployed downhole via wireline or while drilling, as described above and shown in FIG. 4 and FIG. 5. A downhole fluid can be sampled by introducing a portion of the downhole fluid into the tool 100 via the inlet port 102 disposed about the carrier 134. Within the tool 100, the downhole fluid can be pumped using the pump 142 to convey the downhole fluid through one or more fluid conduits 112, to other devices in the tool 100.
In this operational example, the fluid is conveyed to the spectrometer 104 where properties of the fluid within the sample region 108 are estimated based upon the transmissive, refractive and/or reflective properties of the fluid within the sample region 108. Fluid leaving the sample region 108 may be directed to an outlet port or to a fluid test section using the valve 144 installed at the discharge of the sample region 108 in the spectrometer 104. The fluid contacting the surface element 200 of the sample chamber 108 is repelled from the surface element by the fluid repellent material 220 forming a portion or the surface element 200. Fluid may be discharged from the tool for any number of reasons. Sometimes the fluid is discharged until the fluid content is substantially free of wellbore fluids so that fluid entering the test section is substantially pristine formation fluid. Having a fluid repellent material as a portion of the surface element helps to provide self cleaning for the sample region 108. When further testing is desired, then the fluid is directed to the test section via the valve 144, to the several sensors 118, 120, 122, and/or 124 in the test section.
The physical properties of the fluid in the test section, such as density, and downhole conditions such as temperature and pressure, are estimated using the sensors 118, 120, 122, 124. The fluid repellent material 220 forming a portion of the surface element 300 of the several sensors helps repel fluid from the sensor surfaces contacting the fluid. In this manner, the sensor sensitivity may be better maintained due in part to keeping the sensing surface clean of fluid residue. Fluid passing through the test section may be directed to the outlet port 114 downstream of the test section or to the fluid sample chamber 116 via the fluid conduits 112.
The fluid contained within the sample chamber 116 may be retained for later analysis by closing the two-way valve 148 located on the discharge of the sample chamber 116. Alternatively, the fluid within the sample chamber 116 can be rejected from the tool 100 by opening the two-way valve 148, permitting the fluid within the sample chamber 116 to flow through the fluid conduit 112 to the discharge port 114. The fluid repellent material 220 used as a portion of the sample chamber surface element helps when flushing fluid samples from the sample chamber.
The present disclosure is to be taken as illustrative rather than as limiting the scope or nature of the claims below. Numerous modifications and variations will become apparent to those skilled in the art after studying the disclosure, including use of equivalent functional and/or structural substitutes for elements described herein, use of equivalent functional couplings for couplings described herein, and/or use of equivalent functional actions for actions described herein. Such insubstantial variations are to be considered within the scope of the claims below.
Patent Application
20090166037
