Methods and Apparatus for Downhole Extraction and Analysis of Heavy Oil

Abstract

Methods and apparatus for downhole extraction and analysis of heavy oil are disclosed. An example method includes lowering a viscosity of formation fluid in a subterranean formation and flowing the formation fluid from the subterranean formation into a downhole tool. The example method also includes controlling the viscosity of at least a portion of the formation fluid in the downhole tool.

Description

FIELD OF THE DISCLOSURE

This disclosure relates generally to sampling formation fluid and, more particularly, to methods and apparatus for downhole extraction and analysis of heavy oil.

BACKGROUND

Recently, exploration of heavy oil has increased. Venezuela and Canada each have reserves of about 170 billion barrels of heavy oil. The viscosity of the heavy oil is generally between 1,000 cP and 10,000 cP.

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.

An example method disclosed herein includes lowering a viscosity of formation fluid in a subterranean formation, flowing the formation fluid from the subterranean formation into a downhole tool, and controlling the viscosity of a portion of the formation fluid in the downhole tool.

An example downhole tool disclosed herein includes a pressurization device to draw formation fluid from a subterranean formation into a flowline of the example downhole tool. The example downhole tool also includes a chamber to enclose a portion of the flowline. The chamber is to control a viscosity of the formation fluid flowing through the portion of the flowline enclosed by the chamber.

Another example method disclosed herein includes flowing formation fluid from a subterranean formation into a microfluidic flowline disposed in a downhole tool and controlling a viscosity of the formation fluid in a portion of the microfluidic flowline.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an example system in which embodiments of example methods and apparatus for downhole extraction and analysis of heavy oil can be implemented.

FIG. 2 illustrates another example system in which embodiments of the example methods and apparatus for downhole extraction and analysis of heavy oil can be implemented.

FIG. 3 illustrates another example system in which embodiments of the example methods and apparatus for downhole extraction and analysis of heavy oil can be implemented.

FIG. 4 illustrates various components of an example device that can implement embodiments of the methods and apparatus for downhole extraction and analysis of heavy oil.

FIG. 5 also illustrates various components of the example device that can implement embodiments of the methods and apparatus for downhole extraction and analysis of heavy oil.

FIG. 6 illustrates example methods for downhole extraction and analysis of heavy oil in accordance with one or more embodiments.

DETAILED DESCRIPTION

Certain examples are shown in the above-identified figures and described in detail below. In describing these examples, like or identical reference numbers are used to identify common or similar elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale or in schematic for clarity and/or conciseness. Accordingly, while the following describes example systems, persons of ordinary skill in the art will readily appreciate that the examples are not the only way to implement such systems.

Example methods and apparatus for downhole extraction and analysis of heavy oil are disclosed herein. Example methods disclosed herein may include lowering a viscosity of formation fluid in a subterranean formation. Lowering the viscosity of the formation fluid in the subterranean formation may include heating the subterranean formation. The example methods may also include flowing the formation fluid from the subterranean formation into a downhole tool and controlling the viscosity of at least a portion of the formation fluid in the downhole tool. Flowing the formation fluid into the downhole tool may include controlling a pressurization device. The viscosity of at least a portion of the formation fluid in the downhole tool may be controlled by separating a hydrocarbon phase from the formation fluid and heating the hydrocarbon phase. In some examples, the hydrocarbon phase is separated from the formation fluid by flowing the formation fluid through a hydrophobic filter.

FIG. 1 illustrates a wellsite system in which the present invention can be employed. The wellsite can be onshore or offshore. In this example system, a borehole 11 is formed in subsurface formations by rotary drilling in a manner that is well known. Embodiments can also use directional drilling, as will be described hereinafter.

A drill string 12 is suspended within the borehole 11 and has a bottom hole assembly 100 which includes a drill bit 105 at its lower end. The surface system includes platform and derrick assembly 10 positioned over the borehole 11. The assembly 10 includes a rotary table 16, kelly 17, hook 18 and rotary swivel 19. The drill string 12 is rotated by the rotary table 16, energized by means not shown, which engages the kelly 17 at the upper end of the drill string 12. The drill string 12 is suspended from the hook 18, attached to a traveling block (also not shown), through the kelly 17 and the rotary swivel 19, which permits rotation of the drill string 12 relative to the hook 18. As is well known, a top drive system could also be used.

In the example of this embodiment, the surface system further includes drilling fluid or mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers the drilling fluid 26 to the interior of the drill string 12 via a port in the swivel 19, causing the drilling fluid 26 to flow downwardly through the drill string 12 as indicated by the directional arrow 8. The drilling fluid 26 exits the drill string 12 via ports in the drill bit 105, and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows 9. In this well known manner, the drilling fluid 26 lubricates the drill bit 105 and carries formation cuttings up to the surface as it is returned to the pit 27 for recirculation.

The bottom hole assembly 100 of the illustrated embodiment including a logging-while-drilling (LWD) module 120, a measuring-while-drilling (MWD) module 130, a roto-steerable system and motor 150, and drill bit 105.

The LWD module 120 is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, e.g. as represented at 120A. (References, throughout, to a module at the position of 120 can also mean a module at the position of 120A as well.) The LWD module 120 includes capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the present embodiment, the LWD module 120 includes a fluid sampling device.

The MWD module 130 is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string 12 and drill bit. The MWD tool further includes an apparatus (not shown) for generating electrical power to the downhole system. This may include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In the present embodiment, the MWD module 130 includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.

FIG. 2 is a simplified diagram of a sampling-while-drilling logging device of a type described in U.S. Pat. No. 7,114,562, incorporated herein by reference in its entirety, utilized as the LWD tool 120 or part of an LWD tool suite 120A. The LWD tool 120 is provided with a probe 6 for establishing fluid communication with a formation F and drawing the fluid 21 into the tool, as indicated by the arrows. The probe 6 may be positioned in a stabilizer blade 23 of the LWD tool and extended therefrom to engage the borehole wall. The stabilizer blade 23 comprises one or more blades that are in contact with the borehole wall. Fluid drawn into the downhole tool using the probe 6 may be measured to determine, for example, pretest and/or pressure parameters. Additionally, the LWD tool 120 may be provided with devices, such as sample chambers, for collecting fluid samples for retrieval at the surface. Backup pistons 81 may also be provided to assist in applying force to push the drilling tool and/or probe against the borehole wall.

Referring to FIG. 3, shown is an example wireline tool 300 that may be another environment in which aspects of the present disclosure may be implemented. The example wireline tool 300 is suspended in a wellbore 302 from the lower end of a multiconductor cable 304 that is spooled on a winch (not shown) at the Earth's surface. At the surface, the cable 304 is communicatively coupled to an electronics and processing system 306. The example wireline tool 300 includes an elongated body 308 that includes a formation tester 314 having a selectively extendable probe assembly 316 and a selectively extendable tool anchoring member 318 that are arranged on opposite sides of the elongated body 308. Additional components (e.g., 310) may also be included in the tool 300.

The extendable probe assembly 316 may selectively seal off or isolate selected portions of the wall of the wellbore 302 to fluidly couple to the adjacent formation F and/or to draw fluid samples from the formation F. Accordingly, the extendable probe assembly 316 may be provided with a probe having an embedded plate, as described above. The formation fluid may be expelled through a port (not shown) or it may be sent to one or more fluid collecting chambers 320 and 322. In the illustrated example, the electronics and processing system 306 and/or a downhole control system are configured to control the extendable probe assembly 316 and/or the drawing of a fluid sample from the formation F.

FIG. 4 is a schematic view of an example downhole tool 400 that may be used to implement the example tools 100 and 120 of FIGS. 1 and 2 and 300 of FIG. 3. The example downhole tool 400 includes an elongated body 402 having an inlet 404 fluidly coupled to a main flowline 406. A separation block 408 such as, for example, a separation block described in U.S. Pat. No. 7,575,681, entitled “Microfluidic Separator” and filed on Sep. 8, 2004, which is incorporated herein by reference in its entirety, is adjacent the inlet 404 along the main flowline 406. The separation block 408 includes a filter 410 (e.g., a polytetrafluoroethylene membrane). In some examples, the filter 410 is hydrophobic and/or microfluidic. A microfluidic flowline 412 is fluidly coupled to the separation block 408. The microfluidic flowline 412 passes through at least one sensor 414, 416, 418, 420 and 422 (e.g., a viscometer, a bubble point sensor, etc.) disposed in a chamber 424. In some examples, one or more of the sensors 414, 416, 418, 420 and 422 are microfluidic. The chamber 424 encloses a portion of the microfluidic flowline 412.

The chamber 424 includes a heater 426 (e.g., a resistor wire) to control a temperature of an interior of the chamber 424. In some examples, the chamber 424 includes a fan and/or pump to circulate air inside the chamber 424. The microfluidic flowline 412 extends through the chamber 424 and is fluidly coupled to the main flowline 406 downstream of a backpressure regulator 428 such as, for example, a check valve or a relief valve disposed along the main flowline 406. A pressurization device 430 disposed in the example downhole tool 400 is fluidly coupled to an outlet 432 of the main flow line 406. In the example illustrated in FIG. 4, the pressurization device 430 is a piston 434 disposed in a cylinder 436. In some examples, the cylinder 436 has a volume of about 1 L. In other examples, the pressurization device 430 is a pump. The example downhole tool 400 also includes backup pistons 438.

FIG. 5 is a simplified, front view of the example downhole tool 400 of FIG. 4. The example downhole tool 400 includes a packer 500 adjacent the inlet 404 and a heater 502 adjacent the packer 500. The heater 502 is to heat a subterranean formation via conduction, ohmic heating, and/or microwave heating.

During operation, the heater 502 may be used to heat a subterranean formation to lower a viscosity of the formation fluid in the subterranean formation to a suitable viscosity (e.g., about 1000 cP). In some examples, the heater 502 heats about 1 L to about 1.5 L of formation fluid in the subterranean formation. Once the viscosity of the formation fluid is lowered to the suitable viscosity, the pressurization device 430 draws the formation fluid from the subterranean formation into the main flowline 406 of the example downhole tool 400. In some examples, the pressurization device 430 draws about 100 mL to about 0.5 L of formation fluid into the main flowline 406. The pressurization device 430, the backpressure regulator 428 and/or the filter 410 disposed in the separation block 408 cause a pressure differential across the filter 410 and between the main flowline 406 and the microfluidic flowline 412. As a result, the formation fluid passes through the filter 410, and a portion of the formation fluid (e.g., a hydrocarbon phase of the formation fluid) is separated from the formation fluid by the filter 410 and flows into the microfluidic flowline 412. A remainder of the formation fluid flows into the main flowline 406 downstream of the separation block 408, and the separated portion of the formation fluid (e.g., the hydrocarbon phase) is induced to flow into the microfluidic flowline 412 by the pressure differential.

The separated portion of the formation fluid passes through the one or more microfluidic sensors 414, 416, 418, 420 and 422 disposed in the chamber 424 to determine at least one characteristic (e.g., viscosity, density, composition, etc.) of the separated portion of the formation fluid. The heater 426 heats the interior of the chamber 424 to control the viscosity of the separated portion of the formation fluid flowing through the portion of the microfluidic flowline 412 enclosed by the chamber 424. After the separated portion of the formation fluid passes through the one or more microfluidic sensors 414, 416, 418, 420 and 422, the separated portion of the formation fluid flows into the main flowline 406 downstream of the pressure regulator 428. The separated portion and the remainder of the formation fluid are then drawn into cylinder 436 by the piston 434.

FIG. 6 depicts an example flow diagram representative of processes that may be implemented using, for example, computer readable instructions. The example process of FIG. 6 may be performed using a processor, a controller and/or any other suitable processing device. For example, the example processes of FIG. 6 may be implemented using coded instructions (e.g., computer readable instructions) stored on a tangible computer readable medium such as a flash memory, a read-only memory (ROM), and/or a random-access memory (RAM). As used herein, the term tangible computer readable medium is expressly defined to include any type of computer readable storage and to exclude propagating signals. The example process of FIG. 6 may be implemented using coded instructions (e.g., computer readable instructions) stored on a non-transitory computer readable medium such as a flash memory, a read-only memory (ROM), a random-access memory (RAM), a cache, or any other storage media in which information is stored for any duration (e.g., for extended time periods, permanently, brief instances, for temporarily buffering, and/or for caching of the information). As used herein, the term non-transitory computer readable medium is expressly defined to include any type of computer readable medium and to exclude propagating signals.

Some or all of the example process of FIG. 6 may be implemented using any combination(s) of application specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)), field programmable logic device(s) (FPLD(s)), discrete logic, hardware, firmware, etc. Also, one or more operations depicted in FIG. 6 may be implemented manually or as any combination(s) of any of the foregoing techniques, for example, any combination of firmware, software, discrete logic and/or hardware. Further, although the example process of FIG. 6 is described with reference to the flow diagram of FIG. 6, other methods of implementing the process of FIG. 6 may be employed. For example, the order of execution of the blocks may be changed, and/or some of the blocks described may be changed, eliminated, sub-divided, or combined. Additionally, one or more of the operations depicted in FIG. 6 may be performed sequentially and/or in parallel by, for example, separate processing threads, processors, devices, discrete logic, circuits, etc.

FIG. 6 depicts an example process 600 that may be used with the example downhole tool 400 disclosed herein. The example process 600 begins by lowering a viscosity of the formation fluid in the subterranean formation (block 602). The viscosity of the formation fluid may be lowered by heating the subterranean formation. At block 604, it is determined if the viscosity of the formation fluid is less than about 1000 cP. However, a different threshold viscosity value could be used instead. In some examples, whether the viscosity of the formation fluid is less than 1000 cP may be determined by an amount of time the subterranean formation is heated (e.g., 45 minutes). If the viscosity of the formation fluid is not less than 1000 cP, then the example method returns to block 602. If the viscosity of the formation fluid is less than 1000 cP, then the formation fluid is flowed from the subterranean formation into the example downhole tool 400 (block 606). In some examples, the formation fluid is flowed into the main flowline 406 by controlling a pressurization device 430 such as the piston 434.

At block 608, a pressure differential is provided between the main flowline 406 and the microfluidic flowline 412. In some examples, the pressurization device 430, the backpressure regulator 428 and/or the filter 410 disposed in the separation block 408 provide the pressure differential across the filter 410 and between the main flowline 406 and the microfluidic flowline 412. At block 610, a portion of the formation fluid is separated. For example, the pressure differential causes the formation fluid to pass through the filter 410 (e.g., a hydrophobic membrane) in the separation block 408, and the filter 410 separates a portion of the formation fluid from a remainder of the formation fluid. In some examples, the portion of the formation fluid separated from the remainder of the formation fluid is a hydrocarbon phase. At block 612, the separated portion of the formation fluid is flowed into the microfluidic flowline 412. For example, the differential pressure induces the separated portion of the formation fluid to flow into the microfluidic flowline 412.

A viscosity of the separated portion of the formation fluid is then controlled (block 614). The viscosity of the separated portion of the formation fluid may be controlled by controlling a temperature of the separated portion of the formation fluid in the microfluidic flowline 412. For example, the heater 426 of the chamber 424 heats the separated portion of the formation fluid flowing through the microfluidic flowline 412 enclosed by the chamber 424. At block 616, the separated portion of the formation fluid is flowed through at least one microfluidic sensor 414, 416, 418, 420 and 422 (e.g., a viscometer, a bubble point sensor, etc.). At least one characteristic of the separated portion of the formation fluid is determined by the one or more sensors 414, 416, 418, 420 and 422 (block 618).

Although a few 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 this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function, structural equivalents, and also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. § 1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

1. A method, comprising:

lowering a viscosity of formation fluid in a subterranean formation;

flowing the formation fluid from the subterranean formation into a downhole tool; and

controlling the viscosity of at least a portion of the formation fluid in the downhole tool.

2. The method of claim 1 wherein controlling the viscosity of at least a portion of the formation fluid in the downhole tool comprises:

separating a hydrocarbon phase from the formation fluid; and

heating the hydrocarbon phase.

3. The method of claim 2 wherein separating the hydrocarbon phase from the formation fluid comprises flowing the formation fluid through a hydrophobic filter.

4. The method of claim 2 further comprising providing a pressure differential to induce the hydrocarbon phase to flow into a microfluidic flowline.

5. The method of claim 1 wherein controlling the viscosity of at least a portion of the formation fluid in the downhole tool comprises controlling a temperature of at least a portion of the formation fluid in the downhole tool.

6. The method of claim 1 wherein lowering a viscosity of the formation fluid in the subterranean formation comprises heating the subterranean formation.

7. The method of claim 1 wherein flowing the formation fluid comprises controlling a pressurization device.

8. A downhole tool, comprising:

a pressurization device to draw formation fluid from a subterranean formation into a flowline of the downhole tool; and

a chamber to enclose at least a portion of the flowline and control a viscosity of the formation fluid flowing through the portion of the flowline enclosed by the chamber.

9. The downhole tool of claim 8 further comprising a heater to heat the subterranean formation.

10. The downhole tool of claim 8 wherein the chamber comprises a heater to heat an interior of the chamber.

11. The downhole tool of claim 8 further comprising a hydrophobic filter to separate a hydrocarbon phase from the formation fluid, wherein the hydrocarbon phase is to flow through the portion of the flowline enclosed by the chamber.

12. The downhole tool of claim 8 wherein the portion of the flowline enclosed by the chamber is a microfluidic.

13. The downhole tool of claim 8 wherein the pressurization device is a piston.

14. The downhole tool of claim 8 further comprising at least one microfluidic sensor disposed in the chamber to determine a characteristic of the hydrocarbon phase.

15. A method, comprising:

flowing formation fluid from a subterranean formation into a microfluidic flowline disposed in a downhole tool; and

controlling a viscosity of the formation fluid in at least a portion of the microfluidic flowline.

16. The method of claim 15 further comprising heating the subterranean formation.

17. The method of claim 15 wherein controlling a viscosity of the formation fluid in at least a portion of the microfluidic flowline comprises controlling a temperature of at least a portion of the formation fluid in the microfluidic flowline.

18. The method of claim 15 wherein flowing formation fluid from the subterranean formation into the microfluidic flowline comprises:

flowing formation fluid from the subterranean formation into a main flowline; and

providing a pressure differential between the main flowline and the microfluidic flowline.

19. The method of claim 15 wherein flowing the formation fluid from the subterranean formation into a microfluidic flowline comprises controlling a pressurization device.

20. The method of claim 15 further comprising separating a hydrocarbon phase from the formation fluid.