SEPARATION SYSTEM TO SEPARATE PHASES OF DOWNHOLE FLUIDS FOR INDIVIDUAL ANALYSIS

Abstract

An apparatus for sampling a fluid in a borehole may include a vessel configured to be disposed in a borehole and at least one sensor in communication with one phase of the plurality of phases in the vessel. The vessel separates the fluid into a plurality of phases.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application is claims priority from U.S. Provisional Patent Application Ser. No. 61/485,961, filed on May 13, 2011, the disclosure of which is incorporated herein by reference in its entirety.

FIELD OF THE DISCLOSURE

This disclosure pertains generally to investigations of underground formations and more particularly to systems and methods for evaluating downhole fluids.

BACKGROUND OF THE DISCLOSURE

Commercial development of hydrocarbon fields requires significant amounts of capital. Before field development begins, operators desire to have as much data as possible in order to evaluate the reservoir for commercial viability. While data acquisition during drilling provides useful information, it is often also desirable to conduct further testing of the hydrocarbon reservoirs in order to obtain additional data. Therefore, after a borehole for a well has been drilled, the hydrocarbon zones are usually tested with tools that acquire fluid samples, e.g., liquids from the formation. These fluids may be multi-phase fluids; i.e., fluids that are a mixture of water, hydrocarbons, and/or solids. The multi-phase nature of these fluids may reduce the accuracy of evaluation of a particular phase.

In one aspect, the present disclosure addresses the need to separate one or more phases of a downhole fluid.

SUMMARY OF THE DISCLOSURE

In one aspect, the present disclosure provides an apparatus for sampling a fluid in a borehole. The apparatus may include a vessel configured to be disposed in a borehole, the vessel being further configured to separate the fluid into a plurality of phases without substantially affecting a structure of at least one of the separated phases; and at least one sensor in communication with one phase of the plurality of phases in the vessel.

In another aspect, the present disclosure provides a method for sampling a fluid in a borehole. The method may include separating the fluid into a plurality of phases in a vessel positioned in the borehole without substantially affecting a structure of at least one of the separated phases; and estimating a parameter of interest relating to at least one phase separated from the fluid while the at least one phase is in the vessel.

Examples of certain features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:

FIG. 1 shows a schematic of a centrifugal-type of separator according to one embodiment of the present disclosure;

FIG. 2 shows a schematic of a thermal separator according to one embodiment of the present disclosure; and

FIG. 3 shows a schematic of a separator that uses reactive surfaces according to one embodiment of the present disclosure;

FIG. 4 shows a schematic of a membrane-based separator according to one embodiment of the present disclosure;

FIG. 5 illustrates a schematic of a formation evaluation system that includes a separator according to one embodiment of the present disclosure.

DETAILED DESCRIPTION

In aspects, the present disclosure relates to devices and methods to evaluate downhole fluids. As used herein, the term downhole fluid is generally any fluid found in a drilled wellbore and/or any fluid that resides in the formation. Downhole fluids include but are not limited to, naturally occurring fluids such as oil, gas, and water, as well as engineered fluids such as drilling fluids and surface injected fluids. The teachings may be advantageously applied to a variety of systems in the oil and gas industry, water wells, geothermal wells, surface applications and elsewhere. Merely for clarity, certain non-limiting embodiments will be discussed in the context of hydrocarbon producing wells.

Referring initially to FIG. 1, there is schematically illustrated one embodiment of a test tool 100 that may be used to actively separate a fluid into two or more homogeneous materials or phases (e.g., a polar phase, a nonpolar phase, an aqueous phase, a liquid hydrocarbon, a gas hydrocarbon, water, etc.). As discussed in further detail below, the separation may be performed without substantially affecting a structure of one or more of the substances making up the several phases. That is, after the separation, one or more than one of the separated phases still retains the same molecular structure as prior to the separation (e.g., minimal molecular dissolution or association). Of course, a minimal amount of change may be encountered in the post-separated phase, but not to a degree that affects the ability to use the post-separated phase to acquire information relating to that phase prior to separation. Thus, the pre-separation and post-separation phases are structurally similar.

The tool 100 may be used to evaluate one or more characteristics of the separated phase(s) and also estimate one or more parameters relating to the separation process (e.g., pressure, temperature, etc.). The tool 100 may include an inlet 102 through which a fluid 103 enters an active separation chamber 104 and outlets 106a,b through which the separated phases 107a,b exit the separation chamber 104. The tool 100 may include a variety of sensors configured to estimate one or more desired parameters. For example, a sensor 108a may be used to estimate a characteristic of a first phase component (e.g., oil), and a sensor 108b may be used to estimate a characteristic of a second phase component (e.g., water). Other phase components (e.g., condensates) may be evaluated with similar sensors (not shown). Also, sensors 108c may be used to estimate one or more environmental parameters (e.g., pressure, temperature, rotational speed, fluid flow rate, fluid velocity, etc.). In embodiments, the test tool 100 may include a separator 110 that uses rotation to separate the fluid into two or more phase components. The separator 110 may include an enclosure 112, which may be drum-shaped, that is rotated by a suitable motor 114.

During operation, the fluid 103 flows via the inlet 102 into the enclosure 112, which is rotated by the motor 114. The centrifugal forces generated by the rotating enclosure 112 separates phases based on relative density. In other embodiments, the separation may be performed independent of orientation. As shown, the relatively lighter phase 107a (e.g., oil) separates and exits via outlet 106a and the relatively denser phase 107b (e.g., water) separates and exits via outlet 106b.

Further, in some embodiments, the enclosure 112 may be oriented to allow gravity to also separate the phases based on relative density. For example, the tool 100 may include an orientation sensor (not shown) that provides an indication of verticality and an orientation device (not shown) that orients the device such that more dense phases collect at a particular location in the chamber 104.

In conjunction with the separation process, the sensors 108a-c may generate information relating to one or more parameters of the fluid 103, the separated phase components 107a,b and/or the environmental conditions associated with the tool 100. ‘Information’ may be data in any form and may be “raw” and/or “processed,” e.g., direct measurements, indirect measurements, analog signal, digital signals, etc. It should be appreciated that the information provided by the sensors 108a,b is indicative of a state, condition, or property of the separated phase immediately after separation, but before the separated phase has exited the tool 100. Also, the sensors 108c may provide information relating to the conditions under which the separation occurred. Thus, in aspects, the tool 100 may provide information that includes at least a property of one or more separated components and the conditions that caused the separation.

The sensors 108a,b may be configured to generate information regarding the chemical composition(s) or material properties(s) of the separated phases 107a,b. This information may relate to properties that include, but are not limited to, one or more of: (i) pH, (ii) H₂S, (iii) density, (iv) viscosity, (v) thermal conductivity, (vi) electrical resistivity, (vii) chemical composition, (viii) reactivity, (ix) radiofrequency properties, (x) surface tension, (xi) infra-red absorption, (xii) ultraviolet absorption, (xiii) refractive index, and (xiv) rheological properties.

The separation of the phase components may be performed by a number of different devices and techniques in addition to the centrifugal separator shown in FIG. 1. For example, the tool 100 may include a cyclonic separator wherein the fluid 103 is spun in a spiral or helix-like manner in the chamber 104. Still other non-limiting embodiments of separators are discussed below.

Referring now to FIG. 2, there is shown a thermal separator 120 that includes a distillation column 122. In some embodiments, cooling devices such as thermoelectric elements 124a,b may be used to remove heat from the fluid 123 in the column 122. A thermoelectric elements 124a,b may be formed of a suitable material (e.g., bismuth telluride) that when energized by an electrical circuit 126 transfers heat across a space against a temperature gradient (or Peltier effect). A suitable power source 128 may provide electrical power. In other embodiments, heat may be applied by suitable heating elements to separate phases in the distillation column 122. In addition to or instead of thermal separation, electrostatic forces may be used to separate phase components based on the electric charge of the components. As discussed previously, sensors 108a-c may be used to obtain desired information relating to the fluid and/or environment in the distillation column 122.

Referring now to FIG. 3, there is shown a column 140 that includes one or more reactive column surfaces 142 that define a flow conduit 144 where the separator 140 is used for chromatographic purposes, e.g., high performance liquid chromatography, ion exchange chromatography, hydrophobic interaction chromatography, gel filtration chromatography, and combinations thereof. Chromatography is used to separate phases of a liquid. The liquid, i.e., the mobile phase, is poured or dripped through a column surface 142, i.e., the stationary phase. The column surfaces 142 may interact with a targeted phase of the fluid 146. As the fluid 146 flows along the column surface 142, the targeted phase of the fluid 146 interacts with the column surface 142 and is retained by the column surface 142, which allows the remainder of the fluid 146 to continue flowing through the column 140. Thus, the targeted phase of the fluid 146 is separated from the remainder of the fluid 146. Chromatography may be used by designing the column surfaces 142 to interact with the fluid 146 based on dipole-dipole interactions, ionic interactions or molecule sizes. As discussed previously, sensors 108a-c may be used to obtain desired information relating to the fluid and/or environment in the flow conduit 144.

For example, the column surfaces 142 may attract oil or water (e.g., lipophilic, hydrophobic, hydrophilic), cause a phase component to coalesce, and/or cause a desired flow regime. For instance, the surfaces may be a combination of hydrophilic and superhydrophobic surfaces that allow water to coalesce and then flow along a predefined channel. Similar combination of surface may be designed using oleophilic and oleophobic surfaces. In embodiments, the column surfaces 142 may be configured to operate according to HPLC (high performance liquid chromatography). HPLC is generally an automated system having fluids applied in a precise manner with controlled flow rates at high pressures. The column surfaces 142 may be a matrix of specially fabricated glass or plastic beads coated with a uniform layer of chromatographic material. HPLC allows for high speed, high resolution, and reproducibility of the separation.

The column 140 may also be configured for ion exchange chromatography where oppositely charged molecules are bound to the column surfaces 142 to allow a targeted phase to be separated from the fluid 146. For example, if the targeted phase is water to be separated from the fluid 146, charged or ionic molecules would be bound to the column surfaces 142. Water would bind to the ionic molecules and the remainder of the fluid 146 would flow through the column 140.

The column 140 may also be configured for hydrophobic interaction chromatography where the column surfaces 142 are impregnated with nonpolar groups. The nonpolar groups may interact with the hydrophobic phase of the fluid 146, which causes the hydrophobic phase to bind to the column surfaces 142 and allows the charged phase to flow through the column 140. An embodiment of this may include the oil phase being separated from the fluid 146, so that the remainder of the fluid 146 flows through the column 140.

The column 140 may be configured for size exclusion chromatography where molecules are separated according to the size and/or shape of the molecules within the targeted phase of the fluid 146. In this instance, the column surface 142 may have gel beads with pores of a specified size range. The pores may retain molecules of a particular wettability, size and/or shape of the fluid 146. For example, as is known, an oil molecule is size-wise larger than a water molecule. Thus, the pores of the column surfaces 146 may be configured to be penetrable by water but relatively impenetrable by oil. Such a column surface 142 then would retain water but allow the oil to flow through the column 140.

Referring now to FIG. 4, there is shown a separator 160 that includes a permeable material 162 that separates a chamber 164 into a pre-separation section 166 and a post-separation section 168. In one embodiment, the material may be a membrane 162 that has a permeability selected to allow passage of only a selected phase component (e.g., a hydrocarbon). A piston 170 or other suitable movable member reduces the volume in the pre-separation section 166 to generate a pressure differential that forces the selected phase component through the membrane 162 and into the post-separation section 168. In other embodiments, a vacuum pump (not shown) may be used to reduce pressure in the post-separation section 168. In other embodiments, the material 162 may be beads, or a sponge-like material. As discussed previously, sensors 108a-c may be used to obtain desired information relating to the fluid and/or environment in the membrane separator 160. Other embodiments of using membrane separation may use pistons or other pressurizing mechanisms to force the fluid through a membrane which selectively filters molecules. The membrane may be porous, micro-porous, or nano-porous.

It should be appreciated that the above illustrative separation techniques separate the phases without substantially affecting a structure of one or more of the substances making up the several phases. Separation processes involving pressure reduction below bubble point or cooling can cause condensate to in a liquid. However, the liquid and/or the condensate in those processes may undergo a chemical structural change that may make it difficult or impossible to acquire information relating to the fluid prior to such a separation process. The separation techniques of the present disclosure, however, retain the pre-separation structure of phase substance(s) even after separation.

The teachings of the present disclosure may be used in a variety of surface and sub-surface applications. Merely for convenience, there is shown in FIG. 5, a tool configured to characterize a fluid that is configured for sub-surface applications. FIG. 5 schematically illustrates a wellbore system 10 deployed from a rig 12 into a borehole 14. While a land-based rig 12 is shown, it should be understood that the present disclosure may be applicable to offshore rigs and subsea formations. The wellbore system 10 may include a carrier 16 and a wellbore tool 20. Merely for ease of discussion, the wellbore tool 20 is shown as a fluid analysis tool. The fluid analysis tool 20 may include a probe 22 that contacts a borehole wall 24 for extracting formation fluid from a formation 26. Extendable pads or ribs 28 may be used to laterally thrust the probe 22 against the borehole wall 24. The fluid analysis tool 20 may include a pump 30 that pumps formation fluid from formation 26 via the probe 22. Formation fluid travels along a flow line to one or more sample containers 32 or to line 34 from which the formation fluid exits to the borehole 14. The fluid may have one or more pre-existing phase components (i.e., that exist prior to separation). The tool 20 may include a separator 100 as described previously to separate one or more phase components from the fluid extracted from the formation 26. A programmable controller may be used to control one or more aspects of the operation of the tool 20. For example, the wellbore system 10 may include a surface controller 40 and/or a downhole controller 42.

In one mode of operation, the tool 20 is positioned downhole and operated to extract fluid from the formation 26. The fluid from the formation (or formation fluid) may be a multi-phase fluid. Thus, the extracted fluid is conveyed to the separator tool 100. The separator tool 100 separates at least one phase from the extracted fluid. Referring now to FIGS. 1 and 5, during the separation phase, the sensors 108a,b estimate one or more phase properties of the separated phases before the separated fluids have exited the separator tool 100. The sensors 108a,b provide information about the post-separated phase(s) that may be used to characterize the properties of the phases prior to separation.

At the same time, the sensors 108c acquire information that can be used to evaluate the environmental conditions under which the phase separation occurred.

In some embodiments, the wellbore system 10 may be a drilling system that configured to form the borehole 14 using tools such as a drill bit (not shown). In such embodiments, the carrier 16 may be a coiled tube, casing, liners, drill pipe, etc. In other embodiments, the wellbore system 10 may use a non-rigid carrier. In such arrangements, the carrier 16 may be wirelines, wireline sondes, slickline sondes, e-lines, etc. The term “carrier” as used herein means any device, device component, combination of devices, media and/or member that may be used to convey, house, support, or otherwise facilitate the use of another device, device component, combination of devices, media and/or member.

The controller 40, 42 may include an information processor that is in data communication with a data storage medium and a processor memory. The data storage medium may be any standard computer data storage device, such as a USB drive, memory stick, hard disk, removable RAM, EPROMs, EAROMs, flash memories and optical disks, or other commonly used memory storage system known to one of ordinary skill in the art including Internet based storage. The data storage medium may store one or more programs that when executed causes information processor to execute the disclosed method(s). Signals indicative of the parameter may be transmitted to a surface controller 40. These signals may also, or in the alternative, be stored downhole in a data storage device and may also be processed. In one example, wired pipe may be used for transmitting information.

The term “carrier” as used in this disclosure means any device, device component, combination of devices, media and/or member that may be used to convey, house, support or otherwise facilitate the use of another device, device component, combination of devices, media and/or member. As used herein, the term “fluid” and “fluids” refers to one or gasses, one or more liquids, and mixtures thereof.

While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations be embraced by the foregoing disclosure.

Claims

1. An apparatus for sampling a fluid in a borehole, comprising:

a vessel configured to be disposed in the borehole, the vessel being further configured to separate the fluid into a plurality of phases without substantially affecting a structure of at least one of the separated phases; and

at least one sensor in communication with one separated phase in the vessel.

2. The apparatus of claim 1, wherein the at least one sensor comprises a plurality of sensors, each sensor being in communication with a different phase of the plurality of phases.

3. The apparatus of claim 1, wherein the at least one sensor is configured to generate signals representative of a parameter of interest relating to the one phase.

4. The apparatus of claim 1, further comprising an environmental sensor configured to estimate at least one environmental parameter.

5. The apparatus of claim 1, wherein the vessel includes a separator separating the fluid into the plurality of phases.

6. The apparatus of claim 5, wherein the separator is configured to spin the fluid.

7. The apparatus of claim 5, wherein the separator includes a permeable material configured to separate the fluid into the plurality of phases.

8. The apparatus of claim 5, wherein the separator includes at least one material configured to interact with one phase of the plurality of phases.

9. The apparatus of claim 8, wherein the interaction is one of: (i) attraction, (ii) repulsion, (iii) a molecular interaction; (iv) chemical interaction, (v) physical interaction, and (vi) ionic interaction.

10. The apparatus of claim 5, wherein the separator changes a temperature of the fluid.

11. The apparatus of claim 1, wherein the one phase is selected from at least one of: (i) an aqueous phase, (ii) a hydrocarbon, (iii) a precipitate; (iv) a nonpolar phase, and (v) a polar phase.

12. The apparatus of claim 1, wherein the one phase is selected from one of: (i) a solid, (ii) a liquid, and (iii) a gas.

13. A method for sampling a fluid in a borehole, comprising:

separating the fluid into a plurality of phases in a vessel positioned in the borehole without substantially affecting a structure of at least one of the separated phases; and

estimating a parameter of interest relating to at least one separated phase fluid while the at least one phase is in the vessel.

14. The method of claim 13, further comprising estimating an environmental parameter while the fluid is being separated.

15. The method of claim 13, wherein the parameter of interest is estimated while the fluid is being separated.

16. The method of claim 13, further comprising discharging the separated phases from the vessel after estimating the parameter of interest.

17. The method of claim 13 wherein the fluid is separated by a chromatographic procedure.