U.S. patent application number 14/915528 was filed with the patent office on 2016-07-21 for downhole fluid analysis methods for determining compressibility.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Adriaan GISOLF, Kai HSU, Chee Kin KHONG, Youxiang ZUO.
Application Number | 20160208600 14/915528 |
Document ID | / |
Family ID | 52587329 |
Filed Date | 2016-07-21 |
United States Patent
Application |
20160208600 |
Kind Code |
A1 |
GISOLF; Adriaan ; et
al. |
July 21, 2016 |
Downhole Fluid Analysis Methods For Determining Compressibility
Abstract
The present disclosure relates to methods for determining the
compressibility of downhole fluids using measurements obtained
during over-pressurization of a formation fluid sample. In certain
embodiments, the density of the fluid may be measured as the fluid
is directed through a flowline into a sample chamber. The density
measurements can be employed in conjunction with pressure spikes
that occur during over pressuring of a sample chamber to determine
the compressibility.
Inventors: |
GISOLF; Adriaan; (Houston,
TX) ; HSU; Kai; (Sugar Land, TX) ; ZUO;
Youxiang; (Burnaby, CA) ; KHONG; Chee Kin;
(Ilha de Luanda, AO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
sugar Land |
TX |
US |
|
|
Family ID: |
52587329 |
Appl. No.: |
14/915528 |
Filed: |
August 28, 2014 |
PCT Filed: |
August 28, 2014 |
PCT NO: |
PCT/US2014/053146 |
371 Date: |
February 29, 2016 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61872385 |
Aug 30, 2013 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/06 20130101;
E21B 49/081 20130101; E21B 49/08 20130101; E21B 47/00 20130101;
E21B 47/10 20130101 |
International
Class: |
E21B 47/06 20060101
E21B047/06; E21B 49/08 20060101 E21B049/08 |
Claims
1. A downhole fluid analysis method comprising: directing formation
fluid to a sample chamber of a downhole tool; over-pressurizing the
formation fluid within the sample chamber; obtaining pressure and
density measurements during the over-pressurization; and
determining a compressibility of the formation fluid based on the
pressure and density measurements.
2. The downhole fluid analysis method of claim 1, wherein
over-pressurizing comprises operating a pump to increase a pressure
in the sample chamber after the sample chamber has been filled.
3. The downhole fluid analysis method of claim 1, wherein
over-pressurizing comprises pumping the formation fluid through a
primary flowline of the downhole tool, and wherein obtaining
comprises measuring pressure and density of the formation fluid
flowing through the primary flowline.
4. The downhole fluid analysis method of claim 1, wherein
determining comprises calculating the compressibility based on the
pressure and density measurements that were obtained after a
pressure spike.
5. The downhole fluid analysis method of claim 1, wherein
determining comprises calculating the compressibility based on a
rate of change in density with respect to pressure.
6. The downhole fluid analysis method of claim 1, comprising
initiating sampling of the formation fluid within the downhole
tool.
7. The downhole fluid analysis method of claim 6, wherein
initiating comprises opening a valve upstream of the sample chamber
and closing a valve in a primary flowline of the downhole tool.
8. The downhole fluid analysis method of claim 1, wherein
determining comprises determining the compressibility as a function
of pressure based on the pressure and density measurements.
9. The downhole fluid analysis method of claim 1, comprising
detecting that the sample chamber has been filled, wherein the
over-pressurizing occurs within the sample chamber in response to
detecting that the sample chamber has been filled.
10. A downhole tool comprising: a density sensor to measure density
of a formation fluid flowing through a primary flowline of the
downhole tool; a pressure sensor to measure pressure of the
formation fluid flowing through a primary flowline of the downhole
tool; and a controller configured to execute instructions stored
within the downhole tool to: obtain pressure and density
measurements from the respective pressure sensor and the density
sensor during over-pressurization of a sample of formation fluid
within a sample chamber of the downhole tool; and calculate a
compressibility of the formation fluid based on the pressure and
density measurements.
11. The downhole tool of claim 10 comprising a valve selectively
actuated by the controller to direct the formation fluid into the
sample chamber.
12. The downhole tool of claim 10, wherein the controller is
configured to execute instructions stored within the downhole tool
to: detect a spike in the pressure measurements; and operate a pump
to over-pressurize the sample of formation fluid within the sample
chamber in response to detecting the spike in the pressure
measurements.
13. The downhole tool of claim 10, wherein the density comprises a
fluid density.
14. The downhole tool of claim 10, wherein the density comprises an
optical density.
15. A downhole fluid analysis method comprising: directing
formation fluid to a sample chamber of a downhole tool through a
primary flowline; inducing a pressure change in the formation fluid
flowing through the primary flowline; obtaining pressure and
density measurements during the pressure change; and determining a
compressibility of the formation fluid based on the pressure and
density measurements.
16. The downhole fluid analysis method of claim 15, wherein
inducing comprises restricting a flow of the formation fluid
through the primary flowline.
17. The downhole fluid analysis method of claim 15, wherein
inducing comprises momentarily closing a valve disposed in the
primary flowline.
18. The downhole fluid analysis method of claim 15, wherein
inducing comprises over-pressurizing the formation fluid within the
sample chamber.
19. The downhole fluid analysis method of claim 15, wherein the
pressure change comprises a pressure decrease.
20. The downhole fluid analysis method of claim 15, wherein the
pressure change comprises a pressure increase.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is based upon prior filed U.S. provisional
patent application Ser. No. 61/872385 filed on Aug. 30, 2013, the
entire contents of which are incorporated herein by reference.
BACKGROUND OF THE DISCLOSURE
[0002] Wellbores (also known as boreholes) are drilled to penetrate
subterranean formations for hydrocarbon prospecting and production.
During drilling operations, evaluations may be performed of the
subterranean formation for various purposes, such as to locate
hydrocarbon-producing formations and manage the production of
hydrocarbons from these formations. To conduct formation
evaluations, the drill string may include one or more drilling
tools that test and/or sample the surrounding formation, or the
drill string may be removed from the wellbore, and a wireline tool
may be deployed into the wellbore to test and/or sample the
formation. These drilling tools and wireline tools, as well as
other wellbore tools conveyed on coiled tubing, drill pipe, casing
or other conveyers, are also referred to herein as "downhole
tools."
[0003] Formation evaluation may involve drawing fluid from the
formation into a downhole tool for testing and/or sampling. Various
devices, such as probes and/or packers, may be extended from the
downhole tool to isolate a region of the wellbore wall, and thereby
establish fluid communication with the subterranean formation
surrounding the wellbore. Fluid may then be drawn into the downhole
tool using the probe and/or packer. Within the downhole tool, the
fluid may be directed to one or more fluid analyzers and sensors
that may be employed to detect properties of the fluid while the
downhole tool is stationary within the wellbore.
SUMMARY
[0004] The present disclosure relates to a downhole fluid analysis
method that includes directing formation fluid to a sample chamber
of a downhole tool, over-pressurizing the formation fluid within
the sample chamber, obtaining pressure and density measurements
during the over-pressurization, and determining a compressibility
of the formation fluid based on the pressure and density
measurements.
[0005] The present disclosure also relates to a downhole tool that
includes a density sensor to measure density of a formation fluid
flowing through a primary flowline of the downhole tool, a pressure
sensor to measure pressure of a formation fluid flowing through a
primary flowline of the downhole tool, and a controller. The
controller is designed to execute instructions stored within the
downhole tool to obtain pressure and density measurements from the
respective pressure sensor and the density sensor during
over-pressurization of a sample of formation fluid within a sample
chamber of the downhole tool, and calculate a compressibility of
the formation fluid based on the pressure and density
measurements.
[0006] The present disclosure relates to a downhole fluid analysis
method that includes directing formation fluid to a sample chamber
of a downhole tool through a primary flowline, inducing a pressure
change in the formation fluid flowing through the primary flowline;
obtaining pressure and density measurements during the pressure
change, and determining a compressibility of the formation fluid
based on the pressure and density measurements.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] The present disclosure is understood from the following
detailed description when read with the accompanying figures. It is
emphasized that, in accordance with the standard practice in the
industry, various features are not drawn to scale. In fact, the
dimensions of the various features may be arbitrarily increased or
reduced for clarity of discussion.
[0008] FIG. 1 is a schematic view of an embodiment of a wellsite
system that may employ downhole fluid analysis methods for
determining compressibility, according to aspects of the present
disclosure;
[0009] FIG. 2 is a schematic view of another embodiment of a
wellsite system that may employ downhole fluid analysis methods for
determining compressibility, according to aspects of the present
disclosure;
[0010] FIG. 3 is a schematic representation of an embodiment of a
downhole tool that may employ downhole fluid analysis methods for
determining compressibility, according to aspects of the present
disclosure;
[0011] FIG. 4 is a flowchart depicting a fluid analysis method for
determining compressibility, according to aspects of the present
disclosure;
[0012] FIG. 5 is an illustration of charts depicting density,
pressure, and spectrometer measurements obtained during sampling,
according to aspects of the present disclosure;
[0013] FIG. 6 is an illustration of charts depicting density
measurements plotted against pressure measurements obtained during
sampling, according to aspects of the present disclosure;
[0014] FIG. 7 is an illustration of another chart density
measurements plotted against pressure measurements obtained during
sampling, according to aspects of the present disclosure; and
[0015] FIG. 8 is an illustration of a chart depicting a fitting
function applied to the measurements of FIG. 7, according to
aspects of the present disclosure.
DETAILED DESCRIPTION
[0016] It is to be understood that the present disclosure provides
many different embodiments, or examples, for implementing different
features of various embodiments. Specific examples of components
and arrangements are described below to simplify the present
disclosure. These are, of course, merely examples and are not
intended to be limiting.
[0017] The present disclosure relates to methods for determining
the compressibility of downhole fluids. According to certain
embodiments, the compressibility may be determined in substantially
real-time as formation fluid is directed into a sample chamber of
the downhole tool. In certain embodiments, the density of the fluid
may be measured as the fluid is directed through a flowline into a
sample chamber. The density measurements can be employed in
conjunction with pressure spikes that occur during over pressuring
of a sample chamber to determine the compressibility.
[0018] FIGS. 1 and 2 depict examples of wellsite systems that may
employ the compressibility determination systems and techniques
described herein. FIG. 1 depicts a rig 100 with a downhole tool 102
suspended therefrom and into a wellbore 104 via a drill string 106.
The downhole tool 100 has a drill bit 108 at its lower end thereof
that is used to advance the downhole tool into the formation and
form the wellbore. The drillstring 106 is rotated by a rotary table
110, energized by means not shown, which engages a kelly 112 at the
upper end of the drillstring 106. The drillstring 106 is suspended
from a hook 114, attached to a traveling block (also not shown),
through the kelly 112 and a rotary swivel 116 that permits rotation
of the drillstring 106 relative to the hook 114. The rig 100 is
depicted as a land-based platform and derrick assembly used to form
the wellbore 104 by rotary drilling. However, in other embodiments,
the rig 100 may be an offshore platform.
[0019] Drilling fluid or mud 118 is stored in a pit 120 formed at
the well site. A pump 122 delivers the drilling fluid 118 to the
interior of the drillstring 106 via a port in the swivel 116,
inducing the drilling fluid to flow downwardly through the
drillstring 106 as indicated by a directional arrow 124. The
drilling fluid exits the drillstring 106 via ports in the drill bit
108, and then circulates upwardly through the region between the
outside of the drillstring and the wall of the wellbore, called the
annulus, as indicated by directional arrows 126. The drilling fluid
lubricates the drill bit 108 and carries formation cuttings up to
the surface as it is returned to the pit 120 for recirculation.
[0020] The downhole tool 102, sometimes referred to as a bottom
hole assembly ("BHA"), may be positioned near the drill bit 108 and
includes various components with capabilities, such as measuring,
processing, and storing information, as well as communicating with
the surface. A telemetry device (not shown) also may be provided
for communicating with a surface unit (not shown).
[0021] The downhole tool 102 further includes a sampling system 128
including a fluid communication module 130 and a sampling module
132. The modules may be housed in a drill collar for performing
various formation evaluation functions, such as pressure testing
and sampling, among others. According to certain embodiments, the
sampling system 128 may be employed "while drilling," meaning that
the sampling system 128 may be operated during breaks in operation
of the mud pump 122 and/or during breaks in operation of the drill
bit 108. As shown in FIG. 1, the fluid communication module 130 is
positioned adjacent the sampling module 132; however the position
of the fluid communication module 130, as well as other modules,
may vary in other embodiments. Additional devices, such as pumps,
gauges, sensor, monitors or other devices usable in downhole
sampling and/or testing also may be provided. The additional
devices may be incorporated into modules 130 and 132 or disposed
within separate modules included within the sampling system
128.
[0022] The fluid communication module 130 includes a probe 134,
which may be positioned in a stabilizer blade or rib 136. The probe
134 includes one or more inlets for receiving formation fluid and
one or more flowlines (not shown) extending into the downhole tool
for passing fluids through the tool. In certain embodiments, the
probe 134 may include a single inlet designed to direct formation
fluid into a flowline within the downhole tool. Further, in other
embodiments, the probe may include multiple inlets that may, for
example, be used for focused sampling. In these embodiments, the
probe may be connected to a sampling flow line, as well as to guard
flow lines. The probe 134 may be movable between extended and
refracted positions for selectively engaging a wall of the wellbore
104 and acquiring fluid samples from the formation F. One or more
setting pistons 138 may be provided to assist in positioning the
fluid communication device against the wellbore wall.
[0023] FIG. 2 depicts an example of a wireline downhole tool 200
that may employ the systems and techniques described herein. The
downhole tool 200 is suspended in a wellbore 202 from the lower end
of a multi-conductor cable 204 that is spooled on a winch at the
surface. The cable 204 is communicatively coupled to an electronics
and processing system 206. The downhole tool 200 includes an
elongated body 208 that houses modules 210, 212, 214, 222, and 224,
that provide various functionalities including fluid sampling,
fluid testing, operational control, and communication, among
others. For example, the modules 210 and 212 may provide additional
functionality such as fluid analysis, resistivity measurements,
operational control, communications, coring, and/or imaging, among
others.
[0024] As shown in FIG. 2, the module 214 is a fluid communication
module 214 that has a selectively extendable probe 216 and backup
pistons 218 that are arranged on opposite sides of the elongated
body 208. The extendable probe 216 is configured to selectively
seal off or isolate selected portions of the wall of the wellbore
202 to fluidly couple to the adjacent formation 220 and/or to draw
fluid samples from the formation 220. The probe 216 may include a
single inlet or multiple inlets designed for guarded or focused
sampling. The formation fluid may be expelled to the wellbore
through a port in the body 208 or the formation fluid may be sent
to one or more fluid sampling modules 222 and 224. The fluid
sampling modules 222 and 224 may include sample chambers that store
the formation fluid. In the illustrated example, the electronics
and processing system 206 and/or a downhole control system are
configured to control the extendable probe assembly 216 and/or the
drawing of a fluid sample from the formation 220.
[0025] FIG. 3 is a schematic diagram of a portion of a downhole
tool 302 that may employ the compressibility systems and techniques
described herein. For example, the downhole tool 302 may be a
drilling tool, such as the downhole tool 102 described above with
respect to FIG. 1. Further, the downhole tool 302 may be a wireline
tool, such as the downhole tool 200 described above with respect to
FIG. 2. Further, in other embodiments, the downhole tool may be
conveyed on wired drill pipe, a combination of wired drill pipe and
wireline, or other suitable types of conveyance.
[0026] As shown in FIG. 3, the downhole tool 302 includes a fluid
communication module 304 that has a probe 306 for directing
formation fluid into the downhole tool 302. According, to certain
embodiments, the fluid communication module 304 may be similar to
the fluid communication modules 130 and 214, described above with
respect to FIGS. 1 and 2, respectively. Further, in other
embodiments, the probe 306 may be replaced by a single packer, or
other inlet device that directs formation fluid into the downhole
tool 302. The fluid communication module 304 includes a probe
flowline 306 that directs the fluid to a primary flowline 308 that
extends through the downhole tool 302. The fluid communication
module 304 also includes a pump 310 and pressure gauges 312 and 314
that may be employed to conduct formation pressure tests. An
equalization valve 316 may be opened to expose the flowline 306 to
the pressure in the wellbore, which in turn may equalize the
pressure within the downhole tool 302. Further, an isolation valve
318 may be closed to isolate the formation fluid within the
flowline 306, and may be opened to direct the formation fluid from
the probe flowline 306 to the primary flowline 308.
[0027] The primary flowline 308 directs the formation fluid through
the downhole tool to fluid analysis modules 320a and 320b that can
be employed to provide in situ downhole fluid measurements. For
example, the fluid analysis modules 320a and 320b may each include
an optical spectrometer 322a or 322b designed to measure properties
such as, optical density, fluid composition, and the fluid gas oil
ratio (GOR), among others. According to certain embodiments, the
spectrometer 322a and 322b may include any suitable number of
measurement channels for detecting different wavelengths, and may
include a filter-array spectrometer or a grating spectrometer. For
example, the spectrometer 322a and 322b may be a filter-array
absorption spectrometer having ten measurement channels. In other
embodiments, the spectrometer 322a and 322b may have sixteen
channels or twenty channels, and may be provided as a filter-array
spectrometer or a grating spectrometer, or a combination thereof
(e.g., a dual spectrometer), by way of example.
[0028] The fluid analysis modules 320a and 320b also may each
include a density sensor 324a or 324b that can be employed to
measure the density of the fluid flowing through the primary
flowline 308. According to certain embodiments, the density sensors
324a and 324b may each include a vibrating rod whose resonance
characteristics, for the rod oscillating in the fluid, may be
employed in conjunction with electronics included in the sensors
324a and 324b to determine the density of the fluid. However, in
other embodiments, the density sensors 324a and 324b may include
any suitable density sensor, such as a desimeter or densitometer,
among others.
[0029] The fluid analysis modules 320a and 320b further may each
include a pressure and temperature sensor 323b that can be employed
to measure the pressure and temperature of the fluid flowing
through the primary flowline 308. As shown in FIG. 3, the pressure
and temperature measurements are provided by a single sensor 323a
or 323b; however, in other embodiments, the pressure and
temperature measurements may be provided by separate sensors (e.g.,
an individual pressure sensor and an individual temperature
sensor).
[0030] One or more additional measurement devices 325a and 325b,
such as gas analyzers, resistivity sensors, viscosity sensors,
chemical sensors (e.g., for measuring pH or H.sub.2S levels), and
gas chromatographs, may be included within the fluid analysis
modules 320a and 320b. In certain embodiments, the measurement
devices 325a and 325b may include a gas analyzer having a gas
detector and one or more fluorescence detectors designed to detect
free gas bubbles and retrograde condensate liquid drop out.
[0031] In certain embodiments, the fluid analysis modules 320a and
320b also may include a controller 326a and 326b, such as a
microprocessor or control circuitry, designed to calculate certain
fluid properties based on the sensor measurements. Further, in
certain embodiments, the controller 326a or 326b may govern
sampling operations based on the fluid measurements or properties.
As shown in FIG. 3, each fluid analysis module 320a and 320b
includes a controller 326a or 326b; however, in other embodiments,
the fluid analysis modules 320a and 320b may share a single
controller. Moreover, in other embodiments, the controller 326a or
326b may be disposed within another module of the downhole tool
302.
[0032] The downhole tool 302 also includes a pump out module 328
that has a pump 330 designed to provide motive force to direct the
fluid through the downhole tool 302. According to certain
embodiments, the pump 330 may be a hydraulic displacement unit that
receives fluid into alternating pump chambers. A valve block 332
may direct the fluid into and out of the alternating pump chambers.
The valve block 332 also may direct the fluid exiting the pump 330
through the remainder of the primary flowline (e.g., towards the
sample module 336) or may divert the fluid to the wellbore through
an exit flowline 334.
[0033] The downhole tool 302 also includes a sample module 336
designed to store samples of the formation fluid within a sample
chamber 338. The sample module 336 includes valves 340 and 344 that
may be actuated to divert the formation fluid into a volume 342of
the sample chamber 338. For example, to direct formation fluid from
the primary flowline 308 into the volume 342, the valve 344 may be
opened while the valve 340 may be closed. When sampling has
completed, the valve 344 may then be closed to seal the formation
fluid within the sample chamber 338, while the valve 340 may be
opened to direct the formation fluid from the primary flowline
through the downhole tool. The sample chamber 338 also may include
a valve 348 that can be opened to expose a volume 350 of the sample
chamber 338 to the annular pressure. In certain embodiments, the
valve 348 may be opened to allow buffer fluid to exit the volume
350 to the wellbore, which may provide backpressure during filling
of a volume 352 that receives formation fluid. According to certain
embodiments, the volume 342 that stores formation fluid may be
separated from the volume 350 by a floating piston 353.
[0034] The valve arrangements and module arrangements described
herein are provided by way of example, and are not intended to be
limiting. For example, the valves described herein may include
valves of various types and configurations, such as ball valves,
gate valves, solenoid valves, check valves, seal valves, two-way
valves, three-way valves, four-way valves, and combinations
thereof, among others. Further, in other embodiments, different
arrangements of valves may be employed. For example, the valves 340
and 344 may be replaced by a single valve. Moreover, in certain
embodiments, the arrangements of the modules 304, 320a, 320b, 328,
and 336 may vary. For example, in other embodiments, rather than
two fluid analysis modules 320a and 320b, a single fluid analysis
module 320 may be included within the downhole tool 302. In another
example, multiple sample chamber modules 336 may be included within
the downhole tool 302. Further, in certain embodiments, the sample
chamber 336 may include multiple sample chambers 338, as well as
other types of sample chambers, such as single phase sample
bottles, among others.
[0035] FIG. 4 is a flowchart depicting an embodiment of a method
400 that may be employed to determine the compressibility of
formation fluid while sampling. According to certain embodiments,
the method 400 may be executed, in whole or in part, by the
controller 326a and/or 326b (FIG. 3). For example, the controller
326a or 326b may execute code stored within circuitry of the
controller 326a or 326b, or within a separate memory or other
tangible readable medium, to perform the method 400. In certain
embodiments, the method 400 may be wholly executed while the tool
302 is disposed within a wellbore. Further, in certain embodiments,
the controller 326a or 326b may operate in conjunction with a
surface controller, such as the processing system 206 (FIG. 2),
that may perform one or more operations of the method 400. For ease
of description, the method 400 is described below with respect to
operation of the controller 326a and the fluid analysis module
320b. However, in other embodiments, the controller 326b may
perform the method 400 instead of, or in conjunction with, the
controller 326a. Further, in certain embodiments, the fluid
analysis module 320a and the sensors 322a, 323a, 324a, and 325a may
be employed to perform one or more of the measurements in the
method 400.
[0036] The method 400 may begin by initiating (block 402) sampling
of the formation fluid. For example, the formation fluid may be
withdrawn into the downhole tool 302 through the probe 305 and
directed through the primary flowline 308. To initiate sampling,
the controller 326a may set the valve block 332 to direct the
formation fluid through the primary flowline 308 to the sample
module 336. The controller 326b also may open the valve 344 and
close the valve 340 to direct the formation fluid into the sample
chamber 338. During filling of the sample chamber 338, the pressure
and density for the formation fluid flowing through the primary
flowline may be measured using the pressure and temperature sensor
323b and the density sensor 324b. In certain embodiments, during
filling of the sample chamber 338, the fluid analysis module 320b
also may measure the optical absorption spectra of the formation
fluid using the spectrometer 322b.
[0037] The method may then continue by performing (block 404)
measurements while over-pressurizing the sample. For example, the
controller 326b may detect a spike in the measured pressure, which
may indicate that the sample chamber 338 has been filled. The
controller 326b may then continue operation of the pump 330 to
over-pressurize the fluid in the sample chamber 338. During
over-pressurization, the pressure and density for the formation
fluid flowing through the primary flowline may be measured using
the pressure and temperature sensor 323b and the density sensor
324b. In certain embodiments, during over-pressurization of the
sample chamber 338, the fluid analysis module 320b also may measure
the optical absorption spectra of the formation fluid using the
spectrometer 322b.
[0038] FIG. 5 depicts examples of measurements that may be obtained
during sampling and during over-pressurization of a formation fluid
sample. The top chart 500 depicts the optical density 506 measured
by the spectrometer 322b; the middle chart 502 depicts the fluid
density 508 measured by the density sensor 324b, and the bottom
chart 504 depicts the pressure 510 measure by the pressure and
temperature sensor 323b. The x-axis of each chart 500, 502, and 504
represents elapsed time and the y-axis of each chart 500, 502, and
504 represents the optical density 506, the density 508, and the
pressure 510, respectively. As shown in FIG. 5, spikes 512, 514,
and 516 occur during over-pressurization of the sample. FIG. 5
depicts the filling of three separate sample chambers 338, and
spikes (e.g., sharp increases in measurements) 512, 514, 516, 518,
520, 522, 524, 526, and 528 occur during the over-pressurization of
each sample chamber. During filling of each sample chamber 338, the
pressure remains substantially flat, as shown by filling periods
530, 532, and 534, with the pressure then spiking 516, 522, and 528
during the over-pressurization period after sample chamber 338 has
been filled.
[0039] Once measurements have been obtained during
over-pressurization, the method 400 may continue by determining
(block 406) the compressibility of the formation fluid. For
example, the controller 326b may execute code and/or algorithms to
calculate the compressibility using measurements obtained during
over-pressurization of the sample. The compressibility may be
determined using the pressure and density measurements obtained
during over-pressurization of the formation fluid sample. According
to certain embodiments, the compressibility may be determined using
the following equation:
c = 1 .rho. .rho. P = P ln .rho. ( 1 ) ##EQU00001##
[0040] where c represents the compressibility; .rho. is the density
of fluid, for example, as measured by the sensor 324b; and P is the
pressure of the fluid, for example as measured by the sensor
323b.
[0041] In other embodiments, the compressibility may be determined
using the pressure and optical spectrometer measurements obtained
during over-pressurization of the formation fluid sample. For
example, the compressibility may be determined using the following
equation:
c = 1 OD OD P ( 2 ) ##EQU00002##
where c represents the compressibility; OD is the optical density
of fluid, for example, as measured by the spectrometer 322b; and P
is the pressure of the fluid, for example as measured by the sensor
323b. In these embodiments, the optical density obtained from the
spectrometer measurements may be calibrated to account for
measurement variations, such as spectrometer drift, electronic DC
offset, optical scattering, among others. Techniques for
calibrating the optical density measurements are described in
commonly assigned U.S. Pat. No. 8,434,356 to Hsu et al., which is
incorporated herein by reference in its entirety.
[0042] In addition to determining the compressibility of the
formation fluid that is sampled, the method 400 may further include
determining (block 408) the pressure response for the
compressibility of the fluid. In certain embodiments, the pressure
response may be employed to adjust the density measured at the
primary flowline 308, to the pressure of the formation. The
pressure and density and/or optical spectrometer measurements
obtained during over-pressurization may be employed to determine
the pressure response.
[0043] Where the formation fluid compressibility exhibits a
substantially linear response, for example, for an oil-based fluid
or other fluid that is not highly compressible, the pressure
response of the compressibility may be determined through linear
trending. For example, in certain embodiments, the controller 326b
may determine a linear function or equation that represents the
pressure response of the density using the measurements obtained
during over-pressurization. Using the linear function, the density
of the fluid can be adjusted to other pressures, such as the
formation pressure, and the adjusted density can then be employed
in Eq. 1 to determine the compressibility of the fluid at that
pressure.
[0044] FIG. 6 depicts examples of a linear pressure response, with
chart 600 representing measurements obtained during
over-pressurization of a first sample; chart 602 representing
measurements obtained during over-pressurization of a second
sample; and chart 604 representing measurements obtained during
over-pressurization of a third sample of formation fluid. The
x-axis of each chart 600, 602, and 604 represents the measured
pressure, and the y-axis of each chart 600, 602, and 604 represents
the measured density. The points 606 represent the individual
density measurements at the corresponding pressures. Trend lines
610, 612, 614 may be fit to the points 608 to determine the density
response to pressure changes, which can in turn be used to
determine the compressibility at different pressures.
[0045] Where the formation fluid compressibility exhibits a
substantially non-linear response, for example, for a highly
compressible fluid such as a gas, equations for the compressibility
and/or density response as a function of pressure may be
determined. For example, the controller 326b may calculate an
equation that represents the pressure response of the density using
the measurements obtained during over-pressurization. FIG. 7
depicts a chart 700 illustrating a non-linear response, with
density represented on the y-axis and pressure represented on the
x-axis. The curves 702, 704, and 706 represent the density
measurements obtained while over-pressurizing three different
samples, plotted against the pressure measurements and smoothed to
obtain curves. The curves 702, 704, and 706 may be fit with
logarithmic functions, exponential functions, or power functions,
among others. Equations 3-5 below provide three examples of fitting
functions that may be employed to represent the density response as
a function of pressure, for a non-linear fluid response.
.rho. = a ln P + b ( 3 ) 1 .rho. = a exp ( - P c ) + b ( 4 ) ln
.rho. = aP + b ( 5 ) ##EQU00003##
where a, b and c represent unknowns that can be fitted to determine
the parameters for these unknowns. In other embodiments, the
measurements may be fit to functions locally using a moving
Savitzky-Golay filter as described in commonly assigned U.S. Pat.
No. 7, 913,556 to Hsu et. al, which is hereby incorporated by
reference in its entirety.
[0046] FIG. 8 is a chart 800 depicting the fitting results for the
three curves 702, 704, and 706 shown in FIG. 7. A function 802,
804, and 806 is plotted for each of the curves 702, 704, and 706
where the x-axis represents the log of pressure and the y-axis
represents density. The resulting functions may be employed in Eq.
1 to determine the compressibility of fluid at different
pressures.
[0047] The compressibility can also be employed to adjust the
density measured in the primary flowline 308 to other pressures,
such as the formation pressure. For example, Eq. 2 may be
rearranged as follows:
.intg..sub.P.sub.s.sup.P.sup.fc
dP=.intg..sub..rho..sub.s.sup..rho..sup.fd (lnp) (6)
where P.sub.f and P.sub.s are the formation pressure and flowline
pressure, respectively, and .rho..sub.f and .rho..sub.s are the
density at P.sub.f and P.sub.s. With some algebraic manipulation,
Eq. 6 becomes:
.rho. f = .rho. s .intg. P s P f cdP ( 7 ) ##EQU00004##
where e is a mathematical constant representing the base of the
natural logarithm. If the compressibility c is nearly a constant
within the pressure range [P.sub.fP.sub.s], then it can be further
simplified as
.rho..sub.f.apprxeq..rho..sub.se.sup.c(P.sup.f.sup.-P.sup.s.sup.)
(8)
Given the compressibility, c, the density measured in the flowline,
.rho..sub.s, P.sub.f and P.sub.s, Eq. 7 or 8 can be used to adjust
the measured density in the flowline as if it is measured at the
formation pressure.
[0048] The method described above with respect to FIG. 4 also may
be employed during other periods of fluid pressurization, instead
of, or in addition to, the over-pressurization of the sample fluid.
For example, referring back to FIG. 3, pressure, density, and
spectroscopy measurements may be obtained while the valve 340 is
closed momentarily and while the valve 344 remains closed. While
the valve 340 is closed, the pressure in the primary flowline 308
builds, producing pressure spikes similar to those seen during
over-pressurization of a sample. In another example, the valve 340
may be an adjustable valve, orifice, or fluid restrictor that has
an adjustable opening. The opening may be adjusted to build up the
pressure and obtain pressure, density, and optical spectroscopy
measurements for determining compressibility.
[0049] As discussed above with respect to FIG. 4, the techniques
described herein may be employed using measurements obtained by the
fluid analysis module 320b, the fluid analysis module 320a, or by a
combination of measurements from the fluid analysis modules 320a
and 320b. According to certain embodiments, the measurements from
the fluid analysis modules 320a and 320b may be combined and used
to provide a comprehensive compressibility analysis. Further, in
certain embodiments, the measurements from the fluid analysis
module 320a may represent density measurements corresponding to
decreases in pressure. For example, the compressibility methods
employed herein may be employed using density measurements or
optical density measurements obtained during pressure drops, such
as those measured by the pressure and temperature sensor 323a when
fluid in drawn into the pump 330. In another example, the primary
flowline 308 and/or the sample chamber 338 may be depressurized and
the density measurements or optical density measurements obtained
during the pressure drops may be employed to determine
compressibility using techniques described above with respect to
FIG. 4.
[0050] The foregoing outlines features of several embodiments so
that those skilled in the art may better understand the aspects of
the present disclosure. Those skilled in the art should appreciate
that they may readily use the present disclosure as a basis for
designing or modifying other processes and structures for carrying
out the same purposes and/or achieving the same advantages of the
embodiments introduced herein. Those skilled in the art should also
realize that such equivalent constructions do not depart from the
spirit and scope of the present disclosure, and that they may make
various changes, substitutions and alterations herein without
departing from the spirit and scope of the present disclosure.
* * * * *