Note: Descriptions are shown in the official language in which they were submitted.
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SYSTEMS AND METHODS FOR DOWNHOLE FLUID COMPATIBILITY
TESTING AND ANALYSIS
BACKGROUND OF THE INVENTION
1. Field of the Invention
[0002] This invention relates broadly to oil and gas exploration or
production. More particularly, this invention relates to systems and methods
for
testing and analyzing the compatibility of a reservoir with treating fluids,
wellbore
fluids, and the compatibility of these fluids with each other.
2. State of the Art
[0003] It is well known in the arts of oil and gas exploration and production
that it can be advantageous to introduce certain fluids.into the well bore
and/or
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the formation. For example, during drilling, fluid is typically introduced
into the
annulus between the drill string and the wellbore. During exploration, fluid
may
be injected into the formation in order to obtain information related to the
formation. During production, certain additives may be injected into the
formation
to enhance production.
[0004] Before introducing any significant quantity of fluid into the wellbore
or the formation, it is desirable to determine whether the fluid will create
an
undesirable reaction. Thus, one or more fluid compatibility tests are
preferably
performed prior thereto. The testing process may include checks for
compatibility of treating fluids and/or wellbore fluids with a reservoir
formation
and reservoir fluids. In general, fluids are compatible if their mixture does
not
adversely affect the permeability of the formation, or cause the development
of
any undesirable products (such as asphaltenes, waxes, or scale) in the
wellbore,
production tubing, surface facilities, and flowlines.
[0005] Where treating fluids are to be utilized, the treating fluid should
remove existing damage (typically caused during drilling) without creating
additional damage such as precipitates or emulsions through interactions with
the formation rock or fluids. In extreme cases, it is possible that a
seemingly
benign fluid can create significant reactions that may permanently damage the
permeability of the reservoir.
[0006] Presently, fluid compatibility tests are performed in a laboratory
using fluids obtained from a wellbore and/or formation. In some cases, the
fluids
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are obtained using a borehole tool which samples formation fluids as is well
known in the art, A tool is lowered into a borehole which traverses a
formation
and is then brought into contact with the formation. A formation fluid sample
is
obtained by reducing the pressure in the borehole tool below the formation
pressure. The tool with the fluid sample is then brought to the surface. The
fluid
sample is retrieved and sent to a laboratory for testing. Other methods for
obtaining a fluid sample are known in the art, and include retrieving a sample
from a producing well, during well testing or during well production
exploitation.
[00071 The previously incorporated applications disclose downhole tools
for formation testing via injection of non-formation (test) fluids into the
formation
and thereafter sampling the formation fluids. The tools include various
sensors
and circuits for monitoring and analyzing downhole formation fluid
characteristics:
However, it is desirable that, before injecting anything into the formation,
compatibility tests be performed. It would be desirable if fluid compatibility
tests
could be performed downhole either contemporaneous with or prior to the
testing
which requires injection of non-formation fluids into the formation.
SUMMARY OF THE INVENTION
[00081 Some aspects of the invention may provide systems and
methods for downhole fluid compatibility testing and analysis.
[0009] Some aspects of the invention may provide systems for
delivering test fluids downhole.
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[0010] Some aspects of the invention may provide systems for collecting
fluid samples downhole.
[0011] Some aspects of the invention may provide systems for collecting
test fluids downhole.
[0012] Some aspects of the invention may provide downhole systems for
selectively mixing a test fluid with a fluid sample-
[0013] Some aspects of the invention may provide systems for injecting test
fluids into the formation.
[0014] Some aspects of the invention may provide downhole systems for
detecting and analyzing reactions that take place in the mixture of test fluid
and
fluid sample.
[0015] Some aspects of the invention may provide downhole systems for
determining the compatibility of a test fluid with a downhole fluid sample
based on
the detected and analyzed reaction of their mixture.
[0016] Some aspects of the invention may provide methods for determining
downhole the compatibility of test fluids with formation fluids or drilling
fluids.
[0017] According to an exemplary embodiment, the disclosed systems
include a tool having a plurality of chambers for storing test fluids and a
mixing
chamber-
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The chambers are connected to flowlines, a pump and a plurality of valves for
obtaining downhole fluid samples and selectively delivering two or more fluids
into the mixing chamber. The mixing chamber may include some mixing means,
e.g. a spinner. The mixing chamber is provided with one or more sensors
(inside
or outside the chamber) for detecting the occurrence of a reaction in the
mixing
chamber. A circuit or circuits coupled to the one or more sensors are used in
interpreting the output of the sensor(s) and making a determination of fluid
compatibility. In some cases, the circuits are coupled to telemetry equipment
for
conveying the results of the test to surface equipment and for receiving
instructions regarding sampling and testing. In other cases, the sampling and
testing process is controlled by a downhole controller using executing
software
instructions stored on a memory chip. Generally, if no reaction is detected,
the
fluids are determined to be compatible. If a reaction is detected, then the
consequences of this reaction are evaluated with respect to the intended use
of
the test fluid. For example, on the one hand, asphaltene is typically
encountered
in medium to heavy oil reservoirs. It is known that concentration increases
with
decreasing API gravity (increasing density) and increasing viscosity of the
reservoir oil. On the other hand, carbon dioxide injection can be used to
maintain
the pore pressure in a reservoir despite depletion of the reservoir through
production. However, carbon dioxide injection can cause the precipitation of
asphaltene which is often detrimental to production because it may reduce the
permeability of the reservoir. Thus, if carbon dioxide test fluid produces a
detectable precipitation of asphaltene, it will be considered incompatible
with the
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reservoir fluids. The asphaltene precipitation can be detected with an optical
scattering detector of the type described in the art, or any other method.
[0018] According to an alternate embodiment, downhole samples are
obtained by capturing a core and processing it in the tool to extract a
formation
fluid sample. In another alternate embodiment, tests are conducted in-situ by
injecting a test fluid into the formation and providing one or more sensors
which
are specifically located so that they are capable of detecting a reaction
occurring
at the injection site. According to another alternate embodiment, a test fluid
is
injected into the formation, allowed to mix with formation fluid and the
mixture is
extracted from the formation into the tool where the reaction is detected and
analyzed.
[0019] Combined test fluid and fluid sample collected at a first depth can
be injected back into the reservoir at a second depth. Also, the fluid
injected at
the first depth and then recovered at a first depth can be treated and/or
purified
for re-injection at a second depth. The first and the second depth may be the
same or different. Injection rate and injection pressure may be sensed and
analyzed.
[0020] According to other alternate embodiments, the test fluids may be
placed in chambers before the tool is delivered downhole; the test fluids can
be
obtained downhole from the welibore (e.g. drilling mud or completion fluid);
the
test fluid can be supplied as needed from the surface (e.g., via coiled
tubing); the
test fluid can be generated downhole (e.g., heating water to obtain steam as a
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test fluid or reacting two or more chemicals to generate a desired fluid); the
test
fluid may be obtained in-situ from another formation zone during the same or
an
earlier logging run.
[0021] Test fluids suitable for use in accordance with this disclosure
include gases, liquids, and liquids containing solids. Suitable gases include:
hydrogen, carbon dioxide, nitrogen, air, flue gas, natural gas, methane,
ethane,
and steam. Suitable liquids include: hot water, acids, alcohols, natural gas
liquids
(propane, butane) or other liquid hydrocarbons, micellar solutions, and
polymers.
Suitable solids for use in liquids include: proppant, gravel, and sand. In
addition,
test fluids may include: de-emulsifiers (emulsion breakers), asphaltene
stabilizing
agents, microbial solutions, surfactants, solvents, viscosity modifiers, and
catalysts.
[0022] Detectable reactions between test fluids and fluid samples include:
the formation of solid particles (e.g. asphaltene, waxes, or precipitates),
the
formation of emulsions, a change in viscosity of the fluid sample, the
generation
of a gas, the generation of heat, or the change of any other thermophysical
property of the fluid sample (e.g. density, phase envelope, etc.).
[0023] The reaction between the test fluid and the fluid sample is detected
and measured over time using one or more sensors. The sensors may be
located inside and/or outside (e.g., an X-ray sensor or gamma-ray sensor) the
mixing chamber. They may be located along flowlines in the tool. In cases
where
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the reaction is detected in the formation, the sensors may be located on or
near
the exterior of the tool body.
[0024] Useful sensors include sensors that can measure, among other
things, one or more of density, pressure, temperature, viscosity, composition,
phase boundary, resistivity, dielectric properties, nuclear magnetic
resonance,
neutron scattering, gas or liquid chromatography, optical spectroscopy,
optical
scattering, optical image analysis, scattering of acoustic energy, neutron
thermal
decay or neutron scattering, conductance, capacitance, carbon/oxygen content,
hydraulic fracture growth or propagation, radioactive and non-radioactive
markers, bacterial activity, streaming potential generated during injection,
H2S,
trace elements, and heavy metals.
[0025] The downhole tool of this disclosure can be deployed with a
wireline, a tractor, or coiled tubing in an open or cased hole. Alternatively,
it can
be deployed as part of a logging while drilling (LWD) tester that can be
incorporated in a drill string and used while drilling.
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According to an aspect of the invention, there is provided a downhole
tool, comprising: an inlet disposed on an exterior of the tool for engaging a
formation; a chamber fluidly connected to the inlet, wherein a test fluid is
disposed
in the chamber; means for introducing the test fluid from the chamber into the
formation; a sensor arranged to detect a reaction taking place between the
test fluid
and a fluid within the formation, wherein the reaction is taking place within
the
formation and is detected within the formation; and a controller operatively
coupled
to the sensor and configured to make a determination of compatibility of the
test
fluid with the formation fluid based on the detected reaction.
According to another aspect of the invention, there is provided a
downhole tool for testing fluid compatibility with a subterranean formation
fluid,
comprising: an inlet disposed an an exterior of the tool for engaging a
formation; a
first chamber fluidly connected to the inlet via a conduit; a second chamber
fluidly
connected to the first chamber; means for combining a sample fluid obtained
from the
formation and a test fluid disposed in the second chamber; at least one sensor
arranged relative to at least one of the first and second chambers such that
the
sensor detects a reaction taking place between the sample fluid and the test
fluid; a
controller operatively coupled to the sensor for making a determination of the
compatibility of the test fluid with the fluid sample based on the reaction; a
third
chamber fluidly connected to both the first and second chambers, wherein the
means
for combining includes means for moving the contents of the first and second
chambers into the third chamber; and means for introducing the test fluid into
the
formation, wherein the at least one sensor is arranged such that the sensor
can
detect a reaction taking place between the test fluid and the formation fluid
within the
formation, and wherein the controller is configured to make a determination of
the
compatibility of the test fluid with the formation fluid based on the reaction-
[0026] Additional objects and advantages of the invention will become
apparent to those skilled in the art upon reference to the detailed
description taken
in conjunction with the provided figures.
BRIEF DESCRIPTION OF THE DRAWINGS
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[0027] FIG. 1 is a schematic representation of system in accordance with
this disclosure deployed via wire line in a welibore and coupled to surface
equipment;
[0028] FIG. 2A is a schematic diagram of the components of a first
embodiment of a system in accordance with this disclosure;
[0029] FIG. 2B is a schematic diagram of the components of a variation of
the embodiment shown in FIG. 2A;
[0030] FIG. 3 is a schematic diagram of the components of a second
embodiment of a system in accordance with this disclosure;
[0031] FIG. 4 is a schematic diagram of the components of a third
embodiment of a system in accordance with this disclosure;
[0032] FIG. 5 is a schematic diagram of the components of a fourth
embodiment of a system in accordance with this disclosure;
[0033] FIG. 6 is a schematic diagram of the components of a fifth
embodiment of a system in accordance with this disclosure;
[0034] FIG. 7 is a flow chart of a first embodiment of a method in
accordance with this disclosure;
[0035] FIG. 8 is a flow chart of a second embodiment of a method in
accordance with this disclosure;
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[0036] FIG. 9 is a flow chart of a third embodiment of a method in
accordance with this disclosure;
[0037] FIG. 10 is a flow chart of a fourth embodiment of a method in
accordance with this disclosure;
[0038] FIG. 11 is a flow chart of a fifth embodiment of a method in
accordance with this disclosure;
[0039] FIG. 12 is a flow chart of a sixth embodiment of a method in
accordance with this disclosure;
[0040] FIG. 13 is a graph of data obtained from an optical density sensor
indicating asphaltene precipitation following the injection of carbon dioxide;
[0041] FIG. 14 is a graph of data obtained from a fluorescence sensor
indicating asphaltene precipitation following the injection of carbon dioxide;
[0042] FIG. 15 is a graph of data obtained from a density/viscosity sensor
indicating asphaltene precipitation following the injection of carbon dioxide;
[0043] FIG. 16 is a graph of data obtained from an optical spectrometer
after injection of water into formation fluid and indicating that no emulsion
was
formed; and
[0044] FIG. 17 is a graph of data obtained from an optical spectrometer
after injection of water into formation fluid and indicating that an emulsion
was
formed.
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DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0045] Turning now to Fig. 1, the basics of a reservoir exploration
(borehole logging) system are shown. A borehole tool or sonde 10 is shown
suspended in a borehole 14 of a formation 11 by a cable 12, although it could
be
located at the end of coil tubing, coupled to a drill pipe, or deployed using
any
other means used in the industry for deploying exploration tools. The wall of
the
borehole 14 is usually lined with a mudcake 11 a that may assist testing of
the
reservoir formation with the tool or sonde 10. Cable 12 not only physically
supports the borehole tool 10, but typically, signals are sent via the cable
12 from
the borehole tool 10 to surface located equipment 5. Electrical power may be
provided to the tool via the cable 12 as well. The surface located equipment 5
may include a signal processor, a computer, dedicated circuitry, or the like
which
is well known in the art. Typically, the equipment/signal processor 5 takes
the
information sent uphole by the borehole logging system 10, processes the
information, and generates a suitable record such as a display log 18 or the
like.
Suitably, the information may also be displayed on a screen and recorded on a
data storage medium or the like.
[0046] A first embodiment of a system or tool in accordance with this
disclosure is illustrated schematically in Fig. 2A. The system or tool 100
includes
a plurality of test fluid chambers, e.g. chambers 102, 104, 106, a reversible
pump
108, a mixing chamber 110, and a probe or packer 112. The chambers 102,
104, 106, 110 and the probe or packer 112 are selectively coupled to the pump
108 via conduits 102a, 104a, 106a, 110a, 112a and valves 102b, 104b, 106b,
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110b, 112b. The pump 108 is further selectively coupled to the wellbore via
conduit 11 2c and valve 11 2d. Optionally, one or more sample chambers 114
(one shown) is/are selectively coupled to the pump 108 via one or more
conduits
11 4a (one shown) and one or more valves 11 4b (one shown). According to this
embodiment one or more sensors 116 are associated with the mixing chamber
110 and the mixing chamber 110 is provided with a mixing device such as a
spinner 110c. The one or more sensors 116 may be inside the mixing chamber
110 and/or simply near it depending on what type of sensors are used. For
example, pressure and temperature sensors are preferably located inside the
mixing chamber or at least in fluid communication with the mixing chamber. X-
ray and sonic sensors can be located outside the chamber. If the chamber is
clear or is provided with windows, optical spectroscopy sensors can be located
outside the chamber. The sensors 116 are preferably coupled to a circuit or
circuits 118 which process, pre-process or otherwise analyze the sensor
outputs.
The processed sensor output is preferably conveyed to surface equipment via a
telemetry unit 120 coupled to the analysis circuits 118. When possible, the
telemetry 120 is bidirectional and receives commands from the surface
equipment to operate the valves, the pump, and the injector/extractor. Though
not shown in the Figures, it will be appreciated that the remotely controlled
components are coupled to the telemetry. It should be appreciated that the
tool
could operate autonomously using a downhole controller executing software
instructions.
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[0047] In one example, the chambers 102, 104, 106, 110 and 114 if
applicable, are equipped with a sliding piston capable of reciprocating in the
chamber. The piston may define one side of the chamber in fluid communication
with the wellbore. Thus, fluids located on the other side of the chambers are
maintained at wellbore pressure.
[0048] In one example, the probe or packer 112 is an extendable probe.
Probe 112 may be selectively recessed below the outer surface of the tool, or
extended into sealing engagement with the wellbore wall. In the extended
position, the extendable probe 112 establishes a fluid communication between
the tool and the formation. The extendable probe 112 may alternatively be in
fluid communication with the wellbore in the retracted position.
Alternatively, the
probe or packer 112 may be an inflatable straddle packer, and provide a
function
similar but not identical to an extendable probe.
[0049] In another example, the probe or packer 112 isolates a guard zone
and a sample zone on the borehole wall (11 in Fig. 1). Usually, the guard zone
surrounds the sample zone. Fluid drawn from the guard zone by a pump (not
shown) may be disposed in the wellbore (not shown). Fluid drawn
simultaneously from the sample zone by the pump 108 may be used for the
compatibility testing. This arrangement eventually provides a formation fluid
substantially free of mud filtrate or other wellbore fluid. In this
arrangement, the
compatibility testing performed on the fluid drawn from the sample zone may be
essentially identical to the compatibility testing performed on pristine
formation
fluid. In yet another example where the wellbore is cased with a casing, the
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probe or packer includes a mechanism for perforating the casing, such as a
drilling mechanism, and a mechanism for plugging the casing after testing.
[0050] In another example, the pressure and/or the temperature in the
mixing chamber 110 may be adjusted and the sensors 116 may detect a reaction
occurring in the mixing chamber at various pressures and/or temperatures.
[0051] Fig. 2B illustrates a tool 100' in accordance with this disclosure.
The components of the tool 100' are nearly identical to those of the tool 100.
The
similar components have the same reference numerals. The difference in this
embodiment is that the sensors 116' are located in or adjacent to a flowline
such
as the conduit 11 Oa which couples the mixing chamber 110 with the pump 108.
If desired, sensors can be provided at both locations, i.e., in or adjacent
the
flowline between the pump and the mixing chamber as well as in or adjacent the
mixing chamber.
[0052] In the arrangement of Fig. 2B, the sensors 116' may be used to
perform measurements on fluids flowing from the probe or packer 112 prior to
mixing with test fluids in the mixing chamber 110. For example, the sensors
116'
may be used to perform measurements on wellbore or formation fluids. The
sensors 116' may also be used to perform measurements on fluids flowing from
test fluid chambers 102, 104 or 106 prior to mixing with another fluid in the
mixing
chamber 110.
[0053] The sensors 116' may further be used to perform measurements on
fluid mixtures flowing from the mixing chamber 110. In one example, a sampled
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formation fluid and a test fluid react with each other in the mixing chamber
and
the product of the reaction is a solid or a gas. The produced solid or gas may
segregate by gravity from other materials in the mixing chamber. The conduit
11 Oa is connected for example to the bottom of the mixing chamber 110. When
materials are flowed from the mixing chamber through the sensor 116' and the
conduit 11 Oa is connected to the bottom of the mixing chamber 110, the sensor
116' perform measurements on materials with decreasing densities as the mixing
chamber 110 is emptied, thus facilitating in some cases the detection of the
reaction that occurred in the mixing chamber 110.
[0054] Fig. 3 illustrates a second embodiment of a tool 200 in accordance
with this disclosure. The components of the tool 200 are nearly identical to
those
of the tool 100. The similar components have similar reference numerals
increased by one hundred. The difference in this embodiment is that the mixing
of one test fluid flowing from one of the chambers 202, 204 or 206 and the
fluid
flowing from the probe or extendable packer 212 occurs in an inline mixer 230.
The inline mixer 230 may be of any types know in the art, capable of mixing
fluids
flowing from flow lines 210a and 210b. The mixture may flow then through
conduit 212c and be dumped into the borehole. The mixture may alternatively
flow through conduit 214a and be captured in a sample chamber 214.
[0055] In the arrangement of Fig. 3, the proportion of the test fluid and the
sampled fluid in the mixture may be controlled by the ratio of the pumping
rates
of pumps 208 and 208'. This proportion can be modified according to the
objectives of the compatibility test. The sensor 216 is capable of performing
a
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measurement on the mixture having various proportions of sampled fluid and
test
fluid. As shown, the sensor 216 is further capable of measuring the fluid
coming
out of mixer 230. Thus, the information provided by the sensor 216 may be used
to advantage to decide when to collect a sample in the chamber 214.
[0056] In one example, the function of pump 208 may be combined with
the function of chambers 202, 204 and/or 206. For example, a pressure
providing apparatus such as a pump (or a valve coupled to the borehole) could
be provided in conjunction with each chamber to controllably force fluid out
of the
chamber. Alternatively, the fluids in the chambers 202, 204, 206 could be kept
at
high pressure and controllably released for mixture simply by opening a
respective associated valve 202b, 204b, 206b.
[0057] Fig. 4 illustrates a third embodiment of a tool 300 in accordance
with this disclosure. The components of the tool 300 are nearly identical to
those
of the tool 100. The similar components have similar reference numerals
increased by two hundred. The difference in this embodiment is that the
sensors
316 are located to sense reactions occurring in the formation as described in
more detail below with reference to Fig. 9. Since the reactions will take
place in
the formation, no mixing chamber is required for mixing the test fluid with a
formation fluid. It should be appreciated nevertheless that a mixing chamber
may be provided if the test requires injecting a mixture of test fluids that
for any
reason, is not mixed before the tool is run in the hole.
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[0058] In the arrangement of Fig 4, the reaction in the formation is
detected by the sensors 316 and analyzed by the circuits 318. The mixture of
test
fluid and formation fluid may further be extracted from the formation by the
probe
or packer 312 and captured in a chamber 314 if desired.
[0059] The sensors 316 may be located on the body of tool 300 or on the
probe or packer 312. These sensors measure characteristics of the mixture of
formation fluid and test fluid that is still in the formation. Alternatively
or
additionally these sensors measure characteristics of the formation rock in
the
presence of test fluid. Thus the sensors 316 may be used to determine the
compatibility of the test fluids carried downhole by the tool 300 with the
formation
fluid and/or the formation rock.
[0060] Some examples of sensors that could be used are sensors that
measure multi-depth resistivity properties, dielectric properties, nuclear
magnetic
resonance (NMR) properties, neutron spectroscopic properties such as thermal
decay and carbon/oxygen ratio.
[0061] Alternatively or additionally, remote sensors may be deployed in the
formation, as shown for example in US Patent number 6,766,854, assigned to
the assignee of the present invention, and the complete disclosure of which is
incorporated herein by reference. Remote sensors may sense a fluid or a
formation property. The remote sensors preferably communicate the sensed
property to the downhole tool for analysis.
[0062] Although only one probe or packer 312 is shown in Fig. 4, a first
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probe or packer 312 may be used for injecting test fluids and a second probe
or
packer (not shown) may be used for extracting fluid or fluid mixtures from the
formation. The first probe or packer may be similar to or different from the
shape, size or type of the second probe or packer. Each probe or packer may
have its own dedicated pump. The probe/packer used for extracting fluid and
the
probe/packer used for injecting test fluid may be disposed with respect to
each
other in various ways, including having the injection probe/packer surrounding
the extracting probe/packer.
[0063] Fig. 5 illustrates a fourth embodiment of a tool 400 in accordance
with this disclosure. The components of the tool 400 are nearly identical to
those
of the tool 100. The similar components have similar reference numerals
increased by three hundred. The difference in this embodiment is that the
probe/packer 112 (Fig. 2) has been replaced with a core capture and process
apparatus 412 for obtaining formation samples as described in more detail
below
with reference to Fig.12.
[0064] Fig. 6 illustrates a fifth embodiment of a tool 500 in accordance with
this disclosure. The components of the tool 500 are similar to those of the
tool
100. The similar components have similar reference numerals increased by four
hundred. The difference in this embodiment is that the test fluid chambers and
their associated valves and conduits have been replaced with a conduit 502a
and
a valve 502b which are arranged to receive test fluid from the surface while
the
tool 500 is downhole as described in more detail below with reference to
Fig.10.
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[0065] Fig. 7 is a flow chart of a first embodiment of a method in
accordance with this disclosure which can be performed with the tools 100,
100',
or 400. Referring now to Figs. 2A and 7, the method begins at 600 by filling
the
test fluid chambers 102, 104, 106 of tool 100. The tool 100 is then lowered
downhole at 602. An option is selected at 604 to extract formation fluid,
borehole
fluid or drilling fluid if applicable. If formation fluid is to be extracted
at 606, the
probe or packer 112 is extended into contact with the formation. If drilling
fluid is
to be extracted at 608, the probe or packer 112 is not extended beyond the
drilling fluid. In either case, the fluid is extracted by opening the valves
112b and
operating the pump 108. When desired, the valve 110b may be opened. This
causes the extracted fluid to flow to the mixing chamber 110 at 610. When
sufficient sample fluid has filled the mixing chamber, the pump is stopped and
the
valve 112b is closed. Test fluid is sent to the mixing chamber at 612 by
opening
one or more of the valves 102b, 104b, 106b and operating the pump. When
sufficient test fluid has been sent to the mixing chamber 110, the pump is
stopped and all of the valves are closed. The fluids are mixed at 614 by
operating the spinner 11 Oc. A reaction of the fluids with each other is
detected at
616 using sensors 116. The sensor output is analyzed at 618 using the analysis
circuits 118. The results of analysis are transmitted to the surface at 620
using
the telemetry equipment 120. Preferably, the mixing chamber 110 is emptied
and flushed at 622. The mixing chamber can be emptied by opening valve 11 Ob,
and one of valves 112b, 11 4b or 11 2d and operating the pump 108 to transfer
the contents to back into the formation, into the container 114 or into the
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wellbore. The contents of mixing chamber 112 may be alternatively transferred
into one of the preferably empty chambers 102, 104, 106 if desired. If one of
the
test fluid chambers 102, 104, 106 is filled with a non-reactive fluid, it can
be used
to flush the mixing chamber before performing the next test.
[0066] Fig. 8 is a flow chart of a second embodiment of a method in
accordance with this disclosure which can be performed with the tools 100,
100',
or 400. Referring now to Figs. 2A and 8, the method begins at 700 by lowering
the tool downhole with at least one test fluid chamber 102, 104, 106 empty,
e.g.,
102. A test fluid is extracted downhole at 702 by opening the valves 112b and
114b, and operating the pump 108 to collect downhole fluid into the sample
chamber 114. The test fluid may then be transferred into the chamber 102 at
704
by closing valve 11 2b, opening valve 102b and reversing the pump 108. The
fluid collected might be drilling fluid or formation fluid. Formation fluid is
then
extracted at 706 in the same manner as described above with reference to Fig.
7.
The tool might be moved to a different depth between the steps 704 and 706.
The fluid extracted at 706 can be pumped directly into the mixing chamber at
708. The collected test fluid stored in chamber 102 is then added to the
mixing
chamber at 710. The fluids are mixed at 712 and their reaction is detected at
714. The reaction is analyzed at 716 and the results transmitted to the
surface at
718.
[0067] Fig. 9 is a flow chart of a third embodiment of a method in
accordance with this disclosure which, depending on the choice made at 802 can
be performed with one of the tools 100 and 100' or with the tool 300.
According
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to this embodiment, test fluid is injected into the formation at 800. The
injection
rate and injection pressure may be recorded and analyzed as described in
detail
below.
[0068] If one of the tool 100 and 100' is utilized for the test, a test fluid
of
one of the chamber 102, 104 or 106 may be transferred into chamber 110 using
the pump 108. The test fluid may then be injected into the formation using the
probe or packer 112. Alternatively, a mixture of test fluid and sample fluid
can be
collected at the same or different depth, for example in chamber 110 or 102.
The
mixture may be utilized at 800 as a test fluid. If the tool 300 is utilized
for the
test, any test fluid from chamber 302, 304 and 306 can be injected into the
formation using the probe or packer 312 of the tool 300.
[0069] If the test is to be performed in-situ as determined at 802, the tool
300 is preferably used and the in-situ reaction is detected at 808 using the
sensors 316 (Fig. 4). If the determination at 802 is to perform the test in
the
mixing chamber 110, (Fig. 2A or Fig. 2B) the combined test fluid and formation
fluid are extracted at 804 and sent to the mixing chamber at 806 and their
reaction is detected by the sensor(s) 116 or 116' (Fig.2A or Fig. 2B). In
either
case, the output of the sensors is analyzed at 810 and the analysis
transmitted to
the surface at 812. It will be appreciated that in the example given, the
decision
at 802 must be made before the tool is lowered downhole. Alternatively, the
tool
300 could be modified to include a mixing chamber and two sets of sensors, one
set arranged to detect in-situ reactions and another to detect reactions in
the
mixing chamber.
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[0070] Injection rate and injection pressure may be correlated. Their
relationship may be used to identify permeability damage due to the mixing of
the
test fluid and the formation fluid in the reservoir. Alternatively, a mixture
exhibiting a reaction may be utilized as injection fluid. The relationship
between
injection rate and injection pressure may be utilized to assess the impact of
this
reaction on the permeability or mobility of in the formation in which the
mixture is
injected.
[0071] The method of Fig. 9 may be used in combination for example with
the method of Fig. 7. The method of Fig. 7 is applied first and the
compatibility
between the test fluid and the sample fluid is determined. In some cases, the
fluids may be compatible. The method of Fig. 9 is then performed with the same
test fluid being introduced into the formation. Knowing that the fluids are
compatible, if an incompatibility in the formation occurs, an incompatibility
between the test fluid and formation rock can be suspected.
[0072] Fig. 10 is a flow chart of a fourth embodiment of a method in
accordance with this disclosure which can be performed with the tool 500 (Fig.
6). Referring now to Figs. 6 and 10, the tool 500 is lowered downhole at 900.
Using the probe or packer 512, the pump 508, associated valves and conduits,
formation or drilling fluid is extracted at 902 and sent to the mixing chamber
510
at 904. Using the pump 508, conduit 502a and valve 502b, test fluid from
uphole
is sent to the mixing chamber 510 at 906. The fluids are mixed at 908 and a
reaction is detected at 910. The output of sensors 516 is analyzed at 912
using
the circuits 518 and the results of analysis are transmitted to the surface at
914
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using the telemetry equipment 520. It will be appreciated that test fluid from
the
surface could be delivered to the mixing chamber by gravity or surface pumps.
In that case, the conduit 502a would be coupled directly to the mixing
chamber.
[0073] Fig. 11 is a flow chart of a fifth embodiment of a method in
accordance with this disclosure which can be performed with the tools 100,
100',
200 or 400. The tool is lowered downhole at 1000. Formation fluid is extracted
at
1002 and sent to the mixing chamber at 1004. At 1006, the test fluid is
generated, e.g. by heating water to create steam, or by mixing two or more
reactants together. When the reactants include a solid and a liquid, the
liquid
reactant can be pumped into the chamber containing the solid reactant, and the
resulting test fluid may be sent to the mixing chamber at 1008. When the
reactants include two liquids, it is preferable to mix them prior to
contacting the
formation fluid. Thus, they are preferably introduced into the mixing chamber
prior to sending the formation fluid into the chamber. Regardless, the test
and
formation fluids are mixed at 1010 and a reaction is detected at 1012. The
sensor output is analyzed at 1014 and the results of analysis are transmitted
to
the surface at 1016.
[0074] Fig. 12 is a flow chart of a sixth embodiment of a method in
accordance with this disclosure which can be performed with the tool 400.
Referring now to Figs. 5 and 12, the method begins at 1100 by filling the test
fluid
chambers 402, 404, 406. The tool 400 is then lowered downhole at 1102. A
core sample is obtained at 1104 using the core capture and process module 412
which captures the core and extracts formation fluid from it at 1106. The
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extracted fluid is sent to the mixing chamber 410 by opening the valves 41 Ob
and
412b and operating the pump 408. This causes the extracted fluid to flow to
the
mixing chamber 410 at 1108. When sufficient sample fluid has filled the mixing
chamber, the pump is stopped and the valve 412b is closed. Test fluid is sent
to
the mixing chamber at 1110 by opening one or more of the valves 402b, 404b,
406b and operating the pump. When sufficient test fluid has been sent to the
mixing chamber 410, the pump is stopped and all of the valves are closed. The
fluids are mixed at 1112 by operating the spinner 410c. A reaction of the
fluids
with each other is detected at 1114 using sensors 416. The sensor output is
analyzed at 1116 using the analysis circuits 418. The results of analysis are
transmitted to the surface at 1118 using the telemetry equipment 420.
[0075] Test fluids suitable for use with this disclosure include gases,
liquids, and liquids containing solids. Suitable gases include among others:
hydrogen, carbon dioxide, nitrogen, air, flue gas, natural gas, methane,
ethane,
and steam. Suitable liquids include: hot water, acids, alcohols, natural gas
liquids
(propane, butane), micellar solutions, and polymers. Suitable solids for use
in
liquids include: proppant, gravel, and sand. In addition, test fluids may
include
among others: de-emulsifiers (emulsion breakers), asphaltene stabilizing
agents,
microbial solutions, surfactants, solvents, viscosity modifiers, and
catalysts.
[0076] Detectable reactions between test fluids and fluid samples include
among others: the formation of solid particles (e.g. asphaltene, waxes, or
precipitates), the formation of emulsions, a change in viscosity of the fluid
sample, the generation of a gas, the generation of heat, or the change of any
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other thermophysical property of the fluid sample e.g. density, viscosity,
compressibility. Also, phase envelope may be estimated from downhole
measurements as shown for example in US Patent Application 2004/0104341.
[0077] The reaction between the test fluid and the fluid sample is detected
and measured over time using one or more sensors. The sensors may be inside
or outside (e.g., an X-ray sensor) the mixing chamber. They may be located
along flowlines in the tool. In cases where the reaction is detected in the
formation, the sensors may be located on or near the exterior of the tool
body.
[0078] Useful sensors include sensors that can measure among other
things one or more of density, pressure, temperature, viscosity, composition,
phase boundary, resistivity, dielectric properties, nuclear magnetic
resonance,
neutron scattering, gas or liquid chromatography, optical spectroscopy,
optical
scattering, optical image analysis, scattering of acoustic energy, neutron
thermal
decay, conductance, capacitance, carbon/oxygen content, hydraulic fracture
growth, radioactive and non-radioactive markers, bacterial activity, streaming
potential generated during injection, H2S, trace elements, and heavy metal.
[0079] The downhole tool of this disclosure can be deployed with a
wireline, a tractor, or coiled tubing in an open or cased hole. Alternatively,
it can
be deployed as part of a logging while drilling (LWD) tester that can be
incorporated in a drill string and used while drilling.
[0080] The downhole tool of this disclosure may send different information
depending on the telemetry bandwidth available with its mode of deployment or
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conveyance. If deployed with a wireline, the downhole tool will benefit from a
large telemetry bandwidth. Digitized sensor data may be sent uphole for
processing by surface equipment 5 of Fig. 1. If deployed on a drillstring
equipped with mud pulse telemetry, the downhole tool may be attributed a very
low telemetry bandwidth. Digitized sensor data may be stored in downhole
memory for retrieval when the tool is back to surface. The retrieved data may
be
utilized at the well site or at other locations. The sensor data may be also
processed downhole and processing results may be sent uphole, essentially in
real time. The results are optionally sent with related confidence indicators.
[0081] Whether obtained with a surface data processor or with a downhole
data processor, processing results may comprise a flag indicating whether a
reaction has been detected or not. A further refinement includes varying the
proportions of the test fluid and the sampled fluid in the mixture, and
sending the
proportions at which the reaction is detected (if applicable). Yet another
refinement includes varying the pressure and/or the temperature of the
mixture,
and identifying the pressure and/or the temperature at which a reaction is
detected (if applicable). If more than one sensor is used for detecting a
reaction
the information from these sensors can be combined and could be used for
indicating the type of reaction that has been detected.
[0082] Referring now to Figs. 13-15, by way of example only and not by
way of limitation, the results of injecting carbon dioxide into a sample of
formation
fluid are illustrated by graphs of the output of three different sensors. Fig.
13
shows the output of an optical spectrometer with respect to three different
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wavelength channels, channels FS9, FS11, and FS12 that are each in the range
between 900 to 2200 nanometers, before and after the samples were injected
with carbon dioxide test fluid. The notable changes in the optical densities
of the
fluid samples indicates in each case the precipitation of asphaltene. This may
result in a determination that carbon dioxide and the formation fluids are
incompatible.
[0083] Fig. 14 shows the output of a fluorescence sensor before and after
a formation fluid sample was injected with carbon dioxide test fluid. The
change
in fluorescence (Channel 0) of the fluid samples indicates the precipitation
of
asphaltene. This graph also indicates the ratio of the resin to asphaltene
molecules which is useful in estimating the potential damage caused by the
asphaltenes.
[0084] Fig. 15 shows the output of a density/viscosity sensor before and
after a formation fluid sample was injected with carbon dioxide test fluid.
The
notable changes in viscosity and density indicate the precipitation of
asphaltene.
[0085] Referring now to Figs. 16 and 17, by way of example only and not
by way of limitation, the results of injecting water into two different
formation fluid
samples are illustrated by graphs of the output of an optical spectrometer.
Fig.
16 shows two spectral plots, A and B. Plot A is a spectral plot of light
weight oil
before it is injected with water and plot B is a spectral plot of the light
weight oil
after injection with water. These plots indicate that no emulsion was formed
by
injecting water as an emulsion would have caused large scattering in the
visible
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and near infrared wavelengths. Thus, it may be determined that water and the
light weight oil are compatible. Fig. 17 shows two spectral plots for a
different oil
sample before and after injection with water. Plot A is a spectral plot of a
medium weight oil and plot B is a spectral plot of the medium weight oil after
injection with water. The increased and scattered optical density in the 900
to
2200 nanometer wavelength range indicates the formation of an emulsion.
Emulsions can form in medium and heavy oils that contain a significant amount
of asphaltenes. The asphaltenes act as surfactants with formation or treatment
water. The resulting emulsion droplets have high-energy bonds creating a very
tight dispersion of droplets that is not easily separated. These surface-
acting
forces can create both oil-in-water and/or water-in-oil emulsions. Such
emulsions require temperature and chemical treating in surface equipment in
order to separate. Thus, it may be concluded that water is incompatible with
this
oil sample.
[0086] There have been described and illustrated herein several
embodiments of systems and methods for performing fluid compatibility testing
and analysis downhole. While particular embodiments have been described, it is
not intended that the invention be limited thereto, as it is intended that the
invention be as broad in scope as the art will allow and that the
specification be
read likewise. Thus, while three test fluid chambers and one mixing chamber
have been disclosed, it will be appreciated that a greater or fewer number of
chambers could be used as well. In addition, while no particular downhole
power
source has been disclosed, it will be understood that any conventional means
of
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powering a downhole testing tool can be used. Although a pump has been
disclosed for delivering fluids to chambers, fluids can be delivered into and
out of
chambers by means other than a pump. For example, some or all of the fluids
can be delivered via gravity, hydraulic pressure, etc. It should be understood
that
the downhole tool of this disclosure is not limited to mud pulse telemetry or
wireline telemetry. It will therefore be appreciated by those skilled in the
art that
yet other modifications could be made without deviating from the spirit and
scope
of the claims.
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