U.S. patent application number 11/524060 was filed with the patent office on 2007-01-18 for apparatus and methods for improved fluid displacement in subterranean formations.
Invention is credited to James H. Cantrell, Sears T. Dealy, Dennis W. Gray, James F. Heathman.
Application Number | 20070012441 11/524060 |
Document ID | / |
Family ID | 46322502 |
Filed Date | 2007-01-18 |
United States Patent
Application |
20070012441 |
Kind Code |
A1 |
Heathman; James F. ; et
al. |
January 18, 2007 |
Apparatus and methods for improved fluid displacement in
subterranean formations
Abstract
Apparatus and methods for determining suitable displacement
fluids for use in subterranean formations are provided. One example
of a method is a method for identifying an inverter fluid to use
for inverting an oleaginous-external/aqueous-internal fluid in a
subterranean formation.
Inventors: |
Heathman; James F.; (Katy,
TX) ; Dealy; Sears T.; (Comanche, OK) ;
Cantrell; James H.; (Duncan, OK) ; Gray; Dennis
W.; (Comanche, OK) |
Correspondence
Address: |
CRAIG W. RODDY;HALLIBURTON ENERGY SERVICES
P.O. BOX 1431
DUNCAN
OK
73536-0440
US
|
Family ID: |
46322502 |
Appl. No.: |
11/524060 |
Filed: |
September 20, 2006 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
11211974 |
Aug 24, 2005 |
7128149 |
|
|
11524060 |
Sep 20, 2006 |
|
|
|
60603947 |
Aug 24, 2004 |
|
|
|
Current U.S.
Class: |
166/250.14 ;
166/250.01; 166/291; 507/904; 507/927; 73/152.01; 73/152.43 |
Current CPC
Class: |
Y10S 507/904 20130101;
C09K 8/42 20130101; Y10S 507/927 20130101 |
Class at
Publication: |
166/250.14 ;
166/250.01; 166/291; 073/152.01; 073/152.43; 507/904; 507/927 |
International
Class: |
E21B 33/16 20070101
E21B033/16 |
Claims
1. A method of identifying an inverter fluid to use for inverting
an oleaginous-external/aqueous-internal fluid in a subterranean
formation, the method comprising: measuring, at a temperature and
pressure of about the pressure and temperature to which the
inverter fluid will be exposed during placement in the formation, a
value of a parameter related to the electrical conductivity of an
initial composition that comprises: a test fluid portion having a
composition nominally equivalent to the
oleaginous-external/aqueous-internal fluid; and a portion of a
selected inverter fluid; and adding a further portion of the
selected inverter fluid to the initial composition until the
measured value of the parameter indicates that the mixture of the
initial composition plus the added further portion of the selected
inverter fluid has inverted from an
oleaginous-external/aqueous-internal state to an
aqueous-external/oleaginous-internal state.
2. The method of claim 1 further comprising determining a
concentration of an inverter fluid ingredient used in the added
further portion relative to the total volume of selected inverter
fluid in the initial composition and added further portion of the
selected inverter fluid.
3. The method of claim 1 further comprising determining the total
volume of the selected inverter fluid in the initial composition
and the added further part of the selected inverter fluid and
determining the ratio of the determined total volume to the volume
of test fluid in the initial composition.
4. The method of claim 1 further comprising making the initial
composition, the making comprising mixing the test fluid and an
aqueous-based fluid as the selected inverter fluid; and wherein the
step of adding a further portion of the selected inverter fluid
comprises injecting a selected surfactant in the initial
composition.
5. The method of claim 1 further comprising making the initial
composition, the making comprising mixing the test fluid, and a
spacer fluid/ surfactant composition as the selected inverter
fluid, in a selected ratio; and wherein the step of adding a
further portion of the selected inverter fluid includes injecting
additional spacer fluid/surfactant composition in the initial
composition.
6. The method of claim 1 wherein: the measuring step further
comprises elevating the pressure and temperature of the test fluid
and the inverter fluid to a temperature and pressure of about a
temperature and pressure to which the inverter fluid will be
exposed in a subterranean formation; and the adding step further
comprises heating and stirring the initial composition.
7. The method of claim 6 further comprising determining a
concentration of an inverter fluid ingredient used in the added
further portion relative to the total of selected inverter fluid in
the initial composition and added further portion of the selected
inverter fluid.
8. The method of claim 6 further comprising determining the total
volume of the selected inverter fluid in the initial composition
and the added further portion of the selected inverter fluid and
determining the ratio of the determined total volume to the volume
of test fluid in the initial composition.
9. The method of claim 6 further comprising making the initial
composition, the making comprising mixing the test fluid and an
aqueous-based fluid as the selected inverter fluid; and wherein the
step of adding a further portion of the selected inverter fluid
comprises injecting a selected surfactant in the initial
composition.
10. The method of claim 6 further comprising making the initial
composition, the making comprising mixing the test fluid, and an
aqueous-based fluid/ surfactant composition as the selected
inverter fluid, in a selected ratio; and wherein the step of adding
a further portion of the selected inverter fluid comprises
injecting additional spacer fluid/surfactant composition in the
initial composition.
11. A method of identifying an inverter fluid to use for inverting
an oleaginous-external/aqueous-internal fluid in a subterranean
formation, the method comprising: measuring, at a temperature and
pressure of about the pressure and temperature to which the
inverter fluid will be exposed during placement in the formation, a
value of a parameter related to the electrical conductivity of an
initial composition that comprises: a test fluid portion having a
composition nominally equivalent to the
oleaginous-external/aqueous-internal fluid; and a portion of a
selected inverter fluid; adding a further portion of the selected
inverter fluid to the initial composition until the measured value
of the parameter indicates that the mixture of the initial
composition plus the added further portion of the selected inverter
fluid has inverted from an oleaginous-external/aqueous-internal
state to an aqueous-external/oleaginous-internal state; and
determining a concentration of an inverter fluid ingredient used in
the added further portion relative to the total volume of selected
inverter fluid in the initial composition and added further portion
of the selected inverter fluid.
12. The method of claim 11 further comprising determining the total
volume of the selected inverter fluid in the initial composition
and the added further part of the selected inverter fluid and
determining the ratio of the determined total volume to the volume
of test fluid in the initial composition.
13. The method of claim 11 further comprising making the initial
composition, the making comprising mixing the test fluid and an
aqueous-based fluid as the selected inverter fluid; and wherein the
step of adding a further portion of the selected inverter fluid
comprises injecting a selected surfactant in the initial
composition.
14. The method of claim 11 further comprising making the initial
composition, the making comprising mixing the test fluid, and an
aqueous-based fluid/ surfactant composition as the selected
inverter fluid, in a selected ratio; and wherein the step of adding
a further portion of the selected inverter fluid comprises
injecting additional spacer fluid/surfactant composition in the
initial composition.
15. The method of claim 11 further comprising making the initial
composition, the making comprising mixing the test fluid, and a
spacer fluid/ surfactant composition as the selected inverter
fluid, in a selected ratio.
16. The method of claim 11 further comprising determining a
concentration of an inverter fluid ingredient used in the added
further portion relative to the total of selected inverter fluid in
the initial composition and added further portion of the selected
inverter fluid.
17. A method of identifying an inverter fluid to use for inverting
an oleaginous-external/aqueous-internal fluid in a subterranean
formation, the method comprising: providing an initial composition
comprising a test fluid portion having a composition nominally
equivalent to the oleaginous-external/aqueous-internal fluid and a
portion of a selected inverter fluid, the providing comprising
mixing the test fluid and the portion of the selected inverter
fluid; measuring, at a temperature and pressure of about the
pressure and temperature to which the inverter fluid will be
exposed during placement in the formation, a value of a parameter
related to the electrical conductivity of the initial composition;
and adding a further portion of the selected inverter fluid to the
initial composition until the measured value of the parameter
indicates that the mixture of the initial composition plus the
further portion of the selected inverter fluid has inverted from an
oleaginous-external/aqueous-internal state to an
aqueous-external/oleaginous-internal state.
18. The method of claim 17 further comprising determining a
concentration of an inverter fluid ingredient used in the added
further portion relative to the total volume of selected inverter
fluid in the initial composition and added further portion of the
selected inverter fluid.
19. The method of claim 17 further comprising determining the total
volume of the selected inverter fluid in the initial composition
and the added further part of the selected inverter fluid and
determining the ratio of the determined total volume to the volume
of test fluid in the initial composition.
20. The method of claim 17 wherein the measuring step further
comprises elevating the pressure and temperature of the test fluid
and the inverter fluid to a temperature and pressure of about a
temperature and pressure to which the inverter fluid will be
exposed in a subterranean formation; and the adding step further
comprises heating and stirring the initial composition.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] The present application claims priority under 35 U.S.C.
.sctn. 119(e) from U.S. Provisional Patent Application No.
60/603,947, entitled "Apparatus And Methods For Improved Fluid
Displacement In Subterranean Formations," and filed on Aug. 24,
2004, the disclosure of which is incorporated herein by reference
in its entirety.
[0002] This application is a divisional patent application of
commonly-owned U.S. patent application Ser. No. 11/211,974, filed
Aug. 24, 2005, entitled "Apparatus and Methods for Improved Fluid
Displacement in Subterranean Formations," by James F. Heathman, et
al., which is incorporated by reference herein for all
purposes.
[0003] This application is also related to co-pending U.S. patent
application Ser. No. 11/211,975, filed Aug. 24, 2005, entitled
"Apparatus and Methods for Improved Fluid Displacement in
Subterranean Formations," the entirety of which is herein
incorporated by reference.
BACKGROUND
[0004] The present invention relates generally to subterranean
operations involving displacement fluids and water-wetting surfaces
within a subterranean formation. More particularly, the present
invention relates to apparatus and methods for determining suitable
displacement fluids for use in subterranean cementing operations,
and methods of cementing that use such displacement fluids.
[0005] The drilling of well bores in subterranean formations
commonly involves pumping a "drilling fluid" into a rotated drill
string to which a drill bit is attached. The drilling fluid
typically exits through openings in the drill bit, inter alia, to
lubricate the bit and to carry cuttings up an annulus between the
drill string and the well bore for disposal at the surface. One
type of drilling fluid is an emulsion of substances that define a
non-aqueous external phase and an aqueous internal phase. In this
drilling fluid a non-aqueous "oleaginous" external phase (e.g., oil
or synthetic polymers). may be used to inhibit swelling of
water-sensitive drill cuttings (e.g., shale). Typical oil-based
drilling fluids contain some amount of an internal aqueous phase.
The emulsion often may be prepared by using an aqueous
(water-based) internal phase comprising salts (e.g., calcium
chloride). These oil- or synthetic-based drilling fluids also
typically include chemical emulsifying agents that act to form
oleaginous external phase emulsions, also known as "invert"
emulsions. These chemical emulsifying agents also promote the
oil-wetting of surfaces. This oil-wetted state promotes lubrication
of the drill bit and further stabilization of formation
materials.
[0006] After drilling is completed, a casing string commonly is
cemented in the well bore as part of completing the well. One type
of cementing operation includes placing a cement composition
through the casing string and into the annulus to displace the
drilling fluid from the annulus to the surface (however, flow in
the opposite direction can occur in some operations, such as in
reverse circulating or reverse cementing). A successful cementing
operation also includes bonding the cement composition with the
outer surface of the casing string and the inner surface of the
well bore defining the annulus.
[0007] The bond formed between the cement composition and the outer
surface of the casing string as well as the inner surface of the
well bore may not be optimal if the casing string and well bore
surfaces are not conducive to bonding with the cement composition.
For example, the non-aqueous portion of the drilling fluid may coat
the casing string and well bore surfaces. This may interfere with
the bonding of the cement composition to the surfaces, because the
aqueous cement composition generally will not bond readily with the
non-aqueous substances that may coat the surfaces. If improper or
incomplete bonding occurs at either of these surfaces, a thin
region called a "micro-annulus" may be formed. Formation of a
micro-annulus may lead to the loss of zonal isolation of the well
bore, and undesirable fluid migration along the well bore casing
string. Further, casing lifetime may be compromised if migrating
fluids are corrosive.
[0008] Conventional attempts to solve this problem have involved
displacement of the drilling fluid from the annular space between
the formation and casing string, or between an inner casing and an
outer casing strings so as to water-wet the formation and/or casing
surfaces. Accordingly, it often may be desirable for the
displacement fluid to invert the emulsion within the drilling
fluid, while water-wetting the formation and/or casing
surfaces.
[0009] A displacement fluid may be pumped ahead of the cement
composition to create water-wet surfaces. Certain embodiments of
such displacement fluids may cause a non-aqueous (hereafter
"oleaginous") external drilling fluid to invert, such that the
aqueous internal phase becomes external, and the oleaginous phase
becomes internal. Fluids that cause this inversion may be referred
to as "inverter fluids," and often may be suitable for use as
displacement fluids. Examples of suitable inverter fluids include,
inter alia, spacers and/or preflushes. Other nonlimiting examples
of suitable inverter fluids include settable fluids and other
compositions that comprise cementitious components such as
hydraulic cements. Other nonlimiting examples of suitable inverter
fluids are disclosed in, for example, U.S. Pat. Nos. 6,138,759,
6,524,384, 6,666,268, 6,668,929, and 6,716,282, the entire
disclosures of which are incorporated herein by reference.
[0010] Conventional inverter fluids typically comprise an aqueous
base fluid, viscosifying agents, and fluid loss control additives.
Certain inverter fluids also may comprise, inter alia, weighting
agents, surfactants, and salts. The weighting agents may be
included in an inverter fluid, inter alia, to increase its density
for well control, and to increase the buoyancy effect that the
inverter fluid may impart to the drilling fluid and filter cake
that may adhere to the walls of the well bore. Viscosifying agents
may stabilize the suspension of particles within the inverter
fluid, and may control fluid loss from the inverter fluid. The
presence of a surfactant in the inverter fluid may enhance the
chemical compatibility of the inverter fluid with other fluids
(e.g., the drilling fluid, and/or a cement composition that
subsequently may be placed within the formation) and may water-wet
downhole surfaces, thereby improving bonding of the cement
composition to surfaces in the formation, and may facilitate
improved removal of well bore solids. A salt may be included in the
inverter fluid, inter alia, for formation protection, improved
compatibility among fluids in the formation, and to desirably
affect wettability.
[0011] Inverter fluids also may be used to displace
oleaginous-external/aqueous-internal fluids from cased hole or open
hole well bores in operations other than cementing. One example
involves replacement of these inverter fluids with a completion
fluid (e.g., a solution of calcium chloride or bromide). This
operation may be conducted to clean the well bore for further
operations, such as perforation of the casing or, in the case of an
open hole, the onset of production of the well. In this case, the
inverter fluid may serve to displace the previous fluid and leave
the formation surfaces in a water-wet state.
[0012] The use of inverter fluids in cementing and other
subterranean operations often may be problematic, because of, inter
alia, difficulties in identifying a specific inverter fluid
composition that may desirably invert a particular drilling fluid
composition in a manner so as to water-wet the annulus to a desired
degree. Conventional attempts to identify specific inverter fluid
compositions that may desirably invert a particular drilling fluid
composition in a desired manner, at the temperature and pressure to
which both fluids may be exposed in a subterranean formation, often
have involved a multi-step process that may fail to identify
incompatibilities between components of the fluids at the
anticipated subterranean conditions. Commonly, a proposed inverter
fluid composition has been pre-conditioned to the anticipated
temperature and pressure using a high-pressure, high-temperature
apparatus, then cooled, de-pressurized, and removed from the first
apparatus, and placed in a testing apparatus at atmospheric
pressure and only slightly elevated temperature, along with a
sample of the drilling fluid that is to be inverted. This method is
problematic because it may mask certain changes or conditions
(e.g., cloud point changes, solubility changes, and the like) that
may result in an incompatibility between the fluids and/or that may
indicate that the proposed inverter fluid composition will not
invert a particular drilling fluid composition in a desired manner
at the desired temperature and pressure.
SUMMARY
[0013] The present invention relates generally to subterranean
operations involving displacement fluids and water-wetting surfaces
within a subterranean formation. More particularly, the present
invention relates to apparatus and methods for determining suitable
displacement fluids for use in subterranean cementing operations,
and methods of cementing that use such displacement fluids.
[0014] An example of a method of the present invention is a method
of identifying an inverter fluid to use for inverting an
oleaginous-external/aqueous-internal fluid in a subterranean
formation, the method comprising: measuring, at a temperature and
pressure of about the pressure and temperature to which the
inverter fluid will be exposed during placement in the formation, a
value of a parameter related to the electrical conductivity of an
initial composition that comprises: a test fluid portion having a
composition nominally equivalent to the
oleaginous-external/aqueous-internal fluid; and a portion of a
selected inverter fluid; and adding a further portion of the
selected inverter fluid to the initial composition until the
measured value of the parameter indicates that the mixture of the
initial composition plus the added further portion of the selected
inverter fluid has inverted from an
oleaginous-external/aqueous-internal state to an
aqueous-external/oleaginous-internal state.
[0015] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of the preferred embodiments, which follows.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] A more complete understanding of the present disclosure and
advantages thereof may be acquired by referring to the following
description taken in conjunction with the accompanying drawings,
wherein:
[0017] FIG. 1 is a schematic and block diagram for an embodiment of
an apparatus of the present invention.
[0018] FIG. 2 is a schematic circuit diagram of a particular
implementation of a circuit for testing fluid in accordance with
the present invention.
[0019] FIG. 3 is a schematic and block diagram for an embodiment of
an apparatus of the present invention.
[0020] FIG. 4 is a flow chart illustrating an embodiment of a
method of the present invention.
[0021] FIG. 5 is a flow chart illustrating an embodiment of a
method of the present invention.
[0022] FIG. 6 is a graph of the apparent wettability of a fluid
determined through the use of an apparatus and method of the
present invention.
[0023] While the present invention is susceptible to various
modifications and alternative forms, specific embodiments thereof
have been shown in the drawings and are herein described. It should
be understood, however, that the description herein of specific
embodiments does not limit the invention to the particular forms
disclosed, but on the contrary, covers all modifications,
equivalents, and alternatives falling within the spirit and scope
of the invention as defined by the appended claims.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0024] The present invention relates generally to subterranean
operations involving displacement fluids and water-wetting surfaces
within a subterranean formation. More particularly, the present
invention relates to apparatus and methods for determining suitable
displacement fluids for use in subterranean cementing operations,
and methods of cementing that use such displacement fluids.
[0025] In certain embodiments of the present invention, methods are
provided for determining a suitable composition for a displacement
fluid. In certain embodiments of the present invention, the
displacement fluid may be an inverter fluid. Certain embodiments of
the methods of the present invention comprise using an apparatus of
the present invention to measure a value of a parameter related to
the electrical conductivity of an initial mixture of (1) a test
fluid having a composition nominally equivalent to the oleaginous
external/aqueous internal fluid in the well and (2) part of a
selected inverter fluid. Certain embodiments of the methods of the
present invention also comprise adding a further portion of the
selected inverter fluid to the initial mixture, until the measured
value of the parameter indicates the test fluid has inverted from
an oleaginous-external/aqueous-internal state to an
aqueous-external/oleaginous-internal state.
[0026] Referring now to FIG. 1, illustrated therein is a schematic
and block circuit diagram for an embodiment of an apparatus of the
present invention. A fluid whose electrical conductivity is to be
tested is identified by the reference numeral 14. Fluid 14 is
placed in a container 12. Generally, container 12 is a pressure
vessel. In certain embodiments of the present invention, container
12 may be designed to withstand a pressure of at least about 30,000
psi at a temperature of at least about 400.degree. F. In certain
other embodiments of the present invention, container 12 may be
designed to withstand greater pressures at the same, or greater,
temperature. In certain preferred embodiments of the present
invention, container 12 includes a stainless steel test cell with
insulated electrodes and a silicone encased heating jacket.
[0027] Within container 12, paddle 16 is disposed in fluid 14. In
certain embodiments of the present invention, paddle 16 may
comprise a blender blade assembly. In certain embodiments of the
present invention, such blender blade assembly may be a blade
assembly typical of those used in high-temperature, high-pressure
cement consistometers. Paddle 16 can be rotated by electric motor
18, which, in certain embodiments of the present invention, may
comprise an AC or DC electric motor. In certain embodiments of the
present invention, electric motor 18 may be a direct drive motor,
wherein a drive shaft (not shown) penetrates container 12. In
certain embodiments of the present invention, electric motor 18 may
be a magnetic drive motor, wherein a drive shaft (not shown) does
not penetrate container 12. In certain preferred embodiments of the
present invention, the speed of electric motor 18 may be indicated
in revolutions per minute (rpm) on an indicator (not shown). When
fluid 14 within container 12 comprises a mixture of fluids (such
as, for example, a test fluid, a portion of an inverter fluid to be
tested, and any added substances), the stirring rate achieved using
electric motor 18 and paddle 16 should be sufficient to quickly
homogenize fluid 14, but should not be so high that excessive shear
causes air-entrainment, which may affect readings and surfactant
performance.
[0028] Thermocouple 13 is disposed within container 12, such that
at least a portion of thermocouple 13 is immersed in fluid 14. Two
electrodes 20, 22 are immersed in fluid 14 and connected to
respective portions of the remaining electrical circuit shown in
FIG. 1. Electrodes 20, 22 are mounted through, and insulated from
electrical contact with, the side wall of the container 12, and are
spaced circumferentially (e.g., about 90.degree., but other
spacings can be used). As container 12 generally will comprise
metal, electrodes 20, 22 cannot be allowed to contact the metallic
walls of container 12, because contacting the walls can result in
erroneous operation. The electrodes 20, 22 may be made of any
suitable conductive metals, including, inter alia, iron, brass,
nickel or stainless steel. The size of the electrode surface is not
critical; in certain preferred embodiments of the present
invention, the size of the electrode surface is about 0.2 square
inches. Electrode 20 connects to one terminal of a power source 24,
and electrode 22 connects to a potentiometer 26 that is connected
to another terminal of the power source 24. A voltmeter 28 is
connected across the potentiometer 26 to read a voltage across the
potentiometer 26 in response to the conductivity of current through
fluid 14 from one electrode to the other. The measurement of the
voltage, when used in combination with knowledge of the surface
area of paddle 16, provides an indication of the degree of
resistance faced by paddle 16, which may be transformed into a
measurement of the gel strength (measured in pounds per 100
ft.sup.2) or the apparent viscosity (measured in Beardon units of
consistency) of the fluid 14 within container 12. In certain
embodiments of the present invention wherein a measurement of the
gel strength is made, paddle 16 may be rotating at about 1/4 of one
degree per minute. In certain embodiments of the present invention
wherein a measurement of the apparent viscosity is made, paddle 16
may be rotating at about 150 rpm. As will be noted later with
reference to FIG. 2, certain embodiments of the present invention
may employ an ammeter 28' (not shown in FIG. 1) instead of a
voltmeter 28, wherein the ammeter 28' may have the same effect as
the use of a voltmeter 28, if the voltage across the potentiometer
26 is rectified and conditioned by the components 38 connected to
the ammeter 28'.
[0029] The pressure within container 12 is indicated by pressure
indicator 11, and may be controlled by a variety of means.
Generally, the pressure within container 12 will increase as
container 12 is heated to a desired temperature. Additional
pressurization of container 12 may be achieved by injecting a fluid
from fluid supply 30 into container 12 via pump 6. This may be done
manually or automatically. When a fluid is injected into container
12 manually, the pressure on pressure indicator 11 may be visually
observed, and pressure control valve 34 may be manually opened to
permit fluid to be pumped into container 12 through pump 6. In the
embodiment illustrated in FIG. 1, the pressure within container 12
may be automatically controlled. In certain of these embodiments
wherein the pressure is automatically controlled, pressure
indicator 11 comprises a pressure transmitter that sends signal 15
to pressure controller 40. Pressure controller 40 then may compare
the pressure in container 12 to a pressure set point, and may send
a signal 42 to pressure transducer 66, which may send signal 43 to
pressure control valve 34, thereby modulating pressure control
valve 34 (e.g., opening it) to permit pump 6 to inject fluid from
fluid supply 30 into container 12, until the pressure in container
12 reaches a desired value. Signal 42 may be an electrical signal,
while signal 43 may be a pneumatic signal. A bleeder valve 38
optionally may be provided on the piping between pump 6 and
container 12. A wide variety of valves may be suitable for use as
pressure control valve 34. A wide variety of controllers may be
suitable for use as pressure controller 40. In certain embodiments
of the present invention, pump 6 may be a diaphragm pump. An
example of a suitable diaphragm pump is commercially available from
Sprague Corp. In certain embodiments of the present invention (not
shown), pump 6 may be relocated such that fluid supply 30 is
located between pump 6 and container 12. In these embodiments,
fluid supply 30 may comprise a pressure vessel, and pump 6 may
cause fluid supply 30 to be pressurized to a desired pressure. In
certain embodiments, fluid supply 30 also may comprise a heating
element (not shown), such as an external heating jacket, internal
heating coils, or the like, that may heat fluid supply 30 to a
desired temperature. Where fluid supply 30 is used to pressurize
container 12, the fluid within fluid supply 30 generally will have
a composition that closely resembles the composition within
container 12 (e.g., where fluid 14 within container 12 comprises a
particular mixture of inverter fluid and drilling fluid, the fluid
within fluid supply 30 may have a composition similar, or
identical, to that of the particular mixture of inverter fluid and
drilling fluid).
[0030] The temperature within container 12 may be controlled by a
variety of means. In the embodiment illustrated in FIG. 1, heating
element 80 is disposed within container 12. In certain embodiments
of the present invention, heating element 80 comprises electrical
heating coils. In the embodiment illustrated in FIG. 1, heating
element 80 receives electrical current from power supply 70 via
conduit 74. Temperature controller 50 receives a signal 84 from
thermocouple 13 that indicates the present temperature within fluid
14 in container 12, compares the indicated temperature to the
desired temperature, and sends a signal 54 to power supply 70 that
modulates the amount of current supplied by power supply 70 so as
to elevate, or decrease, the indicated temperature. Signals 54 and
84 may be electrical signals. A wide variety of controllers may be
suitable for use as temperature controller 50.
[0031] In certain embodiments of the present invention, a receiving
tank 99 (not shown) may be provided, and may be connected to
container 12 to receive fluid 14 that may be discharged from
container 12. In certain embodiments of the present invention
wherein a receiving tank 99 is provided, receiving tank 99
generally will be a pressure vessel, and may comprise a cooling
element (not shown), such as cooling coils, or the like, along with
a number of optional elements such as a temperature indicator (not
shown), a pressure controller (not shown), and the like.
[0032] Referring now to FIG. 2, a schematic diagram of a circuit
for testing a fluid in accordance with one embodiment of the
present invention is illustrated. One type of power source 24 is a
24-Vac source such as a STANCOR P8616 transformer from Newark
Electronics. A 24-Vac source is preferred, inter alia, for safety
purposes, but other alternating current power sources may be used.
Direct current sources also may be used, though they are not
preferred because electrophoretic mobility of ionic species can
cause plating at the electrodes, which may result in the loss of
the signal, or interference that may lead to inaccurate
measurement. The transformer 24 is energized through an on/off
switch 36 connectible to a suitable primary power supply (e.g., a
conventional power main).
[0033] The potentiometer 26, such as a Bourns 3S00s-2-102, sets the
span of readings described below. In the circuit illustrated in
FIG. 2, an ammeter 28' (e.g., Monnteck 25-DUA-200-U from Allied) is
used instead of a voltmeter. As noted earlier with reference to
FIG. 1, the use of an ammeter 28' may have the same effect as the
use of a voltmeter 28, if the voltage across the potentiometer 26
is rectified and conditioned by the components 38 connected to the
ammeter 28'. Also shown in FIG. 2 is an optional on/off indicating
lamp 40 that illuminates when the switch 36 is closed to place the
circuit in an operative state for testing in accordance with the
present invention.
[0034] FIG. 2 also illustrates an example of a heating jacket
control circuit that may be used in the apparatus of the present
invention. A heating control switch 42 may be used to control a
temperature controller 46 that in turn operates a solid-state relay
44, which may energize, or de-energize, the heating jacket 32. A
lamp 48 illuminates when the heating jacket 32 is energized (e.g.,
is providing heat).
[0035] The apparatus shown in FIGS. 1-2 measure the surface-acting
properties of the fluid 14 by measuring the voltage drop across the
potentiometer 26 (measured either directly as a voltage in FIG. 1
or as a resulting current in FIG. 2). Normally, oleaginous-external
drilling fluids are not electrically conductive, in contrast to
aqueous-based inverter fluids, which are conductive. When the
electrodes 20, 22 are coated with a stable, oleaginous-external
drilling fluid, the voltage drop across the potentiometer 26 is
zero because no current (or an undetectable current) flows between
electrodes 20, 22. The maximum voltage drop, which may be obtained
when using a conductive inverter fluid by itself as the fluid 14,
will be some value above zero.
[0036] Referring now to FIG. 3, illustrated therein is an
alternative embodiment of an apparatus of the present invention. As
illustrated in FIG. 3, an inverter fluid reservoir is provided, and
depicted by the reference numeral 99. Generally, inverter fluid
reservoir 99 is a pressure vessel. In certain embodiments of the
present invention, inverter fluid reservoir 99 may be designed to
withstand a pressure of at least about 30,000 psi at a temperature
of at least about 400.degree. F. In certain other embodiments of
the present invention, inverter fluid reservoir 99 may be designed
to withstand greater pressures at the same, or greater,
temperature. In certain embodiments of the present invention,
inverter fluid reservoir 99 may comprise a heating element 81.
Inverter fluid reservoir 99 may be pressurized by pump 98, which is
supplied with inverter fluid (or another compatible fluid) through
reservoir 97. When a quantity of inverter fluid is desired to be
introduced into container 12 (which generally will already comprise
a drilling fluid to be tested, and which will, in certain
embodiments of the present invention, already be at elevated
temperature and pressure), valves 31, 32, 34, and 36 may be opened
(if each is not already in an open position), and a desired amount
of inverter fluid may be introduced into container 12.
[0037] As illustrated in FIG. 3, effluent vessel 40 may be provided
to receive fluid from flowing out of container 12. Generally,
effluent vessel 40 is a pressure vessel. In certain embodiments of
the present invention, effluent vessel 40 may be designed to
withstand a pressure of at least about 30,000 psi at a temperature
of at least about 400.degree. F. In certain other embodiments of
the present invention, effluent vessel 40 may be designed to
withstand greater pressures at the same, or greater, temperature.
Generally, valve 41 may be included in the flow line between
effluent vessel 40 and container 12, so as to isolate effluent
vessel 40 from container 12 when desired. In certain embodiments of
the present invention, effluent vessel 40 may comprise a cooling
element 42 (e.g., cooling coils).
[0038] Optionally, as illustrated in FIG. 3, a surfactant reservoir
may be provided, and depicted by the reference numeral 96.
Generally, surfactant reservoir 96 is a pressure vessel. In certain
embodiments of the present invention, surfactant reservoir 96 may
be designed to withstand a pressure of at least about 30,000 psi at
a temperature of at least about 400.degree. F. In certain other
embodiments of the present invention, surfactant reservoir 96 may
be designed to withstand greater pressures at the same, or greater,
temperature. In certain embodiments of the present invention,
surfactant reservoir 96 may comprise a heating element 77.
Surfactant reservoir 96 may be pressurized by pump 95, which is
supplied with surfactant (or another compatible fluid) through
reservoir 97. When a quantity of surfactant is desired to be
introduced into container 12, valves 30, 32, 34, and 36 may be
opened (if each is not already in an open position), and a desired
amount of surfactant may be introduced into container 12.
[0039] Generally, a calibrating procedure may be performed before
the apparatus of the present invention is used. Before a test is
run, the voltage or current relative to the potentiometer 26 is
measured using the meter 28/28' and only the
oleaginous-external/water-internal drilling fluid used as the fluid
14. This reading should be zero since the fluid 14 should be
nonconductive. A non-zero reading indicates the instrument is
malfunctioning (e.g., an electrical short occurring through the
instrument or electrodes 20, 22) or the
oleaginous-external/aqueous-internal fluid is contaminated with
water in the external phase. Next, the electrical parameter
(voltage or current) is measured with only the proposed inverter
fluid (e.g., no drilling fluid is present) as the fluid 14. This
should give a non-zero reading through the meter 28/28', which
corresponds to a maximum voltage drop because the aqueous-based
inverter fluid is electrically conductive. The potentiometer 26 can
be adjusted until a desired maximum reading is obtained. The
potentiometer 26 should not be adjusted after this setting is
obtained. Once the zero value of the potentiometer 26 and the
maximum span value of the potentiometer 26 have been determined
using suitable calibrating fluids, the precise moment when the
actual drilling fluid to be tested undergoes an external phase
change, or inversion (thus wettability) may be determined.
[0040] Generally, the composition of the test
oleaginous-external/aqueous-internal fluid may resemble the
particular drilling fluid that may be used in the subterranean
formation. In certain embodiments of the present invention, the
test fluid may be only nominally equivalent to the actual fluid
used (or that may be intended to be used) in the formation. As
referred to herein, the term "nominally equivalent" will be
understood to mean that the test fluid generally has the same
composition as the oleaginous-external/aqueous-internal drilling
fluid used during the drilling procedure, and that the test fluid
generally also may be pre-conditioned to a comparable temperature
and pressure to which the actual downhole fluid may be exposed.
Though the term "nominally equivalent" includes, but is not limited
to, exact identity between the fluids, the term also embraces
slight differences in the test fluid and the drilling fluid (e.g.,
wherein the test fluid and the drilling fluid have different
electrolyte contents). In certain embodiments of the present
invention wherein the apparatus and methods of the present
invention test are used at a well site, the test fluid may comprise
a sample of a batch of the drilling fluid to be placed into the
well bore.
[0041] The initial inverter fluid compositions to be tested against
the test oleaginous-external/aqueous-internal fluid may be chosen
by experience in dealing with the inverter fluids as known by one
skilled in the art, with the benefit of this disclosure.
[0042] Generally, the drilling fluid to be used in the test will be
preconditioned by increasing its pressure and temperature according
to a desired schedule, until the drilling fluid reaches the
temperature and pressure to which it is expected to be exposed in
the subterranean formation. In certain embodiments of the present
invention, this will be the particular well's bottom hole
circulating temperature and pressure. In certain embodiments, the
preconditioning schedule will approximate the variations in
temperature and pressure to which the drilling fluid will be
exposed during at least a portion of its passage through the
subterranean formation. The drilling fluid may be preconditioned
within the apparatus of the present invention, or within any other
suitable apparatus. In certain embodiments of the present
invention, the various selected fluids to be used in the test
(e.g., the drilling fluid, the inverter fluid, and other fluids)
may be placed in an apparatus of the present invention, and
preconditioned therein by increasing their pressure and temperature
according to a desired schedule, until the fluids reach the
temperature and pressure to which the determined inverter fluid is
expected to be exposed in the subterranean formation (e.g., the
particular well's bottom hole circulating temperature and
pressure). In certain embodiments, the preconditioning schedule
will approximate the variations in temperature and pressure to
which the fluids will be exposed during at least a portion of their
passage through the subterranean formation. Such preconditioning
generally ensures the fluids are stable and all chemicals have been
conditioned.
[0043] After the calibration procedure described above has been
performed on potentiometer 26, and the drilling fluid and/or other
fluids to be tested have been preconditioned to a desired extent as
described above, the actual testing of the combination of inverter
fluid and oleaginous-external/water-internal drilling fluid may be
performed, using one or both of two procedures, as well as other
suitable procedures. The particular one(s) chosen can be based upon
prior knowledge of the drilling fluid system, and the inverter
fluids, including the behavior of the various surfactants. During
this procedure, viscosity spikes that may occur at specific
drilling fluid-to-inverter fluid and drilling fluid-to-surfactant
ratios also may be observed and reported.
[0044] In one procedure, the drilling fluid to be tested and the
selected inverter fluid may be mixed in a desired ratio (e.g.,
50:50). The selected inverter fluid may or may not contain one or
more surfactants when mixed with the drilling fluid. After the
mixture is made homogenous by mixing with paddle 16, and while
stirring of the mixture continues, one or more selected surfactants
may be injected into this embodiment of the fluid 14, and the
electrical behavior is observed through the response of the meter
28/28'. As the concentration of surfactants increases within this
mixture, the reading from the meter 28/28' will start to increase
as the surfactants begin to invert the oleaginous-external drilling
fluid and clean the surfaces of electrodes 20, 22. During this
transition process, when the mixture of the inverter fluid and the
drilling fluid is in a bicontinuous phase (often referred to as a
Winsor Type III emulsion), the readings from meter 28/28' may
fluctuate, dropping to a stable minimum value at equilibrium when
the mixture homogenizes and the oil recoats the electrodes.
Eventually, the reading from the meter 28/28' will reach a maximum
value equal to, or slightly greater than, that recorded for 100%
inverter fluid (e.g., wherein drilling fluid is absent) as the
fluid 14, thus indicating the electrodes are completely
water-wetted and the mixture is 100% water-external (e.g., the
drilling fluid has been inverted). The maximum reading may be
slightly above that obtained with 100 percent spacer (e.g., due to
salts dissolved in the aqueous phase of the drilling fluid). To
ensure that inversion has actually occurred, the maximum reading
should remain stable for a suitable length of time, such as twenty
minutes. If the reading decreases, the appropriate surfactant(s)
should again be added and the electrical response monitored until
an electrically stable fluid has been obtained. Once the
electrically stable fluid has been obtained, the concentration of
the injected inverter fluid ingredient(s) (e.g., the one or more
surfactants in this example) in the total mixture in the test
container 12 may be determined. This total mixture includes the
measured initial mixture (e.g., the initial mixture of drilling
fluid and inverter fluid, in this example) plus the measured added
portion of the injected inverter fluid ingredients (e.g., the one
or more surfactants in this example). The concentration of the
injected inverter fluid ingredients in only the total inverter
fluid itself also may be readily determined. This concentration is
readily determined because the volume of inverter fluid in the
initial mixture is known and the volume of added inverter fluid
ingredients (e.g., surfactants) is known from the injection. The
procedure described above is, of course, capable of numerous
modifications, including, inter alia, embodiments wherein the
testing is performed by mixing the drilling fluid to be tested
along with a selected inverter fluid that already comprises a
desired amount of surfactants.
[0045] In the second, alternative procedure, the inverter fluid
initially may be prepared with one or more surfactants. Instead of
injecting surfactant into an initial mixture of drilling fluid and
inverter fluid, the drilling fluid may be present in container 12
without the inverter fluid, and then an inverter fluid may be
injected into the drilling fluid, so as to determine the volume of
inverter fluid required to invert the drilling fluid to a desired
degree. The reading on the meter 28/28' is observed, and once the
maximum reading is obtained for the suitable time period, the
electrically stable fluid has been obtained, thereby identifying
the ratio of the inverter fluid to the drilling fluid. That is, the
total volume of the selected inverter fluid in the initial mixture
(if any) and the added further portion of the selected inverter
fluid are known or determined and the ratio of the final volume of
the inverter fluid to the initial volume of the test
oleaginous-external/aqueous-internal fluid in the initial mixture
can be determined. The procedure described above is, of course,
capable of numerous modifications.
[0046] Having used the apparatus of the present invention to
determine parameters of the drilling fluid and inverter fluid, a
number of determinations may be made. For example, depending on the
viscosity profile of the drilling fluid, inverter fluid, and
mixtures thereof, it may be desirable to adjust the surfactant such
that the inversion from oleaginous-external to water-external
occurs at some specified drilling fluid-to-inverter fluid ratio.
For example, synthetic drilling fluids typically have a low yield
point; therefore, when the phase change occurs, the now
water-wetted solids of the drilling fluid may settle severely. This
can lead to bridging in downhole casing tools and in the annulus
when fluid velocities are insufficient to provide support. This
also may lead to annular solids bed deposition on the low side of
an inclined or horizontal well bore.
[0047] Conversely, some drilling fluid systems viscosify severely
when inverted, especially in the presence of an aqueous spacer.
Depending on where the viscosity peak occurs, it may be desirable
to shift the drilling fluid-to-inverter fluid ratio such that
inversion occurs away from the viscosity peak by adjusting the
surfactant. The injection procedure wherein one or more surfactants
are injected (rather than the entire inverter fluid) is best suited
to pinpointing the critical surfactant concentration. Once that
surfactant concentration is known, the inverter fluid injection
procedure can be repeatedly used with alternate surfactant
concentrations to find a drilling fluid-to-spacer ratio where
inversion occurs but with a lower viscosity spike.
[0048] A properly designed inverter fluid should have adequate
rheological properties to support solids released from the drilling
fluid system. In the case of a drilling fluid system that loses
solids-carrying capacity when it is inverted, it may be more
desirable to adjust (typically reduce) the surfactant loading such
that a higher percentage of inverter fluid is required to cause the
external phase of the resulting mixture to become water-wet. This
will result in more solids-carrying capacity, thus reducing the
risk of dropping solids as described above.
[0049] In one embodiment of a method of the present invention, a
method of designing an inverter fluid is provided that comprises
designing an inverter fluid that intermixes with the
oleaginous-external/aqueous-internal fluid to cause the
oleaginous-external/aqueous-internal fluid (or at least a coating
of this fluid on the outer surface of the tubular string or on the
wall of the well bore) to invert. Designing the inverter fluid
includes testing a selected inverter fluid with a test fluid having
a composition nominally equivalent to the composition of the
oleaginous-external/aqueous-internal fluid.
[0050] Once the desired inverter fluid has been designed, certain
embodiments of the methods of the present invention further
comprise making a quantity of the designed inverter fluid to be
placed in the annulus of the well. This quantity is placed in the
well for inverting the oleaginous external/aqueous-internal fluid
actually in the well on at least a portion of one or more surfaces
of the annulus. One technique for placing the inverter fluid
includes pumping the quantity of inverter fluid in the well along
with a stream of a cement composition such that the present
invention also encompasses a method of cementing a well in addition
to merely water wetting the well. In this application, the inverter
fluid precedes the cement composition such that the pumped inverter
fluid displaces at least part of the
oleaginous-external/aqueous-internal fluid in the annular region
and inverts the coating of oleaginous-external/aqueous-internal
fluid sufficient to remove the coating ahead of the cement
composition. At least part of the pumped inverter fluid is
subsequently displaced by the cement composition to obtain bulk
cement displacement, but without an undesirable micro-annulus.
Pumping of the fluids is performed in a conventional or otherwise
known manner (such as reverse-circulating or reverse cementing, for
example).
[0051] Another technique for placing the inverter fluid includes
pumping the quantity of inverter fluid in the well followed by a
quantity of a completion fluid. Examples of completion fluids may
include, for example, fresh water, along with aqueous salt
solutions (e.g., brines). A broad variety of aqueous salt solutions
may be suitable for use as completion fluids in certain
embodiments, including, for example, solutions that comprise
calcium chloride, sodium chloride, potassium chloride, calcium
bromide, zinc bromide, and formate completion brines (e.g., cesium
formate, potassium formate, and the like); other aqueous salt
solutions also may be suitable. In this technique, displacing and
inverting with the inverter fluid, and ultimately replacing the
oleaginous-external fluid and the inverter fluid with the
completion fluid prepares the well bore for future operations.
[0052] The testing and the making steps referred to above can be
performed at the well or elsewhere (e.g., at a laboratory for the
former and a manufacturing facility for the latter). The testing is
in accordance with further aspects of the present invention
described below. Making the designed inverter fluid is performed in
a conventional manner given a particular design obtained from the
testing of the present invention. For example, in certain
embodiments, the aqueous inverter fluid may be prepared at the well
site. Mixing water is measured into a field blender. Defoaming
agents may be added, followed by a pre-blended dry material
comprised of viscosifying agents and selected clays. Barite or
other weighting agents may be added to adjust the specific gravity
of the inverter fluid to a value usually slightly greater than that
of the drilling fluid. Selected surface active agents (surfactants)
may be added in sufficient quantity to perform the tasks of
inverting the oil-based fluid and leaving well bore surfaces in a
water-wet condition.
[0053] The process of testing in accordance with the present
invention leads to a determination of a particular inverter fluid
that can be used for inverting the particular test composition of
oleaginous-external/aqueous-internal fluid against which the
inverter fluid is tested. In the particular application of
displacing and inverting a drilling fluid emulsion in an oil or gas
well at the leading end of a stream of a cement composition being
pumped into the well, the inverter fluid to be determined is
typically in the class of fluids referred to as spacers. Such
spacers typically are combined with one or more surfactants to make
up the complete inverter fluid.
[0054] FIGS. 4 and 5 illustrate certain embodiments of the methods
of the present invention, and now will be described. Referring now
to FIG. 4, a flow chart is illustrated that depicts one embodiment
of the methods of the present invention, generally referred to as
method 400. Method 400 generally comprises determining a
composition of an inverter fluid that may invert, to a desired
degree, a test fluid that comprises an
oleaginous-external/aqueous-internal drilling fluid. In block 402,
a potentiometer (e.g., potentiometer 26 of FIG. 2) may be
calibrated. Calibration of potentiometer 26 should be performed as
discussed above. Subsequent to calibration of the potentiometer,
container 12 may be flushed (e.g., with water) and allowed to dry,
as depicted in block 404 of FIG. 4. Container 12 may be flushed and
dried, in some embodiments, so that any residue of the inverter
fluid and/or the test fluid may be removed from the surfaces of
electrodes 20, 22.
[0055] In block 406, the test fluid is preconditioned. Those of
ordinary skill in the art will appreciate that preconditioning of
the test fluid may be performed prior to, simultaneously with, or
subsequent to the steps depicted in blocks 402 and 404.
Preconditioning of the test fluid should be performed as discussed
above. For example, in some embodiments, preconditioning of the
test fluid may comprise utilizing high temperature, high pressure
equipment that is separate from the apparatus of the present
invention. In other embodiments, preconditioning of the test fluid
may occur in container 12 of an apparatus of the present invention
depicted in FIG. 1. Preconditioning of the test fluid may occur in
container 12, for example, to ensure that meter 28/28' reads
zero.
[0056] As depicted in block 408, a determination may be made as to
whether preconditioning of the test fluid occurred in container 12.
If preconditioning of the test fluid did occur in container 12, the
execution of the method 400 moves to block 414. If preconditioning
of test fluid did not occur in container 12, the test fluid should
be added to container 12, as depicted in block 410. Once in
container 12 the temperature and pressure of container 12 should be
adjusted, as depicted in block 412, to the temperature and pressure
that the oleaginous-external/aqueous-internal fluid that is being
tested will encounter in the subterranean formation.
[0057] In block 414 of FIG. 4, an initial mixture may be prepared
by injecting a selected inverter fluid into container 12 while
mixing, until a desired ratio of inverter fluid to test fluid
(e.g., a 50:50 ratio) is obtained. As previously discussed, the
inverter fluid may or may not contain surfactants. Furthermore, as
discussed above, once the desired ratio of the inverter fluid to
the test fluid is obtained, one or more selected surfactants should
be injected into the initial mixture, as depicted in block 16,
until inversion of the test fluid has been detected based on the
measured electrical parameters. Once inversion has occurred, a
composition of a desired inverter fluid may be determined because
the volume and composition of the inverter fluid in the initial
mixture is known, as well as the amount of the one or more selected
surfactants that were injected into the initial mixture.
[0058] Referring now to FIG. 5, a flow chart is illustrated that
depicts another embodiment of the methods of the present invention,
generally referred to as method 500. Method 500 generally comprises
determining a composition of an inverter fluid that may invert, to
a desired degree, a test fluid that comprises an
oleaginous-external/aqueous-internal drilling fluid. In block 502,
a potentiometer (e.g., potentiometer 26 of FIG. 2) may be
calibrated. Calibration of potentiometer 26 should be performed as
discussed above. Subsequent to calibration of the potentiometer,
container 12 may be flushed (e.g., with water) and allowed to dry,
as depicted in block 504 of FIG. 5. Contained 12 may be flushed and
dried, in some embodiments, so that any residue of the inverter
fluid and/or the test fluid may be removed from the surfaces of
electrodes 20, 22.
[0059] In block 506, the test fluid is preconditioned. Those of
ordinary skill in the art will appreciate that preconditioning of
the test fluid may be performed prior to, simultaneously with, or
subsequent to the steps depicted in blocks 502 and 504.
Preconditioning of the test fluid should be performed as discussed
above. For example, in some embodiments, preconditioning of test
fluid may comprise utilizing high temperature, high pressure
equipment that is separate from the apparatus of the present
invention. In other embodiments, preconditioning of the test fluid
may occur in container 12 of an apparatus of the present invention
depicted in FIG. 1. Preconditioning of the test fluid may occur in
container 12, for example, to ensure that meter 28/28' reads
zero.
[0060] As depicted in block 508, a determination may be made
whether preconditioning of the test fluid occurred in container 12.
If preconditioning of the test fluid did occur in container 12, the
execution of the method 500 moves to block 514. If preconditioning
of test fluid did not occur in container 12, the test fluid should
be added to container 12, as depicted in block 510. Once in
container 12 the temperature and pressure of container 12 should be
adjusted, as depicted in block 512, to the temperature and pressure
that the oleaginous-external/aqueous-internal fluid that is being
tested will encounter in the subterranean formation.
[0061] In block 514 of FIG. 5, a selected inverter fluid may be
injected into container 12 while mixing. In this embodiment, the
selected inverter fluid should contain the desired concentration of
the one or more surfactants. As discussed above, by observation of
meter 28/28' during injection of the selected inverter fluid a
desirable ratio of the selected inverter fluid to the test fluid
may be identified, wherein the ratio is capable of achieving the
desired inversion of the oleaginous-external/aqueous-internal
drilling fluid that was used as the test fluid. In another
embodiment, a selected inverter fluid may be injected into
container 12 to determine the compatibility of the selected
inverter fluid and the test fluid. The selected inverter fluid may
be injected into container 12 until a desired ratio of inverter
fluid to test fluid is obtained. Once the desired ratio is
obtained, observation of meter 28/28' will allow determination of
the compatibility of the selected inverter fluid and the test fluid
at the desired ratio. In certain embodiments, the step of adjusting
the temperature and pressure of container 12 in block 512 may not
occur until the desired ratio of the selected inverter fluid and
the test fluid is obtained by injection of the selected inverter
fluid into container 12.
[0062] To facilitate a better understanding of the present
invention, the following example of a preferred embodiment is
given. In no way should the following example be read to limit, or
to define, the scope of the invention.
EXAMPLE
[0063] The graph in FIG. 6 shows an example of the apparent
wettability (a dimensionless value) demonstrated by a fluid
comprising 65% by volume of a spacer fluid, and 35% by volume of a
drilling fluid comprising an internal olefin. The spacer fluid
comprised 18 pounds per gallon TUNED SPACER, plus 0.6 gallons per
barrel each of CLEANBORE A surfactant, SEM-8 surfactant, and AS-5
anti-sludging agent, all of which are commercially available from
Halliburton Energy Services, Inc., of Duncan, Okla. The drilling
fluid comprising an invert emulsion comprised an external phase of
C.sub.16-C.sub.18 internal olefin, primary and secondary
emulsifiers, and barite; the internal phase comprised a calcium
chloride brine having a specific gravity of 1.23. Both the spacer
fluid and the drilling fluid had a density of 18 pounds per gallon.
In the graph of FIG. 6, the fluid mixture remained in a
water-wetted state under high temperature, high pressure
conditions, as temperature increased.
[0064] Therefore, the present invention is well adapted to carry
out the objects and attain the ends and advantages mentioned as
well as those which are inherent therein. While the invention has
been depicted and described by reference to embodiments of the
invention, such a reference does not imply a limitation on the
invention, and no such limitation is to be inferred. The invention
is capable of considerable modification, alternation, and
equivalents in form and function, as will occur to those ordinarily
skilled in the pertinent arts and having the benefit of this
disclosure. The depicted and described embodiments of the invention
are exemplary only, and are not exhaustive of the scope of the
invention. Consequently, the invention is intended to be limited
only by the spirit and scope of the appended claims, giving full
cognizance to equivalents in all respects.
* * * * *