U.S. patent application number 12/206388 was filed with the patent office on 2009-03-19 for wellbore fluids for cement displacement operations.
This patent application is currently assigned to M-I LLC. Invention is credited to Andrew Bradbury, Mike Hodder, Jarrod Massam, Doug Oakley.
Application Number | 20090071649 12/206388 |
Document ID | / |
Family ID | 40465187 |
Filed Date | 2009-03-19 |
United States Patent
Application |
20090071649 |
Kind Code |
A1 |
Oakley; Doug ; et
al. |
March 19, 2009 |
WELLBORE FLUIDS FOR CEMENT DISPLACEMENT OPERATIONS
Abstract
A method of cementing a pipe into a wellbore filled with a
drilling fluid that includes displacing the drilling fluid with the
displacement fluid which includes a base fluid, a micronized
weighting agent; suspending a pipe in the wellbore; and pumping
cement into the wellbore to substantially fill the annulus formed
between the outer surface of the pipe and the wellbore is
disclosed.
Inventors: |
Oakley; Doug;
(Bradford-On-Avon, GB) ; Hodder; Mike; (Aberdeen,
GB) ; Bradbury; Andrew; (Kincardinshire, GB) ;
Massam; Jarrod; (Aberdeen, GB) |
Correspondence
Address: |
OSHA LIANG/MI
TWO HOUSTON CENTER, 909 FANNIN STREET, SUITE 3500
HOUSTON
TX
77010
US
|
Assignee: |
M-I LLC
Houston
TX
|
Family ID: |
40465187 |
Appl. No.: |
12/206388 |
Filed: |
September 8, 2008 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11617576 |
Dec 28, 2006 |
7409994 |
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12206388 |
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11145054 |
Jun 3, 2005 |
7176165 |
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11617576 |
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11617031 |
Dec 28, 2006 |
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11145054 |
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11145053 |
Jun 3, 2005 |
7169738 |
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11617031 |
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11737284 |
Apr 19, 2007 |
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11145053 |
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10610499 |
Jun 30, 2003 |
7267291 |
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11737284 |
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09230302 |
Sep 10, 1999 |
6586372 |
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PCT/EP1997/003802 |
Jul 16, 1997 |
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10610499 |
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11737303 |
Apr 19, 2007 |
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09230302 |
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10610499 |
Jun 30, 2003 |
7267291 |
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11737303 |
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11741199 |
Apr 27, 2007 |
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10610499 |
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60576420 |
Jun 3, 2004 |
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60576420 |
Jun 3, 2004 |
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60825156 |
Sep 11, 2006 |
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Current U.S.
Class: |
166/293 |
Current CPC
Class: |
C04B 14/368 20130101;
C04B 14/28 20130101; C04B 14/04 20130101; C04B 20/008 20130101;
C04B 20/1022 20130101; C09K 8/424 20130101; C09K 8/48 20130101;
C04B 20/1022 20130101 |
Class at
Publication: |
166/293 |
International
Class: |
E21B 33/16 20060101
E21B033/16 |
Foreign Application Data
Date |
Code |
Application Number |
Jul 26, 1996 |
GB |
9615549.4 |
Claims
1. A method of cementing a pipe into a wellbore filled with a
drilling fluid, comprising: displacing the drilling fluid with the
displacement fluid, comprising: a base fluid; and a micronized
weighting agent; suspending a pipe in the wellbore; and pumping
cement into the wellbore to substantially fill the annulus formed
between the outer surface of the pipe and the wellbore.
2. The method of claim 1, further comprising: pumping a spacer
fluid into the well prior to pumping the cement.
3. The method of claim 1, further comprising: pumping a second
displacement fluid into the wellbore to displace the pumped cement
into the annulus.
4. The method of claim 1, wherein pumping the cement displaces the
displacement fluid from the wellbore.
5. The method of claim 1, further comprising: introducing at least
one plug into the pipe.
6. The method of claim 1, wherein the micronized weighting agent is
at least one selected from barite, calcium carbonate, dolomite,
ilmenite, hematite, olivine, siderite, hausmannite, and strontium
sulfate.
7. The method of claim 1, wherein the micronized weighting agent is
coated with a dispersant made by the method comprising dry blending
a micronized weighting agent and a dispersant to form a micronized
weighting agent coated with the dispersant.
8. The method of claim 1, wherein the micronized weighting agent
comprises colloidal particles having a coating thereon.
9. The method of claim 1, wherein the micronized weighting agent
has a particle size d.sub.90 of less than about 20 microns.
10. The method of claim 1, wherein the micronized weighting agent
has a particle size d.sub.90 of less than about 10 microns.
11. The method of claim 1, wherein the micronized weighting agent
has a particle size d.sub.90 of less than about 5 microns.
12. The method of claim 7, wherein the coating comprises at least
one selected from oleic acid, polybasic fatty acids, alkylbenzene
sulfonic acids, alkane sulfonic acids, linear alpha-olefin sulfonic
acids, alkaline earth metal salts thereof, polyacrylate esters, and
phospholipids.
13. The method of claim 1, wherein the base fluid is at least one
of an oleaginous fluid and a non-oleaginous fluid.
14. A method of drilling and cementing a wellbore, comprising:
drilling the wellbore with a drilling fluid; displacing the
drilling fluid with a displacement fluid comprising: a base fluid;
and a micronized weighting agent; suspending a pipe in the well;
and pumping cement into the well so as to fill the annulus formed
between the outer surface of the pipe and the wellbore.
15. The method of claim 14, further comprising: pumping a spacer
fluid into the well prior to pumping the cement.
16. The method of claim 14, further comprising: pumping a second
displacement fluid into the wellbore to displace the pumped cement
into the annulus.
17. The method of claim 14, wherein pumping the cement displaces
the displacement fluid from the wellbore.
18. The method of claim 1, further comprising: introducing at least
one plug into the pipe.
19. A method of drilling and cementing a wellbore, comprising:
drilling the wellbore with a wellbore fluid comprising: a base
fluid; and a micronized weighting agent; suspending a pipe in the
well; and pumping cement into the well so as to fill the annulus
formed between the outer surface of the pipe and the wellbore.
20. The method of claim 19, further comprising: pumping a spacer
fluid into the well prior to pumping the cement.
21. The method of claim 19, further comprising: pumping a
displacement fluid into the wellbore to displace the pumped cement
into the annulus.
22. The method of claim 19, wherein pumping the cement displaces
the drilling fluid from the wellbore.
23. The method of claim 19, further comprising: introducing at
least one plug into the pipe.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part of co-pending
U.S. patent application Ser. Nos. 11/737,284 and 11/737,303, which
are, respectively, a continuation application and a divisional
application of U.S. patent application Ser. No. 10/610,499, which
is a continuation-in-part of U.S. application Ser. No. 09/230,302,
which is the U.S. national phase application under 35 U.S.C. .sctn.
371 of a PCT International Application No. PCT/EP97/003802, filed
Jul. 16, 1997 which in turn claims priority under the Paris
Convention to United Kingdom Patent Application No. 9615549.4 filed
Jul. 24, 1996. This application is also a continuation-in-part
application of co-pending U.S. patent application Ser. No.
11/617,576, which is a continuation application of U.S. patent
application Ser. No. 11/145,054, now U.S. Pat. No. 7,176,165, which
claims priority to U.S. Provisional Application Ser. No.
60/576,420. This application is also a continuation-in-part
application of co-pending U.S. patent application Ser. No.
11/617,031, which is a continuation application of U.S. patent
application Ser. No. 11/145,053, now U.S. Pat. No. 7,169,738, which
claims priority to U.S. Provisional Application Ser. No.
60/576,420. This application is also a continuation-in-part
application of U.S. patent application Ser. No. 11/741,199, which
claims priority to U.S. Provisional Application Ser. No.
60/825,156. Each of the above listed priority documents is hereby
incorporated by reference.
BACKGROUND OF INVENTION
[0002] 1. Field of the Invention
[0003] Embodiments disclosed here generally relate to wellbore
fluids for use in cement displacement applications and methods of
using such fluids.
[0004] 2. Background Art
[0005] In the drilling of oil and gas wells, a borehole is formed
in the earth with a drill bit typically mounted at the end of a
string of relatively small diameter tubing or drill string. Upon
drilling a predetermined length successfully, the wellbore is
typically prepared for its completions phase by isolating
formations transversed by the wellbore with a casing string.
Specifically, the bit and drill string are removed from the well,
and a larger diameter string of casing or liner is inserted
therein.
[0006] Generally, the annulus between the casing and the borehole
wall or between the liner and casing is filled with a cement slurry
which will permanently seal the annulus and provide structural
support for the casing or liner. After the cement slurry is pumped
into the annulus, it hardens to bond the casing to the borehole or
liner to prevent fluids in one formation from migrating to another,
and also prevents corrective formation fluids from damaging the
casing. The cement slurry is formed at the well site prior to
cementing, by mixing a dry cementious material such as fly ash with
water to form a thin, watery mixture that is easy to pump. Once
hardened in the annulus, cement is critical for not only supporting
and protecting casing but also for sealing formation pressures
hydraulically.
[0007] Additionally, cementing operations are used to provide zonal
isolation, a means to prevent wellbore fluids from contaminating
sensitive zones such as freshwater aquifers and production
intervals. An important factor for successful cementing is adequate
drilling fluid removal, or "mud displacement." To enhance mud
removal, a primary technique used is to pump a displacement and/or
spacer fluid with modified rheology ahead of the cement slurry to
improve mud displacement.
[0008] Several factors are known to directly impact the success of
a cement operation, including wellbore geometry, mud conditioning,
casing movement via reciprocation and rotation, mud displacement,
casing centralization, and optimizing the pump rate. Of these
factors, the displacement of the drilling fluid is of critical
relevance. In some cases, the rheology of the drilling fluid being
displaced may be such that the pressures in the wellbore while
pumping the cement slurry may exceed the fracture pressure of the
formation. This undesirable event may result in significant fluid
loss to the formation, and consequently a significant increase in
cost due to increased wait time or remedial repair.
[0009] Generally, in any wellbore pumping operation including the
pumping of drilling fluids, cementing fluids, and fracturing fluids
where the formation fracture pressure is low, pump pressures and
ECD may need to be reduced to prevent the formation from being
fractured and inducing fluid losses. For cementing operations in
particular, to prevent the formation from being fractured, the flow
rate and pump pressure are reduced. By reducing the flow rate, the
time required to complete the cement operation and to place the
cement into the annulus is lengthened. Thus, a critical property of
a cement slurry is the `thickening time.` The thickening time is a
relative indication of the hardening process of the cement slurry
and is a measure of the time required for the cement slurry to
become too viscous to be pumpable. It is thus essential that the
time required to place and pump the cement slurry into the annulus
is less than the thickening time of the cementing slurry. Being
able to pump a cement slurry in the annulus, with flow rates as
high as possible, preferably under turbulent flow conditions, in
the shortest possible time, within the constraints of formation
pore and fracture pressures is highly desirable.
[0010] While cementing efficiencies and zonal isolation may be
realized with proper drilling fluid displacement, cementing
generally requires for a much narrower hydraulic tolerance upon the
borehole, thus restricting pump pressures and high flow rates. For
example, the small annular spacing from which a drilling fluid is
being displaced and into which the cement slurry is being pumped
generally leads to increased frictional forces and pressures, which
in turn may lead to an elevated equivalent circulation density
(ECD). If the ECD of the drilling fluid exceeds the ability of the
formation to resist fracture, fluid losses (also referred to as
lost circulation events) typically result. Additionally, due to
narrow fracture formation pressure, little room is left for
conventional ECD reduction devices, and thus, ECD must be
controlled by tailoring the rheological properties of the drilling
fluid.
[0011] Generally, wellbore fluids may be used to provide sufficient
hydrostatic pressure in the well to prevent the influx and efflux
of formation fluids and wellbore fluids, respectively. When the
pore pressure (the pressure in the formation pore space provided by
the formation fluids) exceeds the pressure in the open wellbore,
the formation fluids tend to flow from the formation into the open
wellbore. Therefore, the pressure in the open wellbore is typically
maintained at a higher pressure than the pore pressure. While it is
highly advantageous to maintain the wellbore pressures above the
pore pressure, on the other hand, if the pressure exerted by the
wellbore fluids exceeds the fracture resistance of the formation, a
formation fracture and thus induced wellbore fluid losses may
occur. Further, with a formation fracture, when the wellbore fluid
in the annulus flows into the fracture, the loss of wellbore fluid
may cause the hydrostatic pressure in the wellbore to decrease,
which may in turn also allow formation fluids to enter the
wellbore. As a result, the formation fracture pressure typically
defines an upper limit for allowable wellbore pressure in an open
wellbore while the pore pressure defines a lower limit. Therefore,
a major constraint on well design and selection of wellbore fluids
is the balance between varying pore pressures and formation
fracture pressures or fracture gradients though the depth of the
well.
[0012] A particularly challenging situation arises in depleted
reservoirs, in which high pressured formations are neighbored by or
inter-bedded with normally or abnormally pressured zones. For
example, high permeability pressure depleted sands may be
neighbored by high pressured low permeability rocks, such as shale
or high pressure sands. This can make the drilling and completion
of certain depleted zones nearly impossible because the wellbore
fluid weight required to support the shale exceeds the fracture
resistance of the pressure depleted sands and silts.
[0013] Thus, there remains an increasing need for wellbore fluids
having the rheological profiles that enable wells to be drilled,
cemented, and completed more easily. Drilling fluids having
tailored Theological properties ensure that cuttings are removed
from the wellbore as efficiently and effectively as possible to
avoid the formation of cuttings beds in the well which can cause
the casing string to become stuck, among other issues. There is
also the need from a hydraulics perspective (equivalent circulating
density) to reduce the pressures required to circulate the fluid,
this helps to avoid exposing the formation to excessive forces that
can fracture the formation causing the fluid, and possibly the
well, to be lost. In addition, an enhanced rheology profile is
desired to prevent settlement or sag, i.e., solids falling out of
suspension, of any weighting agents present in the fluid. If
settlement or sag occurs, an uneven density profile within the
circulating fluid system, and thus well control (gas/fluid influx)
and wellbore stability problems (caving/fractures), may result.
[0014] To obtain the fluid characteristics required to meet these
challenges, the fluid must be easy to pump so only a small amount
of pressure is required to force it through restrictions in the
circulating fluid system, such as bit nozzles, down-hole tools, or
narrow wellbore annuli. In other words, the fluid must have the
lowest possible viscosity under high shear conditions.
[0015] Wellbore fluids used during drilling operations,
specifically, may if properly designed, also be used as
displacement and/or as spacer fluids prior to pumping the cement
slurry into the borehole. Thus, such fluids having this rheological
compatibility may be used in both the drilling and completion of a
wellbore. If a higher rheology fluid is used during drilling, a
tailored wellbore fluid having low rheology properties of plastic
viscosity, yield point, viscometer 6 rpm dial readings, and gel
strengths may be displaced into the wellbore prior to cementing to
reduce pump pressure and equivalent circulating density (ECD) while
cementing. As known in the art, maintaining pump pressures and ECD
below the fracture pressure of the formation prevents costly fluid
losses to permeable formations. In addition, higher flow rates of
the cement slurry and sufficiently better zonal coverage around the
casing or liner are desired to avoid costly secondary and tertiary
remedial operations. As will be further appreciated by those
skilled in the art, proper cement displacement often results in
more efficient clean up for a stronger cement bond and the rotation
of casing or liner during the cement operation.
[0016] Being able to also formulate a wellbore fluid having a low
rheology is important in cementing operations where a reduction in
ECD and complete removal of residual wellbore fluids is required.
High rheology properties can result in an increase in pressure at
the bottom of the hole under pumping conditions. Increases in ECD,
as mentioned above, can result in opening fractures in the
formation, and serious losses of the wellbore fluid into the
fractured formation. Further, the stability of the suspension is
also important in order to maintain the hydrostatic head to avoid a
blow out. The goal of low rheology fluids with low viscosity plus
minimal sag of weighting material continues to be a challenge.
[0017] Another highly desirable feature of the drilling fluid,
which is being displaced from the annulus by the spacers,
pre-flushes, chemical washes that are pumped ahead of the cementing
fluid, is the ability to remove residual drilling fluid from the
wellbore and casing/liner to effect a good cement bond between the
cement slurry and the casing/liner. If residual drilling fluid
remains the casing and/or wellbore before the cement slurry is
placed, a micro-annulus or channel may result, thereby favouring
interzonal intercommunication and an incomplete bond between the
cement and casing or wellbore that may, at some later date, require
remedial treatment. Drilling fluids that are viscous, with high gel
strengths are particularly problematic to the ultimate success of a
cementing operation and in some cases, as mentioned above, it is
necessary to reduce the rheology of the drilling fluid prior to the
cementing operation. However, reducing the rheology of a drilling
fluid may induce settlement of the drilling fluid weight material
which may then be difficult to remove by the cementing fluid, cause
channeling and ultimately an incomplete bond between the cementing
fluid and casing.
[0018] Thus, one requirement of these wellbore fluid formulations
is that the additives therein form a stable suspension and do not
readily settle out. A second requirement is that the suspension
exhibits a tailored viscosity and controlled ECD in order to
facilitate pumping and to minimize the generation of high
pressures, while also preventing settlement or sag. Finally, the
wellbore fluid should also prevent fluid losses.
[0019] Accordingly, there exists a continuing need for wellbore
fluids that control fluid ECD while simultaneously reducing
wellbore pressures and minimizing both fluid loss and increases in
pressure, and in particular, fluids that may be used in cement
displacement operations.
SUMMARY OF INVENTION
[0020] In one aspect, the embodiments disclosed herein relate to a
method of cementing a pipe into a wellbore filled with a drilling
fluid that includes displacing the drilling fluid with the
displacement fluid which includes a base fluid, a micronized
weighting agent; suspending a pipe in the wellbore; and pumping
cement into the wellbore to substantially fill the annulus formed
between the outer surface of the pipe and the wellbore.
[0021] In another aspect, the embodiments disclosed herein relate
to a method of drilling and cementing a wellbore that includes
drilling the wellbore with a drilling fluid; displacing the
drilling fluid with a displacement fluid comprising: a base fluid;
and a micronized weighting agent; suspending a pipe in the well;
and pumping cement into the well so as to fill the annulus formed
between the outer surface of the pipe and the wellbore.
[0022] In yet another aspect, the embodiments disclosed herein
relate to a method of drilling and cementing a wellbore that
includes drilling the wellbore with a wellbore fluid comprising: a
base fluid; and a micronized weighting agent; suspending a pipe in
the well; and pumping cement into the well so as to fill the
annulus formed between the outer surface of the pipe and the
wellbore.
[0023] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF DRAWINGS
[0024] FIG. 1 shows a schematic of one embodiment of a drilling
operation or system.
[0025] FIG. 2 shows a schematic of one embodiment of a cement
displacement operation.
DETAILED DESCRIPTION
[0026] In one aspect, embodiments disclosed herein relate to the
use of micronized weighting agents in wellbore fluids used in
cement displacement operations. Such fluids may include micronized
weighting agents mixed into a base fluid which may be any of a
number of fluids including water, seawater, brine, mineral oil,
diesel, and synthetic oils. Use of these fluids may provide for a
fluid to be present in the annulus prior to the cementing operation
that possesses a low rheology and low gel strength, which may
improves the effectiveness/efficiency of cement spacers, washes and
pre-flushes to remove residual drilling fluid prior to the
cementing operation, and which in turn may improve the quality of
the cement bond between casing and wellbore and overall quality of
the cementing operation. Such fluids may also have improved
rheology and ECD properties to simultaneously reduce wellbore
pressures and minimize both fluid loss and increases in pressure in
the wellbore during cement operations.
[0027] The wellbore fluids of the present disclosure may, as
disclosed herein, be pumped prior to the cement displacement
operation, in which a cement slurry is displaced into the annulus
between a pipe and the walls of the borehole. In particular, the
wellbore fluids may be referred to as a displacement fluid because
they are used to displace the fluids used in drilling from the
wellbore prior to cementing. Similarly, displacement fluids may
also be used to displace fluid or a cement slurry out of the casing
string and into the annulus to complete the cement displacement
operation.
[0028] As used herein, the term pipe may include any "casing,"
"liner," "tubular," "casing string," "liner string," or "string" is
known in art to be cemented in place in the wellbore, to provide
structural integrity to the wellbore.
[0029] Referring to FIG. 1, one embodiment of a typical drilling
system is shown. As shown in FIG. 1, a drilling rig 11 is disposed
atop a borehole 12. A drill bit 22 is located at the lower end of
the drill string 18 and carves a borehole 12 through the earth
formation 24. Drilling mud 26 is pumped from a storage reservoir
pit 27 near the wellhead 28, down an axial passage (not shown)
through the drill string 18, out of apertures in the bit 22 and
back to the surface through the annular region 16, generally
referred to as the annulus. Casing 29 is positioned in the borehole
12 above the drill bit 22 for maintaining the integrity of the
upper portion of the borehole 12.
[0030] Segments of casing 29 are placed in borehole 12. Thus, after
following drilling of a segment thereof, to place the casing 29,
the drill string 18 is pulled out of the borehole, a string of
casing 29 (or liner) is run into the well at least down to the
formation 24 which is believed to contain oil and/or gas
hydrocarbons. Greater details of such placements are shown in FIG.
2.
[0031] Referring to FIG. 2, a close-up view of the placement and
cementing of a liner 46 is shown. As shown in FIG. 2, borehole 42
drilled into a subterranean formation 24 from an offshore or
onshore rig has suspended therein a length of liner 46 to be
cemented in place. The liner 46 is suspended by a hanger 80
positioned in the lower portion of the casing 44. The casing 44 is
shown in the upper portion of the wellbore and a further extension
of the wellbore as defined by wellbore walls 42 is shown. The term
"liner" as used herein relates generally to a well casing whose
upper end does not extend all the way to the surface, but is hung
down hole from a larger diameter casing string. Thus, one skilled
in the art would appreciate that the techniques described with
respect to a liner would be the same or similar for cementing a
casing or other pipe. Thus, embodiments of the present disclosure
relate to both placement of casing and liners or other pipes.
[0032] Referring back to FIG. 2, centralizers 48 center the liner
46. Disposed at the bottom of the liner 46 is a landing collar 50
having an annular shoulder 52. Float shoes 64 or landing collars 50
are attached to the lower end of the liner 46 and include an
upwardly closing check valve 60 to prevent reverse flow of cement
slurry 68 once it has been pumped through the check valves 60 and
into the annulus 78 that is formed between the outer diameter of
the liner 46 and the walls of the borehole 42. The purpose of the
cementing operation is to fill the annulus 78 so that fluids in the
formation 24 that have been penetrated by the borehole 42 can not
migrate therethrough. After the cementing operation is completed, a
portion of the liner 46 may be perforated to bring the well into
production, or a smaller diameter borehole may be drilled below the
borehole 42 and then lined and cemented to deepen the well.
[0033] Still referring to FIG. 2, during the drilling of the
borehole 42, borehole 42 is filled with a weighted wellbore mud 72
or "mud" that has hydrostatic head which overbalances the formation
fluid pressure to prevent a blowout. Mud 72 is circulated to remove
cuttings produced by the rotary drilling process. During cementing,
the mud 72 located in annulus 78 is displaced by a cement slurry 68
and removed from the well. To prevent contamination or mixing of
the cement slurry 68 by or with the mud 72, a spacer fluid (not
shown) may be pumped prior to the cement slurry 68 to separate the
mud 72 from the cement slurry 68.
[0034] A cementing head (not shown) is mounted on the top joint of
the casing 44 hanging in the mast or derrick. Just before the
cement slurry 68 arrives at the head, a wiper plug 76 is positioned
at the lower end of the cement slurry 68 to maintain separation of
the cement slurry 68 from mud 72 present in the casing or liner.
The outer edge of each plug 76 is sized to sealingly engage the
inner walls of the liner 46 while sliding downward. The bottom plug
76 separates the cement slurry 68 from any mud 72 inside the casing
44 and prevents the mud 72 from contaminating the cement 68. As
cement slurry 68 is pumped into the well, the cement slurry 68
forwards the bottom plug 76 down the casing 44.
[0035] After pumping the desired quantity of cement slurry 68, a
top plug 58 is placed on top of the cement slurry 68. The top plug
58 separates the last of the cement slurry 68 to go into the casing
44 from displacement fluid 56 pumped on top of the cement slurry
68. Displacement fluid 56, which is usually salt water or a
specially formulated drilling mud, moves or displaces, the cement
slurry 68 from the casing 44 as the cement pump applies pressure to
move the cement slurry 68, the top plug 58, and the displacement
fluid 56 down the casing.
[0036] As the cement pump applies pressure, the bottom plug 76
continues to travel down the string of pipe until it stops or seats
in the landing collar 50. Continued pumping is then used to rupture
a membrane on the bottom plug 76 and open a passage therein. Cement
slurry 68 then proceeds through the bottom plug 76 and continues
down the last few joints of casing 44. The cement slurry 68 flows
through an opening in the guide shoe 64 and up the annulus 78
between the casing 44 and the borehole 42. Pumping continues until
the cement slurry 68 fills the annulus 78. As the last of the
cement slurry 68 enters the casing 44 pumped therethrough, the top
plug 58 is released from the cementing head. The top plug 58 is
similar to the bottom plug 76 with the exception that it has no
membrane or passage.
[0037] Most of the cement slurry 68 flows out of the casing 44 and
into the annulus 78. Eventually, the top plug 58 seats on, or
bumps, the bottom plug 76 in the landing collar 50. When it bumps,
the pump pressure is no longer applied. Cement slurry 68 is only in
the casing below the landing collar 50 and in the annulus 78. Most
of the casing 44 is full of displacement fluid 56. Cement slurry 68
is then allowed to set, bonding the liner 46 to the borehole walls
42 and/or to an inner surface of a portion of an above casing
string.
[0038] As shown in FIG. 2 and described above, cement slurry 68
displaces mud 72 from the annulus 78; however, in accordance with
the present disclosure, mud 72 being displaced by cement slurry 68
may be a fluid formulated with micronized barite (or other
weighting agents). Such micronized barite fluid may be used to
displace the fluid having drilled the interval, and thus it is this
micronized barite fluid which is displaced during cementing.
[0039] According to various embodiments, the wellbore fluids of the
present disclosure may be used in cement displacement operations,
where a casing string is to be sealed and/or bonded in the annular
space between the walls of the borehole and the outer diameter of
the casing with a cementing bonding material. In one embodiment,
the wellbore fluid may include a base fluid and a micronized
weighting agent. However, such a fluid may not be the fluid used to
drill the well. Rather, following drilling of a given interval,
once placement of a casing or liner is desired, the drilling fluid
may be displaced by a micronized barite fluid. The drill bit and
drill string may be pulled from the well and a casing or liner
string may be suspended therein.
[0040] A cement slurry may be pumped through the interior of the
casing, optionally separated from the micronized barite
displacement fluid with one or more spacer fluids or plugs, as
known in the art of cementing. Following the cement slurry, a
second displacement fluid (for example, the fluid with which the
next interval will be drilled or a fluid similar to the first
displacement fluid) may displace the cement slurry into the annulus
between the casing or liner and borehole wall. Once the cement
slurry has set in the annular space, drilling of the next interval
may continue. Prior to production, the interior of the casing or
liner may be cleaned and perforated, as known in the art of
completing a wellbore.
[0041] As discussed above, in order to prevent the formation being
fractured during pumping of any fluids including during cementing
operations, the flow rate (and hence pump pressure) is reduced. By
reducing the flow rate, the time taken to complete the cement
operation and place the cement in the annulus is lengthened such
that it is less than the thickening time property of the cementing
fluid, and the cement sets prior to being pumped into the correct
location (as the cementing fluid thickens it will become so viscous
it is unpumpable). By using the micronized barite fluids of the
present disclosure, greater pump rates for a given ECD ceiling may
be achieved, thus allowing for better placement of the cement
slurry to avoid premature thickening.
[0042] Being able to pump a cement slurry in the annulus, with flow
rates as high as possible, preferably under turbulent flow
conditions, in the shortest possible time, within the constraints
of formation pore and fracture pressures is highly desirable. As a
consequence of using the "low rheology" micronized barite fluids of
the present disclosure, higher flow rates may be achieved, the time
taken to place the cementing fluid in the annulus may be reduced,
and the risk of the cementing fluid prematurely hardening is
similarly reduced. Additionally, for a formation susceptible to
fracture, lower ECDs may result for a given pump rate of the fluids
of the present disclosure.
[0043] Further, it is specifically within the scope of the
embodiments disclosed herein that the micronized barite fluids of
the present disclosure may, as an alternative, be used as drilling
fluids, and be displaced by a cement slurry, without the use of an
additional displacement fluid. Furthermore, while FIG. 2 described
one embodiment of cement displacement; one skilled in the art would
appreciate that the embodiment shown in, FIG. 2 is just one example
of a cementing displacement operation and that there may be
variations and/or different types of equipment and specific
techniques used which do not depart from the scope of the invention
as disclosed herein.
[0044] Micronized Weighting Agent
[0045] Fluids used in embodiments disclosed herein may include
micronized weighting agents. In some embodiments, the micronized
weighting agents may be uncoated. In other embodiments, the
micronized weighting agents may be coated with a dispersant. For
example, fluids used in some embodiments disclosed herein may
include dispersant coated micronized weighting agents. The coated
weighting agents may be formed by either a dry coating process or a
wet coating process. Weighting agents suitable for use in other
embodiments disclosed herein may include those disclosed in U.S.
Patent Application Publication Nos. 20040127366, 20050101493,
20060188651, U.S. Pat. Nos. 6,586,372 and 7,176,165, and U.S.
Provisional Application Ser. No. 60/825,156, each of which is
hereby incorporated by reference.
[0046] Micronized weighting agents used in some embodiments
disclosed herein may include a variety of compounds well known to
one of skill in the art. In a particular embodiment, the weighting
agent may be selected from one or more of the materials including,
for example, barium sulphate (barite), calcium carbonate (calcite),
dolomite, ilmenite, hematite or other iron ores, olivine, siderite,
manganese oxide, and strontium sulphate. One having ordinary skill
in the art would recognize that selection of a particular material
may depend largely on the density of the material as typically, the
lowest wellbore fluid viscosity at any particular density is
obtained by using the highest density particles. However, other
considerations may influence the choice of product such as cost,
local availability, the power required for grinding, and whether
the residual solids or filter cake may be readily removed from the
well.
[0047] In one embodiment, the micronized weighting agent may have a
d.sub.90 ranging from 1 to 25 microns and a d.sub.50 ranging from
0.5 to 10 microns. In another embodiment, the micronized weighting
agent includes particles having a d.sub.90 ranging from 2 to 8
microns and a d.sub.50 ranging from 0.5 to 5 microns. One of
ordinary skill in the art would recognize that, depending on the
sizing technique, the weighting agent may have a particle size
distribution other than a monomodal distribution. That is, the
weighting agent may have a particle size distribution that, in
various embodiments, may be monomodal, which may or may not be
Gaussian, bimodal, or polymodal.
[0048] It has been found that a predominance of particles that are
too fine (i.e. below about 1 micron) results in the formation of a
high rheology paste. Thus, it has been unexpectedly found that the
weighting agent particles must be sufficiently small to avoid
issues of sag, but not so small as to have an adverse impact on
rheology. Thus weighting agent (barite) particles meeting the
particle size distribution criteria disclosed herein may be used
without adversely impacting the rheological properties of the
wellbore fluids. In one embodiment, a micronized weighting agent is
sized such that: particles having a diameter less than 1 microns
are 0 to 15 percent by volume; particles having a diameter between
1 microns and 4 microns are 15 to 40 percent by volume; particles
having a diameter between 4 microns and 8 microns are 15 to 30 by
volume; particles having a diameter between 8 microns and 12
microns are 5 to 15 percent by volume; particles having a diameter
between 12 microns and 16 microns are 3 to 7 percent by volume;
particles having a diameter between 16 microns and 20 microns are 0
to 10 percent by volume; particles having a diameter greater than
20 microns are 0 to 5 percent by volume. In another embodiment, the
micronized weighting agent is sized so that the cumulative volume
distribution is: less than 10 percent or the particles are less
than 1 microns; less than 25 percent are in the range of 1 microns
to 3 microns; less than 50 percent are in the range of 2 microns to
6 microns; less than 75 percent are in the range of 6 microns to 10
microns; and less than 90 percent are in the range of 10 microns to
24 microns.
[0049] The use of micronized weighting agents has been disclosed in
U.S. Patent Application Publication No. 20050277553 assigned to the
assignee of the current application, and herein incorporated by
reference. Particles having these size distributions may be
obtained by several means. For example, sized particles, such as a
suitable barite product having similar particle size distributions
as disclosed herein, may be commercially purchased. A coarser
ground suitable material may be obtained, and the material may be
further ground by any known technique to the desired particle size.
Such techniques include jet-milling, ball milling, high performance
wet and dry milling techniques, or any other technique that is
known in the art generally for milling powdered products. In one
embodiment, appropriately sized particles of barite may be
selectively removed from a product stream of a conventional barite
grinding plant, which may include selectively removing the fines
from a conventional API-grade barite grinding operation. Fines are
often considered a by-product of the grinding process, and
conventionally these materials are blended with courser materials
to achieve API-grade barite. However, in accordance with the
present disclosure, these by-product fines may be farther processed
via an air classifier to achieve the particle size distributions
disclosed herein. In yet another embodiment the micronized
weighting agents may be formed by chemical precipitation. Such
precipitated products may be used alone or in combination with
mechanically milled products.
[0050] In some embodiments, the micronized weighting agents include
solid colloidal particles having a deflocculating agent or
dispersant coated or sprayed onto the surface of the particle.
Further, one of ordinary skill would appreciate that the term
"colloidal" refers to a suspension of the particles, and does not
impart any specific size limitation. Rather, the size of the
micronized weighting agents of the present disclosure may vary in
range and are only limited by the claims of the present
application. The micronized particle size generates high density
suspensions or slurries that show a reduced tendency to sediment or
sag, while the dispersant on the surface of the particle controls
the inter-particle interactions resulting in lower Theological
profiles. Thus, the combination of high density, fine particle
size, and control of colloidal interactions by surface coating the
particles with a dispersant reconciles the objectives of high
density, lower viscosity and minimal sag.
[0051] In some embodiments, a dispersant may be coated onto the
particulate weighting additive during the comminution (grinding)
process. That is to say, coarse weighting additive is ground in the
presence of a relatively high concentration of dispersant such that
the newly formed surfaces of the fine particles are exposed to and
thus coated by the dispersant. It is speculated that this allows
the dispersant to find an acceptable conformation on the particle
surface thus coating the surface. Alternatively, it is speculated
that because a relatively higher concentration of dispersant is in
the grinding fluid, as opposed to that in a drilling fluid, the
dispersant is more likely to be absorbed (either physically or
chemically) to the particle surface. As that term is used in
herein, "coating of the surface" is intended to mean that a
sufficient number of dispersant molecules are absorbed (physically
or chemically) or otherwise closely associated with the surface of
the particles so that the fine particles of material do not cause
the rapid rise in viscosity observed in the prior art. By using
such a definition, one of skill in the art should understand and
appreciate that the dispersant molecules may not actually be fully
covering the particle surface and that quantification of the number
of molecules is very difficult. Therefore, by necessity, reliance
is made on a results oriented definition. As a result of the
process, one can control the colloidal interactions of the fine
particles by coating the particle with dispersants prior to
addition to the drilling fluid. By doing so, it is possible to
systematically control the rheological properties of fluids
containing in the additive as well as the tolerance to contaminants
in the fluid in addition to enhancing the fluid loss (filtration)
properties of the fluid.
[0052] In some embodiments, the weighting agents include dispersed
solid colloidal particles with a weight average particle diameter
(d.sub.50) of less than 10 microns that are coated with a polymeric
deflocculating agent or dispersing agent. In other embodiments, the
weighting agents include dispersed solid colloidal particles with a
weight average particle diameter (d.sub.50) of less than 8 microns
that are coated with a polymeric deflocculating agent or dispersing
agent; less than 6 microns in other embodiments; less than 4
microns in other embodiments; and less than 2 microns in yet other
embodiments. The fine particle size will generate suspensions or
slurries that will show a reduced tendency to sediment or sag, and
the polymeric dispersing agent on the surface of the particle may
control the inter-particle interactions and thus will produce lower
Theological profiles. It is the combination of fine particle size
and control of colloidal interactions that reconciles the two
objectives of lower viscosity and minimal sag. Additionally, the
presence of the dispersant in the comminution process yields
discrete particles which can form a more efficiently packed filter
cake and so advantageously reduce filtration rates.
[0053] Coating of the micronized weighting agent with the
dispersant may also be performed in a dry blending or spray drying
process such that the process is substantially free of solvent. The
process includes blending the weighting agent and a dispersant at a
desired ratio to form a blended material. In one embodiment, the
weighting agent may be un-sized initially and rely on the blending
process to grind the particles into the desired size range as
disclosed above. Alternatively, the process may begin with sized
weighting agents. The blended material may then be fed to a heat
exchange system, such as a thermal desorption system. The mixture
may be forwarded through the heat exchanger using a mixer, such as
a screw conveyor. Upon cooling, the polymer may remain associated
with the weighting agent. The polymer/weighting agent mixture may
then be separated into polymer coated weighting agent, unassociated
polymer, and any agglomerates that may have formed. The
unassociated polymer may optionally be recycled to the beginning of
the process, if desired. In another embodiment, the dry blending
process alone may serve to coat the weighting agent without
heating.
[0054] Alternatively, a sized weighting agent may be coated by
thermal adsorption as described above, in the absence of a dry
blending process. In this embodiment, a process for making a coated
substrate may include heating a sized weighting agent to a
temperature sufficient to react monomeric dispersant onto the
weighting agent to form a polymer coated sized weighting agent and
recovering the polymer coated weighting agent. In another
embodiment, one may use a catalyzed process to form the polymer in
the presence of the sized weighting agent. In yet another
embodiment, the polymer may be preformed and may be thermally
adsorbed or spray dried onto the sized weighting agent.
[0055] In some embodiments, the micronized weighting agent may be
formed of particles that are composed of a material of specific
gravity of at least 2.3; at least 2.4 in other embodiments; at
least 2.5 in other embodiments; at least 2.6 in other embodiments;
and at least 2.68 in yet other embodiments. For example, a
weighting agent formed of particles having a specific gravity of at
least 2.68 may allow wellbore fluids to be formulated to meet most
density requirements yet have a particulate volume fraction low
enough for the fluid to be pumpable.
[0056] As mentioned above, embodiments of the micronized weighting
agent may include a deflocculating agent or a dispersant. In one
embodiment, the dispersant may be selected from carboxylic acids of
molecular weight of at least 150 Daltons, such as oleic acid and
polybasic fatty acids, alkylbenzene sulphonic acids, alkane
sulphonic acids, linear alpha-olefin sulphonic acids, phospholipids
such as lecithin, including salts thereof and including mixtures
thereof. Synthetic polymers may also be used, such as HYPERMER OM-1
(Imperial Chemical Industries, PLC, London, United Kingdom) or
polyacrylate esters, for example. Such polyacrylate esters may
include polymers of stearyl methacrylate and/or butylacrylate. In
another embodiment, the corresponding acids methacrylic acid and/or
acrylic acid may be used. One skilled in the art would recognize
that other acrylate or other unsaturated carboxylic acid monomers
(or esters thereof) may be used to achieve substantially the same
results as disclosed herein.
[0057] When a dispersant coated micronized weighting agent is to be
used in water-based fluids, a water soluble polymer of molecular
weight of at least 2000 Daltons may be used in a particular
embodiment. Examples of such water soluble polymers may include a
homopolymer or copolymer of any monomer selected from acrylic acid,
itaconic acid, maleic acid or anhydride, hydroxypropyl acrylate
vinylsulphonic acid, acrylamido 2-propane sulphonic acid,
acrylamide, styrene sulphonic acid, acrylic phosphate esters,
methyl vinyl ether and vinyl acetate or salts thereof.
[0058] The polymeric dispersant may have an average molecular
weight from about 10,000 Daltons to about 300,000 Daltons in one
embodiment, from about 17,000 Daltons to about 40,000 Daltons in
another embodiment, and from about 200,000-300,000 Daltons in yet
another embodiment. One of ordinary skill in the art would
recognize that when the dispersant is added to the weighting agent
during a grinding process, intermediate molecular weight polymers
(10,000-300,000 Daltons) may be used.
[0059] Further, it is specifically within the scope of the
embodiments disclosed herein that the polymeric dispersant be
polymerized prior to or simultaneously with the wet or dry blending
processes disclosed herein. Such polymerizations may involve, for
example, thermal polymerization, catalyzed polymerization,
initiated polymerization or combinations thereof.
[0060] Given the particulate nature of the micronized and
dispersant coated micronized weighting agents disclosed herein, one
of skill in the art should appreciate that additional components
may be mixed with the weighting agent to modify various macroscopic
properties. For example, anti-caking agents, lubricating agents,
and agents used to mitigate moisture build-up may be included.
Alternatively, solid materials that enhance lubricity or help
control fluid loss may be added to the weighting agents and
drilling fluid disclosed herein. In one illustrative example,
finely powdered natural graphite, petroleum coke, graphitized
carbon, or mixtures of these are added to enhance lubricity, rate
of penetration, and fluid loss as well as other properties of the
drilling fluid. Another illustrative embodiment utilizes finely
ground polymer materials to impart various characteristics to the
fluid. In instances where such materials are added, it is important
to note that the volume of added material should not have a
substantial adverse impact on the properties and performance of the
wellbore fluids. In one illustrative embodiment, polymeric fluid
loss materials comprising less than 5 percent by weight are added
to enhance the properties of the wellbore fluid. Alternatively,
less than 5 percent by weight of suitably sized graphite and
petroleum coke are added to enhance the lubricity and fluid loss
properties of the fluid. Finally, in another illustrative
embodiment, less than 5 percent by weight of a conventional
anti-caking agent is added to assist in the bulk storage of the
weighting materials.
[0061] The particulate materials as described herein (i.e., the
coated and/or uncoated micronized weighting agents) may be added to
a wellbore fluid as a weighting agent in a dry form or concentrated
as slurry in either an aqueous medium or as an organic liquid.
[0062] As is known, an organic liquid should have the necessary
environmental characteristics required for additives to oil-based
drilling fluids. With this in mind, the oleaginous fluid may have a
kinematic viscosity of less than 10 centistokes (10 mm.sup.2/s) at
40.degree. C. and, for safety reasons, a flash point of greater
than 60.degree. C. Suitable oleaginous liquids are, for example,
diesel oil, mineral or white oils, n-alkanes or synthetic oils such
as alpha-olefin oils, ester oils, mixtures of these fluids, as well
as other similar fluids known to one of skill in the art of
drilling or other wellbore fluid formulation. In one embodiment the
desired particle size distribution is achieved via wet milling of
the courser materials in the desired carrier fluid.
[0063] Wellbore Fluid Formulations.
[0064] In accordance with one embodiment, the micronized weighting
agent may be used in a wellbore fluid formulation. The wellbore
fluid may be a water-based fluid, an invert emulsion, or an
oil-based fluid.
[0065] Water-based wellbore fluids may have an aqueous fluid as the
base fluid and a micronized weighting agent. The aqueous fluid may
include at least one of fresh water, sea water, brine, mixtures of
water and water-soluble organic compounds and mixtures thereof. For
example, the aqueous fluid may be formulated with mixtures of
desired salts in fresh water. Such salts may include, but are not
limited to alkali metal chlorides, hydroxides, or carboxylates, for
example. In various embodiments of the drilling fluid disclosed
herein, the brine may include seawater, aqueous solutions wherein
the salt concentration is less than that of sea water, or aqueous
solutions wherein the salt concentration is greater than that of
sea water. Salts that may be found in seawater include, but are not
limited to, sodium, calcium, aluminum, magnesium, potassium,
strontium, and lithium, salts of chlorides, bromides, carbonates,
iodides, chlorates, bromates, formates, nitrates, oxides,
phosphates, sulfates, silicates, and fluorides. Salts that may be
incorporated in a brine include any one or more of those present in
natural seawater or any other organic or inorganic dissolved salts.
Additionally, brines that may be used in the drilling fluids
disclosed herein may be natural or synthetic, with synthetic brines
tending to be much simpler in constitution. In one embodiment, the
density of the drilling fluid may be controlled by increasing the
salt concentration in the brine (up to saturation). In a particular
embodiment, a brine may include halide or carboxylate salts of
mono- or divalent cations of metals, such as cesium, potassium,
calcium, zinc, and/or sodium.
[0066] The oil-based/invert emulsion wellbore fluids may include an
oleaginous continuous phase, a non-oleaginous discontinuous phase,
and a micronized weighting agent. One of ordinary skill in the art
would appreciate that the micronized weighting agents described
above may be modified in accordance with the desired application.
For example, modifications may include the hydrophilic/hydrophobic
nature of the dispersant.
[0067] The oleaginous fluid may be a liquid, more preferably a
natural or synthetic oil, and more preferably the oleaginous fluid
is selected from the group including diesel oil; mineral oil; a
synthetic oil, such as hydrogenated and unhydrogenated olefins
including polyalpha olefins, linear and branch olefins and the
like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters
of fatty acids, specifically straight chain, branched and cyclical
alkyl ethers of fatty acids; similar compounds known to one of
skill in the art; and mixtures thereof. The concentration of the
oleaginous fluid should be sufficient so that an invert emulsion
forms and may be less than about 99% by volume of the invert
emulsion. In one embodiment, the amount of oleaginous fluid is from
about 30% to about 95% by volume and more preferably about 40% to
about 90% by volume of the invert emulsion fluid. The oleaginous
fluid, in one embodiment, may include at least 5% by volume of a
material selected from the group including esters, ethers, acetals,
dialkylearbonates, hydrocarbons, and combinations thereof.
[0068] The non-oleaginous fluid used in the formulation of the
invert emulsion fluid disclosed herein is a liquid and may be an
aqueous liquid. In one embodiment, the non-oleaginous liquid may be
selected from the group including sea water, a brine containing
organic and/or inorganic dissolved salts, liquids containing
water-miscible organic compounds, and combinations thereof. The
amount of the non-oleaginous fluid is typically less than the
theoretical limit needed for forming an invert emulsion. Thus, in
one embodiment, the amount of non-oleaginous fluid is less that
about 70% by volume, and preferably from about 1% to about 70% by
volume. In another embodiment, the non-oleaginous fluid is
preferably from about 5% to about 60% by volume of the invert
emulsion fluid. The fluid phase may include either an aqueous fluid
or an oleaginous fluid, or mixtures thereof. In a particular
embodiment, coated barite or other micronized weighting agents may
be included in a wellbore fluid having an aqueous fluid that
includes at least one of fresh water, sea water, brine, and
combinations thereof.
[0069] Conventional methods may be used to prepare the wellbore
fluids disclosed herein in a manner analogous to those normally
used, to prepare conventional water- and oil-based fluids. In one
embodiment, a desired quantity of water-based fluid and a suitable
amount of one or more micronized weighting agents, as described
above, are mixed together and the remaining components of the
drilling fluid added sequentially with continuous mixing. In
another embodiment, a desired quantity of oleaginous fluid such as
a base oil, a non-oleaginous fluid, and a suitable amount of one or
more micronized weighting agents are mixed together and the
remaining components are added sequentially with continuous mixing.
An invert emulsion may be formed by vigorously agitating, mixing,
or shearing the oleaginous fluid and the non-oleaginous fluid.
[0070] Other additives that may be included in the wellbore fluids
disclosed herein include, for example, wetting agents, organophilic
clays, viscosifiers, fluid loss control agents, surfactants,
dispersants, interfacial tension reducers, pH buffers, mutual
solvents, thinners, thinning agents, and cleaning agents. The
addition of such agents should be well known to one of ordinary
skill in the art of formulating wellbore fluids and muds.
EXAMPLE
[0071] One field example where such an invert emulsion wellbore
fluid was used for a cement displacement operation included a
barite weighting agent with a d.sub.90 of <5 microns. Table 1
below shows the fluid formulations.
TABLE-US-00001 TABLE 1 Drilling Displacement Fluid Fluid FLUID
PROPERTIES Density, lb/gal 12.85 12.90 Oil/Water Ratio 76/24 75/25
Plastic Viscosity (cps) 46 27 Yield Point (lbs/100 ft.sup.2) 21 2 6
rpm 11 1 10 sec/10 min Gel Strengths 13/21 2/4 FLUID FORMULATION
Base Fluid (bbls) 0.56 0.56 CaCl.sub.2 Brine 0.21 0.21 Primary
Emulsifier (lb/bbl) 3.5 3.5 Secondary Emulsifier (lb/bbl) 4.0 4.0
Viscosifier (lb/bbl) 5.0 2.5 Lime 6.0 6.0 Fluid Loss Additive
(lb/bbl) 6.0 6.0 API Grade Barite (lb/bbl) 275 0.0 Micronised
weighting agent (lb/bbl) 0.0 275
[0072] A well was drilled and a liner string ran with an outside
diameter was 51/2'' into a faulted, depleted reservoir with a
narrow pore pressure window prior to a cement operation. Without
displacing the existing oil base drilling fluid, an estimated ECD
of 14.78 at 160 gal/min, which while close to the 14.81 lb/gal
upper ECD limit, would be too slow to place the cement slurry,
increasing the likelihood that cement slurry would begin to thicken
before displacement into annulus was complete. Thus, the existing
drilling fluid was displaced with a micronized barite fluid prior
to pumping the cement slurry. The ECD of the micronized weighting
agent fluid resulted in a displacement flow rate of 160 gal/min and
a lower ECD of 14.1 allowing (use of and further below the ECD
ceiling) a higher pump rate of 250 gal/min, which gives an ECD of
14.65 lb/gal, and no observable fluid losses to the formation.
Thus, use of the micronized displacement fluid allowed for keeping
the ECD at a manageable level without viscosity settling prior to
completion of the cementing operation, and without any measurable
losses of the wellbore displacement fluid to the formation.
[0073] Advantageously, embodiments of the present disclosure
provide for one or more of the following: reduced risk of weighting
agent sag or settlement; improved ability to formulate thin fluids
for reduced pumping pressures; improved ECD control; improved
cement job quality. In cement displacement, the reduction in
annular space generally leads to increased ECD. The fluids of the
present disclosure may possess Theological properties such that
increases in viscosity (and thus ECD) may be minimized while also
allowing for reduction in sag and particle settlement. Further, by
controlling ECD, bottomhole pressures, and thus, wellbore
stability, may be controlled. Additionally, the fluids of the
present disclose may advantageously allow for lower frictional
pressures with less risk of fluid losses where pressures are close
to the fracture pressure, thus resulting in higher flow rates for
turbulent flow placement, and less pumping time required for
placing the cement slurry in the annulus, thereby reducing the risk
of the cement slurry prematurely hardening during cementing
operations.
[0074] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of this disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the invention
as disclosed herein. Accordingly, the scope of the invention should
be limited only by the attached claims.
* * * * *