U.S. patent application number 14/347553 was filed with the patent office on 2014-08-21 for drill cuttings re-injection.
The applicant listed for this patent is Shannon K. Stocks, Ramesh Varadaraj. Invention is credited to Shannon K. Stocks, Ramesh Varadaraj.
Application Number | 20140231084 14/347553 |
Document ID | / |
Family ID | 48290441 |
Filed Date | 2014-08-21 |
United States Patent
Application |
20140231084 |
Kind Code |
A1 |
Varadaraj; Ramesh ; et
al. |
August 21, 2014 |
Drill Cuttings Re-Injection
Abstract
A method for re-injecting formation solids into a subsurface
formation includes obtaining a volume of solid particles from
drilling returns, and then obtaining an aqueous operations fluid
comprising at least one surfactant. Mixing a volume of the
operations fluid with the volume of solid particles to form a
slurry which is injected into a disposal well which includes a NAF
filter cake. Then injecting the slurry into one or more fractures
formed in the subsurface formation such that the slurry contacts
the NAF filter cake en route to the one or more fractures.
Inventors: |
Varadaraj; Ramesh;
(Bartlesville, OK) ; Stocks; Shannon K.; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Varadaraj; Ramesh
Stocks; Shannon K. |
Bartlesville
Houston |
OK
TX |
US
US |
|
|
Family ID: |
48290441 |
Appl. No.: |
14/347553 |
Filed: |
September 13, 2012 |
PCT Filed: |
September 13, 2012 |
PCT NO: |
PCT/US12/55201 |
371 Date: |
March 26, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61557764 |
Nov 9, 2011 |
|
|
|
Current U.S.
Class: |
166/278 |
Current CPC
Class: |
E21B 41/0057 20130101;
E21B 43/40 20130101; E21B 21/066 20130101 |
Class at
Publication: |
166/278 |
International
Class: |
E21B 43/40 20060101
E21B043/40 |
Claims
1. A method for re-injecting drill cuttings into a subsurface
formation, comprising: obtaining a volume of solid particles from
drilling returns; obtaining an aqueous operations fluid comprising
at least one surfactant; mixing a volume of the operations fluid
with the volume of solid particles, thereby forming a slurry;
pumping the slurry into a disposal well, wherein the disposal well
includes a NAF filter cake; injecting the slurry into one or more
fractures formed in the subsurface formation such that the slurry
contacts the NAF filter cake en route to the one or more
fractures.
2. The method of claim 1, wherein the surfactant is an alkyl acid
surfactant, an organo-anionic surfactant, or mixtures thereof.
3. The method of claim 2, wherein the organo-anionic surfactant has
the general formula: {R--X}.sup.-+{Y} wherein: R is selected from
the group comprising linear and branched alkyl and aryl alkyl
hydrocarbon chains, X is an acid, and Y is an organic amine.
4. The method of claim 3, wherein X is selected from the group
comprising sulfonic acids, carboxylic acids, phosphoric acids, and
mixtures thereof.
5. The method of claim 3, wherein Y is selected from the group
comprising monoethanol amine, di-ethanol amine, tri-ethanol amine,
ethylene di-amine, propylene diamine, di-ethylene tri-amine,
tri-ethylene tetra-amine, tetra ethylene pent-amine, di-propylene
tri-amine, tri-propylene tetra-amine, tetra-propylene pentamine,
and mixtures thereof.
6. The method of claim 3, wherein the organo-anionic surfactant is
selected from the group comprising monoethanol ammonium alkyl
aromatic sulfonic acid, monoethanol ammonium alkyl carboxylic acid,
and mixtures thereof.
7. The method of claim 2, wherein the alkyl acid surfactant has the
general formula: {S--Z} wherein: S is selected from the group
comprising linear and branched alkyl and aryl alkyl hydrocarbon
chains of 8 to 24 carbons, and Z is an acid group selected from the
group comprising sulfonic acids, carboxylic acids, phosphoric
acids, and mixtures thereof.
8. The method of claim 1, wherein the operations fluid comprises
surfactant present in solution at a concentration greater than
about 0.01 wt % and less than about 20.0 wt % based on water in the
operations fluid.
9. The method of claim 1, wherein: the operation fluid further
comprises dissolved salts; and the concentration of dissolved salts
is greater than about 0.1 wt % and less than about 25.0 wt % based
on the weight of water in the aqueous fluid.
10. The method of claim 9, wherein the dissolved salts comprise (i)
chloride salt of calcium, (ii) chloride salt of potassium, (iii)
sulfate salt of calcium, (iv) sulfate salt of potassium, and (v)
combinations thereof.
11. The method of claim 1, wherein: the operation fluid further
comprises an alcohol; and the concentration of alcohol is greater
than about 0.001 wt % and less than about 15.0 wt % based on the
weight of water in the aqueous fluid.
12. The method of claim 11, wherein the alcohol comprise methanol,
ethanol, propanol, butanol, pentanol, hexanol, heptanol, octanol,
and combinations thereof.
13. The method of claim 1, further comprising: pumping a volume of
the aqueous operations fluid into the disposal well without the
slurry prior to pumping the slurry into the disposal well.
14. The method of claim 1, wherein the surfactant is comprised
substantially of a weak acid and a weak base.
15. A method for re-injecting drill cuttings into a subsurface
formation, comprising: obtaining a volume of solid particles from
drilling returns; obtaining an aqueous operations fluid comprising
at least one surfactant; pumping a volume of the aqueous operations
fluid into a disposal well in order to remediate a NAF filter cake
residing alone a borehole of the disposal well; preparing a slurry
of aqueous fluid with the volume of solid particles; pumping the
slurry into the disposal well, wherein the disposal well includes a
NAF filter cake; injecting the slurry into one or more fractures
formed in the subsurface formation.
16. The method of claim 16, wherein the surfactant is an alkyl acid
surfactant, an organo-anionic surfactant, or mixtures thereof.
17. The method of claim 16, wherein preparing a slurry of aqueous
fluid with the volume of solid particles comprises mixing a portion
of the operations fluid with the volume of solid particles.
18. The method of claim 16, wherein the organo-anionic surfactant
has the general formula: {R--X}.sup.-+{Y} wherein: R is selected
from the group comprising linear and branched alkyl and aryl alkyl
hydrocarbon chains, X is an acid, and Y is an organic amine.
19. The method of claim 18, wherein X is selected from the group
comprising sulfonic acids, carboxylic acids, phosphoric acids, and
mixtures thereof.
20. The method of claim 18, wherein Y is selected from the group
comprising monoethanol amine, di-ethanol amine, tri-ethanol amine,
ethylene di-amine, propylene diamine, di-ethylene tri-amine,
tri-ethylene tetra-amine, tetra ethylene pent-amine, di-propylene
tri-amine, tri-propylene tetra-amine, tetra-propylene pentamine,
and mixtures thereof.
21. The method of claim 18, wherein the organo-anionic surfactant
is selected from the group comprising monoethanol ammonium alkyl
aromatic sulfonic acid, monoethanol ammonium alkyl carboxylic acid,
and mixtures thereof.
22. The method of claim 16, wherein the alkyl acid surfactant has
the general formula: {S--Z} wherein: S is selected from the group
comprising linear and branched alkyl and aryl alkyl hydrocarbon
chains of 8 to 24 carbons, and Z is an acid group selected from the
group comprising sulfonic acids, carboxylic acids, phosphoric
acids, and mixtures thereof.
23. The method of claim 15, wherein the operations fluid comprises
surfactant present in solution at a concentration greater than
about 0.01 wt % and less than about 20.0 wt % based on water in the
operations fluid.
24. The method of claim 15, wherein the surfactant is comprised
substantially of a weak acid and a weak base.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional No.
61/557,764, filed Nov. 9, 2011.
BACKGROUND OF THE INVENTION
[0002] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present disclosure. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present disclosure. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
FIELD OF THE INVENTION
[0003] This invention relates generally to the field of wellbore
operations. More specifically, the invention relates to the
re-injection of drill cuttings and solids generated during the
formation of a wellbore.
GENERAL DISCUSSION OF TECHNOLOGY
[0004] In the drilling of oil and gas wells, a wellbore is formed
using a drill bit that is urged downwardly at a lower end of a
drill string. The drill bit is rotated against a rock face in order
to form a cylindrical borehole in the subsurface. During most
drilling processes, the drill string is rotated from the surface,
thereby imparting rotational movement to the drill bit downhole. In
some processes, a downhole motor is provided for rotating the drill
bit.
[0005] During the drilling process, a drilling fluid, or "mud," is
circulated through the drill string. The mud is forced downwardly
through the drill string, out ports in or near the drill bit, and
back up to the surface through an annular area formed between the
joints of drill pipe and the surrounding subsurface formation. The
process of rotating the drill bit and circulating mud causes the
subsurface rock to be cut and eroded at ever-increasing depths as
the wellbore is formed. As a result, pieces of formation are
dislodged from the earth and carried up to the surface. These
pieces represent bits of sand, clay, shale, quartz, or other rock,
which are collectively referred to in the industry as
"cuttings."
[0006] Typically, the drill cuttings are circulated back to the
surface and then separated from the drilling fluid using solids
control equipment. The solids control equipment will include
screens or so-called "shakers" that filter out the majority of
solids while releasing the drilling mud. Samples of the cuttings
may be captured where they are logged for correlated depth, and
then analyzed. However, the majority of the cuttings are simply
disposed of while the reclaimed drilling fluid is re-circulated
into the drill string.
[0007] The disposal of drill cuttings and other solid wastes
generated by drilling operations has come under scrutiny.
Specifically, environmental regulations in some areas prevent the
disposal of drill cuttings, especially when such cuttings contain
residual non-aqueous fluids, or NAF's. Moreover, environmental
policies of some operators' may require the cleaning of cuttings or
other special handling before disposal. Accordingly, drilling
companies have begun using a re-injection procedure for some
drilling operations.
[0008] Cuttings re-injection operations, or "CRI," generally
started in the late 1980's. A drill-cuttings injection operation
involves the collection of materials from solids-control equipment
on the rig, and transportation of the materials to a slurrification
unit. Frequently, the cuttings are ground into small particles in
the presence of water to form the slurry. The slurry is then
transferred to a holding tank for final rheological conditioning.
The conditioned drill cuttings slurry is pumped through a casing
annulus or a string of tubing in a well. The well may be a
specially-formed disposal well. The cuttings slurry is then pumped
into subsurface fractures created by injecting the slurry under
high pressure into a disposal formation.
[0009] The injection (or re-injection) of drill cuttings offers an
attractive solution to the disposal of cuttings from a drilling
operation. In this respect, CRI can achieve minimal discharge of
solids, as even the wastes generated from a re-injection operation
are returned to the subsurface. Additionally, there are no future
cleanup liabilities once the disposal well is plugged. For offshore
operations in areas with environmental restrictions for the
disposal of cuttings, and where large volumes of cuttings are
generated, re-injection offers an economically attractive option
compared to the transportation of cuttings onshore, or extensive
de-oiling or other treatment.
[0010] As one might anticipate, various challenges exist with
respect to CRI. Perhaps the most important is the slurry rheology
design. Slurry rheology design includes slurry viscosity,
suspension capacity, and particle size limitations. The slurry must
have adequate viscosity and solids-carrying capacity to transport
the particles into the formation. Further, the particles must be
able to enter the fractures to avoid plugging, either along the
wellbore or in the fracture.
[0011] Another challenge relates to the presence of filter cake.
During a drilling process, the drilling fluid is placed in the bore
of the drill string. The drilling fluid increases the hydrostatic
pressure at the bottom of the wellbore. This, in turn, controls the
flow of formation fluids into the wellbore. The drilling mud also
helps to keep the drill bit cool and clean during drilling. In
addition, the viscous drilling mud helps to carry the drill
cuttings away from the rock face and up to the surface for analysis
and/or disposal, as noted above.
[0012] An additional function of the drilling mud is to leave a
filter cake along the wall of the wellbore. In this respect, as a
wellbore is drilled through a permeable, hydrocarbon-bearing
formation, the drilling mud will form a "filter cake." The filter
cake helps to prevent fluid leak-off into a formation during
drilling, and also helps to maintain wellbore stability. At the
same time, the filter cake creates at least a partial barrier to
the injection of solid drill cuttings into a disposal formation. In
this respect, the filter cake particles can reduce permeability of
the rock in the near-wellbore region. This is particularly true
with respect to filter cakes formed from a non-aqueous fluid (NAF),
such as an oil-based or synthetic oil-based drilling mud.
[0013] A need exists for an improved method of re-injecting drill
cuttings into a disposal formation. Further, a need exists for an
improved method of re-injecting cuttings through a wellbore having
a filter cake, wherein the method uses a slurry that also
remediates a filter cake having NAF fluids therein.
SUMMARY OF THE INVENTION
[0014] The methods described herein have various benefits in the
conducting of oil and gas exploration and production
activities.
[0015] A method for re-injecting drill cuttings into a subsurface
formation is first provided. In one embodiment, the method first
includes obtaining a volume of solid particles from drilling
returns. The solid particles primarily represent formation
cuttings.
[0016] The method then includes obtaining an aqueous operations
fluid comprising at least one surfactant. The operations fluid
preferably comprises surfactant present in solution at a
concentration greater than about 0.01 wt % and less than about 20.0
wt % based on water in the operations fluid.
[0017] In the present methods, the surfactant may be made up of a
weak acid, a weak base, or both. In one aspect, the surfactant is
an alkyl acid surfactant, an organo-anionic surfactant, or mixtures
thereof. Where the surfactant is or includes an organo-anionic
surfactant, the organo-ionic surfactant is preferably selected from
the group comprising monoethanol ammonium alkyl aromatic sulfonic
acid, monoethanol ammonium alkyl carboxylic acid, and mixtures
thereof.
[0018] The operations fluid may be injected into the borehole of a
disposal well in order to remediate a NAF filter cake along the
borehole. Preferably, the method also includes mixing a volume of
the operations fluid with the volume of solid particles to form an
operations fluid slurry. The method then includes pumping the
slurry into the disposal well.
[0019] The method further includes injecting the slurry into one or
more fractures formed in the subsurface formation. Injection is
conducted in such a manner that the slurry contacts the NAF filter
cake en route to the one or more fractures. Because of the weak
base--weak acid formulation of the slurry, the NAF filter cake is
degraded, thereby facilitating the injection of the slurry into
fractures along the wellbore.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] So that the present inventions can be better understood,
certain drawings, charts, graphs and/or flow charts are appended
hereto. It is to be noted, however, that the drawings illustrate
only selected embodiments of the inventions and are therefore not
to be considered limiting of scope, for the inventions may admit to
other equally effective embodiments and applications.
[0021] FIG. 1 presents a side view of a well site wherein a well is
being completed. Known surface equipment is provided to support
wellbore tools (not shown) above and within a wellbore. The well is
a disposal well for the injection of drill cuttings.
[0022] FIG. 2 is a flow chart showing steps for a method of
re-injecting drill cuttings, in one embodiment.
[0023] FIG. 3 is a flow chart showing steps for a method of
re-injecting drill cuttings, in an alternate embodiment.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
[0024] For purposes of the present application, it will be
understood that the term "hydrocarbon" refers to an organic
compound that includes primarily, if not exclusively, the elements
hydrogen and carbon. Hydrocarbons may also include other elements,
such as, but not limited to, halogens, metallic elements, nitrogen,
oxygen, and/or sulfur. Hydrocarbons generally fall into two
classes: aliphatic, or straight chain hydrocarbons, and cyclic, or
closed ring hydrocarbons, including cyclic terpenes. Examples of
hydrocarbon-containing materials include any form of natural gas,
oil, coal, and bitumen that can be used as a fuel or upgraded into
a fuel.
[0025] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids.
For example, hydrocarbon fluids may include a hydrocarbon or
mixtures of hydrocarbons that are gases or liquids at formation
conditions, at processing conditions or at ambient conditions
(15.degree. C. and 1 atm pressure). Hydrocarbon fluids may include,
for example, oil, natural gas, coalbed methane, shale oil,
pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and
other hydrocarbons that are in a gaseous or liquid state.
[0026] As used herein, the terms "produced fluids" and "production
fluids" refer to liquids and/or gases removed from a subsurface
formation, including, for example, an organic-rich rock formation.
Produced fluids may include both hydrocarbon fluids and
non-hydrocarbon fluids. Production fluids may include, but are not
limited to, oil, natural gas, pyrolyzed shale oil, synthesis gas, a
pyrolysis product of coal, carbon dioxide, hydrogen sulfide and
water (including steam).
[0027] As used herein, the term "fluid" refers to gases, liquids,
and combinations of gases and liquids, as well as to combinations
of gases and solids, combinations of liquids and solids, and
combinations of gases, liquids, and solids.
[0028] As used herein, the term "gas" refers to a fluid that is in
its vapor phase at 1 atm and 15.degree. C.
[0029] As used herein, the term "oil" refers to a hydrocarbon fluid
containing primarily a mixture of condensable hydrocarbons.
[0030] As used herein, the term "subsurface" refers to geologic
strata occurring below the earth's surface.
[0031] As used herein, the term "formation" refers to any definable
subsurface region regardless of size. The formation may contain one
or more hydrocarbon-containing layers, one or more non-hydrocarbon
containing layers, an overburden, and/or an underburden of any
geologic formation. A formation can refer to a single set of
related geologic strata of a specific rock type, or to a set of
geologic strata of different rock types that contribute to or are
encountered in, for example, without limitation, (i) the creation,
generation and/or entrapment of hydrocarbons or minerals, and (ii)
the execution of processes used to extract hydrocarbons or minerals
from the subsurface.
[0032] The terms "zone" or "zone of interest" refers to a portion
of a formation containing hydrocarbons. Alternatively, the
formation may be a water-bearing interval.
[0033] For purposes of the present patent, the term "production
casing" includes a liner string or any other tubular body fixed in
a wellbore along a zone of interest.
[0034] As used herein, the term "drilling returns" means a slurry
containing a liquid and a solid, wherein the slurry includes drill
cuttings from a subsurface formation.
[0035] As used herein, the term "wellbore" refers to a hole in the
subsurface made by drilling or insertion of a conduit into the
subsurface. A wellbore may have a substantially circular cross
section, or other cross-sectional shapes. As used herein, the term
"well," when referring to an opening in the formation, may be used
interchangeably with the term "wellbore."
DESCRIPTION OF SELECTED SPECIFIC EMBODIMENTS
[0036] The inventions are described herein in connection with
certain specific embodiments. However, to the extent that the
following detailed description is specific to a particular
embodiment or a particular use, such is intended to be illustrative
only and is not to be construed as limiting the scope of the
inventions.
[0037] FIG. 1 presents a side view of a well site 100 wherein a
well is being completed. The well is a disposal well for the
injection of drill cuttings.
[0038] The well site 100 generally includes a wellbore 150 and a
wellhead 170. The wellbore 150 includes a bore 115 for receiving
drilling equipment and fluids. The bore 115 extends from the
surface 105 of the earth, and into the earth's subsurface 110. The
wellbore 150 is being completed in a subsurface formation,
indicated by bracket 160.
[0039] The wellbore 150 is first formed with a string of surface
casing 120. The surface casing 120 has an upper end 122 in sealed
connection with a lower master fracture valve 125. The surface
casing 120 also has a lower end 124. The surface casing 120 is
secured in the wellbore 150 with a surrounding cement sheath
112.
[0040] The wellbore 150 also includes a lower string of casing 130.
The lower string of casing 130 is also secured in the wellbore 150
with a surrounding cement sheath 114. The lower string of casing
130 has an upper end 132 in sealed connection with an upper master
fracture valve 135. The lower string of casing 130 also has a lower
end 134.
[0041] In the well site 100 of FIG. 1, the lower string of casing
130 does not extend to a bottom 136 of the wellbore 150. Instead, a
lower portion of the wellbore 150 is left uncased. In this way, the
wellbore 150 is completed as an open-hole, particularly along the
subsurface formation 160. However, it is understood that the
wellbore 150 could be completed as a cased hole. In this instance,
the lower string of casing 130 would be a string of "production
casing" that extends to the bottom 136 of the wellbore 150. In that
instance, the casing would be perforated to allow for fluid
communication between the bore 115 of the wellbore 150 and the
subsurface formation 160.
[0042] It is understood that the depth of the wellbore 150 may
extend many thousands of feet below the earth surface 105. In this
way, the subsurface formation 160 may be fractured without concern
over creating fluid communication with any near-surface
aquifers.
[0043] As noted, the well site 100 also includes a wellhead 170.
The wellhead 170 is used during the completion phase of the
wellbore 150. The wellhead 170 includes one or more blow-out
preventers. The blow-out preventers are typically remotely actuated
in the event of operational upsets. In more shallow wells, or in
wells having lower formation pressures, the master fracture valves
125, 135 may be the blow-out preventers. In either event, the
master fracture valves 125, 135 are used to selectively seal the
bore 115.
[0044] The wellhead 170 and its components are used for flow
control and hydraulic isolation during rig-up operations, during
fracturing and fluid injecting operations, and during rig-down
operations. The wellhead 170 may include a crown valve 172. The
crown valve 172 is used to isolate the wellbore 150 in the event a
lubricator (not shown) or other components are placed above the
wellhead 170. The wellhead 170 further includes side outlet
injection valves 174. The side outlet injection valves 174 are
located within fluid injection lines 171. The fluid injection lines
171 provide a means for the injection of fracturing fluids,
weighting fluids, and/or drill cuttings slurry into the bore 115,
with the injection of the fluids being controlled by the valves
174.
[0045] The piping from surface pumps (not shown) and tanks (not
shown) used for injection of fluids are in fluid communication with
the valves 174. Appropriate hoses, fittings and/or couplings (not
shown) are employed. The fluids are then pumped into the lower
string of casing 130 and the open-hole portion of the wellbore 150,
adjacent subsurface formation 160.
[0046] It is understood that the various wellhead components shown
in FIG. 1 are merely illustrative. A typical completion operation
will include numerous valves, pipes, tanks, fittings, couplings,
gauges, and other fluid control devices. These may include a
pressure-equalization line and a pressure-equalization valve (not
shown) for positioning a tool string above the lower valve 125
before a tool string is dropped into the bore 115. Downhole
equipment may be run into and out of the wellbore 150 using an
electric line, slick line or coiled tubing. Further, a drilling rig
or other platform may be employed, with jointed working tubes or
coiled tubing being used as needed.
[0047] The wellbore 150 has been formed through the use of a drill
string and connected drill bit (not shown). Further, the drilling
process involved the use of a drilling fluid, or mud.
[0048] There are three main categories of drilling fluids:
water-based muds, non-aqueous muds, and gaseous drilling fluids.
Non-aqueous muds, sometimes referred to as non-aqueous fluids
(NAFs), are muds where the base fluid is an oil. Environmental
considerations aside, NAFs are often preferred over water-based
muds and gaseous drilling fluids, as NAFs generally offer increased
lubrication of the drill string and drill bit. This is particularly
advantageous in deviated and horizontal drilling operations where
the drill string is forced to slide within and rotate upon the
wellbore wall. In this situation, the non-aqueous-based fluid
provides a slick film along which tubular bodies and equipment may
glide while moving across non-vertical portions of the
wellbore.
[0049] NAFs also help stabilize shale formations more effectively
than do water-based or gaseous muds. NAFs also withstand greater
heat without breaking down, and beneficially tend to form a thinner
filter cake than water-based muds.
[0050] The filter cake from a NAF is comprised primarily of water
droplets, weighting agent particles, and drilled cuttings
previously suspended in the drilling mud. The filter cake forms a
thin, low-permeability layer along permeable portions of the
borehole. Beneficially, the filter cake at least partially seals
permeable formations exposed by the bit. This helps prevent the
loss of the liquid portion (or filtrate) of the drilling fluids
into the formations during the wellbore forming process. The filter
cake also helps prevent the surrounding rock matrix from sloughing
into the wellbore. Of note, the drilling process can be ongoing for
days or even weeks.
[0051] A low-permeability filter cake is also desirable for running
completion equipment in the wellbore. For example, it is sometimes
desirable to run the completion hardware in a clear brine to
prevent solids plugging of a sand control screen. The filter cake
prevents the completion brine from rapidly leaking off to the
formation as the completion hardware is run. In addition, a
low-permeability filter cake helps prevent the gravel used in a
gravel pack from bridging off during gravel placement due to a loss
of hydration in the slurry.
[0052] In the well site 100 of FIG. 1, a filter cake is shown at
162. The filter cake lines a wall 164 of the open hole portion of
the wellbore 150 adjacent subsurface formation 160. The filter cake
comprises a NAF fluid.
[0053] There are two general categories of NAF fluids: oil-based
muds (OBMs) and synthetic-based muds (SBMs). A common example of a
base fluid for an OBM is diesel oil. SBMs use a synthetic oil
rather than a natural hydrocarbon as the base fluid. An example of
a base fluid for a SBM is palm oil. SBMs are most often used on
offshore rigs as SBMs have the beneficial properties of an OBM, but
lower toxicity. This is of benefit when the drilling crew is
working in an enclosed area, as may be the case on an offshore
drilling rig operating in an arctic environment.
[0054] The drilling fluid used for a particular job is generally
selected to avoid formation damage. For example, in various types
of shale formations, the use of conventional water-based muds can
result in a deterioration and collapse of the formation. Similarly,
muds made from fresh water can cause clays in a sandstone or other
type formation to swell and dislodge. This, in turn, can negatively
affect the permeability of the sandstone near the wellbore. The use
of an oil-based formulation circumvents these problems.
[0055] As noted, a conventional oil-based drilling mud formulation
is comprised basically of oil. Examples of oil include diesel oil
and mineral oil. An OBM may also include a thickener, or
"viscosification agent." Examples of viscosification agents are
amine-treated clays such as bentonite. Neutralized sulfonated
ionomers have also been proposed as viscosification agents. An OBM
may also include a wetting agent.
[0056] A NAF will also include a water phase. This typically
represents sodium chloride or calcium chloride brine. The NAF will
also then include a surfactant as an emulsifying agent. An example
of a surfactant is an alkaline soap of fatty acids. The surfactant
aids in blending the base oil with the brine and stabilizing the
continuous oil emulsion. Finally, a weighting agent may be used. An
example of a weighting agent is barite or barium sulfate.
[0057] An entire science has developed around producing beneficial
filter cake properties. Filter cake properties include cake
thickness, toughness, slickness, and permeability. Such properties
are important as the cake that forms on permeable regions of a
wellbore can be beneficial to an operation, or may be detrimental
to an operation. For example, the problems that a filter cake may
present include reduced permeability during production and/or
injection operations. This includes reduced permeability during a
drill cuttings re-injection operation.
[0058] Many publications and inventions have been directed to the
creation and destruction of filter cakes. Exemplary teachings known
in the art include the use of chelating agents to extract metallic
weighting agents from filter cakes, the use of acidic treatment
fluids to dissolve the filter cake elements, and/or the use of
surfactants to clean the filter cake from the surface of a
wellbore. Exemplary publications of such teachings may be found in
U.S. Pat. Publ. No. 2008/0110621, which is incorporated herein in
its entirety by reference. Other exemplary related publications may
be found in U.S. Pat. No. 5,909,774; U.S. Pat. No. 6,631,764; U.S.
Pat. No. 7,134,496; U.S. Pat. Publ. No. 2007/0029085, U.S. Pat.
Publ. No. 2008/0110618; and in Lirio Quintero, et al, Single-phase
Microemulsion Technology for Cleaning Oil or Synthetic-Based Mud,
2007 AADE National Technical Conference (Apr. 10-12, 2007).
[0059] As noted above, filter cakes formed from non-aqueous muds
tend to have a lower permeability. This is beneficial while the
wellbore is being formed; however, filter cakes formed from an
oil-based or synthetic oil-based drilling mud are more difficult to
remediate. While the decreased permeability of NAF filter cakes may
suggest using aqueous drilling fluids to avoid the NAF filter cake,
some implementations require NAF drilling fluids. This, in turn,
may complicate the remediation of the filter cake, often
necessitating complex treatment fluids. While known solutions
provide some level of remediation, the conventional approaches are
costly and complex. Accordingly, a need exists for an improved
method for remediating NAF filter cake, particularly for the
purpose of improving drill cuttings re-injection operations.
[0060] Returning to FIG. 1, fractures 165 are shown extending away
from the wall 164 of the wellbore 150. The fractures 165 have been
formed by injecting drill cuttings as part of a slurry. The
fractures extend through the filter cake 162.
[0061] It is proposed herein to remediate the NAF filter cake 162
prior to or during the injection of drill cuttings. The operations
fluid includes a base aqueous fluid having at least one surfactant.
The base aqueous fluid is referred to herein as an operations
fluid. The surfactant is preferably an alkyl acid surfactant, an
organo-anionic surfactant, or mixtures thereof.
[0062] It is recognized here that surfactants, in the generalized
sense of the term, have been used in hydrocarbon recovery
operations for a variety of purposes. Indeed, drilling fluids
themselves oftentimes have a surfactant component. Surfactants have
also been used for cleaning filter cake and drilling fluids off of
downhole equipment. However, a review of the conventional
compositions and methods reveals that for drilling fluid
remediation methods, the cleaning fluid has employed either a
strong acid or a strong base.
[0063] The use of a strong acid provides the foundation for
acid-based remediation efforts. Strong acids include sulfuric acids
and hydrochloric acids. The use of strong bases, such as in the
form of cationic surfactants, zwitterionic surfactants, and/or
alkali-metal-based surfactants, form the foundation for
conventional surfactant-based remediation efforts.
[0064] Conventional surfactants typically are formed from a strong
base and a weak acid (i.e., a strong/weak surfactant). When using
such a surfactant, a remediation fluid will typically require a
co-solvent, such as an alcohol, to improve the solubility of the
strong/weak surfactant. This is particularly true in high-salinity
slurries or muds. However, the use of a co-solvent increases the
cost of the slurry, increases the complexity of the fluid make-up,
and requires additional clean-up efforts.
[0065] It is also noted that many of the conventional, strong/weak
anionic surfactants require the use of a co-surfactant. Examples of
a co-surfactant are a non-ionic surfactant or a cationic
surfactant. Adding a co-surfactant forms a micro-emulsion or
nano-emulsion. Here again, the use of a co-surfactant increases
costs, complexity, and clean-up requirements.
[0066] The conventional wisdom of surfactant-based remediation
compositions and methods is analogous to cleaning methods in other
fields, where it is generally accepted that a strong base cleans
better than a weak base, and that a surfactant incorporating a
strong base will be most effective at cleaning. In contrast,
organo-anionic surfactants are formed by a weak base and a weak
acid, forming what can be referred to as a weak/weak surfactant or,
in the terms of the present disclosure, an organo-anionic
surfactant. The use of a weak base as the building block for a
filter cake remediation fluid is counter-intuitive based upon the
prior literature and conventional technology, but has been found to
be effective as a remediation fluid, as will be seen herein.
[0067] Weak acids and bases generally fall within the intermediate
pH range. The pH of a solution depends on both the concentration
and the degree of ionization. Weak acids and weak bases are only
partially ionized in their solutions.
[0068] In one embodiment, the surfactant is an alkyl acid
surfactant having the general formula:
{S--Z}
[0069] wherein: [0070] S is selected from the group comprising
linear and branched alkyl and aryl alkyl hydrocarbon chains of 8 to
24 carbons, and [0071] Z is an acid group selected from the group
comprising sulfonic acids, carboxylic acids, phosphoric acids, and
mixtures thereof.
[0072] Preferably, S is an aryl alkyl hydrocarbon chain.
Preferably, the aryl group of the aryl alkyl hydrocarbon is a
1-ring or 2-ring aromatic group. More preferably, the aryl group is
a 1-ring aromatic group. Non-limiting examples of 1-ring aromatic
groups are benzene and xylene. Non-limiting examples of an alkyl
aromatic hydrocarbon chain is dodecyl benzene, decyl xylene and
decyl benzene.
[0073] Preferably, Z is a sulfonic acid group. However, the acid
may be an organic acid, such as alkyl acids, alkyl aromatic acids,
or mixtures thereof. Further, exemplary organic acids may include
alkyl carboxylic acids, aromatic carboxylic acids, alkyl sulfonic
acids, aromatic sulfonic acids, alkyl phosphoric acids, aromatic
phosphoric acids, or mixtures thereof, forming a weak acid.
[0074] In another embodiment, the surfactant is an organo-anionic
surfactant having the general formula:
{R--X}.sup.-+{Y}
[0075] wherein: [0076] R is selected from the group comprising
linear and branched alkyl and aryl alkyl hydrocarbon chains, [0077]
X is an acid selected from the group comprising sulfonic acids,
carboxylic acids, phosphoric acids, and mixtures thereof, and
[0078] Y is an organic amine selected from the group comprising
monoethanol amine, di-ethanol amine, tri-ethanol amine, ethylene
di-amine, propylene diamine, di-ethylene tri-amine, tri-ethylene
tetra-amine, tetra ethylene pent-amine, di-propylene tri-amine,
tri-propylene tetra-amine, tetra-propylene pentamine, and mixtures
thereof.
[0079] While a variety of weak organic bases may be used in the
present compositions and methods, organic amines are preferred.
Preferably, the organic amine is monoethanol amine, diethanol
amine, triethanol amine, or mixtures thereof.
[0080] Based on the representative acids and bases described
herein, the number of available organo-anionic surfactants is
potentially very large. While a variety of organo-anionic
surfactants are within the scope of the present disclosure, they
all have one feature in common: the organo-anionic surfactants of
the present disclosure comprise an anionic acid whose counter ion
is a mono-, di-, or tri-ethanol ammonium cation.
[0081] Organo-anionic surfactants may be prepared by contacting a
weak acid, such as an organic acid or other acid described above,
with a weak base, such as an organic amine or other base described
above. Contacting can be done at any temperature, but preferably in
the range of -50.degree. C. to 200.degree. C. The preferred
temperature range for the acid-base reaction will depend on the
choice of weak acid and weak base.
[0082] The amount of base that is used in the reaction may be equal
to the molar equivalent of the weak or organic acid. As an
illustration, if the weak acid is an organic acid of molecular
weight 200, and the weak base is of molecular weight 100, then in
the case of molar equivalent, the weight ratio of base:acid is
2:1.
[0083] In some implementations, the organo-anionic surfactant may
be formed by contacting a neat base with a neat acid. The resulting
organo-anionic surfactant may then be incorporated into an aqueous
fluid. Additionally or alternatively, in some implementations, each
of the weak base and the weak base may be dissolved in separate
aqueous solutions that are then mixed to contact the base and the
acid to form the organo-anionic surfactant in an aqueous
solution.
[0084] The operations fluid can also contain mixtures of alkyl acid
surfactant and organo-anionic surfactant. Preferably, the
operations fluid contains a mixture of alkyl acid surfactants and
organo-anionic surfactants. When mixtures are used, the ratio of
alkyl acid surfactant to organo-anionic surfactant in the mixture
can vary from 99:1 to 1:99. The surfactant components are
preferably dissolved or dispersed in water. The operations fluid
then comprises mixtures of organo-anionic surfactants, alkyl acid
surfactants, and water.
[0085] The total surfactant concentration may be greater than about
0.01 wt % and less than about 20 wt %, based on the weight of
water. Preferably, the total concentration of surfactant may be
greater than about 0.01 wt % and less than about 10 wt %, and more
preferably the total surfactant concentration may be greater than
about 0.01 wt % and less than about 2 wt %.
[0086] The operations fluid including the organo-anionic
surfactants and alkyl acid surfactants may further comprise
dissolved salts, such as chloride and sulfate salts of calcium and
potassium. The amount of dissolved salts, when included, may be
greater than about 0.01 wt % and less than about 25 wt %, based on
the weight of water. Preferably, greater than about 0.01 wt % and
less than about 5 wt %. The operations fluid may further comprise
alcohols such as methanol, ethanol, propanol, butanol, pentanol,
hexanol, heptanol, octanol and mixtures thereof. The alcohols, when
included, may be greater than about 0.001 wt % and less than about
15 wt %, based on the weight of water.
[0087] As noted, it is proposed herein to inject drill cuttings as
part of a slurry, wherein the slurry includes an aqueous fluid
having at least one surfactant. The base aqueous fluid is referred
to as an operations fluid. One exemplary method of utilizing the
operations fluid is in a method of remediating a NAF filter cake in
a well prior to drill cuttings re-injection. An illustrative
implementation includes: [0088] obtaining an operations fluid
comprising at least one surfactant in water; [0089] pumping a
volume of the operations fluid into a well including a NAF filter
cake, wherein the volume of operations fluid is pumped to contact
the NAF filter cake; and [0090] thereafter, pumping a volume of
drill cuttings slurry. The slurry may include the operations
fluid.
[0091] The effectiveness of the drill cuttings injection operation
depends on the ability of the injected drill cuttings slurry to
filter through the formation face. The formation face may be
plugged by NAF filter cakes. If the operations fluid can remediate
the NAF filter cake, then the permeability of the near-wellbore
formation is increased. This, in turn, allows for rapid filtration
of the drill cuttings slurry into a disposal formation. More
specifically, a drill cuttings slurry may be injected through the
bore 115 of the well site 100, and into the fractures 165 in the
subsurface formation 160.
[0092] The following non-limiting example is an illustration of the
effectiveness of a surfactant-based operational fluid to remediate
a NAF filter cake.
[0093] First, a simulated drill cuttings base slurry was prepared.
The composition of the slurry is shown in Table 1, below.
TABLE-US-00001 TABLE 1 Component Quantity SBM-based fluid 52.5 ml
Simulated seawater 406 ml Simulated drill solids (Rev-Dust) 178
g
The SBM-based fluid may be, for example, XP-2. This is a Baroid
Halliburton.RTM. product, that is generally a n-paraffin based
fluid.
[0094] The slurry had a density (specific gravity) of 1.2 SG. An
oil/water/solids ratio of 10/75/15 (by volume) was provided.
[0095] Rheological properties were obtained for the base slurry
using a 6-speed, coaxial direct-indicating oilfield viscometer. The
viscometer used was a FANN 35 product. After obtaining rheological
properties of the base slurry at room temperature (25.degree. C.,
75.degree. F.), a xanthan gum-based biopolymer was added. An
example of a xanthan gum-based biopolymer is Greenbase.TM.
Flowzan.RTM. Biopolymer. The gum-based biopolymer was added to
obtain a viscosified simulated drill cuttings slurry.
[0096] Table 2 provides the viscosity data for the simulated drill
cuttings slurry.
TABLE-US-00002 TABLE 2 Fann 35 Dial Slurry + 2 lb/bbl GB Reading,
Flowzan (0.8 lb/bbl 25.degree. C., 75.degree. F. Base Slurry
active) 600 19 112 300 14 79 200 12 66 100 9 49 6 8 28 3 7 27 Gels
10/16/21 26/44/52 PV/YP 5/9 33/46
[0097] The viscosified simulated drill cuttings slurry was filtered
through a high temperature high pressure cell at ambient
temperature and 100 psi differential pressure. 8.6 ml of fluid
filtered through after 30 minutes. The resulting filter cake was
thin but very sticky and exhibited high shear stress. This was due
to the high concentration of simulated drill solids which made up
the injection slurry.
[0098] Next, a 1 wt % solution of a surfactant was made in water.
The surfactant was an alkyl acid surfactant having the general
formula:
{S--Z}
[0099] wherein: [0100] S is dodecyl benzene, and [0101] Z is
sulfonic acid.
[0102] This is one example of an operational fluid of the instant
invention. The S may actually be any compound selected from the
group comprising linear and branched alkyl and aryl alkyl
hydrocarbon chains of 8 to 24 carbons. The Z may be any acid
selected from the group comprising sulfonic acids, carboxylic
acids, phosphoric acids, or mixtures thereof.
[0103] To 1 gram of the filter cake was added 10 ml of the
operational fluid. The new solution was mixed for 20 seconds using
a magnetic stir bar. The filter cake was observed to immediately
break up. The break-up of the filter cake upon addition of the
operations fluid is evidence of NAF filter cake remediation of a
drill cuttings slurry.
[0104] FIG. 2 is a flow chart showing steps for a method 200 of
re-injecting drill cuttings, in one embodiment. The drill cuttings
are injected into a subsurface formation. An operations fluid
having at least one surfactant is used.
[0105] The method 200 first includes obtaining a volume of solid
particles from drilling returns. This is shown in Box 210. The term
"volume" is used merely to conveniently reflect broadly that a
quantity of cuttings has been obtained, regardless of whether such
quantity was obtained based upon mass, volume, randomly,
selectively, by type or whatever means is used to collect or obtain
such quantity. The method 200 then includes obtaining an aqueous
operations fluid comprising at least one surfactant. This is seen
in Box 220. The operations fluid preferably comprises surfactant
present in solution at a concentration greater than about 0.01 wt %
and less than about 20.0 wt % based on water in the operations
fluid.
[0106] In the method 200, the surfactant is made up of a weak base
and a weak acid. In one aspect, the surfactant is an alkyl acid
surfactant, an organo-anionic surfactant, or mixtures thereof.
Where the surfactant is or includes an organo-anionic surfactant,
the organo-anionic surfactant is preferably selected from the group
comprising monoethanol ammonium alkyl aromatic sulfonic acid,
monoethanol ammonium alkyl carboxylic acid, and mixtures
thereof.
[0107] The method 200 also includes mixing a volume of the
operations fluid with the volume of solid particles. This is
provided at Box 230. In this way, a slurry is formed. The method
200 then includes pumping the slurry into a disposal well. The
disposal well includes a NAF filter cake. This is shown at Box
240.
[0108] The method 200 further includes injecting the slurry into
one or more fractures formed in the subsurface formation. This is
seen in Box 250. Injection is conducted in such a manner that the
slurry contacts the NAF filter cake en route to the one or more
fractures. Because of the preferred weak base--weak acid
formulation of the slurry, the NAF filter cake is degraded, thereby
facilitating the injection of the slurry into fractures along the
wellbore.
[0109] As an additional step, the operator may choose to pump a
volume of the aqueous operations fluid into the disposal well
without the slurry. This is indicated at Box 260. The pumping step
of Box 260 is preferably performed prior to the pumping step of Box
240.
[0110] FIG. 3 is a flow chart showing steps for a method 300 of
re-injecting drill cuttings, in an alternate embodiment. The drill
cuttings are again injected into a subsurface formation. An
operations fluid having at least one surfactant is used.
[0111] The method 300 first includes obtaining a volume of solid
particles from drilling returns. This is shown in Box 310. The
method 300 then includes obtaining an aqueous operations fluid
comprising at least one surfactant. This is seen in Box 320. The
operations fluid of the method 300 is in accordance with the
operations fluid of the method 200, in its various embodiments. In
this respect, the surfactant is preferably made up of a weak base
and a weak acid. In one aspect, the surfactant is an alkyl acid
surfactant, an organo-anionic surfactant, or mixtures thereof.
Where the surfactant is or includes an organo-anionic surfactant,
the organo-ionic surfactant is preferably selected from the group
comprising monoethanol ammonium alkyl aromatic sulfonic acid,
monoethanol ammonium alkyl carboxylic acid, and mixtures
thereof.
[0112] The operations fluid preferably comprises surfactant present
in solution at a concentration greater than about 0.01 wt % and
less than about 20.0 wt % based on water in the operations
fluid.
[0113] The method 300 also includes pumping a volume of the
operations fluid into a disposal well. This is provided at Box 330.
The disposal well includes a NAF filter cake along the borehole.
The purpose of pumping the operations fluid into the wellbore is to
remediate the NAF filter cake along an open-hole portion, thereby
making the filter cake more permeable.
[0114] The operations fluid may be adapted to remediate the filter
cake by performing at least one of: 1) altering the wettability of
the NAF filter cake from oil wetting to water wetting; and 2)
extracting non-aqueous fluid associated with the NAF filter cake.
This occurs due to the surfactant having an oil-extracting
capability.
[0115] The method 300 further includes preparing a slurry of
aqueous fluid with the volume of solid particles. This is shown at
Box 340. The aqueous fluid may be the same as the operations fluid.
The method 300 then includes injecting the slurry into one or more
fractures formed in the subsurface formation. This is seen in Box
350. Injection is conducted at a pressure that is above the
formation parting pressure.
[0116] In one aspect, the slurry is injected intermittently in
batches into the disposal formation. This batch process involves
injecting approximately the same volumes of slurry and then waiting
for a period of time after each injection. Each batch injection may
last from a few hours to a few days, with shut-in times provided in
between. The batch injections may take place at low pump rates,
such as about 2.0 to 8.0 bpm.
[0117] After the batch re-injection cycles are concluded, the
disposal well may be further drilled, and then completed as a
producer or a water injector.
[0118] It can be understood that the present disclosure provides
compositions comprising alkyl acid surfactants or organo-anionic
surfactants for use in drill cuttings re-injection operations. The
compositions are useful when the well bore includes a NAF filter
cake. More particularly the compositions are useful when drill
cuttings are to be re-injected into the well bore containing NAF
filter cakes.
[0119] While it will be apparent that the inventions herein
described are well calculated to achieve the benefits and
advantages set forth above, it will be appreciated that the
inventions are susceptible to modification, variation and change
without departing from the spirit thereof.
* * * * *