U.S. patent application number 12/345505 was filed with the patent office on 2009-05-07 for method of using water-in-oil emulsion to remove oil base or synthetic oil base filter cake.
This patent application is currently assigned to BJ SERVICES COMPANY. Invention is credited to Brian B. Beall, Sandra L. Berry, Paul H. Javora, Qi Qu, Mark A. Vorderburggen.
Application Number | 20090114394 12/345505 |
Document ID | / |
Family ID | 46328053 |
Filed Date | 2009-05-07 |
United States Patent
Application |
20090114394 |
Kind Code |
A1 |
Javora; Paul H. ; et
al. |
May 7, 2009 |
Method of Using Water-in-Oil Emulsion to Remove Oil Base or
Synthetic Oil Base Filter Cake
Abstract
Fluid producing or injecting wells may be treated with a
water-in-oil emulsion for the removal or inhibition of unwanted
particulates, including pipe dope, asphaltenes and paraffins. In
addition, such emulsions are effective in the displacement of oil
base drilling muds and/or residues from such muds from wells. The
emulsion may also be used to break the interfacial and/or
rheological properties of oil base mud and synthetic oil base mud
filter cakes, and act as a demulsifier to break the water-in-oil
emulsion present in such oil base and synthetic oil base muds. The
water-in-oil emulsions may optionally contain a dispersing agent as
well as a surfactant.
Inventors: |
Javora; Paul H.; (Spring,
TX) ; Beall; Brian B.; (Spring, TX) ;
Vorderburggen; Mark A.; (Spring, TX) ; Qu; Qi;
(Spring, TX) ; Berry; Sandra L.; (Tomball,
TX) |
Correspondence
Address: |
JONES & SMITH , LLP
2777 ALLEN PARKWAY, SUITE 800
HOUSTON
TX
77019
US
|
Assignee: |
BJ SERVICES COMPANY
Houston
TX
|
Family ID: |
46328053 |
Appl. No.: |
12/345505 |
Filed: |
December 29, 2008 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11820085 |
Jun 18, 2007 |
7481273 |
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12345505 |
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11388103 |
Mar 23, 2006 |
7392845 |
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11820085 |
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11701685 |
Feb 2, 2007 |
7455111 |
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11388103 |
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10932965 |
Sep 2, 2004 |
7188676 |
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11701685 |
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Current U.S.
Class: |
166/312 ;
507/203 |
Current CPC
Class: |
C09K 8/52 20130101; Y10S
507/905 20130101; Y10S 507/929 20130101; C09K 8/524 20130101 |
Class at
Publication: |
166/312 ;
507/203 |
International
Class: |
E21B 37/08 20060101
E21B037/08; C09K 8/52 20060101 C09K008/52 |
Claims
1. A method of removing an oil base or synthetic oil base filter
cake from a wellbore and/or subterranean formation which comprises
introducing a composition comprising a water-in-oil emulsion into
the wellbore, wherein solids from the filter cake are dispersed
into the aqueous phase of the emulsion and further wherein at least
a portion of the filter cake is removed from the wellbore.
2. The method of claim 1, wherein the composition further comprises
a dispersing agent.
3. The method of claim 1, wherein the outer phase of the
water-in-oil emulsion is an organic solvent.
4. The method of claim 2, wherein the dispersing agent is a pH
adjusting agent.
5. The method of claim 1, wherein the inner phase of the
water-in-oil emulsion further comprises a pH adjusting agent.
6. The method of claim 1, wherein the inner phase of the
water-in-oil emulsion is an aqueous salt solution.
7. The method of claim 6, wherein the aqueous salt solution is
selected from the group consisting of sodium formate brine,
potassium formate brine, cesium formate brine, sodium bromide
brine, potassium bromide brine, cesium bromide brine, calcium
bromide brine, zinc bromide brine, sodium chloride brine, potassium
chloride brine, cesium chloride brine, calcium chloride brine, zinc
chloride brine, seawater and mixtures thereof.
8. The method of claim 3, wherein the organic solvent is selected
from the group consisting of aromatic petroleum cuts, mono-, di-
and tri-glycerides of saturated or unsaturated fatty acids, esters,
minerals oils, chlorinated hydrocarbons, deodorized kerosene,
naphtha, paraffins, isoparaffins, olefins, aliphatic hydrocarbons,
aromatic hydrocarbons, long chain alcohols, ketones, nitrites,
amides, amines, cyclic ethers, branched ethers, linear ethers,
aliphatic ethers of glycols, pyrrolidones, N-alkyl piperidones,
N,N-dialkyl alkanolamides, N,N,N',N'-tetra alkyl ureas,
dialkylsulfoxides, pyridines, hexaalkylphosphoric triamides,
1,3-dimethyl-2-imidazolidinone, nitroalkanes, nitro-compounds of
aromatic hydrocarbons, sulfolanes, butyrolactones, alkylene
carbonates, alkyl carbonates, tetrahydrofuran, dioxane, dioxolane,
methyltetrahydrofuran, dimethylsulfone, tetramethylene sulfone,
thiophene, polyalkylene glycols, polyalkylene glycols ethers,
polyalkylene glycols esters and mixtures thereof.
9. A method of removing an oil base or synthetic oil base filter
cake containing drilled and/or deposited solids from a wellbore
and/or subterranean formation comprising: (a) introducing into the
wellbore a composition comprising a water-in-oil emulsion; (b)
digesting at least a portion of the filter cake with the
composition wherein at least a portion of the solids are dispersed
in the aqueous phase of the emulsion and further wherein at least a
portion of the solids separate from the filter cake; and (c)
removing the aqueous phase containing at least a portion of the
solids and at least a portion of the filter cake from the
wellbore.
10. The method of claim 9, wherein the composition further
comprises a dispersing agent.
11. The method of claim 9, wherein the outer phase of the
water-in-oil emulsion is an organic solvent.
12. The method of claim 10, wherein the dispersing agent is a pH
adjusting agent.
13. The method of claim 9, wherein the inner phase of the
water-in-oil emulsion further comprises a pH adjusting agent.
14. The method of claim 9, wherein the inner phase of the
water-in-oil emulsion is an aqueous salt solution.
15. The method of claim 11, wherein the organic solvent is selected
from the group consisting of aromatic petroleum cuts, mono-, di-
and tri-glycerides of saturated or unsaturated fatty acids, esters,
minerals oils, chlorinated hydrocarbons, deodorized kerosene,
naphtha, paraffins, isoparaffins, olefins, aliphatic hydrocarbons,
aromatic hydrocarbons, long chain alcohols, ketones, nitrites,
amides, amines, cyclic ethers, branched ethers, linear ethers,
aliphatic ethers of glycols, pyrrolidones, N-alkyl piperidones,
N,N-dialkyl alkanolamides, N,N,N',N'-tetra alkyl ureas,
dialkylsulfoxides, pyridines, hexaalkylphosphoric triamides,
1,3-dimethyl-2-imidazolidinone, nitroalkanes, nitro-compounds of
aromatic hydrocarbons, sulfolanes, butyrolactones, alkylene
carbonates, alkyl carbonates, tetrahydrofuran, dioxane, dioxolane,
methyltetrahydrofuran, dimethylsulfone, tetramethylene sulfone,
thiophene, polyalkylene glycols, polyalkylene glycols ethers,
polyalkylene glycols esters and mixtures thereof.
16. A method of removing an oil base or synthetic oil base filter
cake from a wellbore and/or subterranean formation which comprises
introducing a composition comprising a dispersing agent and a
water-in-oil emulsion into the wellbore, wherein the outer phase of
the water-in-oil emulsion is an organic solvent.
17. The method of claim 16, wherein the dispersing agent is a pH
adjusting agent.
18. The method of claim 16, wherein the inner phase of the
water-in-oil emulsion is an aqueous salt solution.
19. The method of claim 16, wherein the organic solvent is selected
from the group consisting of aromatic petroleum cuts, mono-, di-
and tri-glycerides of saturated or unsaturated fatty acids, esters,
minerals oils, chlorinated hydrocarbons, deodorized kerosene,
naphtha, paraffins, isoparaffins, olefins, aliphatic hydrocarbons,
aromatic hydrocarbons, long chain alcohols, ketones, nitrites,
amides, amines, cyclic ethers, branched ethers, linear ethers,
aliphatic ethers of glycols, pyrrolidones, N-alkyl piperidones,
N,N-dialkyl alkanolamides, N,N,N',N'-tetra alkyl ureas,
dialkylsulfoxides, pyridines, hexaalkylphosphoric triamides,
1,3-dimethyl-2-imidazolidinone, nitroalkanes, nitro-compounds of
aromatic hydrocarbons, sulfolanes, butyrolactones, alkylene
carbonates, alkyl carbonates, tetrahydrofuran, dioxane, dioxolane,
methyltetrahydrofuran, dimethylsulfone, tetramethylene sulfone,
thiophene, polyalkylene glycols, polyalkylene glycols ethers,
polyalkylene glycols esters and mixtures thereof.
20. A method of removing an oil base or synthetic oil base filter
cake containing drilled and/or deposited solids from a wellbore
and/or subterranean formation comprising introducing into the
wellbore a composition comprising a water-in-oil emulsion, wherein
the organic phase of the water-in-oil emulsion dissolves at least a
portion of the oil in the oil base or synthetic oil base filter
cake and further wherein at least a portion of the solids are
dispersed in the aqueous phase of the emulsion.
Description
[0001] This application is a continuation application of U.S.
patent application Ser. No. 11/820,085, filed on Jun. 18, 2007,
which is a continuation-in-part application of U.S. patent
application Ser. No. 11/701,685, filed on Feb. 20, 2007, now U.S.
Pat. No. 7,455,111, which is a divisional application of U.S.
patent application Ser. No. 10/932,965, filed on Sep. 2, 2004, now
U.S. Pat. No. 7,188,676. U.S. patent application Ser. No.
11/820,085 is also a continuation-in-part application of U.S.
patent application Ser. No. 11/388,103, filed on Mar. 23, 2006,
which is now U.S. Pat. No. 7,392,845.
FIELD OF THE INVENTION
[0002] The invention relates to the use of water-in-oil emulsion
compositions for use in oil field production and injection
operations. Such compositions have particular applicability in the
removal of drilling muds, scale, heavy crude, paraffins and/or
asphaltenes from subterranean formations. In addition, the
compositions have particular applicability in breaking oil base mud
and synthetic oil base mud filter cakes.
BACKGROUND OF THE INVENTION
[0003] The increased production flow area provided by a horizontal,
as compared to a vertical, wellbore has driven an increase in the
drilling and completion of horizontal wells. Such wells have long
open-hole sections which remain in contact with the drilling fluid
for long periods of time in overbalanced conditions, forming a
filter cake on the formation and also thereby initiating solids
invasion that may induce formation damage. Regardless of the type
of drilling conducted, the selection of drilling fluid has a major
effect on minimizing skin development and maximizing fluid and gas
production or injection.
[0004] Efficiency in the overall production of fluids and gases
from a well or injection into a well is further highly dependent on
the effectiveness of production and injection chemicals. Such
production chemicals include completion fluids as well as treatment
solutions for production stimulation. It is understood that
chemicals and treatments used to improve production out of a well
are also used to improve injection into a well.
[0005] Exemplary production chemicals include aqueous acid
solutions which are often used to increase the permeability of a
formation. Injection of the aqueous acid solution into the
formation results in dissolution of mineral constituents, thereby
producing flow channels. In such methods, difficulties are often
encountered due to water-in-oil emulsions (having crude oil
deposits as the outer phase) which are formed downhole at the
interfaces between the injected aqueous treating solutions and
crude oil contained in the formations. Solids and particulates,
such as fines and insoluble reaction products, accumulate at the
oil-water interfaces and stabilize the emulsions which in turn tend
to plug the pore spaces in the formations being treated, thereby
restricting the flow of the treating solutions and subsequent
production of fluids therethrough. While a variety of additives
having surface active properties have been developed for preventing
the formation of emulsions, sludge, etc., as well as preventing the
corrosion of metal surfaces, and have been included in the various
treating solutions employed, less than desirable results are often
achieved.
[0006] In addition, and particularly where aqueous acid treating
solutions are utilized, sludge formed as a result of the reaction
of the acid with asphaltic materials contained in the crude oil can
plug the pore spaces of the formations.
[0007] Solids and particulates are known to negatively impact the
overall efficiency of completion of wells. These include
asphaltene, paraffin deposits and scales. Asphaltenes are most
commonly defined as that portion of crude oil which is insoluble in
heptane. Asphaltenes exist in the form of colloidal dispersions
stabilized by other components in the crude oil. They are the most
polar fraction of crude oil, and often will precipitate upon
pressure, temperature, and compositional changes in the oil
resulting from blending or other mechanical or physicochemical
processing. Asphaltene precipitation occurs in pipelines,
separators, and other equipment. Once deposited, asphaltenes
present numerous problems for crude oil producers. For example,
asphaltene deposits can plug downhole tubulars, wellbores, choke
off pipes and interfere with the functioning of separator
equipment.
[0008] Residues from drilling muds further negatively impact the
overall efficiency of completion of wells. Commonly employed
drilling muds are gaseous or liquid. Liquid drilling muds have a
water base or an oil base. The aqueous phase of the more common
water base muds may be formed of fresh water or a brine. As a
discontinuous or disperse phase, water base fluids may contain
gases or water-immiscible fluids, such as diesel oil, in the form
of an oil-in-water emulsion, and solids including weighting
materials, such as barite. Water base fluids also typically contain
clay minerals, polymers, and surfactants for achieving desired
properties or functions.
[0009] Oil base fluids are often referred to as oil based muds
(OBM) and synthetic based muds (SBM). Most OBMs and SBMs are invert
emulsions composed of an aqueous phase dispersed or surrounded by a
continuous oil phase. OBM and SBM filter cakes, composed of colloid
particles, weighting material, drilled solids and water or brine
droplets dispersed in the oil phase, are hydrophobic and exhibit a
permeability which is typically lower than the permeability of the
formation.
[0010] Oil base fluids offer performance advantages over water base
fluids. Such advantages include higher penetration rates, improved
lubricity, shale stability, decreased fluid loss, and thinner
filter-cake characteristics. In addition, oil base fluids provide
gauge hole, higher rates of penetration and deeper bit penetration.
Furthermore, fluid losses to the formation from oil base or
synthetic oil base fluids tend to be less damaging since the base
fluid is oil rather than water. Oil base fluids, however, are
usually more difficult to remove due to the hydrophobic nature of
the base fluid and impermeable nature of the deposited filter
cake.
[0011] Solids and particulates not only cause a restriction in pore
openings in the formation (formation damage) and hence reduction in
the rate of oil and/or gas production, but also cause blockage of
tubular and pipe equipment during production and surface
processing. It is well known that production efficiency increases
if such unwanted solids and particulates are removed from the
wellbore.
[0012] To remove such particulates, the well is generally subjected
to shut-in, whereby compositions are injected into the well,
usually under pressure, and function to remove the unwanted
particulates. Shut-ins are typically performed regularly in order
to maintain high production or injection rates. Shut-ins constitute
down time when no production or injection takes place. Thus, a
reduction in total production or injection corresponds to the
number of down times during the shut-in operation.
[0013] Production is further decreased when ineffective chemicals
are used during shut-in. For instance, ineffective scale inhibitors
fail to reduce total scale build-up. Poor displacement of drilling
mud results in solid residues and mud residues left in the wellbore
which, in turn, typically leads to formation damage, etc. Similar
displacement or mud removal procedures are also performed before
cementing. Mud residue can lead to weak bonding between cement and
the formation surface and gas leakage when the well is turned to
production.
[0014] The prior art has recognized the use of surfactants in the
displacement and removal of oil base muds. Surfactants are first
dissolved in fresh water or seawater at the concentration of 5
volume percent or more and the resulting liquid is then pumped at
sufficient rate to generate turbulent flow to facilitate the mud
cleaning process. Although surfactant systems have been widely used
in field applications, their effectiveness is often limited by
solvency capacity. In addition, the efficiency of surfactant
systems varies for different muds and is negatively impacted by the
condition of the mud when the displacement is conducted.
[0015] Historically, solvent- or aqueous-based systems have been
used in mud displacement processes as well as in processes to
effectuate the removal of oil based and synthetic oil based filter
cakes. While aqueous surfactant based systems are generally
selected over solvent treatments as mud displacement and mud filter
cake clean-up treatments, surfactant systems are often ineffective.
For instance, surfactant based systems are typically ineffective at
breaking the emulsion inside the filter cake and effecting complete
phase separation. Further, aqueous surfactant based treatments
often create additional damage by forming an emulsion block with
the formation oil. Such emulsion blocks have the potential to block
production or injection. Further, such systems are either not
biodegradable or are less efficacious than desired.
[0016] In most cases, due to strong solvency of the organic solvent
toward the base oil in oil based mud, solvents have shown good mud
removal and cleaning effects in both laboratory and field
applications. However, pure organic solvent is generally expensive
and often becomes cost prohibitive. Although water can be mixed
with organic solvent to cut the fluid cost, the effectiveness of
the system can be greatly reduced, even at levels as low as 10 to
20 volume percent of water content. In other cases, especially when
solid content in the mud or mud residue is high and the mud
viscosity is significant, pure solvent is often not effective.
[0017] Organic solvents are further often used in formation
clean-up or near wellbore damage removal when the damage is caused
by asphaltene or paraffin deposition as well as scale deposition.
Very often the solvents are aromatic and leave an environmental
footprint. In other cases, the solvent is not effective, especially
when suspension and dispersion of solids is desired. Pure organic
solvents cannot effectively break up solid aggregation and does not
facilitate solid suspension.
[0018] Improved production chemicals are therefore desired for the
treatment of fluid producing or injecting wells which are capable
of removing or inhibiting the formation of unwanted solids and
particulates within the well.
[0019] For instance, in order to meet more challenging drilling
applications such as for use in deepwater and high-temperature,
high-pressure (HTHP) applications, and further to meet stricter
health, safety, and environmental standards, new systems to
displace and/or remove OBM and SBM filter cakes have been sought.
In particular, there is a need for new systems that do not cause
the problems associated with the aqueous systems of the prior art
and which further are biodegradable.
SUMMARY OF THE INVENTION
[0020] A fluid producing or injecting well penetrating a
subterranean formation is treated, in accordance with the
invention, with a water-in-oil emulsion. In addition to treating
oil and gas wells, the emulsion has particular applicability in the
treatment of injection wells. Preferably, the emulsion is
biodegradable.
[0021] Such emulsions are capable of removing or inhibiting the
formation of unwanted solids and particulates, including pipe dope,
asphaltenes and paraffins, within the well and further serve to
improve the permeability of the formation.
[0022] Such emulsions are also efficacious in displacing oil based
drilling muds and/or residues from such muds from wells. Further,
the emulsions are highly efficacious in the removal of oil based
mud (OBM) and synthetic oil based mud (SBM) filter cakes from the
well and/or formation face. The percent mud cake removal, which is
indicative of disaggregating of the filter cake and solids removal,
is high when water-in-oil emulsions are used to remove oil based
and synthetic oil based filter cakes. As such, water-in-oil
emulsions are highly efficient in breaking the residual emulsion
inside the filter cake, decreasing cake cohesion and reducing cake
adherence to the formation face.
[0023] The present invention relates therefore to a process for
increasing the effectiveness of production chemicals by reducing
the number and duration of shut-in operations needed to increase
the production rate from or into a well.
[0024] The water-in-oil emulsion, or reverse emulsion, for use in
the invention consists of an outer (or continuous) hydrophobic
phase which is particularly useful in dissolving oil residues. In
addition, the outer phase is particularly useful in dissolving
unwanted particulates or loosening such particulates, like
asphaltene and/or paraffin and/or OBM or SBM residues, which have
been deposited within the wellbore and/or onto the formation face
and/or within the formation.
[0025] The emulsion is particularly efficacious in the removal of
oil base or synthetic oil base filter cakes. The emulsions are
capable of breaking the interfacial and/or rheological properties
of filter cakes and muds, thereby acting like a demulsifier to
break OBM or SBM water-in-oil emulsions and adherence of the filter
cake to the wellbore and formation. In some instances, when the
emulsion is specifically formulated, the emulsion may pass the
"no-sheen" requirement, for use in Gulf of Mexico applications,
wherein the emulsion does not produce a silvery or iridescent sheen
on the surface of seawater. The emulsion may be lighter than water
and cover the surface of the water, dissipating over time.
[0026] The water-in-oil emulsions may optionally contain a
dispersing agent as well as a surfactant. The dispersing agent may
act as a pH adjusting agent. The water phase may further include
scale inhibitors, pH adjusting agents, corrosion inhibitors, rust
removing agents, bactericides, hydrogen sulfide scavengers, and/or
other chemical additives. The external phase of the emulsion may
further contain a surfactant dissolved or dispersed in the outer
hydrophobic phase.
[0027] The water-in-oil emulsion used in the invention typically
provides excellent particle suspension capacity. Such capacity
prevents particulates from redepositing within the well, e.g., on
tubings, casings or the formation surface.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0028] The water-in-oil emulsion, or reverse emulsion, for use in
the invention consists of an outer (or continuous) hydrophobic
phase which is particularly useful in dissolving oil residues and
can be specially formulated to be biodegradable. In addition, the
outer phase is particularly useful in dissolving unwanted
particulates or loosening such particulates, like asphaltene and/or
paraffin, which have been deposited within the wellbore, onto the
formation face or within the formation. It is also useful to remove
pipe dope which is routinely used to prevent seizing when pipe
connections are made. In addition, the emulsion of the invention is
useful in stimulating a well by removing unwanted particulates and
thereby improving permeability of the formation.
[0029] In a preferred embodiment, the emulsion is used after
drilling is complete in order to displace, clean-up or remove the
oil based mud (OBM) or synthetic oil based mud (SBM) filter cake
from the formation face as well as residues from such muds from
producing or injecting wells. This, in turn, minimizes skin and
formation damage, increases production or injection flow and
restores the productive zone to a near-natural state. Such clean-up
treatments are needed in order to break down the interfacial and/or
rheological properties of the filter cake, wash the damaged zone of
the wellbore and restore fluid transfer properties.
[0030] The internal (or discontinuous) phase of the water-in-oil
emulsion is water, to which may be added any conventional additive
used to treat unwanted particulates. The aqueous internal phase may
be an aqueous salt solution such as sodium formate brine, potassium
formate brine, cesium formate brine, sodium bromide brine,
potassium bromide brine, calcium bromide brine, zinc bromide brine,
cesium bromide brine, calcium chloride brine, sodium chloride
brine, potassium chloride brine, cesium chloride brine, seawater
and mixtures thereof. The use of such salts may be used to increase
the density of the water-in-oil emulsion in those situations where
higher density is sought at the interface. (Reference herein to
"water" as the internal phase of the water-in-oil emulsion shall
include such aqueous salt solutions.)
[0031] Unwanted particulates, such as solids from an oil based or
synthetic oil based filter cake may be dispersed into the aqueous
phase of the emulsion and removed, along with residual filter cake,
from the wellbore. As such, the water-in-oil emulsion digests at
least a portion of the filter cake such that at least a portion of
the solids are dispersed in the aqueous phase of the emulsion. The
aqueous phase containing the unwanted solids then separates from
the filter cake. The hydrophobic outer phase of the water-in-oil
emulsion is capable of dissolving at least a portion of the oil in
the OBM or SBM filter cake and dispersing oil-wet solids and
particulates.
[0032] In a preferred embodiment, the external phase is a
hydrophobic organic solvent. Mixtures of organic solvents may also
be used. The hydrophobic organic solvent is either non-miscible in
or slightly miscible with water. Preferred solvents include
aromatic petroleum cuts, terpenes, mono-, di- and tri-glycerides of
saturated or unsaturated fatty acids including natural and
synthetic triglycerides, aliphatic esters such as methyl esters of
a mixture of acetic, succinic and glutaric acids, aliphatic ethers
of glycols such as ethylene glycol monobutyl ether, minerals oils
such as vaseline oil, chlorinated solvents like
1,1,1-trichloroethane, perchloroethylene and methylene chloride,
deodorized kerosene, solvent naphtha, paraffins (including linear
paraffins), isoparaffins, olefins (especially linear olefins) and
aliphatic or aromatic hydrocarbons (such as toluene). In one
embodiment of the invention, the external phase consists of a
surfactant dissolved or dispersed in a paraffinic base oil.
[0033] Terpenes are preferred, especially d-limonene (most
preferred), 1-limonene, dipentene (also known as
1-methyl-4-(1-methylethenyl)-cyclohexene), myrcene, alpha-pinene,
linalool and mixtures thereof.
[0034] Further exemplary organic liquids include long chain
alcohols (monoalcohols and glycols), esters, ketones (including
diketones and polyketones), nitrites, amides, amines, cyclic
ethers, linear and branched ethers, glycol ethers (such as ethylene
glycol monobutyl ether), polyglycol ethers, pyrrolidones like
N-(alkyl or cycloalkyl)-2-pyrrolidones, N-alkyl piperidones,
N,N-dialkyl alkanolamides, N,N,N',N'-tetra alkyl ureas,
dialkylsulfoxides, pyridines, hexaalkylphosphoric triamides,
1,3-dimethyl-2-imidazolidinone, nitroalkanes, nitro-compounds of
aromatic hydrocarbons, sulfolanes, butyrolactones, and alkylene or
alkyl carbonates. These include polyalkylene glycols, polyalkylene
glycol ethers like mono (alkyl or aryl)ethers of glycols, mono
(alkyl or aryl)ethers of polyalkylene glycols and poly (alkyl
and/or aryl)ethers of polyalkylene glycols, monoalkanoate esters of
glycols, monoalkanoate esters of polyalkylene glycols, polyalkylene
glycol esters like poly (alkyl and/or aryl) esters of polyalkylene
glycols, dialkyl ethers of polyalkylene glycols, dialkanoate esters
of polyalkylene glycols, N-(alkyl or cycloalkyl)-2-pyrrolidones,
pyridine and alkylpyridines, diethylether, dimethoxyethane, methyl
formate, ethyl formate, methyl propionate, acetonitrile,
benzonitrile, dimethylformamide, N-methylpyrrolidone, ethylene
carbonate, dimethyl carbonate, propylene carbonate, diethyl
carbonate, ethylmethyl carbonate, and dibutyl carbonate, lactones,
nitromethane, and nitrobenzene sulfones. The organic liquid may
also be selected from the group consisting of tetrahydrofuran,
dioxane, dioxolane, methyltetrahydrofuran, dimethylsulfone,
tetramethylene sulfone and thiophene.
[0035] In one preferred embodiment, the hydrophobic organic solvent
is a base oil containing between from about 75 to about 99,
preferably from about 85 to about 95, most preferably about 90,
percent by weight of linear paraffins (alkanes), the remainder
being olefins (alkenes). The base oil typically exhibits low
viscosity (for instance, as low as 1.99 cSt (ASTM D-445). Preferred
base oils include Bio-Base.RTM.637 (a mixture of alkanes and
alkenes) and Bio-Base.RTM.560 (a hydrocarbon blend containing 90%
linear paraffins--n-paraffins or n-alkanes), both of which are
commercially available from Shrieve Chemical Products. With such
formulations, the volume percent of the base oil in the emulsion is
between from about 50 to about 75, preferably between from about 55
to about 65, volume percent.
[0036] The emulsion may be formed by conventional methods, such as
with the use of a homogenizer, with the application of shear.
Surfactants/emulsifiers may be added to the emulsion to help
stabilize and further facilitate formation of the emulsion.
[0037] The composition for use in the invention may further contain
a surfactant. (As used herein, the term "surfactant" is synonymous
with the term "emulsifying agent" or "emulsifier".) The surfactant
is preferably hydrophobic though it may be characterized as having
portions which are strongly attracted to each of the phases
present, i.e., hydrophilic and hydrophobic portions. In a preferred
embodiment, the external phase of the emulsion contains a
surfactant dissolved or dispersed in the base oil. Suitable
surfactants include non-ionic as well as ionic surfactants.
[0038] The water-in-oil emulsion for use in the invention is
preferably polymer-free and may be prepared by first mixing the
surfactant, capable of forming the emulsion, with the hydrophobic
organic solvent. An optional dispersing agent may then be added and
finally an appropriate amount of water may be added, all under
agitation. The resulting water-in-oil emulsion consists of an outer
oil (organic) phase and is particularly useful in dissolving the
base oil and dispersing oily solid and particulate aggregates from
oil base muds, as well as dissolving, dispersing or loosening
asphaltene and/or paraffin deposits. The inner water phase further
is characterized by a low pH and is capable of dispersing the
unwanted solids from the mud. In a preferred embodiment, the inner
water phase is further characterized by high pH.
[0039] At least a portion of the solvent may be replaced with
water. Mixing water with the organic solvent minimizes the expense
of producing the emulsion. The amount of water which may be added
to the organic solvent is an amount that will maintain the
hydrophobicity of the organic solvent.
[0040] Typically the amount of water forming the water-in-oil
emulsion is between from about 10 to about 90, preferably between
from about 20 to about 80, volume percent. In one embodiment of the
invention, the water is present in the emulsion in an amount
between from about 25 to about 35, typically around 28, volume
percent. The water typically increases the viscosity of the
emulsion, rendering a higher carrying capacity for removed solids.
In addition, it serves as a solvent for the pH adjuster and a means
to activate the surfactant.
[0041] Suitable surfactants include acetylated monoglycerides,
sorbitan esters including polyoxyalkylene sorbitan esters,
lecithins, fatty amines, fatty amine carboxylates, fatty amides,
fatty amide carboxylates, polyoxyl castor oil derivatives, macrogol
esters, nonionic polyesters, nonionic hydrophobic-hydrophilic
polyesters, caprylic/capric triglycerides, polyoxyalkylated
glycolysed glycerides, mixture of mono-, di- and triglycerides and
mono- and di-fatty esters of polyalkylene glycol. Preferred are
fatty acids such as C.sub.8-C.sub.10 caprylic/capric acids, fatty
amine carboxylates, polyethylene glycol hydrogenated castor oil,
nonionic hydrophobic-hydrophilic polyesters, polyethylene glycol
glyceryl esters, lecithin, cholesterol and proteins such as casein.
Multiple emulsifying agents can further be used.
[0042] Suitable surfactants further include ionic as well as
nonionic compounds, including those having a hydrophilic lipophilic
balance (HLB) in the range of about 1 to about 30. In a preferred
embodiment, the surfactant is nonionic, preferably having an HLB
between from 2 to about 20, more preferably from about 2 to about
10.
[0043] Examples of these surfactants are alkanolamides including
fatty acid diethanolamides, alkylarylsulfonates, amine oxides,
poly(oxyalkylene) compounds, including block copolymers comprising
alkylene oxide repeat units, carboxylated alcohol ethoxylates,
ethoxylated alcohols, ethoxylated alkyl phenols, ethoxylated amines
and amides, ethoxylated fatty acids, ethoxylated fatty esters and
oils, fatty esters, glycerol esters, glycol esters, lecithin and
derivatives, lignin and derivatives, monoglycerides and
derivatives, olefin sulfonates, phosphate esters and derivatives,
propoxylated and ethoxylated fatty acids or alcohols or alkyl
phenols, amine oxides, sorbitan derivatives such as sorbitan fatty
acid esters, sucrose esters and derivatives, alcohols or
ethoxylated alcohols or fatty esters, sulfonates of dodecyl and
tridecyl benzenes or condensed naphthalenes or petroleum,
sulfosuccinates and derivatives, and tridecyl and dodecyl benzene
sulfonic acids.
[0044] Suitable as nonionic surfactants are alkyl and alkylaryl
polyether alcohols such as linear or branched polyoxyethylene
alcohols, more preferably linear polyoxyethylene alcohols,
comprising (a) from about 8 to about 30, preferably about 8 to
about 20, carbon atoms, and (b) comprising about 3 to about 50
moles, most preferably about 3 to about 20 moles, ethylene oxide.
Most preferred non-ionic surfactants are linear polyoxyethylene
alcohols having from about 13 to about 15 carbon atoms and
comprising about 10 moles ethylene oxide. Further, preferred
surfactants include nonylphenol ethoxylate having a HLB value of
about 16 and comprising 20 ethylene oxide units per molecule,
octylphenol ethoxylate having an HLB value greater than 13.5, and
nonylphenol ethoxylate having a HLB value greater than 13. Further
suitable surfactants include oxyalkylated alkyl phenols like
octylphenol polyethylene oxide ethers and nonylphenol polyethylene
oxide ethers as well as linear alcohol polyethylene oxide ethers
and sorbitan monooleate polyethylene oxide ethers, including those
sold under the commercial names of TERGITOL, TRITON, BRIJ, TWEEN
and MAKON.
[0045] In another preferred embodiment, the non-ionic surfactants
are a combination of alkylaryl ethoxylate and a polyethylene glycol
(PEG) ester of fatty acids. Preferably, the alkylaryl ethoxylate is
octyl, nonyl or dodecylphenol with 3 to 13 moles of ethylene oxide,
while the PEG ester is of molecular weight range 200-600 with
either one or two moles of unsaturated fatty acids.
[0046] Further preferred as nonionic surfactants are
polyoxyethylene sorbitan monopalmitate, polyoxyethylene sorbitan
monostearate, polyoxyethylene sorbitan monooleate, linear alcohol
alkoxylates, alkyl ether sulfates, linear nonyl-phenols,
ethoxylated castor oils such as polyethylene glycol castor oil,
dipalmitoylphosphatidylcholine (DPPC), polyoxyethylene (8.6) nonyl
phenyl ether, ethylene oxide sulfonates (e.g., alkyl
propoxy-ethoxysulfonate), alkyl propoxy-ethoxysulfate,
alkylarylpropoxy-ethoxysulfonate and highly substituted benzene
sulfonates.
[0047] Included within nonionic surfactants are alkyl alkoxylates
and those wherein the hydrophilic part of the molecule contains one
or more saccharide unit(s) such as those derived from sugars like
fructose, glucose, mannose, galactose, talose, gulose, allose,
altose, idose, arabinose, xylose, lyxose and/or ribose, including
alkylpolyglycosides.
[0048] The ionic surfactants can be amphoteric such as alkyl
betaines, alkyldimethyl betaines, alkylamidopropyl betaines,
alkylamido-propyldimethyl betaines, alkyltrimethyl sulfobetaines,
imidazoline derivatives such as alkylamphoacetates,
alkylamphodiacetates, alkylamphopropionates,
alkylamphodipropionates, alkylsultains or alkylamidopropyl
hydroxysultains, amine oxides or the condensation products of fatty
acids and protein hydrolysates.
[0049] Anionic surfactants can include hydrosoluble salts of
alkylsulfates, alkylethersulfates, alkylsulfonates,
alkylisethionates and alkyltaurates or their salts,
alkylcarboxylates, alkylsulphosuccinates or alkylsuccinamates,
alkylsarcosinates, alkylated derivatives of protein hydrolysates,
acylaspartates, and alkyl and/or alkylether and/or alkylarylether
ester phosphates and phosphonates. The cation is generally an
alkali or alkaline-earth metal such as sodium, potassium, lithium,
magnesium or an ammonium group NR.sub.4.sup.+ where R, which may be
identical or different, represents an alkyl and/or aryl group which
may or may not be substituted by an oxygen or nitrogen atom.
[0050] The surfactant when present is in a quantity sufficient to
maintain the present composition as an emulsion. In one embodiment,
it is present at a level of about 0.005 to about 20 weight percent,
preferably from about 0.005 to about 15 weight percent, more
preferably from about 3.5 to about 15, most preferably from about 4
to about 10, weight percent. When used to treat OB/SB mud samples,
optimization of the oil/surfactant system should preferably be
conducted on a given OB/SB mud sample to determine the proper
concentration of active surfactants required to obtain complete
breaking of the emulsion inside the filter cake and disruption of
the cake cohesion.
[0051] The dispersing agent serves to disperse solids upon the in
situ removal of oil or organic deposits mixed with solid particles.
The dispersing agent is preferably an inorganic or organic acid or
salts or esters and may, optionally, function as a pH adjusting
agent.
[0052] Suitable dispersing agents include organophosphate esters,
including salts thereof, such as alkali metal salts. These embrace
a diversity of predominantly partially esterified phosphorus
containing surface active materials, including alkyl
orthophosphates, e.g., mono (2-ethylhexyl) orthophosphate and
di(2-ethylhexyl) orthophosphate and mixtures thereof, as well as
partial esters of polyphosphoric acids, glycerophosphoric acid,
sugar phosphates, phosphatidic acids having long-chain fatty acyl
groups, amino phosphoric acids, and partial phosphate esters of
nonionic surfactants. Exemplary and preferred partial phosphate
ester dispersants include, for example, phosphated polyoxyethylated
nonylphenols; cetyl phosphates and oxyethylated cetyl phosphates;
mono or di phosphate esters made from aromatic (phenols) or linear
alcohols, usually polyoxyethylated; and phosphated fatty
glycols.
[0053] Preferred dispersing agents include aliphatic phosphonic
acids with 2-50 carbons, such as hydroxyethyl diphosphonic acid,
and aminoalkyl phosphonic acids, salts and esters thereof, e.g.
polyaminomethylene phosphonates with 2-10 N atoms e.g. each bearing
at least one methylene phosphonic acid group; examples of the
latter are ethylenediamine tetra(methylene phosphonate),
diethylenetriamine penta(methylene phosphonate) and the triamine-
and tetramine-polymethylene phosphonates with 2-4 methylene groups
between each N atom, and for example, with at least 2 of the
numbers of methylene groups in each phosphonate being different.
Other preferred dispersing agents include lignin or derivatives of
lignin such as lignosulfonate and naphthalene sulfonic acid and
derivatives.
[0054] The amount of dispersing agent added to the composition is
an amount sufficient to maintain the dispersed particles in
dispersion. Typically the amount of dispersing agent to the
composition is between from about 0.5 to about 50 weight percent
(based on the total weight of the composition).
[0055] The composition may further contain a suitable amount of a
pH modifying agent such as mineral acids (like hydrochloric acid),
organic acids (like formic acid, acetic acid, or citric acid), and
chelating agents, in particular cationic salts of
polyaminocarboxylic acids chelating agents. For instance, a 10% HCl
could be used to lower the pH to about -1. The pH of the
formulation is suitably from about -1 to about 6.
[0056] The aqueous inner phase may further contain any additive
used in the art to improve productivity, such as pH adjustment
agents, corrosion inhibitors, scale inhibitors, rust removers,
hydrogen sulfide scavengers and bactericides. Such agents may be
used in place of or in combination with the dispersing agent. For
instance, soda ash may be used as a pH adjuster to raise the pH to
from about 7 to about 10 or more, and most preferably about 9 to
10. The scale inhibitor is effective in stopping calcium and/or
barium scale with threshold amounts rather than stoichiometric
amounts. Conventional scale inhibitors may be used, such as
water-soluble organic molecules with at least 2 carboxylic and/or
phosphonic acid and/or sulfonic acid groups e.g. 2 to 30 such
groups, oligomers or polymers, or may be a monomer with at least
one hydroxyl group and/or amino nitrogen atom, especially in a
hydroxycarboxylic acid or hydroxy or aminophosphonic, or, sulfonic
acid.
[0057] Examples of corrosion inhibitors are non-quaternized long
aliphatic chain hydrocarbyl N-heterocyclic compounds.
[0058] The hydrogen sulfide scavenger may be an oxidant, such as an
inorganic peroxide, e.g. sodium peroxide, or chlorine dioxide, or
an aldehyde, e.g. of 1 to 10 carbons such as formaldehyde or
glutaraldehyde or (meth)acrolein.
[0059] Further, the emulsion may be used in conjunction with an
alcohol, glycol or glycol ether which principally serves to enhance
the emulsion. Suitable alcohols, glycols and glycol ethers include
mid-range primary, secondary and tertiary alcohols with between 1
and 20 carbon atoms, such as t-butanol, n-butanol, n-pentanol,
n-hexanol and 2-ethyl-hexanol as well as detergent range alcohol
ethoxylates, ethylene glycols (EG), polyethylene glycols (PEG),
propylene glycols (PG) and triethylene glycols (TEG). When
employed, the alcohol, glycol or glycol ether (or combinations
thereof) may be present in the emulsion in an amount between from
about 1 to about 50 volume percent, more typically between 1 and 20
volume percent, and most typically between 1 and 5 volume
percent.
[0060] The emulsion may further be used in conjunction with
enzymes, buffers, surfactants, oxidizers and/or chemical breakers
conventional in the art.
[0061] The water-in-oil formulations of the present invention may
be prepared on the platform or can be prepared at a plant and
transported as such to the site of use. Typically, the oil soluble
components such as certain corrosion inhibitors and surfactants,
are mixed with the solvent, and then the aqueous phase in
appropriate proportions is slowly mixed in using high shear to
achieve the desired homogeneity. Typically the aqueous phase
contains the water soluble dispersing agents, surfactants and/or
other additives.
[0062] The oil based emulsions have particular applicability since
they inhibit the generation of water based emulsions in the
formation. In addition, the oil based surfactant emulsions provide
a more economical alternative to solvent-based systems. Further,
the emulsions may further be used as breakers to weaken and remove
OBM and SBM filter cakes. The emulsions are capable of separating
an OBM or SBM into its component phases. Use of a water-in-oil
emulsion is also effective in avoiding the generation of an
emulsion with the formation oil, which apparently can form when
certain aqueous based surfactant systems are used. Such emulsion
blocks have the potential to create substantial damage to the
formation.
[0063] In addition to treating fluid producing wells, the
compositions of the invention have applicability in injection
wells, wherein fluids are injected rather than produced.
[0064] The following examples demonstrate the more salient features
of the invention. Other embodiments within the scope of the claims
herein will be apparent to one skilled in the art from
consideration of the specification and practice of the invention as
disclosed herein. It is intended that the specification, together
with the examples, be considered exemplary only, with the scope and
spirit of the invention being indicated by the claims which
follow.
EXAMPLES
[0065] In the Examples, the following components were used:
[0066] Bio-Base 637 is a mixture of alkanes and alkenes, a product
of Shrieve Chemical Products Co.
[0067] Tween.RTM. 81 is a polyoxyethylene (5) sorbitan monooleate,
a product of ICI America, Inc.
[0068] Paravan 25, a product of BJ Services Company, contains
d-limonene, and is capable of cleaning oil or organic deposits;
[0069] SP-78, a product of Special Products Inc., is an
organophosphonate dispersing agent which further functions as a pH
reducing agent;
[0070] Viscoflex-X, a product of BJ Services Company, is a
surfactant comprising about 24% by weight of ethylene glycol
monobutyl ether and about 76% by weight of lecithin. Viscoflex-X is
used as an emulsifier to promote water-in-oil emulsions;
[0071] CI-25, a product of BJ Services Company, is a corrosion
inhibitor comprising a blend of quaternary salts, alcohols,
formamide and ethoxylated nonylphenol;
[0072] MDR-1, a product of BJ Services Company, is an active
dispersing agent which further functions as a pH adjusting
agent;
[0073] MDR-E, a product of BJ Services Company, is an active
emulsifying agent capable of emulsifying a glycol ether
solvent;
[0074] E-31, a product of BJ Services Company, is an oil external
emulsifier which provides a stable emulsion that retards the
activity of HCl by limiting contact between the acid and formation;
and
[0075] US-40, a product of BJ Services Company, is a mutual solvent
of ethylene glycol monobutyl ether.
Example 1
[0076] This Example illustrates the displacement process for
eliminating drilling mud components, especially solids and oil,
from a well system prior to introduction of solids-free completion
and/or packer brine. All percentages expressed in this Example are
in weight percentages. The drilling mud is displaced from the well
system by circulating therein. Two compositions were tested as
designated below:
TABLE-US-00001 Composition 1: Composition 2: 40% Paravan 94%
Paravan 1% Viscoflex - X 1% Viscoflex - X 5% SP-78 5% SP-78 54%
water
The compositions were used with sludge produced from a well of
Venezuelan crude oil. Mud displacement: 100 ml of mud sample was
poured into a glass jar (4 oz) to coat the wall completely and
excess mud was poured out. 100 ml of Composition 1 and 2 were
poured into separate sludge treated jars, respectively, and stirred
under constant RPM. After a pre-defined time, the liquids were
poured out and the jars were examined for mud removal efficiency.
Composition 1 effectively removed the muds 100% within 5 minutes.
The organic solvent in Composition 1 can be further reduced to 30%
by volume. For Composition 2, a contact time of 10 minutes was
needed for 100% cleaning efficiency. Sludge and Paraffin/Asphaltene
Removal: A mud sludge or crude with high content of
paraffin/asphaltene was first coated on the inner surface of a
glass jar. 100 ml of Composition 1 and 2 were poured into separate
sludge-treated jars and stirred under constant RPM. After
pre-defined time, the liquids were poured out and the jars examined
for mud removal efficiency. Composition 1 completely removed heavy
crude oil with high content of asphaltene from a glass jar within 7
minutes of contact time. Composition 2 cleaned all the mud and
sludge 100% within 2 minutes of contact time.
[0077] The Example demonstrates use of the invention as a spearhead
fluid which can remove the heavy crude and asphaltene from the
formation and leave its surface clean for subsequent well
treatments.
Example 2
[0078] An emulsion was prepared consisting of 65% Bio-Base 637, 28%
water, 3 pounds per barrel (ppb) soda ash and 7% Tween 81. (All
percentages expressed in this Example are volume percentages.) The
emulsion was prepared by introducing the oil and surfactant into a
vessel and mixing the components at room temperature until
uniformly mixed, about 10 minutes. To the resultant was added an
aqueous system containing the soda ash. The components were then
mixed at room temperature until uniformly mixed, about ten minutes.
The resulting product, Treatment Emulsion, contained linear
paraffins and surfactant as the external phase and an aqueous
internal phase. The pH of the emulsion was approximately 9.5.
Examples 3-12
[0079] Ten field drilling mud systems from actual drilling
operations with varying compositions were used to evaluate the
effectiveness of the Treatment Emulsion to break down the
interfacial and/or rheological properties of the mud cakes and
adherence of the cakes to the formation. Table I outlines the ten
drilling mud systems as well as their mud density and rheological
properties at 70.degree. F.
TABLE-US-00002 TABLE I Fann Dial Fann Dial Fann Dial Fann Dial
Example Readings Readings Readings Readings 10 sec Gel/ No. Density
600/300 200/100 60/30 6/3 10 min Gel 3 14.0 ppg 200/110 75/42 27/17
6/5 5/25 4 9.0 ppg 67/47 40/30 22/17 9/7 2/10 5 9.2 ppg 105/62
45/25 15/6 1/1 1/2 6 14.0 ppg 48/28 19/12 8/7 3/2 3/5 7 12.5 ppg
64/34 24/12 12/7 2/1 1/1 8 13.3 ppg 186/100 70/41 26/16 6/5 9/12 9
15.5 ppg >320/220 172/92 57/32 8/5 7/22 10 15.9 ppg 133/75 55/33
21/14 6/5 5/8 11 18.5 ppg 292/160 112/62 42/27 12/9 10/14 12 18.8
ppg >320/192 137/77 53/35 16/14 4/22
[0080] A dynamic (stirred) high-temperature high-pressure (HTHP)
fluid loss cell was used to evaluate the effectiveness of the
Treatment Emulsion in removing the drilling mud filter cakes. This
HTHP filter press was used to measure filtration properties under
varying dynamic downhole temperature conditions. A motor driven
shaft was fitted with a propeller blade rotated at varying speeds
inside a standard 500 ml HTHP cell. RPM settings from 1 to 1600 rpm
were selected to give laminar or turbulent flow to the fluid inside
the cell. Power was driven to the stirring shaft by a timing belt
that was easily accessible for quick adjustment and removal. A
variable speed motor controlled through a speed control recorder
(SCR) provided the ability to change the speed of the stirring
shaft. A digital tachometer indicated the rpm reading of the
stirring shaft.
[0081] The modified HTHP fluid loss cell was utilized to form the
mud filter cake with each of the ten drilling mud systems and to
test various formulations for breaking mud filter cakes. In each
test, a mud filter cake was obtained by filtration of the mud
system on Fann specially hardened filter paper. A one lab barrel
aliquot of the well mixed field drilling mud was poured into the
HTHP cell and the cell was capped. Each test mud was heat-aged for
a 20-minute period at 150.degree. F. (65.degree. C.) and 300-rpm
stirring shear stress. After the 20-minute heat-aging period, the
mud filter cake was generated by applying a 250-psi nitrogen
differential pressure to atmosphere with 300-rpm stirring shear
stress on the HTHP cell for three hours. Fluid loss data was
recorded during the three-hour filter cake formation. After the
3-hour incubation period, the cell was depressurized, excess mud
decanted out of the cell, and the mud filter cake was removed from
the cell. The total weight and thickness of the mud filter cake was
then determined.
[0082] Another lab barrel aliquot of each mud, respectively, was
then added to the Dynamic HTHP fluid loss cell to generate a new
filter cake which was then used to evaluate the ability of the
Treatment Emulsion to break the mud filter cake. The procedure
outlined in the paragraph above was repeated to generate each mud
filter cake, respectively. At the end of the 3-hour period, the
cell was removed from the heater jacket and depressurized. The HTHP
cap was removed and the mud sample was decanted slowly from the
cell. One lab barrel of the Treatment Emulsion was slowly poured
down the side of the cell and the stirrer cap assembly was replaced
on top of the cell. The HTHP cell was placed back into the
pre-heated jacket at 150.degree. F. and pressurized with 250-psi
nitrogen. The Treatment Emulsion was stirred for 10 minutes at
300-rpm to simulate pumping of the Treatment Emulsion down the
wellbore. Stirring rate was monitored and maintained with the speed
controller and tachometer located on the motor assembly. After the
10-minute period, the stirrer mechanism was shut off and the
Treatment Emulsion was allowed to stand for 17 hours at 150.degree.
F. and 250-psi nitrogen pressure. After the 17-hour static soak,
the stirrer mechanism was restarted for a 10-minute period at
300-rpm to simulate pumping the Treatment Emulsion from the
wellbore. After the 10-minute period, stirring was stopped and the
HTHP cell was removed from the heater jacket and the pressure
released. The HTHP cap was removed, and the Treatment Emulsion was
decanted out of the cell. The HTHP cell bottom was removed and the
hardened filter paper was removed to observe and quantify the
remaining mud filter cake.
[0083] The post-treatment filter cake was evaluated for thickness
and the remaining deposited residue by weight. Differences between
the initial and post-treatment filter cake weight were used to
calculate the % Mud Removal of the Treatment Emulsion for each mud
filter cake. Table II sets forth the % Mud Removal for each the 10
test muds.
TABLE-US-00003 TABLE II Example No. % Mud Removal 3 92% 4 99% 5 95%
6 75% (after drying, the remaining deposits were shown to be non-
emulsified solids.) 7 88% 8 92% 9 85% 10 99% 11 96% 12 85%
As presented in Table II, Examples 3-12 demonstrate the
effectiveness of the Treatment Emulsion in breaking interfacial
and/or rheological properties of filter cakes and acting as a
demulsifier to break the water-in-oil emulsions of a wide range of
mud types. Furthermore, the Treatment Emulsions were very efficient
in breaking the residual emulsions inside the filter cake,
decreasing cake cohesion, and reducing filter cake adherence.
Example 13
[0084] Two emulsions (Composition 3 and Comparative Composition 4)
were prepared as designated below (percentages reference volume
percentage):
TABLE-US-00004 Composition 3: Comparative Composition 4: 51.2% of
15% HCl 49.5% of US-40 4.7% of MDR-1 0.5% MDR-E 0.5% of CI-25 0.5%
of CI-25 41.7% of d-limonene 49.5% of MDR-1 1.9% of E-31
Composition 3 was prepared by introducing the d-limonene, CI-25 and
E-31 into a vessel and mixing the components at room temperature
until uniformly mixed, about 5 minutes. To the resultant was slowly
added an aqueous system containing the HCl and MDR-1 while mixing
at high shear. The components were then mixed at high shear until
uniformly mixed, about 10 minutes. The resulting product contained
the d-limonene and E-31 as the external phase and an aqueous
internal phase. Comparative Composition 4 was prepared by
introducing each of the components except MDR-1 into a vessel and
mixing the components at room temperature until uniformly mixed,
about 5 minutes. The MDR-1 was then added slowly while mixing at
high shear, and then mixed at high shear for about 8 minutes.
Examples 14-16
[0085] The compositions of Example 13 were used to remove a filter
cake deposited from two commercially available pH sensitive
invert-emulsion reservoir drill-in fluids (DIFs), one of which, the
9.6 ppb DIF, contained sized calcium carbonate bridging material
(approximately 40 ppb). 20 ppb formation shale and 10 ppb formation
sand were added as drilled solids to each DIF.
[0086] For Example 14, a Brine/DIF emulsion was prepared by mixing
the 9.6 ppg DIF with 9.6 ppg NaCl Brine in a 1:1 volume ratio. The
resultant Brine/DIF emulsion was then mixed at a rate of 1000 rpm
for about 1 minute, and was used in several tests summarized
below.
[0087] In Examples 15 and 16, a 9.2 ppg commercial solids-free
drill-in fluid was used without CaCO.sub.3.
[0088] A dynamic (stirred) high-temperature high-pressure (HTHP)
fluid loss cell and 10 micron ceramic disc were used to evaluate
the effectiveness of Composition 3 and Comparative Composition 4 in
removing the deposited DIF filter cake.
[0089] The test procedures are summarized as follows: [0090] 1.
Establish initial production direction flow rate to diesel at 10
psi and 140.degree. F. [0091] 2. Establish initial injection
direction flow rate to diesel at 10 psi and 140.degree. F. [0092]
3. Fill the cell with preheated drill-in fluid and begin the static
leak-off test at 200 psi differential pressure and 140.degree. F.
[0093] 4. Record the filtrate volume every five minutes for four
hours. [0094] 5. Decant the excess drill-in fluid without
disturbing the filter cake. [0095] 6. For Example 14 and 16, place
50 cc's of the Brine/DIF emulsion of Example 14 on top of the
deposited filter cake. For Example 15, no Brine/DIF emulsion was
placed on top of the deposited filter cake. [0096] 7. Place 250
cc's of Composition 3 (Example 14) or Comparative Composition 4
(Example 16) on top of the Brine/DIF emulsion. In Example 15, 250
cc's of Comparative Composition 4 was placed directly on top of the
deposited filter cake (Brine/DIF emulsion was not used). [0097] 8.
Shut-in the cell at 200 psi for 48 hours at 140.degree. F.
Periodically open the bottom valve and check for fluid breaking
through the filter cake. Once 10 cc's of break-through fluid was
collected, the bottom valve was closed for the duration of the
test. [0098] 9. After the shut-in time, decant the treatment fluid
out of the HTHP cell. [0099] 10. Establish final production
direction flow rate to diesel at 10 psi and 140.degree. F. [0100]
11. Establish final injection direction flow rate to diesel at 10
psi and 140.degree. F. [0101] 12. Calculate the percent return flow
for both directions.
[0102] In Example 14, The Brine/DIF emulsion was used in Step 6 and
Composition 3 was used in Step 7 of the test procedure. A return
flow rate of 94% was obtained in the production direction and 89%
in the injection direction, respectively. The Composition 3
treatment broke through both the Brine/DIF emulsion and the filter
cake after approximately 55 minutes at 200 psi. The cell was
thereafter shut-in for the remaining time.
[0103] In Examples 15 and 16, Comparative Composition 4 was used.
No Brine/DIF emulsion was used in Example 15 and return flow rates
of 95% and 93% were obtained in the production and injection
directions, respectively. For Example 16, the Brine/DIF emulsion
prepared for Example 14 was used in Step 6. Return flow rates of
99% in the production direction and an 83% in the injection
direction were obtained.
[0104] Fluid loss results summarizing each of the Examples 14 to 16
are presented in Tables III, IV and V, respectively.
TABLE-US-00005 TABLE III Elapsed Time, Filtrate Weight Filtrate
Volume minutes (grams) (cc) 5 1.3 1.1 10 1.4 1.2 15 1.4 1.2 20 1.5
1.3 25 1.5 1.3 30 1.6 1.4 35 1.6 1.4 40 1.7 1.5 50 1.7 1.5 55 1.8
1.5 65 1.8 1.6 70 1.9 1.7 80 1.9 1.7 85 2.0 1.7 90 2.1 1.8 120 2.1
1.8 125 2.2 1.9 145 2.2 1.9 150 2.3 2.0 180 2.3 2.0 185 2.4 2.1 215
2.4 2.1 220 2.5 2.2 240 2.5 2.2
TABLE-US-00006 TABLE IV Elapsed Time, Filtrate Weight Filtrate
Volume minutes (grams) (cc) 5 13.2 12.0 10 13.4 12.1 15 13.5 12.2
20 13.6 12.3 25 13.6 12.3 30 13.7 12.4 35 13.7 12.4 40 13.9 12.6 45
13.9 12.6 50 14.0 12.7 55 14.0 12.7 60 14.1 12.8 70 14.1 12.8 75
14.2 12.9 80 14.3 13.0 85 14.3 13.0 90 14.4 13.1 100 14.4 13.1 105
14.5 13.1 120 14.5 13.1 125 14.5 13.1 130 14.6 13.2 135 14.7 13.3
145 14.7 13.3 150 14.8 13.4 165 14.8 13.4 170 14.9 13.5 175 14.9
13.5 180 15.0 13.6 200 15.0 13.6 205 15.1 13.7 220 15.1 13.7 225
15.2 13.8 235 15.2 13.8 240 15.3 13.9
TABLE-US-00007 TABLE V Elapsed Time, Filtrate Weight Filtrate
Volume minutes (grams) (cc) 5 10.9 9.9 10 11.9 10.8 15 12.5 11.3 20
12.9 11.7 25 13.2 12.0 30 13.4 12.1 35 13.6 12.3 40 13.8 12.5 45
13.8 12.5 50 14.1 12.8 55 14.3 13.0 60 14.4 13.1 130 14.4 13.1 135
14.6 13.2 140 14.8 13.4 145 14.8 13.4 150 15.0 13.6 200 15.0 13.6
205 15.1 13.7 210 15.5 14.1 220 15.5 14.1 225 15.6 14.1 230 15.6
14.1 235 157 14.2 240 15.7 14.2
[0105] From the foregoing, it will be observed that numerous
variations and modifications may be effected without departing from
the true spirit and scope of the novel concepts of the
invention.
* * * * *