U.S. patent application number 11/460843 was filed with the patent office on 2007-02-08 for prevention of water and condensate blocks in wells.
Invention is credited to Keng Seng Chan, Pascal Cheneviere, Philippe Enkababian, Mohan K.R. Panga, Mathew Samuel.
Application Number | 20070029085 11/460843 |
Document ID | / |
Family ID | 37716614 |
Filed Date | 2007-02-08 |
United States Patent
Application |
20070029085 |
Kind Code |
A1 |
Panga; Mohan K.R. ; et
al. |
February 8, 2007 |
Prevention of Water and Condensate Blocks in Wells
Abstract
Compositions and methods are given to prevent, alleviate and
remedy water blocks and gas blocks (condensate block or condensate
banking). Wettability modifiers are contacted with the formation to
change the surfaces from water wet or oil wet to intermediate wet
or gas wet. Preferred wettability modifiers include partially or
completely fluorinated surfactants or polymers, for example
fluorosilanes such as perfluorosilanes, urethane oligomers
containing perfluoro alkyl moieties, fluoroacrylates, and
fluoroalkyl containing terpolymers or their mixtures. Other
examples include surfactants, for example viscoelastic surfactants
such as cationic surfactants such as quaternary amines, and
zwitterionic surfactants, such as betaines, optionally mixed with
co-surfactants.
Inventors: |
Panga; Mohan K.R.; (Sugar
Land, TX) ; Samuel; Mathew; (Kuala Lumpur, MY)
; Chan; Keng Seng; (Kuala Lumpur, MY) ;
Enkababian; Philippe; (Balikpapan, ID) ; Cheneviere;
Pascal; (PAU Cedex, FR) |
Correspondence
Address: |
SCHLUMBERGER TECHNOLOGY CORPORATION
IP DEPT., WELL STIMULATION
110 SCHLUMBERGER DRIVE, MD1
SUGAR LAND
TX
77478
US
|
Family ID: |
37716614 |
Appl. No.: |
11/460843 |
Filed: |
July 28, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60706238 |
Aug 5, 2005 |
|
|
|
Current U.S.
Class: |
166/263 ;
166/305.1; 166/312; 507/205; 507/240; 507/250; 507/265 |
Current CPC
Class: |
C09K 8/88 20130101; C09K
8/588 20130101; C09K 8/584 20130101; C09K 8/602 20130101; C09K
2208/30 20130101; E21B 43/25 20130101; C09K 8/035 20130101 |
Class at
Publication: |
166/263 ;
166/305.1; 166/312; 507/250; 507/240; 507/265; 507/205 |
International
Class: |
E21B 43/22 20070101
E21B043/22; E21B 43/25 20070101 E21B043/25 |
Claims
1. In a subterranean formation penetrated by a well bore, the
formation containing an accumulation of liquid, selected from
water, oil, condensate, and mixtures thereof, that is blocking at
least some flow of fluid in the formation, a method for removing at
least a portion of the accumulation of liquid, selected from water,
oil, condensate, and mixtures thereof, by altering the wettability
of the formation from an initially oil or water wet state to an
intermediate or gas wet state, comprising the step of contacting
the formation with a treatment fluid comprising a wettability
modifier.
2. The method of claim 1 wherein the step of contacting is preceded
by a preflush step.
3. The method of claim 1 wherein the step of contacting is followed
by a postflush step.
4. The method of claim 1 wherein the step of contacting further
comprises a soak period.
5. The method of claim 1 wherein the treatment fluid comprises more
than one wettability modifier.
6. The method of claim 1 wherein the wettability modifier is
selected from the group consisting of cationic surfactants,
quaternary amines, erucyl bis-(2-hydroxyethyl) methyl ammonium
chloride, zwitterionic surfactants, betaines, erucic amidopropyl
dimethyl betaine, cocoalkyl betaines, cocoamido betaines, cocoalkyl
amines, cocoalkyl acetates, tallow alkyl amine acetates, and
cocoamphodiacetates.
7. The method of claim 1 wherein the wettability modifier is
selected from the group consisting of fluorosurfactants and
fluoropolymers.
8. The method of claim 7 wherein the fluoropolymers are selected
from the group consisting of fluorosilanes, fluoroalkoxysilanes,
polymeric fluoroacrylates, perfluoro alkyl urethane oligomers, and
mixtures thereof.
9. The method of claim 1 wherein the wettability modifier is
present in a concentration of between about 0.1 per cent by volume
and about 10 per cent by volume of active material.
10. The method of claim 9 wherein the wettability modifier is
present in a concentration of between about 0.5 per cent by volume
and about 5 per cent by volume of active material.
11. In a subterranean formation penetrated by a well bore, a method
for reducing the formation of an accumulation of liquid, selected
from water, oil, condensate, and mixtures thereof, that would block
the flow of fluid, by altering the wettability of the formation
from an initially oil or water wet state to an intermediate or gas
wetting state by the step of contacting the formation with a
wettability modifier.
12. The method of claim 11 wherein the step of contacting is
preceded by a preflush step.
13. The method of claim 11 wherein the step of contacting is
followed by a postflush step.
14. The method of claim 11 wherein the step of contacting further
comprises a soak period.
15. The method of claim 11 wherein the treatment fluid comprises
more than one wettability modifier.
16. The method of claim 11 the wettability modifier is selected
from the group consisting of cationic surfactants, quaternary
amines, erucyl bis-(2-hydroxyethyl) methyl ammonium chloride,
zwitterionic surfactants, betaines, erucic amidopropyl dimethyl
betaine, cocoalkyl betaines, cocoamido betaines, cocoalkyl amines,
cocoalkyl acetates, tallow alkyl amine acetates, and
cocoamphodiacetates.
17. The method of claim 11 wherein the wettability modifier is
selected from the group consisting of fluorosurfactants and
fluoropolymers.
18. The method of claim 17 wherein the fluoropolymers are selected
from the group consisting of fluorosilanes, fluoroalkoxysilanes,
polymeric fluoroacrylates, perfluoro alkyl urethane oligomers, and
mixtures thereof.
19. The method of claim 11 wherein the wettability modifier is
present in a concentration of between about 0.1 per cent by volume
and about 10 per cent by volume of active material.
20. The method of claim 19 wherein the wettability modifier is
present in a concentration of between about 0.5 per cent by volume
and about 5 per cent by volume of active material.
21. The method of claim 11 wherein the step of contacting the
formation with a wettability modifier comprises incorporating the
wettability modifier in a treatment fluid selected from the group
consisting of drilling fluids, completion fluids, and stimulation
fluids.
22. In a subterranean formation penetrated by a well bore, a method
for preventing the formation of an accumulation of liquid, selected
from water, oil, condensate, and mixtures thereof, that would block
the flow of fluid, by altering the wettability of the formation
from an initially oil or water wet state to an intermediate or gas
wetting state by the step of contacting the formation with a
wettability modifier.
23. The method of claim 22 wherein the step of contacting is
preceded by a preflush step.
24. The method of claim 22 wherein the step of contacting is
followed by a postflush step.
25. The method of claim 22 wherein the step of contacting further
comprises a soak period.
26. The method of claim 22 wherein the treatment fluid comprises
more than one wettability modifier.
27. The method of claim 22 wherein the wettability modifier is
selected from the group consisting of cationic surfactants,
quaternary amines, erucyl bis-(2-hydroxyethyl) methyl ammonium
chloride, zwitterionic surfactants, betaines, erucic amidopropyl
dimethyl betaine, cocoalkyl betaines, cocoamido betaines, cocoalkyl
amines, cocoalkyl acetates, tallow alkyl amine acetates, and
cocoamphodiacetates.
28. The method of claim 22 wherein the wettability modifier is
selected from the group consisting of fluorosurfactants and
fluoropolymers.
29. The method of claim 28 wherein the fluoropolymers are selected
from the group consisting of fluorosilanes, fluoroalkoxysilanes,
polymeric fluoroacrylates, perfluoro alkyl urethane oligomers, and
mixtures thereof.
30. The method of claim 22 wherein the wettability modifier is
present in a concentration of between about 0.1 per cent by volume
and about 10 per cent by volume of active material.
31. The method of claim 30 wherein the wettability modifier is
present in a concentration of between about 0.5 per cent by volume
and about 5 per cent by volume of active material.
32. The method of claim 22 wherein the step of contacting the
formation with a wettability modifier comprises incorporating the
wettability modifier in a treatment fluid selected from the group
consisting of drilling fluids, completion fluids, and stimulation
fluids.
Description
[0001] This application claims the benefit of U.S. Provisional
Patent Application No. 60/706238, filed on Aug. 5, 2005.
FIELD OF THE INVENTION
[0002] The invention relates to the prevention of water blocks and
the prevention of condensate banking in oil and gas producing
subterranean formations. More particularly, it relates to treating
subterranean formations to change the wettability from oil or water
wet to intermediate wet or gas wet.
BACKGROUND OF THE INVENTION
[0003] The accumulation of water near the wellbore in an oil or gas
well can decrease the productivity by decreasing the relative
permeability of oil or gas. The sources for water accumulation
could be filtrate water from drilling mud, cross flow of water from
water-bearing zones, water from completion or workover operations,
water from matrix/fracture treatments, water from emulsions, etc.
The problem of productivity decline because of an increase in near
wellbore water saturation is known as water block.
[0004] In gas wells, in addition to water, liquid hydrocarbons that
accumulate near the wellbore can also decrease the productivity of
gas. The sources for the accumulation of hydrocarbons could be the
use of oil-based drilling mud in drilling operations, hydrocarbon
liquids used in workover operations, the use of oil-based
fracturing fluids, etc. In addition to such external sources, the
liquid hydrocarbons that condense out of the gas phase (called
condensates) due to the decline in pressure below the dew point
pressure of the gas also hinder the gas production. This phenomenon
of condensation with a decrease in pressure is called retrograde
condensation. When condensates block the production, the problem is
called condensate block or condensate banking. In this
specification, the term condensate banking is used for a decline in
gas production due to any liquid hydrocarbons, condensates, or
hydrocarbons from external sources such as those mentioned above,
for example oil based drilling muds.
[0005] Water blocks and condensate banks can occur together or
independently, leading to a decrease in well productivity and in
some cases to complete shut down in production. (See, for example,
SPE papers 13650, 28479, and 30767.) During the early stages of
production, condensate banking occurs close to the wellbore where
the pressure first decreases below the dew point pressure. Even for
a small amount of condensate drop out (as a fraction of the
produced hydrocarbon), significant condensate build-up can occur,
as several pore volumes of gas pass through the wellbore. With
time, the condensate bank extends deep into the reservoir due to
drawdown and depletion of the reservoir pressure. Unlike water
blocks, which mainly affect the near wellbore region, condensate
banks can affect a region far from the wellbore. Condensate banking
is a continuing problem, because the condensate accumulates with
time even after an initial cleanup.
[0006] To increase temporarily the production in a well affected by
water block or condensate bank the following methods have been
employed (see SPE paper 77546): fracturing the well; dry gas
injection; and solvent injection (see, for example, SPE papers
62935, 63161, 68683, 80901, and 84216). In fracturing, the purpose
is to bypass the zone damaged by water or by condensate blocks and
to increase the bottomhole pressure, if possible, above the dew
point pressure to decrease the formation of condensate. In dry gas
injection, the clean up is by vaporization of condensate into the
gas (see, for example, SPE papers 68683 and 71526). In the third
method, solvents such as methanol, isopropyl alcohol, and others,
are injected into the well. The solvents mix with water or
condensate and enhance clean up by reducing the interfacial tension
and by increasing the volatility of the liquid.
[0007] The methods described above are remedial, and help in the
temporary clean-up of existing water or condensate blocks. If the
above-mentioned methods are used, then if the water block or
condensate bank problem reoccurs, then the well must be treated
again. It would be beneficial to have a more permanent method of
preventing water block and gas banking.
SUMMARY OF THE INVENTION
[0008] A method has been developed for prevention of water blocks
in gas and oil wells and condensate blocks in gas wells using
wettability modifiers. This method may be applied to all oil or gas
wells with no water or condensate block problems as a preventive
solution. It may also be used as a remedial method for clean-up of
most or all of existing water or condensate blocks; after these
clean-ups it will act to prevent future water block or condensate
blocking in the same location. Alternatively, the chemical system
may be mixed with fluids used in fracturing, acidizing, drilling
and other workover operations to unload the unwanted oil or water
based fluids that enter the formation during the operation. The
method may also be used to enhance production in oil wells and
injection of water in injector wells because of low near well bore
pressure drop resulting from the wettability alteration. The
wettability alteration is permanent.
[0009] The application of this method to treating a subterranean
formation may involve single or multiple stages, separated into
pretreatment, main and post treatment stages. The pretreatment
stage may involve injection of a preflush of water or brine, one or
more alcohols, one or more of other solvents, one or more clay
stabilizers, one or more water-solvent mixtures, or one or more
treatment fluids used in such oilfield treatments as matrix
stimulation, and other treatments, one or more other fluids, or
mixtures of such fluids. In the main stage, the wettability
modifier may be dispersed or mixed in a carrier fluid that may be a
solvent or water and may be injected into the well. Optionally, the
formation may be soaked in the fluid that contains a wettability
modifier for a period of time (shut-in period). The soaking may not
be necessary for some wettability modifiers, some formations, or
some conditions. The wettability modifier adheres to the formation
by adsorption, chemical bonding, aggregation, electrostatic
attraction, precipitation, aggregation, etc. In a typical post
treatment stage the fluid injected in the main stage is displaced
immediately after the main stage, or after a shut-in period, using
a gas such as N.sub.2, CO.sub.2, etc., or any of the fluids used in
the pretreatment stage, or fluids similar to those fluids. This
procedure provides better placement of the wettability modifier,
and/or enhancement of the flow back of the fluid or fluids injected
in the main stage. In this specification, we may occasionally use
the term "solvent" or "carrier fluid" for any of the pretreatment
main or post treatment fluids. When the well is put into
production, or back on production, or used as an injector, the
solvent and the left-over wettability modifier flow out of the
formation or deeper into the formation, leaving a coating of the
wettability modifier in the formation. This alters the wettability
of the formation that is initially water or oil wet to an
intermediate or gas wetting condition that reduces the capillary
pressure of the formation. During the production life cycle of the
well, although it generally will not occur, if any water or
condensate accumulate in this wettability altered zone, they may
easily be cleaned up, thus preventing the formation of water or
condensate blocks and enhancing production.
[0010] The wettability modifiers may include cationic, anionic, or
zwitterionic surfactants, or polymers containing chemical groups or
moieties that have a tendency to repel oil or water. For example,
the presence of fluorine in the surfactant or polymer may give both
hydrophobic and oleophobic nature to the chemical. Preferred
wettability modifiers include partially or completely fluorinated
surfactants or polymers, for example fluorosilanes such as
perfluorosilanes, urethane oligomers containing perfluoro alkyl
moieties, fluoroacrylates, and fluoroalkyl containing terpolymers.
Other examples include surfactants, such as cationic, zwitterionic,
anionic, and nonionic surfactants.
[0011] The wettability modifier may be introduced in solution, for
example in water, brine, an alcohol such as methanol, isopropyl
alcohol, etc., a ketone, an ether, an ester, hydrocarbons such as
petroleum distillates, diesel, biodiesel, or their derivatives, or
a mixture of these solvents.
[0012] Since this is a preventive or remediative treatment, the
fluids injected into the formation should not create an additional
water or condensate block. Thus, the carrier fluid for the
chemicals may optionally contain solvents that are volatile (e.g.:
alcohol-based solvents) or have low interfacial tension with the
gas phase (low capillary pressure) so that, when the well is put on
production, the fluid flows out of the formation or deeper into the
formation either because of displacement by the gas or evaporation
into the gas phase because of high volatility. Since the
wettability modifier is adhering to the formation and cannot easily
be removed by the flow of fluids or gas, this composition and
method provides a long-term solution for the prevention of
water/condensate blocks.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] FIG. 1 shows the contact angle .theta. of water when placed
on a solid surface.
[0014] FIG. 2 shows the experimental set-up for the imbibition
test.
[0015] FIG. 3 shows imbibition data for a fluorocarbon wettability
modifier of the Invention, before and after treatment.
[0016] FIG. 4 shows imbibition data with another fluorocarbon
wettability modifier of the Invention, before and after
treatment.
[0017] FIG. 5 shows imbibition data with a cationic surfactant
wettability modifier of the Invention, before and after
treatment.
[0018] FIG. 6 shows brine saturation in a core before and after
treatment with a fluorocarbon wettability modifier of the
Invention.
DETAILED DESCRIPTION OF THE INVENTION
[0019] A long-term solution for preventing or remediating water
block and condensate banking (gas blocking) has been found. A well
that does not have a water block or condensate bank problem is
treated with the method to prevent formation of water blocks or
condensate banks in the future. This method may also be used to
clean up existing water or condensate blocks in the well and to
protect against the occurrence of future water block and condensate
banking. (The terms "gas banking" and "condensate banking/block"
are used interchangeably here.)
[0020] Water and condensate blocks occur when a formation is liquid
wet, i.e. either water wet or oil wet. When a well is treated using
the chemical method described here, the wettability of the
formation is altered from water-wet or oil-wet to intermediate or
gas-wetting conditions. The alteration of wettability of a
formation that is initially water or oil wet to intermediate or gas
wetting creates a hydrophobic (water repelling) and oleophobic (oil
repelling) surface. Because of this wettability alteration, water
or condensate blocks can be cleaned up easily. The chemicals used
in this method adhere to the pore walls of the formation by
chemical bonding, adsorption, precipitation, aggregation, or
electrostatic attraction, etc., with minimal damage, and cannot
easily be removed by the flow of liquids or gases. As a result, the
induced intermediate or gas wettability by treatment with the
chemical lasts for a long time, thus providing a long-term
preventive solution to the formation of water and condensate
blocks.
[0021] This prevention method may be applied to newly drilled oil
or gas wells before putting them on production or to producing
wells to prevent formation of water or condensate blocks. In cases
in which the well is already affected by water or condensate
blocks, use of this method enhances clean-up (flow back of water
and oil that enter the formation during the operation or by cross
flow) and may be used for remediation. The chemical system may be
mixed with fluids used in fracturing, acidizing, drilling or other
well intervention operations to unload the water or oil that may
invade the formation during these operations. The wettability
modifier, along with the carrier fluid, may also be pumped as a
preflush or post flush before pumping a treatment such as hydraulic
fracturing, acid fracturing, matrix stimulation, drilling, gravel
packing, frac packing, stim packing, water packing, water fracing,
lost circulation control, diversion, sand control, scale
dissolution, scale removal, scale control, water control, mud
damage removal, completion, mud cake cleaning, or other. The low
pressure drop experienced by flowing liquids in such
wettability-altered formations (altered from oil or water-wet to
intermediate or gas-wet) may also be used to decrease the near
wellbore pressure drop, thus enhancing both the production of oil
in producing wells and the injectivity of water in injector wells.
The wettability modifier adheres to the formation and creates an
intermediate or gas-wetting surface that enhances the flow back of
water and oil that enter the formation during the operation.
[0022] In another application of this method a producing oil well
or water injection well may be treated with the carrier fluid
containing a wettability modifier to alter the wettability of the
formation to intermediate or gas wetting. The altered wettability
increases the liquid permeability of the medium, thereby enhancing
production from oil wells and injectivity of injection wells.
[0023] The invasion of water into a formation or a layer of a
formation may occur when the fluid pressure, for example in a well
or fracture or layer of a formation, is greater than the formation
fluid pressure or the pressure in a layer, or when there is a
pressure difference between different layers in the formation, or
when there is imbibition, for example from a well or fracture or
another layer into a given layer or formation. For example, in
hydraulic fracturing, the high injection pressure of the fluid used
to fracture a well may cause water-based fracturing fluids to leak
into the formation. This is very typical in a fracturing treatment
and clean-up of the fluid entering the formation may or may not be
a problem depending on the nature of the fluid, the nature of the
formation, and the amount of fluid that enters the formation (see
for example SPE paper 38620). Water may also enter the formation
through imbibition, a process in which a wetting phase displaces a
non-wetting phase in a porous medium. For example, if, for a porous
medium, the wetting phase is water (i.e., the formation is water
wet) and the non-wetting phase is gas and/or oil, then if the
formation contains mobile oil and/or gas, upon contact, water will
imbibe into the porous medium, displacing the gas and/or oil in the
medium. Once water enters the formation it may be trapped there,
creating a water block if the formation fluids (oil and/or gas)
cannot displace it. The reasons for water-trapping could be high
capillary pressure at the water-gas or water-oil interface,
interaction of water with minerals such as clays in the formation,
etc. In gas wells, water trapping may also occur due to viscous
fingering because the gas has lower viscosity than water. In such a
case, the gas breaks through the trapped water (fingers through the
water) leaving a high saturation of water near the wellbore, which
creates a water block.
[0024] In condensate banking, condensate drops out of the gas phase
when the gas pressure falls below the dew point pressure. This
phenomenon, where liquid hydrocarbons condense out of the gas phase
with a decrease in pressure below the dew point, is called
retrograde condensation. Due to a steep decrease in pressure near
the well bore, the well flowing pressure first falls below the dew
point, at which time liquid hydrocarbons condense out of the gas
phase. Due to drawdown and reservoir depletion, the pressure
farther and farther away from the wellbore gradually decreases
below the dew point and the condensed liquid hydrocarbon slowly
accumulates, forming a condensate bank. As mentioned earlier, in
addition to condensates, liquid hydrocarbons may also accumulate in
the formation because of external sources.
[0025] One of the ways of enhancing clean-up of trapped water or
trapped liquid hydrocarbons is by decreasing the capillary pressure
at the water-gas or oil-gas interface. The capillary pressure
across a gas-liquid interface is given by the Young-Laplace
equation, P.sub.c=2.pi.cps.theta./r (Eq. 1) where P.sub.c is the
capillary pressure, .sigma. is the interfacial tension at the
gas-liquid interface, .theta. is the contact angle and r is the
mean radius of curvature of the gas-liquid interface. In a porous
medium, the mean radius of curvature is approximated by the mean
pore size, which may be approximated further by the relation
r.about. {square root over (k/.phi.)} where k is the permeability
and .phi. is the porosity of the porous medium. Thus, in general,
capillary pressure is strong in low permeability formations and
weak in high permeability formations. The problem of water and
condensate blocks may be reduced if the capillary pressure across
the gas-liquid interface can be decreased. From Eq. 1, it can be
seen that the capillary pressure can be decreased by reducing the
interfacial tension between the fluid and the gas, by increasing
the contact angle, or by increasing the permeability of the
medium.
[0026] Addition of interfacial tension reducers such as surfactants
or alcohol-based solvents can decrease the capillary pressure.
However, this method is only temporary, because the conventionally
used surfactants and solvents flow out of the formation once the
well is put into production. If the water block or
condensate-banking problem occurs again, which is to be expected
because the underlying cause has not been addressed, then the well
has to be re-treated with solvents or surfactants when
necessary.
[0027] An alternative method of decreasing the capillary pressure
is to alter the wettability of the formation or pore surface
permanently in such a way that the contact angle .theta. of the
liquid with the pore surface is increased. For example, if the
contact angle is altered from 0.degree. to 90.degree., then the
capillary pressure can be reduced to zero (from Eq. 1), which helps
in removal of water or condensate blocks. Wettability alteration
for removal of water or condensate blocks is a long-term solution,
because the formation wettability is permanently altered.
[0028] Wettability is defined as the ability of one fluid to spread
on to a solid surface in the presence of another immiscible fluid.
When two fluids, mutually immiscible with each other, both contact
a solid surface, the less-wetting fluid will retreat from contact
with the solid while the stronger-wetting fluid will be attracted
to the surface. At the point of intersection between the two fluid
phases and the solid surface, a contact angle is produced (see FIG.
1). The three-phase contact angle that forms as a result of the
equilibrium of the three interfacial tensions is described by
Young's equation, which for a solid, liquid and gas system is shown
in Eq. 2: .sigma..sub.SG-.sigma..sub.SL=.sigma..sub.LGcps.theta.
(Eq. 2) where .sigma..sub.SG is the interfacial tension between
solid and gas, .sigma..sub.SL is the interfacial tension between
solid and liquid (water or oil) and .sigma..sub.LG is the
interfacial tension between the liquid (water or oil) and gas. When
the contact angle is less than 50.degree., the surface is referred
to as being water-wet or oil-wet; when it is greater than
90.degree., the surface is considered to be gas-wet; and the
intermediate range of contact angles from 50.degree. to 90.degree.
is considered to be representative of an intermediate wet
condition. The contact angle of water with most reservoir rocks is
very low, which means that these rocks are water wet. To reduce
capillary pressure for removal of water blocks, the contact angle
of water with the reservoir rock should be made close to or greater
than 90.degree.. Thus, the wettability of the rock has to be
altered from water wet to intermediate wet or gas wetting
conditions.
[0029] Experimental studies have been reported in the literature
for clean-up of condensate blocks in gas condensate reservoirs by
altering the wetting nature of the formation from oil or water wet
to intermediate or gas wetting. Li and Firoozabadi (Li, K., and
Firoozabadi, A., SPE Reservoir Eval. & Eng., 3(2), 139-149,
April, 2000) have used 3M-manufactured FC722 and FC754 to alter the
wettability of Berea and chalk core samples from water or oil-wet
to gas-wet. FC722 is a fluoropolymer and FC754 is a cationic
surfactant. They observed that FC754 could alter the wettability
from strong water wetting to intermediate gas-wetting and from
strong oil wetting to less oil wetting. FC722 could alter the
wettability from strong water and oil wetting to preferential gas
wetting. Tang and Firoozabadi (Tang, G., and Firoozabadi, A., SPE
Reservoir Eval. & Eng., 427-436, December, 2002; Tang G., and
Firoozabadi, A., Transport in Porous Media, 52, 185-211, 2003) have
investigated FC722 and FC759, that are manufactured by 3M, at
temperatures in the range of 25.degree. C. to 93.degree. C. Their
experiments show good wettability alteration of formations
initially oil or water wet to gas wetting after treatment with
FC722 and FC759.
[0030] The above laboratory studies investigated the use of
wettability alteration as a remedial operation to treat gas wells
affected by condensate blocks. However, experimental or field
studies reported thus far have not used wettability modification as
a preventive method for formation of water blocks in gas or oil
wells and condensate blocks in gas wells.
[0031] The invention is a method of changing the wettability of a
formation from oil wet or water wet to intermediate wet or gas wet
by contacting the formation with a wettability modifier. The
treatment eliminates or greatly reduces the tendency to form water
blocks and condensate blocks (or condensate banking). It may be
applied to prevent water blocks and/or condensate blocks in new gas
wells, oil wells, oil and gas wells, and injection wells (for
example in enhanced recovery), or to reduce or eliminate water
blocks and/or condensate blocks in producing gas wells, oil wells,
and oil and gas wells, and in injection wells. It may also be used
in wells that produce other materials such as helium or carbon
dioxide, or that are used for other purposes such as for material
storage or disposal. It may also be used as part of a treatment
(for example drilling, stimulation, or workover) of a well.
[0032] In general, the fluid used for wettability modification
contains two main components, a carrier fluid, and a wettability
modifier. However, the number of components may vary. The
wettability modifier is dispersed or mixed or diluted in the
carrier fluid to a specified concentration to achieve suitable
wettability alteration from water or oil wet to intermediate or gas
wetting conditions. This concentration depends upon the formation
type. One method of determining a suitable concentration of a
wettability modifier required for good wettability alteration is to
perform a contact angle test. The concentration that gives the
maximum contact angle is preferred. The carrier fluid may be, for
example, water, brine, an alcohol such as methanol, isopropyl
alcohol, etc., a ketone, an ether, an ester, hydrocarbons such as
petroleum distillates, diesel, biodiesel, or their derivatives, or
a mixture of these solvents, but the solvent is not limited to
these materials.
[0033] The wettability modifier may be a partially or completely
fluorinated surfactant or polymer. One example of such a polymer is
the family of fluorosilanes such as, but not limited to, 1H,
1H,2H,2H-perfluourodecyltriethoxysilane, and
1H,1H,2H,2H-perfluorooctylmethyldimethoxysilane, which may be used
in a concentration range of from about 0.1% to about 10% by volume,
preferably at a concentration of from about 0.5% to about 2% by
volume. (Note that these concentrations are expressed here as
volumes of active ingredients, not as volumes of as-received
commercial materials, which are usually purchased as concentrates
in solvents.)
[0034] Another example of such a polymer is urethane oligomers
containing perfluoro alkyl moieties, such as but not limited to
those described in the following patents and published patent
applications: US 20050075471, US 20040147188, U.S. Pat. No.
6,803,109, U.S. Pat. No. 6,753,380, US 6,646,088, WO 2005037884, WO
0214443, and WO 0162687. The US publications are hereby
incorporated in their entirety. Such materials may also be used in
a concentration range of from about 0.1% to about 10% by volume,
preferably at a concentration of from about 0.5% to about 2% by
volume (based on active ingredients).
[0035] Yet another example of such a polymer is fluoroacrylates
that have the general formula:
C.sub.nF.sub.2n+1-X--OC(O)NH-A-HNC(O)O--(C.sub.pH.sub.2p)(O)
COC(R').dbd.CH.sub.2 in which n is 1 to 5; X is
--SO.sub.2--M(R)--C.sub.mH.sub.2m--, --CO--NH--C.sub.mH.sub.2m--,
--CH(R.sub.f)--C.sub.yH.sub.2y--, or --C.sub.qH.sub.2q--; R is H or
an alkyl group of from 1 to 4 carbon atoms; m is 2 to 8; R.sub.f is
C.sub.nF.sub.2n+1; y is 0 to 6; q is 1 to 8; A is an unbranched
symmetric alkylene group, arylene group, or aralkylene group; p is
2 to 30; and R' is H, CH.sub.3, or F. Examples of this are given in
patent applications US20050143541 (hereby incorporated in its
entirety), and WO2005066224. Such materials may also be used in a
concentration range of from about 0.1% to about 10% by volume,
preferably at a concentration of from about 0.5% to about 2% by
volume (based on active ingredients).
[0036] Another example of such a polymer is a fluoroalkyl
containing terpolymer of the type described in U.S. Pat. No.
5,945,493, U.S. Pat. No. 6,238,792, and U.S. Pat. No. 6,245,116
(all hereby incorporated in their entirety): ##STR1## wherein X is
a C 2-10 alkyl, C 6-12 aryl, or C 4-12 alkoxy radical, d is from
about 3 to about 50, R is a fluoroalkyl radical R f --(A) v --(B) w
--, R f is a fully fluorinated straight or branched aliphatic
radical optionally interrupted by at least one oxygen atom, A is a
divalent radical selected from --SO 2 N(R'')--, --CON(R'')--,
--S--, or --SO 2 --, where R'' is H, or a C 1-6 alkyl radical, B is
a divalent linear hydrocarbon radical --C t H 2t --, where t is 1
to 12, Y is a divalent radical --CH 2 --O--, u, v, and w are each
independently zero or 1, R' is hydrogen or methyl, e is from about
0.05 to about 10, M is hydrogen, alkali metal, or ammonium, and f
is from about 5 to about 40. Such materials may also be used in a
concentration range of from about 0.1% to about 10% by volume,
preferably at a concentration of from about 0.5% to about 2% by
volume (based on active ingredients).
[0037] Examples of suitable surfactants are those used as
viscoelastic surfactants in fracturing fluids. Suitable cationic
surfactants of this type, such as quaternary amines, such as erucyl
bis-(2-hydroxyethyl) methyl ammonium chloride, are described in
U.S. Pat. Nos. 5,964,295, 5,979,557, 6,306,800 and 6,435,277;
suitable zwitterionic surfactants of this type, such as betaines,
such as erucic amidopropyl dimethyl betaine are described in U.S.
Pat. Nos. 6,258,859 and 6,399,546. All of these patents are hereby
incorporated in their entirety. Suitable cationic surfactants that
may be used include those that are commonly used as emulsifiers,
such as cocoalkyl amines, cocoalkyl acetates, cocoalkyl betaines,
tallow alkyl amine acetates, cocoamphodiacetates,
cocoamidobetaines, and their mixtures with or without
cosurfactants, solvents, paraffins, and hydrocarbons. Suitable
anionic surfactants may be based on phosphate head groups (for
example branched alcohol ethoxylate phosphate esters). These
surfactants are not adsorbed as strongly as are the fluoropolymers,
so they work best at lower temperatures, and the effects may not be
as long-lasting, especially at higher temperatures. These
surfactants may also be used in the concentration range of from
about 0.1% to about 10% by volume, preferably at a concentration of
from about 0.5% to about 2% by volume (based on active
ingredients).
[0038] The compositions and methods may be used as stand-alone
treatments intended to prevent or remediate water blocks and gas or
condensate banking, or the wettability modifiers can be used in
other treatment fluids. Thus, in addition to stand-alone
treatments, the compositions of the Invention may be added to a
number of main treatment fluids with beneficial results. Examples
are drilling fluids, completion fluids, stimulation fluids, for
example matrix treatment fluids, fracture fluids and gravel packing
fluids. When used in drilling and completion fluids, the
compositions prevent the formation of water blocks. When used as
additives in stimulation fluids in production wells, the
compositions speed up and increase the extent of clean up and
increase oil and gas production after the treatment. When used as
additives in stimulation fluids in water injection wells, the
compositions of the Invention increase injectivity. Alternatively,
treatments may be done as a pre-treatment before stimulation, or as
a post treatment after drilling, completion, and stimulation. In
another use, fluids containing the wettability modifiers may be
selectively introduced into certain layers of a multilayer
formation (for example by isolating them with packers), to alter
the wettability of those layers, and thereby alter either the
relative productivity or injectivity of those layers, or the
relative permeability to oil/gas or water of those layers.
[0039] Other treatment fluids are known for use in stand-alone
treatments; these are generally mixtures of components such as
alcohols, mutual solvents, ethers, esters, ketones hydrocarbons,
and mixtures of these. These fluids may alter the wettability, but
the effect is usually temporary. The compositions of the Invention
may be added to such fluids, especially at low temperatures, to
make the effects more long-lasting so that the single fluid
treatment can act as both a remedial and a prevention
treatment.
EXAMPLES
[0040] Two types of tests were conducted to check the ability of
chemical systems to alter wettability. First a contact angle test
was performed, followed by an imbibition test.
[0041] Wettability in a water-gas-rock system was determined by
observing the contact angle made by a drop of water 2 on a rock 4
with gas 6 as the third phase (see FIG. 1). The angle .theta. was
measured from the rock-water interface through the liquid to the
water-gas interface as shown in FIG. 1. When the angle .theta. was
small, then water was said to wet the rock or the rock was
water-wet in nature. When the angle .theta. was large, then water
did not wet the rock or the rock was intermediate gas wetting. The
observation was similarly extended to oil-gas-rock systems.
[0042] In a porous medium, the ability of water to wet the medium
was determined by means of an imbibition test. Imbibition is the
process in which a wetting phase displaces a non-wetting phase in a
porous medium. The experimental apparatus used for the tests is
shown in FIG. 2. In this test, a dry core 8 of known porosity and
permeability was brought into contact with a liquid 10, for example
water, such that one end of the core was slightly immersed in the
liquid. Because of capillary pressure the liquid rose into the
core, displacing the air inside the core. The amount of liquid that
had imbibed into the core was estimated by measuring the decrease
in mass of liquid with the scale 12. The core was suspended from a
line 14 connected to a stand 16. In general, if the core was
initially water wet then the amount of water imbibed was more than
40% of the void volume inside the core. However, this percentage
changed depending upon the capillary pressure, which in turn
depended upon the water-gas interfacial tension, and upon core
properties such as permeability, porosity, etc. (see Eq. 1).
Similarly, the oil wetting nature of the core was estimated using
oil instead of water as the liquid phase for the imbibition
test.
[0043] Typically, a pair of imbibition tests was performed. First,
an imbibition test was performed on a dry core to establish the
initial wettability of the core. Then the core was treated with a
solution containing the wettability modifier and a solvent that was
either alcohol-based or water-based, by flowing the solution
through the core and soaking the core in the solution for a period
of time that depended on the wettability modifier used and on the
temperature. Tests were also conducted to determine the errors due
to evaporation, and corrections were made. The wettability modifier
is believed to adhere to the surface of the pores inside the core
in this test. Then the core was dried and an imbibition test was
again performed to check the liquid imbibition rate and volume. If
either the rate of liquid intake or total volume of liquid imbibed
decreased when compared to the initial imbibition test before
treatment with the wettability modifying solution then the
wettability was considered to have been altered to an intermediate
or gas wetting nature.
[0044] To judge the ability of the method and of a specific
wettability modifier to alter wettability of the formation so that
prevention of water blocks was achieved, the following tests were
conducted. Cores used were typical sandstones, such as Berea, from
Ohio, U.S. A., Bandera, from Kansas, U. S. A., and Tunu from
Indonesia; the latter contains carbonates. The choice of sandstone
made little difference in the tests with these three sandstones,
and similar results are expected with carbonate cores. First, the
contact angle of water with a dry core chip (a thin slice of a
core) was observed by placing a drop of water on the core. Then the
core chip was treated with a solution containing a wettability
modifier by soaking it in the solution. Then the core chip was
dried and a drop of water was placed on it to check the contact
angle. If the contact angle was more than the initial contact
angle, then the wettability modifier had increased the gas wetting
nature of the core, which was desired for prevention of water
blocks.
[0045] A soak (shut in period) may optionally be used in the method
of the invention. Whether or not a soak is required in practice
depends upon the formation, and its temperature, and the choice of
the wettability modifier. Not to be limited by theory, but it is
believed that if a head group of the wettability modifier, for
example a silane head group, reacts with the surface of the
formation, for example in the pores, for example quartz components,
this occurs more rapidly at higher temperature, so less soak time
or no time will be required at higher temperatures for such
materials.
[0046] Formation minerals affect the adsorption of surfactants,
depending upon the head group charge and the charge of the mineral
surface, and this affects the required shut-in period.
Consequently, at higher temperatures desorption may occur and
wettability modifiers that act by adsorption may perform better at
low temperature than at high temperature. These factors may be
tested by simple laboratory experiments with core samples and
wettability modifier chemicals.
Example 1
[0047] The contact angle test on a core chip was observed using
water as the fluid phase, before and after treatment with a
wettability modifier (Rhodafac-PA-32.RTM., a linear alcohol
ethoxylate phosphate ester, available from Rhodia Inc., Cranbury,
N.J., U. S. A.). Before treatment, water spread on the core chip
(the contact angle was close to zero) showing that the core was
water-wet. After treatment the contact angle was greater than
90.degree. showing that the wettability had been altered to gas
wetting.
Example 2
[0048] FIG. 3 shows the data from an initial imbibition test on a
dry core and then an imbibition test on the same core after
treatment with Zonyl 8740.RTM.. Zonyl 8740.RTM. is an aqueous
dispersion containing 30% by weight of a perfluoroalkyl methacrylic
copolymer. It is commercially available from DuPont Specialty
Chemicals, Wilmington, Del., U. S. A., and is described as being a
"waterborne oil and water repellent" material. The y-axis shows the
percentage of void volume in the core occupied by water as a
function of time. Before treatment, 55% of the void volume was
filled with water in less than 50 minutes, showing that the core
was water-wet. After treatment with the wettability modifier, the
water intake was drastically reduced, showing that the wettability
of the core had been changed from water-wet to gas wetting.
Example 3
[0049] The contact angle test was performed on a core chip that had
been treated with a solution of 5% Zonyl 8740.RTM. +93 % water+2%
KCl. The contact angle was greater than 90.degree. after the
treatment, indicating that the wettability had been altered to gas
wetting. The imbibition test data for this fluid system was given
in example 2. From the contact angle and imbibition data it can be
seen that this system may be used for prevention of water blocks.
The contact angle test was also performed on a core chip that had
been treated with a dilute solution of Novec.RTM. fluorosurfactant
FC-4430, available from 3M, Performance Materials Division, St.
Paul, Minn., U. S. A. This material is a non-ionic polymeric
fluorochemical surfactant (fluoroaliphatic polymeric esters)
obtained as a solution that was 2%, in water and methanol, of a
mixture that had been 90% active ingredient, 8% non-fluorochemical
additives (polyether polymer), and 2%
N-methyl-2-pyrrolidone/toluene solvent. From the contact angle data
(not shown) it was seen that this system may be used for prevention
of water blocks. Similar experiments were also done to evaluate the
performance of additives to prevent condensate banking.
Example 4
[0050] FIG. 4 shows the results of imbibition tests made with the
wettability modifier SRC-220.RTM., a commercial fluorochemical
urethane material obtained from 3M Specialty Materials, St. Paul,
Minn., U. S. A, and described as a "Stain Resistant Additive". As
received, the material is 19-22% active material, 70-76% water, and
4-7% 2-methoxymethylethoxypropanol. It was used as 2% SRC-220.RTM.
+96% of 50% isopropyl alcohol+2% KCl. The contact angle test showed
that the wettability of the rock was changed to gas wetting
conditions (the contact angle was greater than 90.degree. after the
treatment). FIG. 4 shows that the initial imbibition into the core
was 45% of the void volume of the core. After treatment with the
fluid, the final imbibition volume was reduced to 10%, which shows
that the system may be used for water block and condensate banking
prevention.
Example 5
[0051] FIG. 5 shows the results of imbibition tests with a
wettability modifier that is a cationic surfactant; it was obtained
from Baker Petrolite, Sugar Land, Tex., U. S. A., as Aquet
942.RTM., which is supplied as about 50% active ingredient and
about 50% organic solvents. It was used as 5% Aquet 942.RTM. +93%
of 50% isopropyl alcohol+2% KCl. The contact angle test showed that
the wettability was altered to gas wetting conditions (the contact
angle was greater than 90.degree. after the treatment). The
imbibition data showed that, before treatment with the chemical
system, over 90% water was imbibed in a little over 150 minutes,
and that after treatment with the chemical the imbibition rate of
water and the total water imbibed were drastically reduced.
Example 6
[0052] Several tests were performed using cationic, anionic, and
zwitterionic surfactants, fluorosurfactants, and fluoropolymer
based chemicals to check their ability to alter wettability of the
formation and thereby to prevent water block formation. Table 1
shows the experimental data. T1 was the time taken for 60%
imbibition of water before treatment with the chemical, and T2 was
the time taken for 60% imbibition of water after treatment with the
chemical. The ratio of T2/T1 is a convenient measure of the ability
of the chemical to alter the wettability of the formation. A large
ratio indicates better wettability alteration; "inf" means
infinite. TABLE-US-00001 TABLE 1 Chemical (Vol %) T1 (min) T2 (min)
T2/T1 Aquet 942 .RTM. 5 63 786 12.5 Cationic Surfactant A 5 63 612
9.7 Cationic Surfactant B 5 83 1210 14.6 Cationic Surfactant C 5 42
954 22.7 Cationic Surfactant D 5 20 84 4.2 Zwitterionic Surfactant
2 10 38 3.8 3M SRC-220 .RTM. 2 16 inf inf (Fluoropolymer) Dupont
Zonyl 8470 .RTM. 5 40 inf inf (Fluorosurfactant) Rhodia Rhodafac
PA-32 .RTM. 5 16 117 7.3
Cationic Surfactants A and B are blends of cocoalkyl amines and
acetates. Cationic Surfactant C is
N-cis-13-docosenoic-N,N,-bis(2-hydroxymethyl)-N-methyl ammonium
chloride. Cationic Surfactant D is a mixture of alkyl and alkenyl
bis(2-hydroxyethyl) ammonium chlorides. Zwitterionic Surfactant is
erucic amidopropyl dimethyl betaine. Note that the concentrations
given in Table 1 are of as-received material concentrates including
solvents.
Example 8
Core Test
[0053] A different type of test was performed to determine the
effectiveness, the extent of possible damage imparted by this
chemical, and the permanency of the treatments of the Invention. A
core test was conducted at 126.6.degree. C. (260.degree. F.) using
a standard Hassler cell. In this test, the core (length=6.35 cm;
diameter=3.77 cm, permeability=12 mD, porosity=14%) was initially
saturated with 6% KCl brine, and N.sub.2 gas was then injected into
the core to displace water. The removal of water was measured by
applying different gas pressure gradients along the length of the
core and weighing the water expelled from the core at each pressure
gradient. Then the core was treated with a solution containing 5%
Zonyl 8470.RTM. and 95% of 6% KCl brine, by injecting 5 pore
volumes of the solution into the core; the core was not shut-in.
After the treatment, 6% KCl brine was injected into the core as a
post flush to displace the treatment solution. Once the core was
fully saturated with brine, N.sub.2 gas was again injected at three
different pressure gradients, and the water removed from the core
was measured and compared to that obtained before treatment. After
this stage, four more brine-gas cycles were done (to check the
long-term efficiency of the system); in these, the core was again
saturated with brine and then a gas flush was performed to measure
the water expelled from the core. Note that from the brine that was
expelled from the core, the remaining brine saturation could be
calculated since the porosity of the core was known.
[0054] FIG. 6 (the data are shown in Table 2) shows the brine
saturations (Sw) in the untreated and treated core when the three
different gas pressure gradients were applied across the core. For
the untreated core, the brine saturations in the core were 73%, 58%
and 57%, at differential pressures of 0.034 MPa (5 psi), 0.103 MPa
(15 psi) and 0.276 MPa (40 psi) respectively. When the pressure
gradient was increased from 0. 103 MPa (15 psi) to 0.276 MPa (40
psi), the additional water removed was very low for the untreated
core. The additional decrease in brine saturation was only 1%. This
shows that a large amount of brine was trapped in small pores whose
capillary entry pressure was greater than 0.276 MPa (40 psi).
[0055] After treatment (cycles 1-5), the brine saturation in the
core was lower than that of the untreated core at all pressure
gradients. This was due to capillary pressure reduction by Zonyl
8470.RTM. which allowed the clean up of water from smaller pores.
When differential pressure was increased from 0.103 MPa (15 psi) to
0.276 MPa (40 psi), reduction in brine saturation was in the range
of 6%-13%, compared to 1% before treatment. The slope of the lines
between 0.103 MPa (15 psi) and 0.276 MPa (40 psi), after treatment
showed that higher differential pressures resulted in further clean
up. Before treatment, the line was almost vertical, showing that
increasing pressure did not enhance clean up at the same rate as
for a treated core. TABLE-US-00002 TABLE 2 .DELTA.P1 .DELTA.P2
.DELTA.P3 (MPa) Sw1 (MPa) Sw2 (MPa) Sw3 Untreated 0.032 0.73 0.106
0.58 0.278 0.57 Treated Cycle 1 0.037 0.65 0.099 0.55 0.273 0.45
Cycle 2 0.057 0.65 0.110 0.56 0.272 0.49 Cycle 3 0.055 0.67 0.113
0.58 0.272 0.45 Cycle 4 0.038 0.58 0.103 0.49 0.276 0.42 Cycle 5
0.035 0.67 0.101 0.54 0.273 0.48
Example 9
Field Application
[0056] A typical field application of this method may have three
stages: pretreatment, main treatment, and post treatment stages. In
the pretreatment stage, a preflush fluid is injected into the
formation. The fluid may contain brine, solvent, organic or
inorganic clay stabilizer solution, matrix stimulation fluids, etc.
In the main stage, a carrier fluid containing the wettability
modifier, solvents and other components, is pumped into the
formation. The fluid is then left in the formation for a period of
time that depends upon the fluid and upon the temperature of the
formation. In some cases, it may not be necessary to leave the
fluid in the formation. The wettability modifier adheres to the
pore walls in the formation either by adsorption, by chemical
bonding, by precipitation, by aggregation or by electrostatic
attraction. Following the main stage, a post treatment stage may
optionally be performed, either immediately after the main stage or
after the shut-in period. In the post treatment stage, a gas, foam
or brine may be injected into the formation to displace the main
stage fluid further into the formation or to spread the wettability
modifier uniformly. The post treatment stage may also be done to
enhance the flow back of the carrier fluid, solvents, and excess
wettability modifier injected in the main stage. When the well is
put on production, the fluids flow back to the surface, leaving a
coating of wettability modifier on the pore walls of the formation.
Because of the wettability modifier, the formation becomes
intermediate or gas wetting, which prevents the formation of water
or condensate blocks. The treatment will be long-lasting.
* * * * *