U.S. patent application number 13/070081 was filed with the patent office on 2012-09-27 for selective fluid with anchoring agent for water control.
Invention is credited to Syed A. Ali, Sumitra Mukhopadhyay.
Application Number | 20120241156 13/070081 |
Document ID | / |
Family ID | 46876347 |
Filed Date | 2012-09-27 |
United States Patent
Application |
20120241156 |
Kind Code |
A1 |
Mukhopadhyay; Sumitra ; et
al. |
September 27, 2012 |
SELECTIVE FLUID WITH ANCHORING AGENT FOR WATER CONTROL
Abstract
Methods and apparatus for using a fluid within a subterranean
formation including forming a fluid comprising an oil-soluble resin
acid and an organosilicon compound and introducing the fluid to the
formation, wherein the relative permeability of the formation
increases, and wherein the production of water is reduced more than
if no fluid was introduced to the formation. Methods and apparatus
for reducing water production within a subterranean formation
including forming a fluid comprising an oil-soluble resin acid and
an organosilicon compound and introducing the fluid to the
formation, wherein the production of water is reduced more than if
no fluid was introduced to the formation.
Inventors: |
Mukhopadhyay; Sumitra;
(Sugar Land, TX) ; Ali; Syed A.; (Sugar Land,
TX) |
Family ID: |
46876347 |
Appl. No.: |
13/070081 |
Filed: |
March 23, 2011 |
Current U.S.
Class: |
166/305.1 |
Current CPC
Class: |
C09K 8/5083 20130101;
C09K 8/502 20130101; C09K 8/506 20130101 |
Class at
Publication: |
166/305.1 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method of using a fluid within a subterranean formation,
comprising: forming a fluid comprising an oil-soluble resin acid
and an organosilicon compound; and introducing the fluid to the
formation; wherein the relative permeability of the formation
increases, and wherein the production of water is reduced more than
if no fluid was introduced to the formation.
2. The method of claim 1, wherein the organosilica compound anchors
the relative permeability modifier to the formation surfaces.
3. The method of claim 1, wherein the oil-soluble resin acid is
abietic acid, abieta-7,13-dien-18-oic acid,
13-isopropylpodocarpa-7,13-dien-15-oic acid, neoabietic acid,
dehydroabietic acid, palustric acid, levopimaric acid, or a
combination thereof.
4. The method of claim 1, wherein the oil-soluble resin acid
comprises a calcium salt of abietic acid.
5. The method of claim 1, wherein the oil-soluble resin acid is
pimaric acid, pimara-8(14),15-dien-18-oic acid, isopimaric acids,
or a combination thereof.
6. The method of claim 1, wherein the organosilicon compound is an
organosilane halide or an organosilane alkoxide.
7. The method of claim 1, wherein organosilicon compound is
silanol, silanediol, and/or silanetriol.
8. The method of claim 1, wherein the organosilicon compound is
organosilane halide, silanes, alkoxysilanes, organosilazane
compounds, and/or polymeric silicon compounds.
9. The method of claim 1, wherein the organosilicon compound
comprises silanol.
10. The method of claim 1, wherein a temperature of the formation
is 300 deg F. or lower.
11. The method of claim 1, wherein a pressure of the formation is
1000 psi or lower.
12. A method of reducing water production within a subterranean
formation, comprising: forming a fluid comprising an oil-soluble
resin acid and an organosilicon compound; and introducing the fluid
to the formation; wherein the production of water is reduced more
than if no fluid was introduced to the formation.
13. The method of claim 12, wherein the oil-soluble resin acid is
abietic acid, abieta-7,13-dien-18-oic acid,
13-isopropylpodocarpa-7,13-dien-15-oic acid, neoabietic acid,
dehydroabietic acid, palustric acid, levopimaric acid, or a
combination thereof.
14. The method of claim 12, wherein the oil-soluble resin acid
comprises a calcium salt of abietic acid.
15. The method of claim 12, wherein the oil-soluble resin acid is
pimaric acid, pimara-8(14),15-dien-18-oic acid, isopimaric acids,
or a combination thereof.
16. The method of claim 12, wherein the organosilicon compound is
an organosilane halide or an organosilane alkoxide.
17. The method of claim 12, wherein organosilicon compound is
silanol, silanediol, and/or silanetriol.
18. The method of claim 12, wherein the organosilicon compound is
organosilane halide, silanes, alkoxysilanes, organosilazane
compounds, and/or polymeric silicon compounds.
19. The method of claim 12, wherein the organosilicon compound
comprises silanol.
20. The method of claim 1, wherein a temperature of the formation
is 300 deg F. or lower and wherein a pressure of the formation is
1000 psi or lower.
Description
FIELD
[0001] Embodiments of the invention relate to fluids for use in
oilfield applications for subterranean formations. More
particularly, embodiments of the invention relate to methods and
compositions for enhanced water control.
BACKGROUND
[0002] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0003] It has been increasingly challenging to develop a suitable
solution to reduce water production without reducing oil and gas
production, especially for mature reservoirs. Worldwide, on
average, water production is three times as much as the oil
production, the impact is significant on the operating cost. Water
production also limits the oil production substantially from the
oil-rich zones in the reservoir. In the treatment of oil and gas
wells including hydraulic fracturing treatments, viscosifiers such
as polymer systems are commonly used in carrier fluids. A fluid
loss additive is often used with such carrier fluids to inhibit
excessive fluid loss from the carrier fluid. The fluid loss
additive helps form a filter cake on the surface of the
formation.
[0004] In a fracturing operation, the fluid efficiency is directly
related to the amount of fluid loss. High fluid efficiency
minimizes the amount of fluid needed to generate a given length of
fracture and limits the amount of filter cake that is generated.
Fluid loss additives can be used to decrease fluid loss and
increase fluid efficiency. The filter cake formed by the fluid loss
additives reduces permeability at the fluid-rock interface.
Conventional fluid loss additives usually contain fine particles
such as mica or silica flour with a broad distribution of particle
sizes designed to effectively plug the pore throats of the rock
matrix. Starches or other polymers can be added to help fill in the
spaces and further reduce the flow.
[0005] Often, fluid loss additives are injected into a fracture
with the initial pad volume used to initiate hydraulic fracturing.
After the pad is injected, proppant slurry which may also contain a
fluid loss additive is pumped into the fracture in various stages
depending on job design. The proppant is designed to hold the
fracture open and allow reservoir fluid to flow through the
proppant pack. The proppant slurry generally includes a viscous
carrier fluid to keep the proppant from prematurely dropping out of
the slurry. After the proppant has been placed in the fracture, the
pressure is released and the fracture closes on the proppant. After
the treatment, it is necessary to remove or break both the
viscosifier in the carrier fluid and the filter cake (that may
contain viscosifier polymer) so that reservoir fluids can
thereafter flow into the fracture and through the proppant pack to
the wellbore and the production string.
[0006] Fracture clean-up issues are a problem. Although other
systems such as viscoelastic surfactants, gelled oil, slick water,
etc. are used, the majority of fluids used to create the fracture
and carry the proppants are polymer-based. In most reservoirs with
lower permeability, the polymer concentrates as carrier fluid leaks
off during the fracturing process. The concentrated polymer hinders
fluid flow in the fracture and often results in underperforming
fractures. Typical remedies include use of breakers, including
encapsulated breakers that allow a significant increase of the
breaker loading. The breaker is added to the fluid/slurry and is
intended to reduce the viscosity of the polymer-based carrier fluid
and facilitate fracture clean-up. Despite high breaker loading, in
such breaker systems the retained permeability of the proppant pack
is still only a fraction of the initial permeability. In certain
cases, the encapsulated breakers may have a large particle size
(e.g. 1 mm) that prevent the solid breaker material from entering
small natural fractures of the formation so that the polymer that
enters these small fractures remains unbroken. And soluble breaker
materials are only used in limited concentrations as the base fluid
rheology must be maintained for some time. If too much soluble
breaker is used, the viscosity of the fluid may drop prematurely.
Soluble breaker materials may also tend to leak off into the
formation, where they are no longer effective.
[0007] Historically, the industry has used a method for selectively
reducing the water production from a hydrocarbon reservoir. The
treatment fluid is comprised of 5-40 weight percent of a
water-immiscible dissolved compound based on a cyclic carbonic acid
such as abietic acid and capable of forming a precipitate that is
substantially soluble in hydrocarbon and substantially insoluble in
water. This system, however, does not impart long-lasting
effectiveness in higher permeability rocks.
Another historical approach uses a chemical treatment that
selectively reduces water production. Such treatments employ
polymeric relative permeability modifier and an organosilicon
compound. Although the relative permeability modifiers are
effective in reducing the water, they also reduce oil production to
some extent.
[0008] Embodiments of the present invention provide further
approaches and methods to improve the clean-up of hydraulic
fracturing treatments.
SUMMARY
[0009] Embodiments of the invention provide methods and apparatus
for using a fluid within a subterranean formation including forming
a fluid comprising an oil-soluble resin acid and an organosilicon
compound and introducing the fluid to the formation, wherein the
relative permeability of the formation increases, and wherein the
production of water is reduced more than if no fluid was introduced
to the formation. Embodiments of the invention provide methods and
apparatus for reducing water production within a subterranean
formation including forming a fluid comprising an oil-soluble resin
acid and an organosilicon compound and introducing the fluid to the
formation, wherein the production of water is reduced more than if
no fluid was introduced to the formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] FIG. 1 is a photograph series comparing treatment fluid (15
wt % calcium resinate) (middle top) diluted with either oil (left)
or brine (right).
DETAILED DESCRIPTION
[0011] The procedural techniques for pumping fluids down a wellbore
to fracture a subterranean formation or to perform other well
services treatments are well known. The person that designs such
treatments is the person of ordinary skill to whom this disclosure
is directed. That person has available many useful tools to help
design and implement the treatments, including computer programs
for simulation of treatments.
[0012] In the summary of the invention and this description, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified), and then read again as not
so modified unless otherwise indicated in context. Also, in the
summary of the invention and this detailed description, it should
be understood that a concentration range listed or described as
being useful, suitable, or the like, is intended that any and every
concentration within the range, including the end points, is to be
considered as having been stated. For example, "a range of from 1
to 10" is to be read as indicating each and every possible number
along the continuum between about 1 and about 10. Thus, even if
specific data points within the range, or even no data points
within the range, are explicitly identified or refer to only a few
specific numbers, it is to be understood that inventors appreciate
and understand that any and all data points within the range are to
be considered to have been specified, and that inventors have
disclosed and enabled the entire range and all points within the
range. All percents, parts, and ratios herein are by weight unless
specifically noted otherwise.
[0013] A selective fluid system based on a waxy solid resin soluble
in oil but insoluble in brine with organosilica for water control
problems is needed. Embodiments of the invention provide a fluid
that effectively reduces the water flow for an extended period of
time without causing any damage to the oil zone by blocking the
water zone selectively.
[0014] The fluid system as a solution for water control contains
two different components: 1) oil-soluble, water-insoluble resin
acids (example: calcium salt of abietic acid, commercially known as
DERTOCAL 140.TM. which is commercially available from DRT DAX of
Cedex, France) and 2) an organosilica compound, such as an
organosilane halide or an organosilane alkoxide. The waxy solid
will selectively precipitate in the water zone causing damage to
the water zone and the organosilicon compound will act as an
anchoring agent of the precipitate by anchoring to the formation
surface or surfaces for long-term efficacy. The acids are soluble
in mutual solvents and oil. The reaction is faster if the
organosilicone compound is soluble in the same solvents. Some
embodiments will benefit if the chemicals are in mutual solvent or
oil. Some embodiments will benefit if there is a spacer before
water/brine is pumped to prevent precipitation in the wellbore. In
some embodiments, cleanup can be done with oil easily. Some
embodiments of the composition are best for sandstone formation.
Temperatures as high as 300 deg F. and pressures as high as 1000
psi have been tested successfully for some embodiments. Embodiments
of the invention may benefit a formation when the temperature of
the formation is 300 deg F. or lower. Water control processes,
formation of water-insoluble plugs, and diversion may benefit from
embodiments of the invention.
[0015] The selective fluid includes a mixture of a waxy solid or
salt of a resin acids, such as (but not limited to) DERTOCAL
140.TM., and an organosilicon compound. DERTOCAL 140.TM. is the
calcium salt of abietic acid as shown below. Abietic acid is a
natural product derived from pine tree resin.
##STR00001##
Abietic acid (left) and the calcium salt of abietic acid.
[0016] This resin acid salt is highly soluble in oil and in a
mutual solvent (which is miscible with both water and oil), such as
dipropylene glycol methylether (DPM, shown below).
##STR00002##
Dipropylene glycol methylether (DPM).
[0017] Resin acids and their Na, K, Ca salts that would work with
the aforementioned organosilica compounds to form insoluble waxy
material as water control agents: [0018] 1. The most prevalent
resin acids are:
[0019] Abietic-type acids
##STR00003##
Abietic acid [0020] abietic acid [0021] abieta-7,13-dien-18-oic
acid [0022] 13-isopropylpodocarpa-7,13-dien-15-oic acid [0023]
neoabietic acid [0024] dehydroabietic acid [0025] palustric acid
[0026] levopimaric acid [0027] simplified formula
C.sub.20H.sub.30O.sub.2, or C.sub.19H.sub.29COOH [0028] represents
the majority 85-90% of typical tall oil. [0029] structurally shown
as (CH.sub.3).sub.4C.sub.15H.sub.17COOH [0030] molecular weight
302. Pimaric-type acids
##STR00004##
[0030] Pimaric acid [0031] pimaric acid [0032]
pimara-8(14),15-dien-18-oic acid [0033] isopimaric acids [0034]
simplified formula C.sub.20H.sub.30O.sub.2 or C.sub.19H.sub.29COOH
[0035] structurally represented as
(CH.sub.3).sub.3(CH.sub.2)C.sub.15H.sub.18COOH [0036] molecular
weight 302 [0037] 2. Other long chain (including unsaturated bonds)
water-insoluble fatty acids also should work.
[0038] A long-term effect in blocking the water zone requires a
strategy by which the waxy, solid precipitate can be retained in
the core. For this purpose, an organosilicon compound capable of
forming a water soluble silanol by hydrolysis will be particularly
useful. The organosilicon compound increases flow resistance and
can attach to the resin such as calcium resinate as well as to the
mineral surface of the formation. As a result, retention of the
calcium resinate precipitate in the formation can be extended
significantly producing a much longer water control treatment.
[0039] Additional organosilicon compounds to form products with the
resin acids include the following.
1. With organosilanol: [0040] a) Silanol
##STR00005##
[0040] R, R.sup.1, R.sup.2, R.sup.3, R.sup.4, R.sup.5 can be alkyl,
allyl, ary groups (both aliphatic and aromatic). Cyclic siloxanes
and linear chains may be selected for some embodiments. More
hydrophobic groups are desirable for plugging water. [0041] b)
Silanediol
[0041] ##STR00006## [0042] c) Silanetriol
##STR00007##
[0042] 2. Other organosilicon compounds that form silanol: [0043]
a) Organosilane halide: These compounds form organosolanols upon
hydrolysis with water (this can provide controlled delay in the
process to form the desired water control agent). The reaction with
acid would then be the same as in scheme L [0044] b) Silanes: same
as in (a) [0045] c) Alkoxysilanes: same as in (a)
[0045] ##STR00008## [0046] d) Organosilazane compounds:
[0046] ##STR00009## [0047] e) Any polymeric silicon compounds with
a Si--OH, or Si--H, or Si--X (X=halogen), or Si--OR, or Si--OCOR
group:
##STR00010##
[0047] Silines (Si.dbd.C compounds) and silynes (Si-tripplebonded
to C) are also options that may be selected for some embodiments,
but these are less stable compared to the more common Si--C
compounds.
EXAMPLES
[0048] The following examples are presented to illustrate the
preparation and properties of fluid systems, and should not be
construed to limit the scope of the invention, unless otherwise
expressly indicated in the appended claims. All percentages,
concentrations, ratios, parts, etc. are by weight unless otherwise
noted or apparent from the context of their use.
[0049] When injected in the oil zone, this fluid causes no damage
to the oil permeability. On the other hand, when water or brine is
added to the solution, the solid starts precipitating out and forms
a yellow flocculant solid, as shown in FIG. 1.
[0050] When a fluid containing 20 or 30 weight percent DERTOCAL
140.TM. in oil or DPM is injected in a brine saturated core, it
damages the brine permeability significantly (up to 80%, from
available core data). However, this damage is not long-lasting.
With the continuing flow of brine through the core (5-10 pore
volume) the precipitate slowly starts to come out of the core
resulting in an increase in the brine perm, eventually gaining the
initial value. This is observed because the particle size of the
waxy solid precipitate is not large enough to block the pores of
the formation permanently.
[0051] The particular embodiments disclosed above are illustrative
only, as the invention may be modified and practiced in different
but equivalent manners apparent to those skilled in the art having
the benefit of the teachings herein. Furthermore, no limitations
are intended to the details herein shown, other than as described
in the claims below. It is therefore evident that the particular
embodiments disclosed above may be altered or modified and all such
variations are considered within the scope and spirit of the
invention. Accordingly, the protection sought herein is as set
forth in the claims below.
* * * * *