U.S. patent application number 14/257782 was filed with the patent office on 2014-10-30 for hydraulic diversion systems to enhance matrix treatments and methods for using same.
This patent application is currently assigned to CLEARWATER INTERNATIONAL, LLC. The applicant listed for this patent is Andrew Duncan, Kern L. Smith, Ronald van Petergem, Alfredo Mendez Zurita. Invention is credited to Andrew Duncan, Kern L. Smith, Ronald van Petergem, Alfredo Mendez Zurita.
Application Number | 20140318793 14/257782 |
Document ID | / |
Family ID | 51731900 |
Filed Date | 2014-10-30 |
United States Patent
Application |
20140318793 |
Kind Code |
A1 |
van Petergem; Ronald ; et
al. |
October 30, 2014 |
HYDRAULIC DIVERSION SYSTEMS TO ENHANCE MATRIX TREATMENTS AND
METHODS FOR USING SAME
Abstract
Systems and methods for treating formation intervals including
forming a low permeability layer on a surface of the interval and
pumping a sand control treating solution through the layer, which
diverts the flow into the formation permitting improved treatment
uniformity and improved overall internal treatment.
Inventors: |
van Petergem; Ronald;
(Houston, TX) ; Duncan; Andrew; (Houston, TX)
; Zurita; Alfredo Mendez; (Houston, TX) ; Smith;
Kern L.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
van Petergem; Ronald
Duncan; Andrew
Zurita; Alfredo Mendez
Smith; Kern L. |
Houston
Houston
Houston
Houston |
TX
TX
TX
TX |
US
US
US
US |
|
|
Assignee: |
CLEARWATER INTERNATIONAL,
LLC
Houston
TX
|
Family ID: |
51731900 |
Appl. No.: |
14/257782 |
Filed: |
April 21, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61814071 |
Apr 19, 2013 |
|
|
|
Current U.S.
Class: |
166/305.1 ;
166/179 |
Current CPC
Class: |
E21B 33/138 20130101;
C09K 8/50 20130101; C09K 2208/26 20130101; E21B 49/08 20130101;
C09K 2208/20 20130101; E21B 43/14 20130101; C09K 8/5751 20130101;
C09K 8/506 20130101; C09K 8/508 20130101; E21B 43/025 20130101;
E21B 21/00 20130101 |
Class at
Publication: |
166/305.1 ;
166/179 |
International
Class: |
E21B 43/25 20060101
E21B043/25 |
Claims
1. A system comprising: a well bore drilled into a geological
structure including a producing or injection formation, interval,
or intervals, a diversion layer or a plurality of diversion layers
formed on a surface of the formation, the interval, or the
intervals, where layer or layers comprises at least one erodible or
dissolvable component and at least one removable component, where
the erodible or dissolvable components erode or dissolve in contact
with well fluids or by treating the layer or layers with a
dissolving fluid, where the removable components are removed by
exposing the layer or layers to a removing fluid, and where the
layer or layers have controlled permeabilities diverting a treating
fluid passing thererthrough improving coverage, uniformity, and/or
completeness across the formation, interval, or intervals has
improved.
2. The system of claim 1, further comprising: a well screen
assembly, a gravel pack, or a sand pack associated with the
formation, interval, or intervals, and wherein the layer or layers
are formed on a surface of the screen assembly, the gravel pack or
the sand pack or passed through the assembly or packs to form
between the assembly or the packs and the formation or interval
surfaces or in a lower portion of the assembly or the packs.
3. The system of claim 1, further comprising: a packer or a
plurality of packers to isolate the formation, interval or
intervals, and a work string or production tubing.
4. The system of claim 1, wherein the layer or layers comprise
particulate materials having a desired particle size distribution,
a desired particle shape distribution and size distribution, or a
desired particle shape distribution, size distribution, and density
distribution, where the permeability of the layer or layers are
established due to the packing of the particles forming the layer
or layers.
5. The system of claim 4, wherein the particulate materials
comprise a combination of erodible or dissolvable particulate
materials and removable particulate materials.
6. The system of claim 5, wherein the permeability of the layer or
layers change over time as the erodible or dissolvable materials
erode or dissolve over time due to being in contact with well
fluids or due to being in contact withe a dissolution fluid
introduced into the well.
7. The system of claim 4, wherein the removable materials are
selected from the group consisting of (1) alkaline metal
carbonates, (2) asphalts, and (3) mixtures or combinations thereof,
and wherein the erodible or dissolvable materials are selected from
the group consisting of hydratable polymers, gelled hydratable
polymers, hydrocarbon soluble polymers, and mixture and
combinations thereof.
8. The system of claim 7, wherein the alkaline metal carbonates are
selected from the group consisting of such as magnesium carbonate
(MgCO.sub.3), calcium carbonate (CaCO.sub.3), strontium carbonate
(SrCO.sub.3), and/or barium carbonate (BaCO.sub.3) and combinations
or mixtures thereof and wherein the asphalts are selected from the
group consisting of gilsonite, bitumen, asphaltum and combinations
or mixtures thereof.
9. The system of claim 4, wherein the hydratable polymers are
selected from the group consisting of natural hydratable polymers,
synthetic hydratable polymers, and combinations or mixtures
thereof.
10. The system of claim 9, wherein the natural hydratable polymers
are selected from the group consisting of {add list} and mixtures
or combinations thereof and the synthetic hydratable polymers are
selected from the group consisting of {add list} and mixtures or
combinations thereof.
11. The system of claim 1, wherein the well treatments are selected
from the group consisting of a sand control treatment, an
aggregating treatment, a zeta modifying treatment, a sticky/tacky
material treatment, a sand consolidation/formation consolidation
treatment, an in situ polymerizable formation consolidate
treatment, a scale inhibitor treatment, a paraffin inhibitor
treatment, a wettability modifier treatment, a biocide treatment, a
gel breaker treatment, an enzyme treatment, a defoamer treatment,
an acid treatment, and mixtures or combinations thereof.
12. A method for diverting well treatments comprising: forming a
diversion layer or a plurality of diversion layers on a formation
surface, an interval surface, on well screen assembly, a gravel
pack, and/or a sand pack associated with a formation or interval
surface, or between the formation or interval surface and a
production tubing or working sting, where the layer or layers have
a controlled and/or desirable permeability, pumping a treating
fluid into the well, and diverting the fluid as it passes through
the layer or layers improving treatment coverage, uniformity, and
completeness.
13. The method of claim 12, further comprising: isolating the
interval using an isolation packer or a plurality of packers prior
to forming the layers.
14. The method of claim 12, wherein the layer or layers comprise
particulate materials having a desired particle size distribution,
a desired particle shape distribution and size distribution, or a
desired particle shape distribution, size distribution, and density
distribution, where the permeability of the layer or layers are
established due to the packing of the particles forming the layer
or layers.
15. The system of claim 14, wherein the particulate materials
comprise a combination of erodible or dissolvable particulate
materials and removable particulate materials.
16. The system of claim 15, wherein the permeability of the layer
or layers change over time as the erodible or dissolvable materials
erode or dissolve over time due to being in contact with well
fluids or due to being in contact withe a dissolution fluid
introduced into the well.
17. The system of claim 14, wherein the removable materials are
selected from the group consisting of (1) alkaline metal
carbonates, (2) asphalts, and (3) mixtures or combinations thereof,
and wherein the erodible or dissolvable materials are selected from
the group consisting of hydratable polymers, gelled hydratable
polymers, hydrocarbon soluble polymers, and mixture and
combinations thereof.
18. The system of claim 17, wherein the alkaline metal carbonates
are selected from the group consisting of such as magnesium
carbonate (MgCO.sub.3), calcium carbonate (CaCO.sub.3), strontium
carbonate (SrCO.sub.3), and/or barium carbonate (BaCO.sub.3) and
combinations or mixtures thereof and wherein the asphalts are
selected from the group consisting of gilsonite, bitumen, asphaltum
and combinations or mixtures thereof.
19. The system of claim 14, wherein the hydratable polymers are
selected from the group consisting of natural hydratable polymers,
synthetic hydratable polymers, and combinations or mixtures
thereof.
20. The system of claim 19, wherein the natural hydratable polymers
are selected from the group consisting of {add list} and mixtures
or combinations thereof and the synthetic hydratable polymers are
selected from the group consisting of {add list} and mixtures or
combinations thereof.
21. The system of claim 12, wherein the well treatments are
selected from the group consisting of a sand control treatment, an
aggregating treatment, a zeta modifying treatment, a sticky/tacky
material treatment, a sand consolidation/formation consolidation
treatment, an in situ polymerizable formation consolidate
treatment, a scale inhibitor treatment, a paraffin inhibitor
treatment, a wettability modifier treatment, a biocide treatment, a
gel breaker treatment, an enzyme treatment, a defoamer treatment,
an acid treatment, and mixtures or combinations thereof.
22. A system for diverting well treatments comprising: a source
subsystem including a filter cake composition including sized,
selectively self-degradable particles capable of forming
predictable low permeability filter-cake layer or layers; a
filter-cake placement subsystem for engineered placement of the
filter-cake composition to create a predictable low permeability
filter-cake layer or layers on a surface of a producing formation,
interval, or intervals, on a surface of an injection formation,
interval, or intervals, in an annular space between the formation
or interval surfaces and production tubing surface, on a surface of
a screen assembly, on a surface of a gravel and/or on a surface of
a sand pack, where the filter-cake composition may be a Newtonian
fluid or a non-Newtonian fluid; and an injection subsystem for
injecting a treating fluid into the formation, interval or
intervals, where the layer or layers divert the treating fluid so
that the treating fluid is more uniformly introduced into the
formation, and where the layers degrade over time.
Description
RELATED APPLICATION
[0001] This application claims the benefit of and prior to U.S.
Provisional Patent Application Ser. No. 61/814,071, filed 19 Apr.
2013.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] Embodiments of this invention relates to systems and methods
for controlling leak off of formation treatments injected into a
producing formation or injection formation or a zone thereof,
especially in producing formations having long producing intervals
such as horizontal wells or in producing formations having short
producing intervals having high permeability segments.
[0004] More particularly, embodiments of this invention relates to
systems and methods for controlling leak off of formation
treatments injected into a producing formation or a zone thereof,
especially in producing formations having long producing intervals
such as horizontal wells or in producing formations having short
producing intervals with high permeability segments, where the
systems and methods include forming a controlled permeability layer
on the formation surface, on a well screen, on a gravel pack, on a
sand pack, or between the formation surface and/or the production
tubing or working sting so that injected treatments are diverted
through the controlled permeability layer into the formation or
intervals yielding a uniform distribution of the treatment across
the formation or intervals.
[0005] 2. Description of the Related Art
[0006] During the placement of chemicals in a formation, formation
zone or a formation matrix, it is often very difficult to achieve
acceptable coverage of a complete interval, especially if the
interval is a long extending interval or has non constant or high
permeability like interval(s) found in horizontal wells.
Specifically during matrix treatments such as sand and water
control treatments, placement and coverage is critical.
Permeability contrasts within the matrix may cause treating fluids
to leak-off uncontrolled causing parts of the matrix to remain un
or insufficiently treated.
[0007] Historically, the problem has been addressed in several
ways, including rate diversion, mechanical diversion such as
packers, polymers, etc. While many temporary plugs for leak-off and
diversion have been developed for drilling and fracturing
application, such temporary diversion layers have not been applied
to create a controlled permeability layer to enhance diversion of
chemical sand control product treatments or applications or other
treatment or applications.
[0008] On the other hand, in this invention, pumping a filter
composition of this invention will form a filter cake or filter
layers across the entire formation. The filter cake or layer will
have a controlled permeability that partially or substantially
equalizes the effective formation permeability so that well
treatments may be delivered to all formation zones equally with
equal effectiveness. Therefore, the well treatment will actually
occur through the filter cake or layer across the entire or a
majority portion of a formation or zone or zones thereof, rather
than the filter cake or layer being used to seal off segments of
the formation and then divert away from them.
SUMMARY OF THE INVENTION
[0009] Embodiments of this invention provide systems including a
well bore having a producing formation, a producing interval, or
producing intervals or an injection formation, an injection
interval, or injection intervals and one controlled permeability
layer or a plurality of controlled permeability layers formed on
the formation or interval surfaces or in an annular space between
the formation or interval surfaces and the surfaces of production
tubing. The controlled permeability layers are sometimes referred
to as diversion layers. The controlled permeability layers have a
tailored or desired permeability and are temporary, i.e., the
layers comprise temporary or removable bridging layers. The layers
comprise a reduced permeability filter cake on the formation or
interval surfaces allowing controlled leak off of chemical treating
solution into the formation or intervals so that the chemical
treatments are more uniformly distributed across the formation or
interval. The controlled permeability of the layers may be due to
the nature of the layer materials used or may be formed in the
layers by the inclusion of one or more (one or a plurality of)
erodible or dissolvable components in the filter cake forming
composition, i.e., the composition used to form the diversion
layers include one or more (one or a plurality of) removable
components and one or more (one or a plurality of) erodible or
dissolvable components. The erodible or dissolvable components are
designed to be erodible or dissolvable when placed in contact with
a treating fluid such as a solvent system. In other embodiments,
the layers have augmented permeabilities due to the selective
removal of erodible or dissolvable components in the layers. In
other embodiments, the systems may also include isolation packers
to isolate formations, intervals, or segments to be treated. In
certain embodiments, the layer or layers are selectively
dissolvable or removable using a dissolution solution. In other
embodiments, the layer or layers are erodible or removable due to
in situ acid generation or due to minimal lift-off pressure. In
other embodiments, the layers may be permanent or substantially
permanent and the permeability of the layer(s) may vary with time,
or may be engineered so that the permeability of the layer(s)
changes over time. In certain embodiments, the layer(s) may be only
partially removed, especially for injection wells. In other
embodiments, the permeability of the layer(s) may be increased over
time, especially for injection wells.
[0010] Embodiments of this invention also provide methods for
diverting well treatments, including forming a reduced permeability
layer or plurality of reduced permeability layers on a surface of a
producing formation, a producing formation interval, or producing
formation intervals or an injection formation, an injection
formation interval, or injection formation intervals, on an annular
space between the formation or interval surfaces and production
tubing surface, or on a screen assembly and/or a gravel or sand
pack, where the layers may be placed prior to and/or during
treatment. In certain embodiments, the methods include forming or
placing the layers prior to sand control treatment. In other
embodiments. the methods include forming or placing the layer(s)
with a composition including one or more (one or a plurality)
removable components and one or more (one or a plurality) erodible
or dissolvable components (i.e., erodible or dissolvable when
exposed to a particular solvent system or placing solution) prior
to sand or water control treatment followed by exposing the layers
to a dissolution solution to erode or dissolve the erodible or
dissolvable components. In other embodiments, the methods may also
include one or more interval isolation packers so that different
portions of the intervals may be treated separately. In other
embodiments, the intervals are associated with producing
formations, while, in other embodiments, the intervals are
associated with injection formations. In other embodiments, the
methods may also include preparing a layer that is more
permanent--substantially permanent to permanent, but may be
engineered so that the permeability of the layers change over time.
The more permanent layers are especially well suited for injection
wells.
[0011] Embodiments of this invention also provide methods and
systems for diverting well treatments including providing a filter
cake composition including sized, selectively dissolvable/removable
particles capable of forming a predictable low permeability
filter-cake layer or layers. The methods and systems also include
engineered placement of particles to form the filter-cake that
create a predictable low permeability filter-cake layer or layers
on a surface of a producing formation, a producing formation
interval, or producing formation intervals or an injection
formation, an injection formation interval or injection formation
intervals, on an annular space between the interval surface and
production tubing surface, on screen assembly and/or on a gravel
pack or on a sand pack, where the filter-cake placement may occur
with a Newtonian fluid or a non-Newtonian fluid. The methods and
systems also include using a leak-off model to design the treatment
fluid placement, where the layer or layers act to divert the
treating fluid so that the treating fluid is more uniformly
introduced into the formation or interval resulting in a more
uniform formation treatment. The methods and systems also include
filter-cake removal either by using a filter-cake removal
composition or by in situ acid generation or by minimal lift-off
pressure as fluids are produced from the formation, interval, or
intervals. In the case of injection formation, the layers may be
permanent or substantially permanent or may be removed by treating
the formation with a filter-cake removal composition or by in situ
acid generation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] The invention can be better understood with reference to the
following illustrative drawings:
[0013] FIG. 1 depicts an embodiment of a vertically disposed well
having a long producing interval including one diversion layer
showing the diverted flow of treating material into the
formation.
[0014] FIG. 2 depicts an embodiment of a horizontally disposed well
having a long producing interval including one diversion layer
showing the diverted flow of treating material into the
formation.
[0015] FIGS. 3A-C depict embodiments of diverted formations.
[0016] FIGS. 4A&B depict other embodiments of diverted
formations and methods for preparing them.
[0017] FIG. 5 depicts another embodiment of diverted formations and
methods for preparing the diverted formation.
[0018] FIG. 6 depicts another embodiment of a diverted formation
and a method for preparing same.
[0019] FIG. 7 illustrates a prior art treatment of a formation,
where a diverting layer was not deposited on the formation prior to
treatment.
[0020] FIG. 8 illustrates a treatment of a formation including a
diversion layer deposited on the formation prior to treatment.
[0021] FIG. 9 depicts a representation of a well with zones of
largely varying permeability.
[0022] FIGS. 10A-C depicts a particle size distributions for A)
Wel-Carb 2 (D.sub.50=3.8 .mu.m), B) Wel-Carb 25 (D.sub.50=21.5
.mu.m), and C) Wel-Carb 50 (D.sub.50=39.6 .mu.m).
[0023] FIGS. 11A-C depicts a calculation of filter cake
permeability from flow vs time data for the materials of FIGS.
10A-C.
[0024] FIG. 12 depicts a filter cake after on-the-fly zeta
potential or aggregation modifying agent treatment (left) and sand
agglomerated by zeta potential or aggregation modifying agent
passing through filter cake (right).
[0025] FIG. 13 depicts a general design of horizontal well model
apparatus.
[0026] FIG. 14 depicts an embodiment of a model horizontal well
apparatus.
[0027] FIG. 15 depicts flowrates through each core initially, with
Wel-Carb 20 filter cake, and again after an hour with filter
cake.
[0028] FIG. 16 depicts flowrates through each core initially, with
Wel-Carb 50 filter cake, and again after an hour with filter
cake.
[0029] FIG. 17 depicts a summary of the effective core
permeabilities after filter cake formation and demonstrates the
ability to equalize permeability across the model formation.
DETAILED DESCRIPTION OF THE INVENTION
[0030] The inventors have found that systems and methods may be
implements for diverting sand and/or water control or other
chemical treatments into a formation by forming a controlled
permeability layer on the surface of a producing interval, where
the layer includes a composition having a low permeability. The
layer comprises a graded/sized bridging material having controlled
permeability. The inventors have found that the present invention
increases the interval length that can be treated with S and Aid, a
Weatherford treatment technology, or other matrix treatment from
short intervals because of limitations in product placement into
long sections with varying permeability. The inventors have also
found that the layer may also include viscosifiers to improve the
formation of the reduced permeability filter cake across the
interval. The inventors have found that the bridge layer include
pore spaces formed by materials in the layer, which may include
particulate solids, and erodible or dissolvable particulate
materials. The inventors have also found that the layer may also
include a polymer to enhance placement of the reduced permeability
filter cake. The inventors have found that after breaking the
optional polymer gel or viscosifier, a filter cake may be formed
that has a predictable and selective permeability. Once formed, the
inventors have found that a sand and/or water control treatment may
be pumped into formation from the bullhead at the surface using a
brine carrier, where the filter cake acts as a diversion layer for
more uniformly distributing the treating composition into the
interval.
[0031] The inventors have also found that the diversion layer may
be used with coil tubing (CT) or jointed pipe. The inventors have
found that a filter cake may be formed across the whole interval,
but without any breaker or removing agent. The inventors have found
that the methods may also include selectively, treating each
interval, where annular cross flow may be prevented by placing
pressure in the CT/OH (or casing or even screen) annulus, while
treating down the CT. In this embodiment, we would first pump a
weak acid to break the polymer and then use the permeable filter
cake to do the diversion. This method, has no theoretical limits to
it length, other than how far CT may be extended into the well,
especially a horizontal well with long intervals.
[0032] The inventors have found that the size, shape, density, and
packing of the bridging material may be used to control
permeability of the low permeable filter cake layer, because that
can be done without any intervention. The inventors have also found
that the cake layer material may just be produced back or the layer
may be dissolved using a layer dissolution treating solution.
Layer Properties of this Invention
[0033] The layer forming compositions may include between 0.1 vol.
% to 60 vol. % of particulate solids suspended in a base fluid. In
certain embodiments, the layer forming compositions include between
1 vol. % to 10 vol. % of particulate solids suspended in a base
fluid. Suitable base fluid include water, viscosified water,
aqueous solutions, well treating fluids, or other similar fluids
used in downhole operations.
[0034] The thickness of the diversion layer or layers range from
about 0.01 mm to about 30 mm. In certain embodiments, the diversion
layer or layers thickness range from about 0.1 mm to about 10 mm.
In other embodiments, the diversion layer or layers thickness range
from about 0.2 mm to about 2 mm. In certain embodiments, the
diversion layer or layers thickness range from about 0.2 mm to
about 1 mm. In certain embodiments, larger thickness may be needed
to fill any cracks or natural fractures in the formation, on top of
which smaller particle diversion layer can form.
[0035] The particle size distributions of the diversion layer
forming materials are between 0.1 .mu.m and 800 .mu.m. In certain
embodiments, the particle size distributions of the diversion layer
forming materials are between 0.5 .mu.m and 500 .mu.m. In other
embodiments, the particle size distributions of the diversion layer
forming materials are between 0.1 .mu.m and 200 .mu.m. In other
embodiments, the particle size distributions of the diversion layer
forming materials are between 0.1 .mu.m and 100 .mu.m. In other
embodiments, the particle size distributions of the diversion layer
forming materials include materials having different particle size
distribution. In certain embodiments, the layer materials include
materials having a particles size distribution between 0.1 .mu.m
and 50 .mu.m, materials having a particle size distribution between
0.1 .mu.m and 500 .mu.m. In certain embodiments, the layer
materials include materials having a particles size distribution
between 0.1 .mu.m and 500 .mu.m, but having overlapping
distributions having peak distribution values of about 5 .mu.m, 10
.mu.m, 20 .mu.m, 40 .mu.m, 50 .mu.m, 60 .mu.m, 70 .mu.m, 80 .mu.m,
90 .mu.m and 100.mu.. The term peak distribution means the
particles size making the largest contribution to the distribution.
In other embodiments, the particle size distribution of the
material is initially high, between 1 mm and 3 mm, to fill in any
cracks or natural fractures in the formation, and then successively
lower particle sizes are pumped to form the diversion layer.
[0036] The layer or layers have a permeability between about 1 mD
and about 100 mD. In certain embodiments, the permeability is
between about 1 mD and about 90 mD. In other embodiments, the
permeability is between about 1 mD and about 80 mD. In other
embodiments, the permeability is between about 1 mD and about 70
mD. In other embodiments, the permeability is between about 1 mD
and about 60 mD. In other embodiments, the permeability is between
about 1 mD and about 50 mD. The layers once deposed or placed on
the surfaces of formation, interval, intervals or zones thereof,
the layers equalize the permeability of the zone reducing or
eliminating "thief zones". Thus, the layers equalize the
permeability of zones having permeability ranging from 100 mD to
3000 mD so that well treating fluids will flow more evenly into all
zone without being directed only to the high permeability zones. In
this manner, the diversion layers permit well treatments to have
improved zone coverage, uniformity and completeness.
Suitable Reagents for Use in the Invention
Removable Components
[0037] suitable removable bridging or diversion agents for forming
the low permeability or diversion layer include, without
limitation, any particulate material that has low or no solubility
in a given carrier such as a brine. Exemplary examples of removable
components include, without limitation, (1) alkaline metal
carbonates such as magnesium carbonate (MgCO.sub.3), calcium
carbonate (CaCO.sub.3), strontium carbonate (SrCO.sub.3), and/or
barium carbonate (BaCO.sub.3), (2) asphalts such as gilsonite,
bitumen, and/or asphaltum, (3) mixtures or combinations thereof.
The removable agents or components are removable by treating the
layer under acid conditions, i.e., treating the layer with an acid
solution. Suitable acids include, mineral acids, organic acids, or
mixtures or combinations thereof. Suitable mineral acids include,
without limitation, hydrochloric acid, sulfuric acid, and/or nitric
acid. Suitable organic acids include, without limitation, formic
acid, acetic acid, lactic acid, glycolic acid, propanoic acid,
other lower carbon number acids, or mixtures and combinations
thereof.
Erodible or Dissolvable Components
[0038] suitable erodible or dissolvable bridging or diversion
agents for adding into the bridging agents include, without
limitation, hydratable polymers, gelled hydratable polymers,
hydrocarbon soluble polymers, other polymers that may be added to
the bridging agents and erode or dissolve away after placement of
the layer by production fluids or using a dissolution fluid that
solubilizes the polymers, or mixture and combinations thereof. For
hydratable or gelled hydratable polymers, aqueous solutions are
suitable to erode or dissolve the polymers. In certain embodiments,
the aqueous solution includes a breaker to break the gelled
hydratable polymers to enhance erosion or dissolution. For
hydrocarbon soluble polymers, erosion will generally occur simply
by being exposed to producing fluids as the hydrocarbon components
in the producing fluids dissolve the hydrocarbon polymers. In other
embodiments, the solution may be a solvent system injected into the
well to dissolve the polymers. Suitable solvent system include
diesel fuels or other light hydrocarbon fluids. With other
polymers, the solvent system will include components known to
dissolve or erode the polymers.
Hydratable Polymers
[0039] Suitable hydratable polymers that may be used in embodiments
of the invention include any natural and/or synthetic hydratable
polymer capable of forming a gel in the presence of at least one
cross-linking agent of this invention and any other polymer that
hydrates upon exposure to water or an aqueous solution capable of
forming a gel in the presence of at least one cross-linking agent
of this invention. For instance, suitable natural hydratable
polysaccharides include, but are not limited to, galactomannan
gums, glucomannan gums, guars, derived guars, and cellulose
derivatives. Specific examples are guar gum, guar gum derivatives,
locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl
hydroxyethyl cellulose, and hydroxyethyl cellulose. Presently
preferred thickening agents include, but are not limited to, guar
gums, hydroxypropyl guar, carboxymethyl hydroxypropyl guar,
carboxymethyl guar, and carboxymethyl hydroxyethyl cellulose.
Suitable hydratable polymers may also include synthetic polymers,
such as polyvinyl alcohol, polyacrylamides, poly-2-amino-2-methyl
propane sulfonic acid, and various other synthetic polymers and
copolymers. Other suitable polymers are known to those skilled in
the art. Other examples of such polymer include, without
limitation, guar gums, high-molecular weight polysaccharides
composed of mannose and galactose sugars, or guar derivatives such
as hydropropyl guar (HPG), carboxymethyl guar (CMG),
carboxymethylhydropropyl guar (CMHPG), hydroxyethylcellulose (HEC),
hydroxypropylcellulose (HPC), carboxymethylhydroxyethylcellulose
(CMHEC), xanthan, scleroglucan, and/or mixtures and combinations
thereof. Suitable synthetic polymers include, without limitation,
polyacrylamide, polyacrylate polymers and copolymers thereof, and
mixtures or combinations thereof. Other examples of suitable
hydratable polymers are set forth herein. Suitable Chia seed
materials include, without limitation, Salvia hispanica seed,
Salvia lavandulifolia seed, Salvia columbariae seed, or mixtures
and combinations thereof. These species are in the following
genius: Plantae, Angiosperms, Eudicots, Asterids, Lamiales,
Lamiaceae, and Salvia. In certain embodiments, the Chia seed
material are used without further processing. In other embodiments,
the Chia seed material is fractured or partially ground. In other
embodiments, the Chia send material is fully ground.
[0040] Suitable synthetic hydratable polymers for use in the
crosslinkable polymer systems of this invention include, without
limitation, a partially hydrolyzed acrylamide polymer or mixture of
partially hydrolyzed acrylamide polymers. The partially hydrolyzed
acrylamide polymers comprise acrylamide polymers being hydrolyzed
to a degree greater than or equal to about 0.2% (percent of
acrylamide groups hydrolyzed to carboxylate groups). In certain
embodiments, the degree of hydrolysis is greater than or equal to
about 0.5%. In other embodiments, the degree of hydrolysis is
between about 0.2% and about 15%. In other embodiments, the degree
of hydrolysis is between about 0.5% and about 10%. The average
molecular weight of the acrylamide polymer is generally in the
range between about 10,000 and about 50,000,000. In certain
embodiments, the acrylamide polymer has an average molecular weight
between about 100,000 to about 20,000,000. In other embodiments,
the acrylamide polymer has an average molecular weight between
about 200,000 and about 12,000,000. In other embodiments, the
acrylamide polymer has an average molecular weight between about
100,000 to about 11,000,000. In other embodiments, the acrylamide
polymer has an average molecular weight between about 200,000 and
about 1,000,000. In other embodiments, the acrylamide polymer has
an average molecular weight between about 250,000 and about
300,000. The polyacrylamide has most preferably greater than about
0.1 mole % polymer carboxylate groups. The polymer concentration in
the gelation compositions are generally between about 0.05% and 10%
by weight. In certain embodiments, the polymer concentration is
between about 1% and about 8% by weight. In certain embodiments,
the polymer concentration is between about 2% and about 5% by
weight of polymer in water.
Crosslinking Agents
[0041] Suitable crosslinking agents for use in the crosslinking
systems of this invention include, without limitation, a polyvalent
metal carboxylate complex crosslinking agent derived from a
carboxylate compound or mixture thereof. In solution, the
crosslinking agent comprises an electronegative carboxylate
species, which may include one or more of the following water
soluble species: formate, acetate, proprionate, lactate,
substituted derivatives thereof, and mixtures thereof. In addition
to electronegative carboxylate species, the solution comprises
electropositive metallic species such as Al.sup.3+, Fe.sup.3+,
Ti.sup.4+, Zn.sup.2+, Sn.sup.4+, Cr, etc. In certain embodiments,
the crosslinking agents are chromium (III) acetate complexes. The
weight ratio of polymer to crosslinking agent is generally between
about 5:1 and about 50:1. In certain embodiments, the ratio is
between about 6:1 and about 20:1. In other embodiments, the ratio
is between about 7:1 and about 10:1.
[0042] Suitable chromium III species include, without limitation,
trivalent chromium and chromic ion, an equivalent term, carboxylate
species derived from water-soluble salts of carboxylic acids. In
certain embodiments, the carboxylic acids are low molecular weight
mono-basic acids. Exemplary examples of such carboxylic acids
include formic acid, acetic acid, propionic acid, lactic acid,
lower substituted derivatives thereof and mixtures thereof. The
carboxylate species include the following water-soluble species:
formate, acetate, propionate, lactate, lower substituted
derivatives thereof, and mixtures thereof. Optional inorganic ions
include sodium, sulfate, nitrate and chloride ions. A
non-exhaustive list of representative examples of chromic compounds
include: [Cr.sub.3(CH.sub.3CO.sub.2).sub.6(OH).sub.2].sup.+,
[Cr.sub.3(OH).sub.2(CH.sub.3CO).sub.6]NO.sub.3.6H.sub.2O,
[Cr.sub.3(H.sub.2O).sub.2(CH.sub.3CO.sub.2).sub.6].sup.3+, and
[Cr.sub.3(H.sub.2O).sub.2(CH.sub.3CO).sub.6](CH.sub.3CO.sub.2).sub.3.H.su-
b.2O.
[0043] A host of complexes of the type described above and their
method of preparation are well known in the leather tanning art.
These complexes are described in Shuttleworth and Russel, Journal
of The Society of Leather Trades' Chemists, "The Kinetics of Chrome
Tannage Part I.," United Kingdom, 1965, v. 49, p. 133-154; "Part
III.," United Kingdom, 1965, v. 49, p. 251-260; "Part IV.," United
Kingdom, 1965, v. 49, p. 261-268; and Von Erdman, Das Leder,
"Condensation of Mononuclear Chromium (III) Salts to Polynuclear
Compounds," Eduard Roether Verlag, Darmstadt, Germany, 1963, v. 14,
p. 249; and are incorporated herein by reference. Udy, Marvin J.,
Chromium, Volume 1: Chemistry of Chromium and its Compounds,
Reinhold Publishing Corp., N.Y., 1956, pp. 229-233; and Cotton and
Wilkinson, Advanced Inorganic Chemistry 3rd Ed., John Wiley &
Sons, Inc., N.Y., 1972, pp. 836-839, further describe typical
complexes which may be within the scope of the present invention
and are incorporated herein by reference. The present invention is
not limited to the specific complexes and mixtures thereof
described in the references, but may include others satisfying the
above-stated definition.
Gel Delaying Agents
[0044] The gelation delaying agent is a monocarboxylic acid or a
monocarboxylic acid salt or mixtures thereof in sufficient
concentration to raise or lower the pH of the aqueous gelation
solution to about 3.5 to about 6.8, preferably about 3.5 to about 6
and most preferably about 3.5 to about 5. Exemplary acids include
formic, acetic, propionic, lactic, etc. Exemplary acid salts
include salts of formate, acetate, propionate, lactate, etc.
[0045] In addition to the delaying agent, the buffer is any water
soluble buffer subsystem having a pKa value between about 3.5 and
about 6.8. In certain embodiments, the buffer subsystem has a pKa
value between about 3.5 and about 6. In other embodiments, the
buffer subsystem has a pKa value between about 3.5 to about 5.
Exemplary buffers include monocarboxylates such as formate,
acetate, propionate and lactate salts, hydrogen phosphates and
polyamines such as triethylene tetraamine, tetraethylene pentamine
and hexamethylene tetraamine or mixtures thereof. Dicarboxylate and
tricarboxylate buffers such as those based on the use of malonic,
oxalic and citric acids should be avoided because the closely
spaced dicarboxylates and tricarboxylates strongly chelate the
chromium (III) gelation agent thereby preventing gelation.
[0046] A molar ratio of the delaying subsystem to the crosslinkable
polymer subsystem ranges between about 0.1:1 and about 3.0:1. In
certain embodiments, the molar ratio is between about 0.5:1 and
about 2.5:1. In certain embodiments, the molar ratio is between
about 0.75 to 1 and about 2.0:1.
[0047] The crosslinkable polymer system, the crosslinking system,
the crosslink delaying subsystem, and the solvent system can be
mixed at or near the wellhead by in-line mixing means before or
during injection. Or, the delaying system, polymer system and the
solvent system can be admixed and then the crosslinking system
added to form a bulk gel composition suitable for injection.
Sequential injection should not be used because it results in
inadequate mixing and subsequent incomplete gelation.
[0048] Suitable solvent system for use the present invention
include, without limitation, fresh water or brine. Exemplary fresh
water include tap water, production water, or any other source of
free water. Exemplary brine include any water containing an
inorganic or organic salt dissolved in the water including brines
containing salts up their solubility limit in water.
Dissolution Fluids
[0049] Suitable hydrocarbon base fluids for use in this invention
includes, without limitation, synthetic hydrocarbon fluids,
petroleum based hydrocarbon fluids, natural hydrocarbon
(non-aqueous) fluids or other similar hydrocarbons or mixtures or
combinations thereof. The hydrocarbon fluids for use in the present
invention have viscosities ranging from about 5.times.10.sup.-6 to
about 600.times.10.sup.-6 m.sup.2/s (5 to about 600 centistokes).
Exemplary examples of such hydrocarbon fluids include, without
limitation, polyalphaolefins, polybutenes, polyolesters,
biodiesels, simple low molecular weight fatty esters of vegetable
or vegetable oil fractions, simple esters of alcohols such as
Exxate from Exxon Chemicals, vegetable oils, animal oils or esters,
other essential oil, diesel, diesel having a low or high sulfur
content, kerosene, jet-fuel, white oils, mineral oils, mineral seal
oils, hydrogenated oil such as PetroCanada HT-40N or IA-35 or
similar oils produced by Shell Oil Company, internal olefins (IO)
having between about 12 and 20 carbon atoms, linear alpha olefins
having between about 14 and 20 carbon atoms, polyalpha olefins
having between about 12 and about 20 carbon atoms, isomerized alpha
olefins (IAO) having between about 12 and about 20 carbon atoms,
VM&P Naptha, Linpar, Parafins having between 13 and about 16
carbon atoms, and mixtures or combinations thereof.
[0050] Suitable polyalphaolefins (PAOs) include, without
limitation, polyethylenes, polypropylenes, polybutenes,
polypentenes, polyhexenes, polyheptenes, higher PAOs, copolymers
thereof, and mixtures thereof. Exemplary examples of PAOs include
PAOs sold by Mobil Chemical Company as SHF fluids and PAOs sold
formerly by Ethyl Corporation under the name ETHYLFLO and currently
by Albemarle Corporation under the trade name Durasyn. Such fluids
include those specified as ETYHLFLO 162, 164, 166, 168, 170, 174,
and 180. Well suited PAOs for use in this invention include bends
of about 56% of ETHYLFLO now Durasyn 174 and about 44% of ETHYLFLO
now Durasyn 168.
[0051] Exemplary examples of polybutenes include, without
limitation, those sold by Amoco Chemical Company and Exxon Chemical
Company under the trade names INDOPOL and PARAPOL, respectively.
Well suited polybutenes for use in this invention include Amoco's
INDOPOL 100.
[0052] Exemplary examples of polyolester include, without
limitation, neopentyl glycols, trimethylolpropanes,
pentaerythriols, dipentaerythritols, and diesters such as
dioctylsebacate (DOS), diactylazelate (DOZ), and
dioctyladipate.
[0053] Exemplary examples of petroleum based fluids include,
without limitation, white mineral oils, paraffinic oils, and
medium-viscosity-index (MVI) naphthenic oils having viscosities
ranging from about 5.times.10.sup.-6 to about 600.times.10.sup.-6
m.sup.2/s (5 to about 600 centistokes) at 40.degree. C. Exemplary
examples of white mineral oils include those sold by Witco
Corporation, Arco Chemical Company, PSI, and Penreco. Exemplary
examples of paraffinic oils include solvent neutral oils available
from Exxon Chemical Company, high-viscosity-index (HVI) neutral
oils available from Shell Chemical Company, and solvent treated
neutral oils available from Arco Chemical Company. Exemplary
examples of MVI naphthenic oils include solvent extracted coastal
pale oils available from Exxon Chemical Company, MVI extracted/acid
treated oils available from Shell Chemical Company, and naphthenic
oils sold under the names HydroCal and Calsol by Calumet and
hydrogenated oils such as HT-40N and IA-35 from PetroCanada or
Shell Oil Company or other similar hydrogenated oils.
[0054] Exemplary examples of vegetable oils include, without
limitation, castor oils, corn oil, olive oil, sunflower oil, sesame
oil, peanut oil, palm oil, palm kernel oil, coconut oil, butter
fat, canola oil, rape seed oil, flax seed oil, cottonseed oil,
linseed oil, other vegetable oils, modified vegetable oils such as
crosslinked castor oils and the like, and mixtures thereof.
Exemplary examples of animal oils include, without limitation,
tallow, mink oil, lard, other animal oils, and mixtures thereof.
Other essential oils will work as well. Of course, mixtures of all
the above identified oils can be used as well.
Hydrocarbon Soluble Polymers
[0055] Suitable polymers for use as anti-settling additives or
polymeric suspension agents in this invention include, without
limitation, linear polymers, block polymers, graft polymers, star
polymers or other multi-armed polymers, which include one or more
olefin monomers and/or one or more diene monomers and mixtures or
combinations thereof. The term polymer as used herein refers to
homo-polymers, co-polymers, polymers including three of more
monomers (olefin monomers and/or diene monomers), polymer including
oligomeric or polymeric grafts, which can comprise the same or
different monomer composition, arms extending form a polymeric
center or starring reagent such as tri and tetra valent linking
agents or divinylbenzene nodes or the like, and homo-polymers
having differing tacticities or microstructures. Exemplary examples
are styrene-isoprene copolymers (random or block), triblocked,
multi-blocked, styrene-butadiene copolymer (random or block),
ethylene-propylene copolymer (random or block), sulphonated
polystyrene polymers, alkyl methacrylate polymers, vinyl
pyrrolidone polymers, vinyl pyridine, vinyl acetate, or mixtures or
combinations thereof.
[0056] Suitable olefin monomer include, without limitation, any
monounsaturated compound capable of being polymerized into a
polymer or mixtures or combinations thereof. Exemplary examples
include ethylene, propylene, butylene, and other alpha olefins
having between about 5 and about 20 carbon atoms and sufficient
hydrogens to satisfy the valency requirement, where one or more
carbon atoms can be replaced by B, N, O, P, S, Ge or the like and
one or more of the hydrogen atoms can be replaced by F, Cl, Br, I,
OR, SR, COOR, CHO, C(O)R, C(O)NH.sub.2, C(O)NHR, C(O)NRR', or other
similar monovalent groups, polymerizable internal mono-olefinic
monomers or mixtures or combinations thereof, where R and R' are
the same or different and are carbyl group having between about 1
to about 16 carbon atoms and where one or more of the carbon atoms
and hydrogen atoms can be replaced as set forth immediately
above.
[0057] Suitable diene monomer include, without limitation, any
doubly unsaturated compound capable of being polymerized into a
polymer or mixtures or combinations thereof. Exemplary examples
include 1,3-butadiene, isoprene, 2,3-dimethyl butadiene, or other
polymerizable diene monomers.
[0058] The inventors have found that Infineum SV150, an
isoprene-styrene di-block and starred polymer, offers superior
permanent shear stability and thickening efficiency due to its
micelle forming nature.
Well Treatments
[0059] Suitable well treatments include, without limitation, any
well treatment that may be diverted through the diversions layers
of this invention. Exemplary treatments include sand control
treatments, aggregating treatments, and zeta modifying treatments
such as S and Aid/zeta potential, sticky/tacky materials such as S
and Wedge, sand consolidation/formation consolidation treatments,
where monomers are pumped through filter cake and then polymerize
in situ to consolidate the formation such as thermal epoxy, furan,
phenolic resins, etc., scale inhibitor treatments, paraffin
inhibitor treatments, wettability modifier treatments, biocide
treatments, gel breaker treatments, enzyme treatments, defoamer
treatments, acid treatments, and mixtures or combinations thereof.
For injection wells, the filter cake will allow even surfactant and
polymer flooding treatments to be pumped through the filter cake
into the formation which also experiences the same uneven
permeability issues.
Compositional Ranges
Thickening Agent Compositional Ranges--Water Based Fluids
[0060] The hydratable polymer may be present in the fluid in
concentrations ranging between 0.001 wt. % and about 5.0 wt. % of
the aqueous fluid. In other embodiments, the range is between about
0.01 wt. % and about 4 wt. %. In yet other embodiments, the range
is between about 0.1% and about 2.5 wt. %. In certain other
embodiments, the range if between about 0.20 wt. % and about 0.80
wt. %.
Thickening Agent Compositional Ranges--Oil Based Fluids
[0061] The hydratable polymer may be present in the fluid in
concentrations ranging between 0.001 wt. % and about 5.0 wt. % of
the oil based fluid including a base oil. In other embodiments, the
range is between about 0.01 wt. % and about 4 wt. %. In yet other
embodiments, the range is between about 0.1% and about 2.5 wt. %.
In certain other embodiments, the range if between about 0.20 wt. %
and about 0.80 wt. %
Cross-Linking System Compositional Ranges
[0062] In other embodiments, the crosslinking agents is present in
a range of from about 10 ppm to about 1000 ppm of metal ion of the
crosslinking agent in the hydratable polymer fluid. In some
applications, the aqueous polymer solution is crosslinked
immediately upon addition of the crosslinking agent to form a
highly viscous gel. In other applications, the reaction of the
crosslinking agent can be retarded so that viscous gel formation
does not occur until the desired time.
[0063] Historically, companies in the industry have been combining
borate ions and organozirconate in cross-linking systems for
cross-linking CMHPG gel systems in order to show higher surface
cross-linking properties. For example, U.S. Pat. No. 6,214,773
disclosed an improved high temperature, low residue viscous well
treating fluid comprising: water; a hydrated galactomannan
thickening agent present in said treating fluid in an amount in the
range of from about 0.12% to about 0.48% by weight of said water in
said treating fluid; a retarded cross-linking composition for
buffering said treating fluid and cross-linking said hydrated
galactomannan thickening agent comprised of a liquid solvent
comprising a mixture of water, triethanolamine, a polyhydroxyl
containing compound and isopropyl alcohol, an organotitanate
chelate or an organozirconate chelate and aborate ion producing
compound, said retarded cross-linking composition being present in
said treating fluid in an amount in the range of from about 0.04%
to about 1.0% by weight of water in said treating fluid; and a
delayed gel breaker for causing said viscous treating fluid to
break into a thin fluid present in said treating fluid in an amount
in the range of from about 0.01% to about 2.5% by weight of water
in said treating fluid.
[0064] The cross-linking compositions of this invention generally
have a mole ratio of a borate of a borate generating compound and a
transition metal alkoxide between about 10:1 and about 1:10. In
certain embodiments, the mole ratio is between about 5:1 and about
1:5. In other embodiments, the mole ratio is between about 4:1 and
1:4. In other embodiments, the mole ratio is between about 3:1 and
1:3. In other embodiments, the mole ratio is between about 2:1 and
1:2. And, in other embodiments, the mole ratio is about 1:1. The
exact mole ratio of the reaction product will depend somewhat on
the conditions and system to which the composition is to be used as
will be made more clear herein. While the cross-linking systems of
this invention includes at least one cross-linking agent of this
invention, the systems can also include one or more conventional
cross-linking agents many of which are listed herein below.
Filter Cake or Filter Layer Formation and Arran
[0065] Referring now to FIG. 1, an embodiment of a diversion system
for diverting a treating fluid into a producing interval of a
vertically oriented well, generally 100, is shown to include a bore
hole 102 in the earth through a non-producing formation 104 into a
producing interval 106 having different geological strata 108. The
system 100 includes casing 110, a working string or production
tubing 112 and a packer 114 to isolate the interval 106 from the
non-producing formation 104. The system 100 also includes a
controlled permeability layer 116 formed on a surface 118 of the
interval 106. The diversion layer 116 has controlled permeability
either due to the particle size distribution of the material
comprising the layer 116 or produced in the layer 116 by dissolving
or eroding dissolvable or erodible components in the layer 116. As
a treating fluid 120 such as a sand control fluid or other well
treating fluid is pumped into the working string or production
stream 112, the fluid 120 passes through the layer 116 and is
diverted or spread out forming diversion jets 122 improving
treating coverage, completeness and/or uniformity. Thus, the layer
116 evens out the effective permeability of segments of the
formation so that the permeability of the entire formation surface
is the same or substantially the same, where the term substantially
means that the permeability from point to point along the formation
differs by no more than 500%. In certain embodiments, the
permeability differs by no more the 50%. In other embodiments, the
permeability differs by no more than 25%. In other embodiments, the
permeability differs by no more than 10%.
[0066] Referring now to FIG. 2, an embodiment of a diversion system
for diverting a treating fluid into a well having an extended
producing horizontal interval, generally 200, is shown to include a
bore hole 202 in the earth through a non-producing formation 204
into an extended producing interval 206 of a geological stratum
208. The system 200 includes casing 210, a working string or
production tubing 212. The system 200 also includes a controlled
permeability layer 214 formed on a screen 216 disposed adjacent the
interval 206. The diversion layer 214 has controlled permeability
either due to the particle size distribution of the material
comprising the layer 214 or produced in the layer 214 by dissolving
or eroding dissolvable or erodible components in the layer 214. As
a treating fluid 218 such as sand and/or water control fluid is
pumped into the working string 212, passes through the layer 216
and is diverted or spread out into the interval 206 forming
diversion jets 220 as it passes through the layer 214 and the
screen 216 improving treating coverage, completeness and/or
uniformity.
Diverted Formations
[0067] Referring now to FIG. 3A, an embodiment of a diverted
formation of the present invention, generally 300, is shown to
include a producing formation 302. The producing formation 302 has
formed or deposited thereon a diversion layer 304. The diversion
layer 304 is shown here to be of non-uniform thickness across the
portion of the producing formation 302 shown and having a first
porosity. In this embodiment, the thickness may vary up to +50% of
an average thickness of the diversion layer 304.
[0068] Referring now to FIG. 3B, another embodiment of an
embodiment of a diverted formation of the present invention,
generally 320, is shown to include a producing formation 322. The
producing formation 322 has formed or deposited thereon a diversion
layer 324. The diversion layer 324 is shown here to be of more
uniform thickness across the portion of the producing formation 322
shown, but having a consistent waved surface--uniform variations in
layer thickness--and having a second porosity. In this embodiment,
the thickness may vary up to +25% of an average thickness of the
diversion layer 324. In this embodiments, the wavelength of the
waved surface is between about 50 cm and 10 m.
[0069] Referring now to FIG. 3C, another embodiment of a diverted
formation of the present invention, generally 340, is shown to
include a producing formation 342. The producing formation 342 has
formed or deposited thereon a diversion layer 344. The diversion
layer 344 is shown here to be of a more uniform thickness across
the portion of the producing formation 342 shown, but having a
consistent waved surface with smaller waves--smaller uniform
variations in the layer thickness and having a third porosity. In
this embodiment, the thickness may vary up to +10% of an average
thickness of the diversion layer 344. In this embodiments, the
wavelength of the waved surface is between about 1 cm and 50
cm.
[0070] Referring now to FIG. 4A, another embodiment of a diverted
formation of the present invention, generally 400, is shown to
include a producing formation 402. The diverted formation 400
includes a screen assembly 404 disposed on the formation 402. The
diverted formation 400 also includes a diversion layer 406 formed
on the screen assembly 404, where the diversion layer 406 comprises
particles having a larger diameter than the openings of the screen
assembly 404.
[0071] Referring now to FIG. 4B, another embodiment of a diverted
formation of the present invention, generally 450, is shown to
include a producing formation 452. The diverted formation 450
includes a screen assembly 454 disposed on the formation 452. The
diverted formation 450 also includes a diversion layer 456 disposed
between the screen assembly 454 and the formation 452. In this
case, the diversion layer 456 comprises particles having a smaller
diameter than the openings of the screen assembly 454. The layer
456 is formed by depositing a diversion composition 458 on the
screen assembly 454. The composition 458 then flows through the
screen assembly 458 to form the layer 456.
[0072] Referring now to FIG. 5, another embodiment of a diverted
formation of the present invention, generally 500, is shown to
include a producing formation 502. The diverted formation 500
includes a screen assembly 504 disposed on the formation 502. The
diverted formation 500 also includes a first diversion layer 506
interposed between the formation 502 and the screen assembly 504,
and a second diversion layer 508 formed on the screen assembly 504,
where the first diversion layer 506 comprises particles having a
smaller larger diameter than the openings of the screen assembly
504 and the second diversion layer 508 comprises particles having a
larger diameter than the openings of the screen assembly 504. The
first diversion layer 506 is formed by depositing a first diversion
composition 510 on the surface of the screen assembly 504, which
then flows through the screen assembly 504 to form the first
diversion layer 506, while the second layer 508 is simple deposed
on the screen assembly 504.
[0073] Referring now to FIG. 6, another embodiment of a diverted
formation of the present invention, generally 600, is shown to
include a producing formation 602. The diverted formation 600
includes a diversion layer 604 formed on the formation 602. Once
formed on the formation 602, the diversion layer 604 is treated
with a solution 606, which removes dissolvable or erodible
components in the layer composition changing the porosity of the
layer 608.
Prior Art Treatments without Diversion Layer
[0074] Referring now to FIG. 7, an illustration of a prior art
treatment of a producing formation without a diversion layer,
generally 700, is shown to include a producing formation 702. A
treating composition 704 is then applied to the formation 702.
Because the formation 702 does not include a diversion layer, the
treating composition 704 penetrates the formation 702 in solution
channels 706, while the channels 706 are exaggerated; the figure is
designed to illustrate the non-uniformity of the treatment.
Present Treatments with a Diversion Layer
[0075] Referring now to FIG. 8, an illustration of a treatment of a
producing formation having a diversion layer of this invention,
generally 800, is shown to include a producing formation 802 having
a diversion layer 804 formed on the formation 802. A treating
composition 806 is then applied to the diversion layer 804 of the
formation 802. The treating composition 806 is diverted through the
diversion layer 804 to form a diverting layer 808. Because the
formation 802 includes the diversion layer 804, the treating
composition 806 enters the formation 802 from the diverting layer
808 in a more uniform manner to form a treated formation 810. Once
the treating composition 806 has penetrated the formation 802 to
the extent desired, flow back of the treating solution 806 leaves a
permanent treated formation 812. Once treatment flow back has
occurred, the flow back and production from the formation 802 will
begin to erode the diversion layer 804 forming partially eroded
layer 814, further eroded layer 816, until the layer 804 is fully
removed.
EXPERIMENTS OF THE INVENTION
Introduction
[0076] Sand production from oil and/or gas wells may lead to damage
or plugging of screens, tubulars, and surface equipment and may
necessitate costly maintenance or work over operations. Various
mechanical and chemical treatments are available to mitigate this
problem including zeta potential or aggregation modifying agent
products such as S and Aid available from Weatherford. Remedial
pumping of zeta potential or aggregation modifying agents into a
formation or formation zone may decrease sand production and
increase the maximum sand free rate at which a well may produce.
Great success has been achieved in the matrix treatment of short
intervals with sand control, scale inhibitor, paraffin inhibitor,
acidizing and other treatments. However, proper placement of such
treatments becomes much more difficult in long horizontal wells for
two main reasons. First, too large of a pressure drop along the
well will lead to insufficient treatment towards the end of the
wellbore. Second, such wells typically have a high variability in
permeability along the formation. FIG. 9 shows a representation of
varying permeability across an interval, which is common with long
horizontal wells. In such cases, a majority of any treatment fluid
leaks off into high permeability zones and not enough enter lower
permeability zones. This situation is generally exacerbated if a
high permeability region (thief zone) is located towards the heel
of the well, leading to even more leak-off at the beginning of the
well, or if there are any natural fractures in the formation.
[0077] In order to properly treat a well with this configuration,
it is necessary to divert some treatment fluid away from high
permeability zones or segments to lower permeability zones or
segments. The methods of this invention provide treatments for long
horizontal wells by depositing or building up a
controlled-permeability filter cake on an inside of the wellbore
and then pumping the treatment through the filter cake. If the
filter cake permeability is engineered correctly, then the
effective permeability across the formation should be substantially
even, leading to the even treatment to each zone. The term
substantially here means that the permeability across the formation
differs by no more that 500%. In certain embodiments, the
permeability across the formation differs by no more than 250%. In
certain embodiments, the permeability across the formation differs
by no more than 100%. In certain embodiments, the permeability
across the formation differs by no more than 50%. In certain
embodiments, the permeability across the formation differs by no
more than 25%. In other embodiments, the permeability across the
formation differs by no more than 10%. In other embodiments, the
permeability across the formation differs by no more than 5%.
Results and Discussions
[0078] Test Filter Cake Formation and Permeability
[0079] The permeability and particle size requirements for the
filter cakes or layers were tested experimentally. Assuming a
lowest permeability zone of 100 mD, the filter cake should have a
permeability at least this low. However, initial modeling suggested
that a filter cake permeability of about 1 mD to about 50 mD may be
adequate. We approximated material particle size distributions to
achieve a 50 mD filter cake using the Rumpf-Gupte approximation for
packed spheres, which gave a particle size of about 9 .mu.m.
However, samples of real filter cake materials always have a
particle size distribution, which will affect filter cake
permeability. Actual particle size distributions for several
batches of sized calcium carbonate used for drilling fluids
applications are shown in FIGS. 10A-C. These samples show a
relatively broad particle size distribution which is beneficial for
bridging a wide distribution of pore throat diameters that are seen
in real formations.
[0080] The filter cake permeability was determined by plotting
brine flow vs time through a filter cake formed in a 350 mL filter
press. Results for three are described calcium carbonate samples is
given in FIGS. 11A-C.
[0081] The results shown in FIGS. 11A-C clearly demonstrate that
filter cake permeability may be controlled by choosing the correct
particle size. Indeed, the targeted range of about 5 mD to about 50
mD was covered well with calcium carbonate D.sub.50 having
particles ranging from about 4 .mu.m to about 40 .mu.m. The
substrate for these experiments was a ceramic disk with
permeability of about 2500 mD indicating that the filter cake is
capable of forming on high permeability zones.
[0082] Test Treatment Through Filter Cake
[0083] A method was developed to inject zeta potential or
aggregation modifying agents, or other treatments, on-the-fly to
create a turbulent environment to provide adequate mixing. The
degree of turbulence in a flow path is principally determined by
flow rate and pipe diameter (as well as fluid viscosity, pipe
surface smoothness, and temperature). In order to generate
turbulent flow, a lower inner-diameter capillary tube was used.
Thus, sand control agents or treatments with reduced aqueous
solubility would have to be injected on-the-fly at a high rate into
a brine stream and flown through the filter cake as shown
schematically in FIG. 12.
[0084] The sand control chemical was injected on the fly and passed
through the filter cake in a modified filter press. The effluent
was collected into a beaker containing sand and brine and the sand
mixed manually. The results of this experiment clearly showed that
the sand control agents penetrated the filter cake and were still
capable of agglomerating sand afterwards.
[0085] Test Removal of the Filter Cake
[0086] After the diverting filter cake had been formed and zeta
potential or aggregation modifying agents have been pumped
therethrough, we demonstrated that the filter cake were removable,
while minimizing damage to the formation. While calcium carbonate
is easily removable with acid treatment, decomposing to water,
carbon dioxide, and calcium ions, zeta potential or aggregation
modifying agents are known to be sensitive to acidic conditions and
work best around neutral pH.
[0087] We demonstrated that a buffered acetic acid system based on
a 10% acetic acid solution brought to pH 4.5, pH 4.75, and pH 5
using sodium hydroxide were effective in filter cake removal. A
zeta potential or aggregation modifying agent treatment was carried
out and the agglomerated sand was then treated overnight with each
acetate buffer solution. The results showed that the samples
treated with the buffers held together upon bottle inversion,
retaining their agglomeration ability.
[0088] Build a Model Horizontal Well Apparatus
[0089] In order to test the feasibility of the diverting filter
cake concept, we built an apparatus to model a horizontal well with
zones having different permeabilities. The general design of the
apparatus is shown in FIG. 13. Each zone in the well is modeled by
a sandstone tube having a longitudinal hole drilled therethrough.
The sandstone tubes were arranged in series and flow occurs
horizontally through the core centers and radially outward through
the body of each core. The core arrangement of FIG. 13 shows one of
the most demanding horizontal well situations in which a high
permeability zone (here a high permeability core) is located at the
head of the well functioning as a large "thief-zone" stealing most
of the treatment fluid. If a diverting filter cake functions
adequately under these conditions, then it will be well suited for
most other reservoir conditions.
[0090] Referring now to FIG. 14, an embodiment of the apparatus of
FIG. 13, generally 900, is shown to include a fluid treatment
reservoir 902 connected to a fluid delivery tube 904 including a
fluid valve 906. The apparatus 900 also includes a filter material
reservoir 908 connected to a slurry delivery tube 910 having a
slurry valve 912. The tubes 904 and 910 are connected to a control
valve 914 designed to permit either a fluid or a slurry to be
directed into a horizontal well model section 916. The valve 914 is
connected to the section 916 via inlet conduit 918. The section 916
includes five core assemblies 920a-e. The assemblies 920a-e include
transparent outer layers 922a-e. Mounted in interiors 924a-e of the
assemblies 120a-e are cores 926a-e having different permeabilities.
The assemblies 920a-e also include top valves 928a-e and bottom
valves 930a-e. The bottom valves 930a-e are connected via conduits
932a-e to flow collection containers 934a-e. The assemblies 920a-d
are connected via interconnecting conduits 936a-d, while the
assembly 920e is connected to an outlet conduit 938 having an
outlet valve 940 leading to an outlet receiving container 942. The
outer layers 922a-e of the assemblies 920a-e are constructed out of
a clear material so that particulate flow may be visualized, are
capable of withstanding up to 200 psi of pressure, and are capable
of capturing the fluid flowing through each core. The clear
material used here was machined clear polymethylmethacrylate
(PMMA). The apparatus 900 also include one or more pressures
sensors 944, here two 944a&b.
[0091] The apparatus 900 including the five zones of varying
permeability is designed to collect flow-through liquid, which may
be captured directly into contains such as beakers or may be routed
through tubing attached to the valves around each core. The
presence of the valves allows for flow to be directed to certain
cores or through the end-valve. Pressure valves located at the
beginning and end of the apparatus are used to calculate
permeability changes throughout the process. A pump capable of
flow-rates greater than 3 L/min is fed by a brine tank or from a
mixing calcium carbonate slurry. A 3-way valve on the pump inlet
allows pumping of either the brine or particulate slurry
sequentially.
[0092] Using Model Apparatus
[0093] Three main steps were performed to show that effectiveness
of the diverting filter cakes of this invention with the model
apparatus. First, it was necessary to show that uneven flow
patterns exist with the model apparatus using cores of different
permeabilities. Second, it was necessary to show that the filter
compositions of this invention form filter cakes on the bore
through the cores leading to a more uniform or even flow through
all of the cores. In certain embodiments, the filter cakes will
form uniform or substantially uniform flow through all of the
cores. Finally, it was necessary to show that the filter cakes
erode or dissolve over time restoring the original permeabilities
of the cores without permeability damage to the cores. In a typical
experiment, a 3 wt. % KCl brine was pumped through the apparatus
100 for 2 min at a flow rate of about 3 L/min and flow through each
core was collected and the pressure in the apparatus was measured.
Measurement of pressure at the beginning and end of the apparatus
showed that constant pressure was present along the entire system,
because of the relatively small interval lengths. Equation 1 shows
the calculation of permeability in a radial flow regime
k = Q .mu.ln ( r o / r i ) 2 .pi. h .DELTA. p ##EQU00001##
where k is the permeability, Q is the flow rate, .mu. is the
viscosity, r.sub.o is the outer radius, r.sub.i is the inner
radius, h is the length of interval, and .DELTA.p is the
differential pressure. Because permeability depends on fluid flow
and differential pressure and pressure is the same at each core,
fluid flow through each core is directly proportional to the
permeability.
[0094] After the initial flow and permeability values for each core
were recorded, a calcium carbonate slurry is pumped to establish a
filter cake on the interior surface of each core. The particulate
concentration was designed to be sufficiently high to allow
effective bridging. In this case, 2 wt. % calcium carbonate was
found to give good results and was pumped onto the cores at 3
L/min, which was determined to be a sufficiently high pump rate.
The pumping method involved 1) slurry and brine were pumped
alternatively for 30 seconds each for a total of 5 minutes, 2)
brine was pumped to clear out any suspended solids, and 3) brine
was pumped for 10 minutes and the amount of liquid produced over
this time period was recorded.
[0095] While calcium carbonate particles centered around 5 .mu.m
calcium carbonate (Imerys Wel-Carb 5) formed diversion layers, the
smaller particle size distribution materials form better using a
different pumping regimes, for instance where pumping of zeta
potential or aggregation modifying agents and filter cake is
alternated rather than pre-forming a filter cake.
[0096] For particulate compositions having a broader particle size
distribution (PSD) such as Wel-Carb 20 which has a similar PSD to
the Wel-Carb 25, the diversion layer or filter cake results are
shown in FIG. 15, which showed highly imbalanced flow at the start,
even flow after the filter cake had been formed, and also showed
that the filter cake remained stable even after pumping was stopped
and pressure removed for an hour (and even a day). The results are
displayed from left to right corresponding to the first to last
core in the model apparatus and the flow volume was measured for 2
minutes in the initial stage and 10 minutes with the filter cakes.
Overall flow rate decreases greatly, because of the reduced
permeability of the cores and increased differential pressure
buildup in the model apparatus. The effective per-core permeability
was found to be about 13 mD or a filter cake permeability of about
1 mD assuming a filter cake thickness of 0.5 mm.
[0097] For even larger particle size compositions such as Wel-Carb
50 with a D.sub.50 of 39.6 .mu.m, the results are shown in FIG. 16.
In this case, two zones have very high permeabilities and would act
as the major thief-zones in a well. Formation of the filter cakes
decreased flow rates through all cores to about the same level.
This means that the filter cakes are still acting successfully to
equalize the core permeabilities and produce even flow along the
apparatus. Dissolution with acid shows that flow rates rebound to
at least pre-filter cake levels, demonstrating efficient removal of
the calcium carbonate.
[0098] This experiment was carried out two more times with
different core configurations to confirm that the results were
reproducible and worked in different well structures. Core
configurations included highest permeability core at the start,
middle, and end of the model apparatus. FIG. 17 shows a summary of
the effective core permeabilities after filter cake formation and
demonstrates the ability to equalize permeability across the model
formation. The results are tabulated below for initial flow rates
and permeabilities, with filter cake values and after filter cake
removal values (removal here by HCl solution treatment):
TABLE-US-00001 Initial With Filter Cake After Dissolution Perme-
Perme- Perme- Flowrate ability Flowrate ability Flowrate ability
(mL/min) (mD) (mL/min) (mD) (mL/min) (mD) 1235 3911.4 94 23.8 1675
3617.0 220 696.8 85 21.5 750 1619.6 205 649.3 75 19.0 110 237.5
1255 3974.8 76 19.3 1665 3595.4 10 31.7 91.5 23.2 10 21.6
[0099] It may also not be necessary to form a filter cake evenly
along the entire wellbore as it may be sufficient to bring the
permeability of the higher permeability segments near to the level
of the lowest permeability segments. A real well may also have
larger cracks, fractures, etc. on which it would be impossible to
form a filter cake with small size particulate. In such scenarios,
it may be necessary to use a graded pumping regime starting with
large diameter material and working down to particle sizes
sufficient to even out the flow profile across the formation.
Examples
Test Filter Cake Formation and Permeability
[0100] Samples of Wel-Carb 2, 5, 20, 25, and 50 were obtained from
Imerys.
[0101] Filter cake permeability was determined by weighing 8 g of
calcium carbonate and adding it directly to a filter press having
about a 2500 mD ceramic disk. Brine was added and particulate was
manually mixed with a spatula. Brine (at least 350 mL) was passed
under atmospheric pressure through the filter press to form the
filter cake. Once formed, a volume of brine in the filter press was
constantly topped off to maintain the volume at about 350 mL while
the volume flowing through the filter press was recorded. The
pressure due to gravity and the flow rate was calculated and
Darcy's law was used to calculate the permeability. The
flow-through filter press apparatus was found to be the easiest
method to achieve constant flow or pressure through the filter
cake.
[0102] Treatment Through Filter Cake
[0103] On-the-fly injection of a treatment through the filter cake
was carried out using a 100 mL filter press modified with a
flow-through piston attachment as shown in FIG. 12. 5 g of PLA were
added directly to the filter press with about a 2500 mD ceramic
disk followed by brine, which was then mixed to suspend the solid.
The set-up was heated to 180.degree. F. Next brine was passed
through the apparatus at 20 mL/min for a total of 100 mL to form
the filter cake. Next, a sand control agent (SandAid) was injected
on the fly at 10 vol. % concentration until S and Aid droplets
began to elute from bottom of filter press. The sand control
chemical was stirred with sand, demonstrating retention of sand
aggregation ability.
[0104] Test Removal of the Filter Cake
[0105] Acetate buffers at pH 4.5, pH 4.75, and pH 5 were created by
addition of 25% NaOH solution to 10% acetic acid solution in water
until the proper pH was reached. Sand was agglomerated with the
zeta potential or aggregation modifying agent S and Aid using the
standard beaker agglomeration test: to 100 g 20/40 sand mixed in
100 mL 2 wt. % KCl brine was added 7 mL SandAid, the solution was
washed twice with 100 mL brine, and the agglomerated sand
transferred to a bottle. Next, 100 mL of the appropriate acetate
buffer was added and aged overnight. Bottles were inverted to test
for agglomeration.
[0106] Build Horizontal Well Model Apparatus
[0107] Assembly of apparatus of FIG. 14: Cores were washed to
remove drilling fines and allowed to dry. End pieces were attached
to the cores by placing clear silicone RTV onto the end piece and
carefully inserting onto core and squeezing down by hand. After one
end piece is attached, the process is repeated on the other side.
RTV is allowed to set for 24 hours before continuing.
[0108] O-rings are inserted into the plastic core-holder sections
and the cores are inserted with some lubricant added to sides of
plastic core end-pieces to aid insertion. Apparatus is then
assembled by alternating one core-holder and one intermediate
piece. Stainless steel threaded rods are used to hold the apparatus
together as shown in FIG. 14 and are tightened enough to seal the
flange O-rings. Plastic nipples are attached to threaded openings
in core-holder sections and stainless steel valves are attached to
those. End-flanges with appropriate fittings are attached to ends
of the apparatus. Pressure gauges are placed at the start of the
apparatus and at each connecting tube as desired. Valves were
placed to allow flow through the end of the apparatus and to divert
flow at the start of the apparatus. A gear pump and inverter motor
capable of about 15 L/min flow rate was used. A pressure-release
valve (150-200 psi max pressure) must be used to prevent unsafe
rise in pressure.
[0109] Using Model Apparatus
[0110] Procedure for filter cake formation in long-horizontal well
model apparatus: 60 L of 3 wt. % KCl brine was made up and
transferred to holding tank. 10 L of 2 wt. % by mass calcium
carbonate suspension was made up and stirred at between 150 rpm and
200 rpm with a large mixing blade. A 3-way valve was used to feed
either brine or carbonate slurry into the apparatus at a pump rate
of 15 Hz. Initial flow and permeability was measured by flowing
brine at 15 Hz (about 3 L/min) for 2 min and collecting the
effluent of each core in a beaker and massed. Next, carbonate
slurry and brine were alternatively pumped for 30 seconds each for
a total of 5 min and brine was pumped for 1 more minute. At this
point, beakers were switched out for empty ones and flow was
continued for 10 min, after which fluid in each beaker was
massed.
[0111] Acid dissolution of filter cake was carried out by pumping
5% HCl through the apparatus, and then the core holder valves were
closed one after another until the core holders were filled with
acid solution. After the apparatus was shut-in overnight, brine was
flowed through the apparatus to clear out the acid and then was
flown again for 2 minutes to record the flow.
[0112] All references cited herein are incorporated by reference.
Although the invention has been disclosed with reference to its
preferred embodiments, from reading this description those of skill
in the art may appreciate changes and modification that may be made
which do not depart from the scope and spirit of the invention as
described above and claimed hereafter.
* * * * *