U.S. patent application number 11/780037 was filed with the patent office on 2008-09-04 for apparatus and method of fracturing.
This patent application is currently assigned to Trican Well Service Ltd.. Invention is credited to David Browne, Dale Dusterhoft, Sam Luk, Michael Tulissi, Jason Vaughan.
Application Number | 20080210424 11/780037 |
Document ID | / |
Family ID | 39731937 |
Filed Date | 2008-09-04 |
United States Patent
Application |
20080210424 |
Kind Code |
A1 |
Dusterhoft; Dale ; et
al. |
September 4, 2008 |
Apparatus and Method of Fracturing
Abstract
A method and apparatus for fracturing a formation containing a
wellbore comprising the steps of (a) injecting a gel into the
wellbore; (b) permitting for the gel to increase viscosity and (c)
fracturing the formation in the vicinity of the gel.
Inventors: |
Dusterhoft; Dale; (Red Deer,
CA) ; Browne; David; (Calgary, CA) ; Vaughan;
Jason; (Calgary, CA) ; Luk; Sam; (Calgary,
CA) ; Tulissi; Michael; (Calgary, CA) |
Correspondence
Address: |
Akin Gump Strauss Hauer & Feld LLP
44th Floor, 1111 Louisiana Street
Houston
TX
77002-5200
US
|
Assignee: |
Trican Well Service Ltd.
Calgary
CA
|
Family ID: |
39731937 |
Appl. No.: |
11/780037 |
Filed: |
July 19, 2007 |
Current U.S.
Class: |
166/292 ;
166/242.6; 166/308.2 |
Current CPC
Class: |
C09K 2208/26 20130101;
C09K 8/685 20130101; E21B 43/26 20130101; Y10S 507/925
20130101 |
Class at
Publication: |
166/292 ;
166/242.6; 166/308.2 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 33/13 20060101 E21B033/13 |
Foreign Application Data
Date |
Code |
Application Number |
Mar 2, 2007 |
CA |
2580590 |
Claims
1. A method of fracturing a formation containing a wellbore
comprising the steps of: (a) injecting a gel into the wellbore; and
(b) fracturing the formation adjacent the area of the gel.
2. The method according to claim 1, further including the step of
permitting the gel to increase in viscosity prior to the fracturing
step.
3. The method according to claim 2, wherein the gel forms a plug in
the wellbore.
4. The method according to claim 3, including the step of
introducing a fluid into the wellbore prior to injection of the
gel.
5. The method according to claim 4, wherein the gel comprises a
base fluid and a viscosifying agent.
6. The method according to claim 5, wherein the base fluid is water
or hydrocarbon based.
7. The method according to claim 5, wherein the viscosifying agent
is a viscosifying polymer or surfactant.
8. The method according to claim 5, wherein the viscosifying agent
is guar, hydroxyl ethyl cellulose or derivatives thereof.
9. The method according to claim 5, wherein the viscosifying agent
is a phosphate ester.
10. The method according to claim 5, wherein the gel further
includes a crosslinker.
11. The method according to claim 10, wherein the crosslinker is a
multivalent metal ion.
12. The method according to claim 11, wherein the multivalent metal
ion is borate, antimony, zirconium, chrome, titanium or iron.
13. The method according to claim 10, wherein the gel further
includes a one for more of a clay stabilizing, salt, methanol, pH
adjustors, biocide and flowback enhancer.
14. The method according to claim 10, wherein the gel further
includes a breaker.
15. The method according to claim 14, wherein the breaker is an
enzyme or oxidizer.
16. The method according to claim 14, wherein the breaker is a
persulfate, peroxide, acid or bleach.
17. The method according to claim 14 wherein the breaker is a pH
buffer or caustic fluid.
18. The method according to claim 4 wherein the gel has a yield
strength sufficient to minimize movement of fracturing fluid to
another part of the well.
19. A method of fracturing a formation containing a wellbore
comprising the steps of: (a) inserting tubing into the wellbore to
a first location in the wellbore; (b) introducing a gel into the
wellbore via the tubing sufficient at the first location; and (c)
introducing a fracturing fluid into the wellbore via the tubing to
fracture the formation at the first location.
20. The method according to claim 19, further including the step of
introducing a fluid into the wellbore prior to the injection of the
gel.
21. The method according to claim 19, further including the step of
permitting the gel to increase in viscosity.
22. The method according to claim 19, wherein the fracturing fluid
is introduced into the gel.
23. The method according to claim 19, further including the step of
moving the tubing to a second location and repeating step (c).
24. The method according to claim 23 further including the step of
introducing additional gel prior to repeating step (c).
25. A new use of a gel for purposes of well stimulation, comprising
the step of: use of a gel to isolate a well for well
stimulation.
26. The method according to claim 25, wherein the gel comprises a
base fluid and a viscosifying agent.
27. The method according to claim 26, wherein the base fluid is
water or hydrocarbon based.
28. The method according to claim 26, wherein the viscosifying
agent is a viscosifying polymer or surfactant.
29. The method according to claim 26, wherein the viscosifying
agent is guar, hydroxyl ethyl cellulose or derivatives thereof.
30. The method according to claim 26, wherein the viscosifying
agent is a phosphate ester.
31. The method according to claim 27, wherein the gel further
includes a crosslinker.
32. The method according to claim 31, wherein the crosslinker is a
multivalent metal ion.
33. The method according to claim 32, wherein the multivalent metal
ion is borate, antimony, zirconium, chrome, titanium or iron.
34. The method according to claim 26, wherein the gel further
includes a one for more of a clay stabilizing, salt, methanol, pH
adjustors, biocide and flowback enhancer.
35. The method according to claim 26, wherein the gel further
includes a breaker.
36. The method according to claim 35, wherein the breaker is an
enzyme or oxidizer.
37. The method according to claim 35, wherein the breaker is a
persulfate, peroxide, acid or bleach.
38. The method according to claim 35 wherein the breaker is a pH
buffer or caustic fluid.
39. The method according to claim 26 wherein the gel has a yield
strength sufficient to minimize movement of fracturing fluid to
another part of the well.
40. A bottomhole apparatus for introducing a fluid into a wellbore
comprising: a tube including a first end connectable to tubing and
a second end which is closed, the tube including a least one slot
in the side thereof, whereby fluid entering the apparatus from the
first end is directed out the side of the tube.
41. The bottomhole apparatus according to claim 40, further
including a cone at the second end adapted to laterally deflect
fluid out of the apparatus.
42. The bottomhole apparatus according to claim 41, wherein the
slot is an elongated slot.
43. The bottomhole apparatus according to claim 42, further
including means for coupling the apparatus to tubing.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from Canadian Patent
Application Serial No. 2,580,590 filed Mar. 2, 2007.
MICROFICHE APPENDIX
[0002] Not applicable.
FIELD OF INVENTION
[0003] This invention relates to fracturing of subterranean
formations in general and the isolation of a formation during
fracturing in particular.
BACKGROUND OF THE INVENTION
Isolation of Horizontal Wells
[0004] Many wells are drilled horizontally into subterranean
formations. On occasion, it is desired to create a number of
hydraulic fractures along the length of these horizontal wells.
When creating multiple fractures, it is important to be able to
isolate one fracture from another so the same part of the well is
not repeatedly fractured.
[0005] A number of prior art methods have been used to isolate
fractures. In one such method, steel pipe (liner) is cemented in
the well and then perforated. The liner is first perforated at a
first location. A hydraulic fracturing treatment is then performed
at this location. After the fracturing treatment, a mechanically
set plug (bridge plug) is set inside the casing above the fractured
area and a new set of perforations are shot closer to the heel of
the well. A second fracturing treatment is then performed at the
location of the new set of perforations. The procedure is then
repeated along the length of the horizontal section of the liner
resulting in a number of perforating and fracturing treatments
being completed in the well. While effective at providing isolation
between the fractures, this procedure is costly and time
consuming.
[0006] Another isolation method involves cementing a liner in a
horizontal well and perforating the liner at all of the intervals
along the well where fracturing is to be performed. An isolation
packer assembly is then run on tubing to isolate the various
intervals from each other. Fracturing is performed at a perforated
interval with the packer cups bounding the area of the fracture.
The isolation packer is then pulled up the hole and a fracturing
treatment is performed on each perforated interval.
[0007] Another isolation method involves leaving the well in an
open hole state with no liner or casing in place. In this
situation, inflatable packers or other mechanical tools are run in
the well to isolate one part of the horizontal well from another.
Various fracturing treatments are performed in these isolated
intervals between the packers or other tools. Such treatments are
performed through tubing.
[0008] Another isolation method involves isolating the well with a
number of packers and sliding sleeves which are originally run into
the well with all the sleeves closed except for the interval
closest to toe of the horizontal well. A fracturing treatment is
pumped through this open sleeve. After the treatment, a ball is
pumped down the well to isolate the sleeve across the interval that
was just fractured and to open a sleeve on a new interval that is
closer to the heel of the well. A second fracturing treatment is
then pumped into this newly isolated interval. This procedure is
repeated on all the sleeves until all the intervals in the well
have been stimulated.
[0009] Another isolation method involves initiating a cut in the
formation using a jetting nozzle and sand run on the end of tubing.
This cut is immediately followed by a fracturing treatment pumped
through the same jetting nozzle or down the annulus of the tubing
and the steel casing. This method relies on a negative pressure
drop created by the jetting nozzle to divert the fracturing
treatment into the cut that was just created in the formation. The
tubing is then moved to a new location in the horizontal section of
the well. The procedure is repeated. This procedure can be used
with tools run on tubing or coiled tubing and can be in cased or
open hole. Such methods are described in Canadian Patents 2225571,
2130365, 2104138 and U.S. Pat. Nos. 5,361,856, 5,494,103, 5,765,642
and 7,159,660.
[0010] Another method, described in U.S. Pat. No. 4,951,751,
involves a method of diverting fracturing treatments in cased wells
that are cemented and perforated. In this method, a well is
perforated at the farthest desired location from the heel and a
fracturing treatment is performed. The fracturing treatment is
followed by a solidifiable gel containing a breaker and a sold
mechanical wiper plug of rubber, metal, wood, etc. The wiper plug
is similar to a pipeline plug. The gel and wiper plug is displaced
across the first fracturing treatment and the gel is allowed time
to solidify. The well is then perforated again at a location closer
to the heel and a second fracturing treatment is performed in a
similar manner. The solid wiper plug and the gel both work to
divert the fracturing treatment away from the first fracturing
treatment. The lack of perforations towards the heel of the
fracture ensures diversion of the fracturing treatment above the
perforated interval. In this method, the fracturing treatments are
pumped directly down the casing with no tubing or coiled tubing in
place.
Isolation of Vertical Wells
[0011] Many wells are drilled vertically or at an angle from
vertical (deviated) but are not horizontal. In many of these wells,
a number of subterranean formations are present that require
hydraulic fracturing treatments. In these wells, it is often
desirable to fracture each subterranean formation separately. To do
this, a number of methods have been developed to isolate one
formation from another.
[0012] One such method is to perforate all of the desired intervals
and isolate the formations by using a combination of packers and
bridge plugs. A subterranean formation is isolated between these
mechanical plugs and a fracturing treatment is performed. The plugs
and packer are then moved to the next interval and a second
fracturing treatment is performed. This procedure is repeated on
each formation that needs to be fractured moving up the well until
all have been done. In this procedure, the fracturing treatments
are normally pumped down tubing but can also be pumped down coiled
tubing. The method can also be used pumping down the casing with
bridge plugs in place, with no perforations above the interval to
be fractured and no packer.
[0013] Another method uses rubber cups run on coiled tubing in a
perforated cased well. The rubber cups seal to the casing when
pressure is applied from the inside and a fracturing treatment is
pumped into a formation that is isolated between the cups. When the
treatment is completed the pressure is released and the cups relax.
The cups are then moved to the next formation and the procedure is
repeated. This method is normally used when the fracturing
treatment is pumped through coiled tubing but can also be used on
regular tubing.
[0014] Another method involves a perforation strategy, and on
occasion, ball sealers to divert the fracturing treatment into
different formations. This method, often known as limited entry
fracturing is normally used when the fracturing treatment is pumped
directly down the casing with no tubing in the wellbore.
SUMMARY
[0015] According to one aspect, the invention relates to a method
of fracturing a formation containing a wellbore comprising the
steps of (a) injecting a gel into the wellbore, and (b) fracturing
the formation adjacent the area of the gel.
[0016] According to another aspect, the invention relates to a
method of fracturing a formation containing a wellbore comprising
the steps of: (a) inserting tubing into the wellbore to a first
location in the wellbore; (b) introducing a gel into the wellbore
via the tubing sufficient at the first location; and (c)
introducing a fracturing fluid into the wellbore via the tubing to
fracture the formation at the first location.
[0017] According to another aspect, the invention relates to a
bottomhole apparatus for introducing a fluid into a wellbore
comprising: a tube including a first end connectable to tubing and
a second end which is closed, the tube including a least one slot
in the side thereof, whereby fluid entering the apparatus from the
first end is directed out the side of the tube.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] The invention is described below with reference to the
accompanying drawings, and wherein:
[0019] FIG. 1 is a schematic representation of coiled tubing or
tubing inside a horizontal wellbore;
[0020] FIG. 2 is a schematic representation of a gel according to
the invention being introduced into the wellbore of FIG. 1;
[0021] FIG. 3 is a schematic representation of a first fracture in
the formation of FIG. 1;
[0022] FIG. 4 is a schematic representation of the coiled tubing or
tubing of FIG. 1 pulled back to a second fracturing interval
according to the invention;
[0023] FIG. 5 is a schematic representation of a second fracture at
the second fracturing interval of FIG. 1;
[0024] FIG. 6 is a schematic representation of the wellbore of FIG.
1 with the tubing removed and fracturing completed;
[0025] FIG. 7 is a schematic representation of the wellbore of FIG.
1 being flowed back following breaking of the gel plug according to
the invention;
[0026] FIG. 8 is a schematic representation of a diverting tool
usable in a method according to the invention;
[0027] FIG. 9 is a cross section of the tool of FIG. 8; and
[0028] FIG. 10 is a graph of Viscosity versus Time for a gel plug
according to the invention.
DETAILED DESCRIPTION OF THE DRAWINGS
[0029] With reference initially to FIG. 1, in one embodiment of the
invention, wellbore jointed tubing or coiled tubing 2 is run into a
well casing 4 and an open hole formation 8 below this casing to a
depth where the first fracturing treatment is to be initiated. In a
vertical well this will be at the formation nearest the bottom of
the well. In a horizontal well this will be at a location closest
to the toe 6 of the horizontal section indicated generally at 8 of
the well. After the tubing 2 has been placed at the desired
location, the wellbore 10, if not already full, is filled with an
annulus fluid 9 which may be water, a hydrocarbon fluid, or any
suitable fluid that can fill the wellbore 10. This fluid is
incompressible and has no viscosity increasing chemicals added to
it.
[0030] After the wellbore 10 is filled with the annulus fluid, the
entire wellbore 10 or a part thereof, is filled with a viscous gel
12 by circulating the gel 12 down the tubing 2 and out through a
bottomhole apparatus diverting tool 14 as shown in FIG. 2. The gel
12 displaces the annulus fluid 9 previously placed in the well 10.
After introduction of the gel 12 into the wellbore 10, the
viscosity of the gel 12 increases over time (typically about a half
an hour) to a maximum viscosity and forms a gel plug 18 in the
wellbore 10. In the embodiment of FIG. 2, the wellbore is filled
with gel to a level indicated by 20. The gel plug 18 does not
solidify and permits the tubing 2 to pass through it.
[0031] Referencing to FIG. 3, following the formation of the gel
plug 18, a fracturing fluid 22 (or other suitable stimulation
fluid) is pumped down the tubing 2 and is directed laterally
against the formation. The fracturing fluid 22 displaces an amount
of the plug 18 away from the formation face and then initiates a
fracture into the subterranean formation.
[0032] Referring to FIGS. 8 and 9, diverting tool 14 is connected
to the end of the tubing 2 by tubing connector 50 to divert the
fracturing treatment 22 in a direction generally perpendicular to
the longitudinal axis for the tool 14, rather than out the end of
the tubing 2, thus initiating a fracture adjacent to the side of
the tool 14. The structure of the flow diverter 52 diverts flow
from the middle of the tubing 2 and directs it tangentially out the
sides of the tool 14 through slots 54. The slots 54 are designed
with sufficient flow area so as not to impede the flow of the
fluid. The tool 14 does not create a pressure drop nor does it
cause any jetting action on the formation itself. The tool uses a
solid cone 56 to deflect the fluid tangentially. The end of the
tool has a rounded bullnose 58 to allow the tool to be easily
pushed into the well. The tool 14 is not essential to but improves
the ability of the fracturing fluid to be directed against the
formation during the fracturing treatment.
[0033] The annulus pressure is normally monitored at the surface
during the fracturing treatment. Pressure may be increased in the
annulus to help keep the gel plug 18 in place or the hydrostatic
pressure of the annulus fluid 9 may also perform this purpose.
[0034] The rheological properties of the gel are such that
migration of the fracturing fluid 22 along the wellbore 10 away
form the area of the fracture 24 is minimized due to the yield
strength of the gel. Fractures created by the fracturing treatment
are thus contained or isolated by the gel plug 18 to the area of
the tool 14.
[0035] A fracture 24 adjacent the tool 14 is shown in FIG. 3. After
the first fracturing treatment is completed, the tubing 2 tubing is
pulled back through the gel plug 18 in the direction of arrow 28 as
shown in FIG. 4 towards the heel indicated generally at 30 of the
wellbore 2. If required, additional gel 12 may be circulated into
the wellbore 10 while and/or after the tubing 2 is pulled back to
the next interval or location indicated generally at 32 in the
formation, where the next fracturing treatment is to be performed.
The previously described fracturing method can then be performed to
create a second fracture 34 in the area of location 32 as shown in
FIG. 5.
[0036] This method can be repeated as many times as required in the
wellbore 10. In FIG. 6, five fractures are shown. After all of the
desired fracturing treatments have been performed, the tubing 2 is
pulled from the wellbore 10 leaving behind the gel plug 18 and the
fractures 24, 34, 36, 38 and 40, wherein the fractures 24, 34, 36,
38 contain fracturing fluid 22. After the elapse of a sufficient
amount of time, a gel breaker contained in the gel 12 causes the
viscosity of the gel plug 18 to degrade (break). Once the viscosity
degrades to a suitable amount, the well can be flowed back to
surface together with the fracturing fluid 22 and oil and gas (not
shown) from the formation in the direction indicated by arrows 42
in FIG. 7. The well is normally flowed back the day after
fracturing is carried out but can be flowed back as soon as the 12
gel breaks which can occur a few hours after the fracturing
treatment. Alternately a chemical breaker may be circulated through
the tubing 2 into the wellbore 10 after the final fracture
treatment to accelerate the degradation of the gel plug 18.
[0037] The method described above can also be used when stimulating
a formation below fracturing pressure which is commonly known as a
matrix stimulation. In matrix stimulations, it is desirable to
isolate and inject stimulation fluid at different intervals in a
wellbore, to for example, stimulate different formations.
Stimulation fluid is injected below normal fracturing pressure. The
fracturing fluid is diverted into the desired part of the well
using the same general method as is described above. A gel plug
isolates a certain part of the wellbore and prevents the
stimulation fluid from moving to a different part of the well
during the treatment. Injected fluids can be acid, water,
hydrocarbons, solvents, chemical formulations, alcohols, nitrogen,
carbon dioxide, natural gas and any other fluid that needs to be
confined to a particular area of the wellbore and is designed to
stimulate the reservoir.
[0038] Gel plugs according to the invention are designed not to
leak into the formation or into any fractures in the formation. The
plug is also designed to have a sufficient yield stress that when
combined with hydrostatic or applied annulus pressure, it will
withstand the pressure exerted on it by the fracturing treatment or
stimulation. This yield stress is designed to be low enough to
allow the fracturing fluid to displace it slightly at the point of
initiation so that the fracturing fluid can create a hydraulic
fracturing in the rock, and be high enough to prevent the
fracturing fluid from moving to another part of the wellbore. The
required yield stress of the gel will vary from well to well
depending on the characteristics of the well, formation, fracturing
fluid and the pressure that the fracturing treatment will create in
the wellbore. In each case, calculations are made prior to
performing the treatment to determine the pressure that will be
created at the point where the fracture or stimulation fluid
injection is at the wellbore. Calculations are then made to
determine the yield stress of the gel required to withstand this
pressure adjacent to the formation and to ensure that the
stimulation will only enter at the targeted point.
[0039] Fracturing pressure can be calculated using equation
(1):
BHFP=FG.times.Depth equation Eq. (1)
[0040] where: FG=fracturing gradient of the formation known from
experience [0041] Depth=depth of the well [0042] BHFP=bottom hole
fracturing pressure
[0043] Calculation to determine Differential Pressure Resistance of
a gel plug according to the invention can be made using equations
(2) and (3):
.DELTA.P=4L.tau..sub.yield/D Eq. (2)
[0044] In concentric circular conduits
.DELTA.P=2(r.sub.o-r.sub.i)L.tau..sub.yield/(r.sub.o.sup.2-r.sub.i.sup.2-
) Eq. (3)
[0045] where: .tau..sub.yield=Yield Stress of Gel [0046] L=Length
of gel plug [0047] D=Diameter of conduit [0048] r.sub.o=Internal
radius of outer conduit [0049] r.sub.i=External radius of inner
conduit Units of measurement are in consistent units of length and
Pressure .tau..sub.yield may be measured in the lab.
[0050] Differential pressure resistance may be calculated for a
given length along the well or across openings in the formation
such as previously induced fractures, pre-existing fractures or
faults, natural fractures, and pore openings in the formation.
[0051] One or more of the following variables may need to be taken
into account when designing the gel plug:
[0052] The hole or inside casing diameter.
[0053] The temperature of the well.
[0054] The permeability and leakoff characteristics of the
well.
[0055] The permeability, conductivity, and leakoff characteristics
of the previously created fractures.
[0056] The geology, natural fractures, and faults in the
formation.
[0057] The compatibility of the plug with wellbore and stimulation
fluids to ensure that the plug does not damage the well or react
with stimulation fluids.
[0058] The yield stress(or yield strength) of the gel plug.
[0059] The differential pressure resistance of the gel plug of the
gel plug.
[0060] The annulus or hydrostatic pressure required to keep the
plug in place.
[0061] The gel includes a base fluid which can be an aqueous-based
fluid, a hydrocarbon-based fluid or is any other fluid in which
sufficient viscosity and yield stress can be created and
subsequently reduced. The gel also includes a viscosifying agent
which can be any chemical or substance that creates viscosity and
static yield stress in a liquid. Normal viscosifying chemicals for
water, alcohols and acids that are used are guar or guar
derivatives, hydroxyl ethyl cellulose or derivatives, viscoelastic
surfactants, and any other polymer that will viscosify the water.
Normal viscosifying materials for hydrocarbons are phosphate esters
crosslinked with iron or aluminium. Aluminium octoate can also be
used as a viscosifying agent.
[0062] Crosslinking chemicals in aqueous fluids can be any
multivalent metal ion, such as borate, antimony, zirconium, chrome,
titanium and iron. They are added to the gels to increase the
viscosity and yield stress of the plug. Surfactants, clay
stabilizers, salt, methanol, pH adjustors, biocide and flowback
enhancers can all be added to the water to improve flowback of the
fluids or to ensure chemical and physical compatibility with the
formation and formation fluids, however these additives are not
employed to create the yield stress in the plug.
[0063] A breaker is added to the gel which causes the gel to
degrade (break) over a period of time leaving a very low viscosity
fluid in the well that will flow out of the well after the
stimulation treatments are performed. The gel plug is designed such
that its viscosity is maintained at a suitable level while the
stimulation treatments are performed and degrades after a given
period which normally is after the last treatment is completed.
[0064] The breaker can be any chemical that reduces the viscosity
of the gel over time. Common breakers for water, alcohol or acid
plugs are enzymes or oxidizers such as persulfates, peroxides,
acids or bleach. Common breakers for hydrocarbon plugs are pH
buffers or caustic fluids. The breaker can cause the gel to break
at any time from minutes to days depending on what is required to
complete the well.
[0065] Surfactants, clay stabilizers, salt, methanol, pH adjustors,
brocide and flowback enhancers can be added to the base fluid to
improve flowback of the fluids or to reduce damage to the formation
but are not added to viscosify the gel.
EXAMPLES
[0066] An example of a water based gel plug according to the
invention includes the following components: [0067] Base Fluid:
Fresh Water [0068] Gellant: Guar, Hydroxypropyl Guar or
Carboxymethyl hydroxypropyl guar, or Hydroxyethyl Cellulose at 3.6
to 10.0 kg/m.sup.3. [0069] Breaker: Persulfate run at 0.05 to 2.0
kg/m.sup.3 with or without encapsulation. [0070] Surfactant:
Non-emulsifier, surface tension reducing and flow back enhancer run
between 0.5 to 5 L/m.sup.3. [0071] Clay Stabilizer: Either KCL at
1.0 to 10% or an amine based product such as TMAC or DADMAC at 0.5
to 10.0 L/m.sup.3. [0072] Crosslinker: Borate or Zirconium
solutions at concentrations from 1.0-100 L/m.sup.3.
[0073] The clay stabilizer and surfactant are not required to
create the necessary yield stress of the plug.
[0074] An example of a hydrocarbon based plug according to the
invention includes the following components: [0075] Base Fluid:
Crude Oil, Refined Hydrocarbon [0076] Gellent: Phosphate Esther at
8-201/m.sup.3. [0077] Crosslinker: Metal solution of iron and
aluminium at 8-20 l/m.sup.3. [0078] Breaker: pH breaker such as
Magnesium Oxide run from 2-20 L/m.sup.3.
[0079] The method described above can be used on a variety of
wells. It can be used on vertical wells that require stimulations
on multiple formations, on deviated wells, and on horizontal wells.
The method can be used on wells that are open hole with no casing,
on cased and cemented wells, or on wells with liners or casing in
them that is not cemented in place. In this situation, a gel plug
can be circulated on the inside of the casing as well as in the
annular space between the casing and the formation.
[0080] The tubing that is used to pump the fluids through can be of
any size that allows flow of fluid at a rate required to perform
the designed stimulation. It can be coiled tubing or conventional
jointed tubing. Common sizes of coiled tubing would be 50.8 mm,
60.3 mm, and 73 mm. Common sizes of jointed tubing are 60.3 mm, 73
mm and 88.9 mm.
[0081] The stimulation and fracturing fluids can be any fluid
including but not limited to water, salt water, hydrocarbon, acid,
methanol, carbon dioxide, nitrogen, foam, and emulsions. The method
is normally used when the fluid is pumped into the formation above
fracturing pressure but can also be used when any of the above
fluids are pumped into the formation below fracturing pressure.
[0082] The tubing or coiled tubing can either be pulled out of the
well after the last fracturing treatment has been performed or run
back to the bottom or the toe and can be used to circulate the
broken plug from the well. Additional chemical can also be pumped
at this time to enhance or accelerate the degradation of the gel
plug.
[0083] A method according to the invention was used to fracture
four sand stone formations at approximately 1,500-1,600 m true
vertical depth. The well casing was 177.8 mm in diameter and was
cemented in the wells to a measured depth of between 1,644-1,761 m
measured depths. The casing was run through the vertical section of
the well and was landed in the horizontal section of the well. The
measured depths of the wells varied from 2,014 to 3,040 m. The
horizontal portions of the wells varied from 370 to 1,332 m.
[0084] Below the casing, the wells were drilled to 159 mm diameter
and left in an open hole state with no liners, casing or tubing in
them. The temperature of the wells was approximately 70.degree. C.
The bottom hole pressure of the wells was 17,000 kPa.
[0085] Fracturing Design: The anticipated fracturing pressure in
the wells was designed to be 37,000 kPa on surface and 26,000 kPa
on bottom. A gel plug according to the invention was designed to
withstand this pressure and to prevent flow of the gel plug into
the formation and into the previously created fractures. The yield
stress of the plug when combined with the annular fluid above the
plug was designed to prevent the fracturing fluid and pressure at
the formation from moving the plug during the fracturing
treatments. The designed fracture rate was 2.5 m.sup.3/min. and
each well had a different number of intervals that needed to be
fractured. Each well also had a different amount of sand that was
to be placed in each interval.
[0086] The following method was used to fracture the well. 73.0 mm
coiled tubing was fitted with the diverter tool of the type
described above and was run in the wells to the end of the
horizontal section (toe of the well). The hole was circulated to
clay control water to ensure that it was full. Once returns of clay
control water was seen at surface, gel fluid was pumped down the
coiled tubing to bottom and was circulated in place from the toe of
the well to 100 m inside the casing.
[0087] The gel consisted of:
[0088] Fresh Water
[0089] Guar Gum added at 4.8 kg/m.sup.3
[0090] Amine Clay Control Additive added at 2 L/m.sup.3
[0091] Borate Crosslinker added at 2.5 L/m.sup.3
[0092] Non Ionic Surfactant added at 2 L/m.sup.3.
The properties of the fluid are set out in tables 1, 2 and 3 and
the graph of FIG. 10.
TABLE-US-00001 TABLE 1 Power Law Data Time (hours) n' k' 0.0 -1.16
17127.03 0.5 0.35 28.59 1.0 0.70 6.91 1.5 0.58 10.36 2.0 0.06 94.76
2.5 0.30 27.30 3.0 -0.15 161.66 3.5 0.54 6.34 4.0 0.26 21.68 4.5
0.43 8.95 5.0 0.14 27.39 K' units: (Newton * Sec{circumflex over (
)}n)/m{circumflex over ( )}2
TABLE-US-00002 TABLE 2 Gel Test Results Vortex Closure: 2:00
(min:sec) Crosslink Time: 4:00 (min:sec) Final pH: 9.1
TABLE-US-00003 TABLE 3 Break Test Results Breaker: Potassium Temp:
70.degree. C. Persulfate Concentration Break Time 0.8 kg/m.sup.3
10:30 (hr:min) 1.5 kg/m.sup.3 7:30 (hr:min)
[0093] A delayed encapsulated potassium persulfate chemical breaker
was added to the gel plugs at 0.8 kg/m.sup.3 to reduce the
viscosity of the plugs from high viscosity to that of water in
about 6 to 12 hours. Each gel plug was designed to have high
viscosity while the fracturing treatments were pumped and to
degrade back to water within 2-4 hours after the last treatment was
performed.
[0094] After circulating the gel plug in place, the coiled tubing
was positioned at the place where the first fracturing treatment
was to be performed and operations were shut down for 15-30 minutes
to allow for the gel plug to gain viscosity. The gel plug was
displaced into the open hole section with fracturing fluid.
[0095] After waiting 15-30 minutes, the first fracturing treatment
was performed. The sand was placed into the fracture that was
created. The sand was displaced with fracturing fluid that was to
be used on the next interval. During the fracturing treatment no
pressure was added to the annulus and the annulus between the
coiled tubing and the casing was monitored on surface to ensure
that no pressure or fluid was being transmitted up the annulus.
[0096] After displacing the first fracturing treatment, the coil
was immediately pulled back to the next fracturing interval and a
second fracturing treatment was initiated.
[0097] This procedure was repeated until all the intervals in the
wellbore were fractured. Up to 9 fractures were performed at
various spots in each well. In each case, negligible pressure was
seen on the annulus during the fracturing treatments indicating
that the gel plug confined the fracture to the desired
interval.
[0098] After the last fracturing treatment was completed, the coil
was pulled from the wellbore and the well was shut-in to allow the
gel plug and the fracturing fluid to break.
[0099] The well was then put on production. No significant amounts
of sand was produced back or found in the wellbore which indicated
that the gel plug successfully diverted the fracturing treatments
into the desired interval.
* * * * *