U.S. patent application number 14/623915 was filed with the patent office on 2015-08-20 for method for providing multiple fractures in a formation.
The applicant listed for this patent is Shell Oil Company. Invention is credited to Shawn Patrick HOLZHAUSER, Victoria Xiaoping QIU.
Application Number | 20150233226 14/623915 |
Document ID | / |
Family ID | 53005622 |
Filed Date | 2015-08-20 |
United States Patent
Application |
20150233226 |
Kind Code |
A1 |
HOLZHAUSER; Shawn Patrick ;
et al. |
August 20, 2015 |
METHOD FOR PROVIDING MULTIPLE FRACTURES IN A FORMATION
Abstract
The invention includes providing a propped hydraulic fractures
in a subterranean formation including the steps of: injecting a
fracturing fluid into the subterranean formation at a pressure
sufficient to initiate and propagate at least one hydraulic
fracture wherein the fracturing fluid comprises a proppant; when
the at least one hydraulic fracture has reached a target size,
adding to the fracturing fluid a predetermined amount of a diverter
material wherein the diverter material comprises material having a
specified size distribution, and comprising a material that
degrades at conditions of the subterranean formation, the diverter
material effective to essentially block flow of fracturing fluid
into the at least one fracture; and continuing to inject fracturing
fluid at a pressure effective to initiate at least one additional
fracture within the subterranean formation.
Inventors: |
HOLZHAUSER; Shawn Patrick;
(Spring, TX) ; QIU; Victoria Xiaoping; (Sugar
Land, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Shell Oil Company |
Houston |
TX |
US |
|
|
Family ID: |
53005622 |
Appl. No.: |
14/623915 |
Filed: |
February 17, 2015 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61941583 |
Feb 19, 2014 |
|
|
|
Current U.S.
Class: |
166/280.1 |
Current CPC
Class: |
E21B 43/267 20130101;
C09K 8/74 20130101; C09K 8/516 20130101; C09K 2208/18 20130101;
C09K 8/92 20130101; C09K 8/70 20130101 |
International
Class: |
E21B 43/267 20060101
E21B043/267; E21B 43/10 20060101 E21B043/10; E21B 43/11 20060101
E21B043/11 |
Claims
1. A method to provide propped hydraulic fractures in a
subterranean formation comprising: injecting a fracturing fluid
into the subterranean formation at a pressure sufficient to
initiate and propagate at least one hydraulic fracture wherein the
fracturing fluid comprises a proppant; adding to the fracturing
fluid, when the at least one hydraulic fracture has reached a
target size, a predetermined amount of a diverter material wherein
the diverter material comprises between 10 to 30 weight percent of
particles having a size larger than 2000 microns, between 1 and 15%
by weight of particles between 1000 and 2000 microns, 10 to 40
percent by weight particles having a diameter in the range of 500
to 1000 microns, 40 to 70 percent by weight particles smaller than
500 microns, and comprising a material that degrades at conditions
of the subterranean formation, the diverter material effective to
essentially block flow of fracturing fluid into the at least one
fracture; and continuing to inject fracturing fluid at a pressure
effective to initiate at least one additional fracture within the
subterranean formation.
2. The method of claim 1 further comprising the step of providing a
wellbore withink the subterranean formation and providing a casing
within the wellbore
3. The method of claim 2 further comprising perforating the casing
within the subterranean formation wherein the diverter material is
sized to bridge the perforations
4. The method of claim 3 wherein the diverter material is sized to
bridge the perforations.
5. The method of claim 1 wherein the time when the fracture has
reached the target size is determined by the volume of fracturing
fluid injected.
6. The method of claim 1 wherein the time when the fracture has
reached the target size is determined by the rate at which fracture
fluid can be injected into the formation at a pressure that is less
than the fracture initiation pressure.
7. The method of claim 1 wherein the time when the fracture has
reached the target size is determined by microseismic data.
8. The method of claim 1 wherein the material that degrades at
conditions of the subterranean formation comprises polylactate,
9. The method of claim 1 wherein the material that degrades at
conditions of the subterranean formation comprises
polyglycolate.
10. The method of claim 1 wherein the material that degrades at
conditions of the subterranean formation comprises oil soluble
resins.
11. The method of claim 1 wherein the material that degrades at
ambient conditions of the subterranean formation degrades within a
time period in the range of six hours to ninety days.
12. The method of claim 1 wherein the steps are repeated a
plurality of times.
13. The method of claim 1 further comprising the step of producing
hydrocarbons from the subterranean formation through the
fractures.
14. The method of claim 1 wherein the wellbore is essentially
horizontal for at least a portion of the wellbore within the
subterranean formation.
15. The method of claim 1 wherein the wellbore is slanted from
horizontal for at least a portion of the wellbore within the
subterranean formation.
16. The method of claim 1 wherein the wellbore is essentially
vertical for at least a portion of the wellbore within the
subterranean formation.
17. The method of claim 1 wherein the concentration of diverter in
the fracturing fluid is between 25 and 200 grams per liter.
18. A method to provide propped hydraulic fractures in a
subterranean formation comprising: injecting a fracturing fluid
into the subterranean formation at a pressure sufficient to
initiate and propagate at least one hydraulic fracture wherein the
fracturing fluid comprises a proppant; when the at least one
hydraulic fracture has reached a target size, adding to the
fracturing fluid a predetermined amount of a diverter material
wherein the diverter material comprises between 10 to 30 weight
percent of particles having a size larger than 2000 microns,
between 1 and 15% by weight of particles between 1000 and 2000
microns, 10 to 40 percent by weight particles having a diameter in
the range of 500 to 1000 microns, 40 to 70 percent by weight
particles smaller than 500 microns, and comprising a material that
degrades at ambient conditions of the subterranean formation, the
diverter material effective to essentially block flow of fracturing
fluid into the at least one fracture; and continuing to inject
fracturing fluid at a pressure effective to initiate at least one
additional fracture from the wellbore within the subterranean
formation.
19. A method to provide acid or reactive chemical etched fractures
in a subterranean formation comprising: injecting a reactive
chemical into the subterranean formation at a pressure sufficient
to initiate and propagate at least one hydraulic fracture wherein
the fracturing fluid comprises a reactive chemical that can etch
the fracture surface; when the at least one hydraulic fracture has
reached a target size, adding to the fracturing fluid a
predetermined amount of a diverter material wherein the diverter
material comprises between 10 to 30 weight percent of particles
having a size larger than 2000 microns, between 1 and 15% by weight
of particles between 1000 and 2000 microns, 10 to 40 percent by
weight particles having a diameter in the range of 500 to 1000
microns, 40 to 70 percent by weight particles smaller than 500
microns, and comprising a material that degrades at ambient
conditions of the subterranean formation, the diverter material
effective to essentially block flow of fracturing fluid into the at
least one fracture; and continuing to inject fracturing fluid at a
pressure effective to initiate at least one additional fracture
from the wellbore within the subterranean formation.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. provisional patent
application 61/941,583, filed on Feb. 19, 2014, the disclosure of
which is incorporated herein by reference.
BACKGROUND TO THE INVENTION
[0002] Technology for hydraulic fracturing of formations has
advanced rapidly in recent years and has enabled economic
development of hydrocarbon resources previously considered to not
be economically producible. Typically, long horizontal wells are
provided in a target formation and fractures are provided every two
hundred to five hundred feet along the length of the horizontal
wellbore. Fractures are often provided by methods such as those
suggested in U.S. Pat. Nos. 7,775,287 and 7,703,525 or US patent
application publication US2011/0209868. These methods include
injection of viscous fluids into the formation at such high
pressures and rates that the reservoir rock fails and forms a
plane, typically vertical (depending on the direction of minimum
stress). Proppant material such as sand, ceramic beads, or other
material may be injected in a later portion of the fracturing fluid
to hold the fracture open after pressure on the fracturing fluid is
decreased.
[0003] Either cased or uncased wellbores may be fractured, but
typically wellbores within target formations are cased, the casings
cemented, and then the cemented casings are perforated at
predetermined intervals along the length of the wellbore.
[0004] In carbonate formations, the fracturing fluids may contain
acids or acid precursors that react with carbonates to alter the
shape of the rock at the surface of the fracture so that after
pressure on the fracturing fluid is released, and the fracture
closes, the faces of the rock no longer match. Flow paths for
fluids to traverse from along the surface of the fracture to the
wellbore are therefore provided.
[0005] Tools are available for isolating sections of a horizontal
wellbore for fracturing perforations within that isolated segment.
A further improvement has been to isolate multiple perforations,
and attempt to perform multiple fractures at the same time, thus
reducing rig time needed to relocate packers and set up for pumping
fracturing fluids. But provision of multiple fractures from a
single isolated segment of a wellbore can be problematic because a
fracture will initiate at the weakest point within the isolated
segment, and because fracture propagation requires less pressure
than fracture initiation pressure, subsequent fractures will not
initiate until the first fracture is very large, The initial large
fracture will increase the stress on the formation, and therefore
each subsequent fracture will be smaller and less effective than
previous fractures.
[0006] U.S. Pat. No. 7,644,761 suggests a method where slugs of
proppant are injected in an acid fracturing fluid so that existing
fractures may be plugged, permitting pressure within the wellbore
to increase to above a fracture initiation pressure and thereby
initiation of a second or subsequent fracture. The proppant may be
a combination suggested in U.S. Pat. No. 7,004,255, which is a
combination of two or three different sizes so that the ultimate
void volume of the proppant may be as low as less that seventeen
percent.
[0007] It is also suggested in U.S. Pat. No. 7,644,761 that the
proppant could include degradable fibers as suggested in U.S. Pat.
No. 7,275,596. It is suggested that the fibers degrade at formation
temperatures in a time between about four hours and one hundred
days leaving a more porous screen at each fracture. U.S. Pat. No.
7,275,596 suggests a method for minimizing the amount of metal
crosslinked viscosifier necessary for treating a wellbore with
proppant or gravel is given. The method includes using fibers to
aid in transporting, suspending and placing proppant or gravel in
viscous carrier fluids otherwise having insufficient viscosity to
prevent particulate settling. Fibers are suggested that have
properties optimized for proppant transport but degrade after the
treatment into degradation products that do not precipitate in the
presence of ions in the water such as calcium and magnesium.
SUMMARY OF THE INVENTION
[0008] In accordance with preferred embodiments of the invention a
system and technique are provided to provide propped hydraulic
fractures in a subterranean formation comprising: injecting a
fracturing fluid into the subterranean formation at a pressure
sufficient to initiate and propagate at least one hydraulic
fracture wherein the fracturing fluid comprises a proppant; when
the at least one hydraulic fracture has reached a target size,
adding to the fracturing fluid a predetermined amount of a diverter
material wherein the diverter material comprises between 10 to 30
weight percent of particles having a size larger than 2000 microns,
between 1 and 15% by weight of particles between 1000 and 2000
microns, 10 to 40 percent by weight particles having a diameter in
the range of 500 to 1000 microns, 40 to 70 percent by weight
particles smaller than 500 microns, and comprising a material that
degrades at conditions of the subterranean formation, the diverter
material effective to essentially block flow of fracturing fluid
into the at least one fracture; and continuing to inject fracturing
fluid at a pressure effective to initiate at least one additional
fracture within the subterranean formation.
[0009] The diverter material may be, for example polylactate,
polyglycolate, or oil soluble resins. Slugs of diverter material
may be injected may be injected between batches of injected
fracturing fluid with each batch of diverter inhibiting flow of
fracturing fluid into existing fractures. The greater the flow of
fracturing fluid going into a particular fracture, the greater the
amount of diverter initially entering the fracture will be, and
thus rapidly growing fractures will be limited to essentially the
size of the fracture at the time the diverter is injected. This
allows subsequent fractures to become larger instead of dominate
fractures containing the majority of the fracturing fluid and
proppant.
[0010] In one embodiment of the invention, the size range of the
diverter material is selected to enable bridging at the
perforations and therefore blockage of fluid flow at the
perforation. By essentially blocking flow of fracturing fluid at
the perforation, the amount of diverter needed is predictable, and
the amount of diverter is also considerably less than if the
divertor were to be sized to block fluid flow in the fracture or
within the proppant that has been placed within the fracture.
Minimizing the amount of diverter material needed reduces costs of
the diverter material, the costs and equipment needed to add the
diverter material, and minimizes damage caused by the residual of
the diverter material left in the formation after degradation of
the diverter material.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] For a more detailed understanding of the invention,
reference is made to the accompanying wherein:
[0012] FIG. 1 is a schematic drawing of a wellbore fractured
according to the process of the present invention.
[0013] FIGS. 2 and 3 are plots of the amount of fracturing fluid
forced into perforations in segments of wellbores with and without
the use of the present invention.
DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT
[0014] Referring now to FIG. 1, a wellbore 101 is shown penetrating
a subterranean formation 102. The subterranean formation could be,
for example, a hydrocarbon containing formation such as a light
tight oil reservoir or a tight gas reservoir, or a formation into
which carbon dioxide is to be sequestered. Generally formations
having limited permeability require hydraulic fracturing such as
provided by the present invention in order for fluids to be
produced or injected into the formations. Low permeability
formations could be formations having less than 10 milidarcy
permeability. The wellbore could be vertical, horizontal, or
deviated. In general, long horizontal wellbores are typically used
for light tight oil and tight gas production so that many hydraulic
fractures could be provided from each wellbore. The wellbore is
provided by known drilling and completion methods. The wellbore
could be an open hole completion within the formation to be
produced, but to provide multiple fractures without having to move
packers, wellbores that are cased with casing 103 and cemented into
the formation with cement 104. The cement is generally pumped down
the casing and followed by a wiper 105, which separates the cement
from wellbore fluids behind the cement. The wiper may be stopped by
a stopper ring 106 at the end of the casing. Known cement
compositions and methods could be applied with the present
invention.
[0015] A previously fractured segment of the wellbore 107 is show
with three fractures 108 already provided into the subterranean
formation. The casing is shown as having been provided with
perforations 109 which penetrate the casing into the subterranean
formation. A outboard packer 110 and an inboard packer 111, through
which fracturing fluid may be provide via tubular 112, are provided
to isolate a segment of the wellbore 114 from which additional
fractures could now be provided. The tubular 112 is shown attached
to both packers, and packers could be provided that could be
released and moved via a separate hydraulic control line (not
shown), or set to provide an isolated segment of the wellbore
between the two packers. Only two segments of the wellbore
containing fractures are shown, but it should be understood that
typically many more segments are isolated and many more sets of
fractures are provided. For example, a horizontal wellbore having a
horizontal section 1828.8 meters long could be provided with
hydraulic fractures every 15 to 200 meters to provide a wellbore
having from 10 to 120 fractures. The fractures could be provided in
sets of, for example, 2 to 10 fractures at a time. By providing
multiple fractures at one time it is meant that the fractures are
provided without changing the zone within the wellbore into which
fracturing fluid is injected.
[0016] When packers are set, or a segment of a wellbore is
otherwise isolated in preparation for providing hydraulic
fractures, fracturing fluid 113 could be injected into the isolated
segment of the wellbore 114, and through perforations 109, into the
subterranean formation 102 at a pressure sufficiently high to
initiate at least one new fracture.
[0017] Fracturing fluids 113 may be thickened to lower the rate at
which proppants settle from the fluids, enabling the fluids to
carry the proppants deeper into fractures. Thickeners may be
viscosifying polymers such as a solvatable (or hydratable)
polysaccharide, such as a galactomannan gum, a glycomannan gum, or
a cellulose derivative. Examples of such polymers include guar,
hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxyethyl
guar, hydroxyethyl cellulose, carboxymethyl-hydroxyethyl cellulose,
hydroxypropyl cellulose, xanthan, polyacrylamides and other
synthetic polymers. Of these, guar, hydroxypropyl guar and
carboxymethlyhydroxyethyl guar are typically preferred based on
commercial availability and cost/performance.
[0018] Alternatively, a fracturing fluid can be what is known as a
slick water composition. A slick water comprises water and a low
concentration of friction reducer along with a proppant such as
sand. Typically slick water contains 99.5 percent by weight of
water and sand, and 0.5 perceont by weight of additives, including,
for example; a friction reducing polymer such as polyacrylamide;
biocides such as bromine, methanol or naphthalene; surfactants such
as butanol, or ethylene glycol monobutyl ether; and scale
inhibitors such as hydrochlorinc acid or ethylene glycol. The slick
water fracturing fluid does not include thickeners. High pumping
rates are used to place the fracturing fluids within the formations
before the proppants settle from the fluids. Slick water
compositions are therefore more useful in shallow wells, wells with
shorter horizontal laterals, or near the heal end of long
horizontal wells. When slick water compositions can be utilized,
they are generally preferred because thickeners increase hydraulic
frictional pressure losses, and cause at least some formation
damage.
[0019] Hydraulic fractures may be initiated with fluids not
containing proppants, but proppants can then be added as the
fractures propagate. Proppants may be sands or ceramic particles,
polymer pellets, or glass particles. Proppants provide a more
permeable filler for hydraulic fractures if they are provided with
a relatively narrow range of sizes. Proppants such as those
disclosed in U.S. Pat. Nos. 7,913,762, 7,836,952, or 8,327,940
could be used in the present invention. Proppants having relatively
narrow size distributions provide high permeability propped
fractures because void volumes are maximized Typical volume average
size of useful proppants range from 100 to 2000 microns, and the
distributions are preferably narrow.
[0020] Fracturing proppants size is specified as a mesh screen size
that the sand pass through and a second mesh screen size which the
proppant does not pass through. Porppant sizes useful in the
present invention include, for example, 8/12, 10/20, 20/40, and
70/140. These screens correspond, respectively, to size range of
1.68 to 2.38, 0.84 to 2.00, 0.42 to 0.84, millimetres, and 105 to
210 microns. Most often, 20/40 sand is utilized.
[0021] Fracturing sand is also specified by sphericity and
roundness by a chart devised by Krumbein and Sloss, and typically
both sphericity and roundness are greater than 0.6 according to the
chart of Krumbein and Sloss.
[0022] When a set of perforations within a wellbore is exposed to
fluids at a pressure which exceeds the formation fracture
initiation pressure, one or two dominate fractures will be
initiated and will initially propagate. The majority of the
injected proppant will flow into these dominate fractures until
proppant injection is discontinued or no more proppant can be
forced into the fracture. If proppant injection is continued after
fractures are essentially filled with proppant, proppant may sand
out in the wellbore. Generally, proppant injection is discontinued
after a pre-determined amount of proppant has been injected to
prevent proppant from filling the wellbore. The pre-determined
amount of proppant could be estimated as the amount of proppant
that could be placed in a fracture without the proppant "sanding
out", or becoming bridged within the fracture and blocking further
movement of proppant into the fracture.
[0023] After injection of the proppant is discontinued, a flush of
fracturing fluid that does not contain proppant will be injected to
move proppant from within the wellbore into the fractures. In the
present invention, a slug of a diverter material is pumped into the
wellbore, preferably after the flush of proppant free fracturing
fluid. The slug of diverter material comprises water or fracturing
fluid, and diverter materials. The amount of pre-determined amount
of proppant and fluid is based on fracturing job design that would
give the target size of fractures.
[0024] Alternatively, the size of the area of the fracture may be
inferred from micro seismic data, or it could be inferred merely
from the volume of proppant containing fracturing fluid, or
proppant, that has been injected.
[0025] Alternatively, the amount of fracturing fluid may be
determined for the set of perforations to be fractured to optimize
the fracturing based on normal considerations including the cost of
the factures and the value of marginally larger fractures, and then
this amount of fracturing fluid being injected in essentially equal
portions, separated by slugs of fracturing fluid containing
diverter material. The fracturing fluid may be divided into, for
example, two, three, or four essentially equal portions, separated
by one, two or three slugs of diverter materials.
[0026] Portions of fracturing fluids and proppants separated by the
diversion slugs may be unequal based on fracturing design
optimizations.
[0027] Before the slug of diverter is injected, the pressure at
which fracturing fluid is being injected is typically stable. After
the fluid containing the diverter has been injected, and the
diverter material has traversed the tubular to the zone being
fractured, the pressure at the wellhead will be seen to rise as
fluid flow to existing fractures is blocked by the diverter
material. Eventually, additional fractures open. Increases in
pressure from fifty to three thousand pounds per square inch have
been observed after injection of a slug of diverter. Because
initial fractures increase the stress on the formation, each
successive fracture will require increased pressure to initiate and
propagate. Acceptable diverter material may be, for example,
polylactate, polyglycolate, or oil soluble resins. Manufactures of
such materials are capable of providing particles of such materials
having specified size ranges and distributions, and which degrade
under formation conditions at predictable rates.
[0028] Diverters of the present invention degrade at formation
conditions over a time period that permits production of
hydrocarbons from the wellbore within a reasonable amount of time.
For example, the diverters may be designed to degrade at formation
conditions between six and ninety days. By degrade, it is meant
that the polymers lose more than half of their tensile strength.
The degradation could also be accomplished by providing diverter
material which is at least partially soluble in formation fluids,
such as oil. The degradation could also be accomplished,
accelerated, or triggered, by, for example, flushing an acidic
component into the perforations. Alternatively a diverter material
could be used that reacts with oxidizing agents and the degradation
could be accomplished, accelerated, or triggered by flushing the
perforations with an oxidizing agent.
[0029] The maximum size of the diverter, and the amount expected to
block each perforation may be determined by, for example, labatory
tests flowing diverter material through perforated rocks.
[0030] Diverter material could be added to the fracturing fluid as
it is being injected, for example, by a screw pump into a mixing
vessel or by direct manual feeding into a mixing vessel, and then
being feed to fracturing fluid injection pumps. The diverter
material may be added in a concentration that is great enough to be
effective. If the concentration is not sufficient, the diverter
material will not be sufficient to block flow into the fracture. To
high of a concentration of diverter will be uneconomical, and
difficult to add and mix into the fracturing fluid. Concentrations
of diverter material between about 25 and about 200 grams per liter
of fracturing fluid have been found to be effective and cost
effective. Concentrations of between about 50 and 100 grams per
liter may be acceptable.
[0031] To be an effective diverter material, the size distribution
of the diverter material must be sufficiently broad. An acceptable
broad particle size range would be a combination of particles
wherein between 10 to 30 weight percent of particles have a size
larger than 2000 microns, between 1 and 15% by weight of particles
between 1000 and 2000 microns, 10 to 40 percent by weight particles
having a diameter in the range of 500 to 1000 microns, 40 to 70
percent by weight particles smaller than 500 microns. The largest
particles need to be large enough to bridge the perforations at the
opening, and there need to be a sufficient amount of particles
about one third of that size to bridge the openings between the
largest particles, and then a sufficient amount of particles small
enough to bridge the openings of between the smaller particles, and
so on, until the particle size is below 500 micron. The different
size range particles could be injected at one time, or could be
injected sequentially with larger sizes injected first.
[0032] The size of the largest diverter particles, or for example,
the diameter of which ten percent by volume of the material is
greater than this diameter, depends upon where the diverter
material is intended to block flow into the formation. If it is
intended that flow into the formation is to be blocked at the face
of proppant within the fracture, then this maximum diameter of
diverter may be about one half of the average diameter of the
proppant. If the diverter is intended to block flow within the
fracture, then this maximum diameter of the diverter may be about
one half of the width of the expected fracture opening. If the flow
is intended to be blocked at the perforation itself, then the
maximum diameter of the diverter material should be about half of
the diameter of the perforation. Providing this size of diverter
material minimizes the amount of diverter material needed to block
the flow into the perforation. U.S. Pat. No. 7,004,255, for
example, suggests combination of sizes of particles effective to
block flows of fluids through proppant packed fractures. Bimodal
distributions or trimodal distributions could be utilized, but a
broad range of distributions is also effective.
[0033] The size distribution of the diverter material is preferably
selected to block perforations. Blocking of the perforations can be
accomplished with, for example, three to thirty kilograms of
properly sized materials for each perforation. The amount of
diverter material needed to block the perforations is also much
more predictable than the amount of material needed to block the
fracture or the proppant placed within the fracture because the
dimensions of the actual perforation are known and are not
significantly altered by the fracturing process.
[0034] The amount of diverter material may be, for example, between
one and thirty kilograms per perforation to be blocked.
[0035] The present invention may be utilized to provide multiple
fractures from within an isolated section of a wellbore, or could
be utilized to provide fractures from a wellbore without isolating
a section. For example, the whole segment of the wellbore to be
provided with factures could be subjected to sequences of proppant
containing fracturing fluids followed by slugs of diverter material
repeatedly until fractures have been provided from each of the
perforations in the wellbore without isolating sections of the
wellbore.
[0036] The present invention could also be used with a well from
which fractures had previously been provided. In this embodiment,
proppant could be forced into existing fractures prior to could be
subjected to injection of diverter material, to reopen or enlarge
existing fractures. Alternatively, flow into existing fractures
could be inhibited by injection of diverter material before new
fractures are placed from the wellbore.
[0037] After a formation has been provided with hydraulic fractures
according to the present invention, hydrocarbons may be produced
from the formation by way of the hydraulic fractures. The
hydrocarbons may be, for example, natural gas, crude oil, and/or
light tight oil.
EXAMPLE 1
[0038] Diverter material was obtained from ICO Polymers North
America, Inc, located in Akron, Ohio. The material was a
polylactate biodegradable polymer with a size distribution of 1 to
2830 micron. In a horizontal well bore that had been drilled,
cased, and all but the last three stages were fraced by normal
procedures. The last three stages, at the heel end of the wellbore,
were combined into one stage to test the effectiveness of one
embodiment of the present invention. This section of the wellbore
was about eight hundred feet long. This segment was peforated with
nine clusters of perforations, the clusters being separated by
about 84 feet. The amount of fracturing fluid and proppant used was
the normal amount for three stages, or three times the amount used
for the previous individual stages. The total amount of proppant
pumped was about 900,000 pounds. The proppant and fluid was
injected in three roughly equal batches, each batch separated by a
slug of diverter material in fluid. For each batch of diverter,
about 450 pounds of diverter material was added to 600 gallons of
liner gel solution. After the first batch of proppant was pumped,
and the first batch of diverter, the diverter caused the back
pressure to build by about 700 psi. After the first slug of
diverter was pumped, a second batch of proppant was pumped. The
second batch of proppant required about two hundred psi more
pressure than the first. This indicates that new perforations were
opening. After the second batch of proppant was pumped, the second
batch of diverter material was pumped. Again, about 450 pounds of
diverter were pumped in about 600 gallons of liner gel fluid. This
time the pressure built as the diverter was being pumped by about
400 psi. A third and final batch of proppant was then pumped, and
again the fracturing pressures increased by about another two
hundred psi, indicating that the proppant was entering new
fractures.
EXAMPLE 2
[0039] For this example, the diverter material was commercially
available material, Biovert, from Halliburton Energy Services,
Inc., of Houston, Tex. The well was a well equipped with a fiber
optic sensor capable of measuring a complete temperature and
acoustic profile within the well. With the complete acoustic and
temperature profile, as a function of time, the distribution of
fracturing fluid going into different perforations within a cluster
may be calculated. Typically, without the present invention, it is
observed that when a cluster of six perforations are fractured,
there will be one to three dominate fractures, with three to five
fractures receiving considerably less proppant. Therefore, normal
procedures would be to not attempt to fracture more than three
clusters per stage. This results in more effective fractures within
the wellbore, and more predictable placement of fractures, but
increases completion costs. To demonstrate the effectiveness of one
embodiment of the present invention, the proppant was pumped in two
batches, separated by a batch of fluids containing BioVert
material. FIG. 1 shows the relative distribution of proppant
material for the two batches of proppant for each of six clusters
of perforations. The proppant pumped first went mostly into the
first three sets of perforations. It can be seen that over ninety
percent of the proppant went into these perforations. After the
injection of the diverter material, much more of the second batch
of proppant went into the other three perforations, with about
fifty percent going into the fourth perforation and less than ten
percent going into each of the first three. Although in this
example, sufficient proppant was not forced into the fifth and
sixth perforations, the distribution of proppant was significantly
improved by the slug of diverter material.
EXAMPLE 3
[0040] Another test to determine if open clusters could be blocked
to divert fracture fluids into unopened clusters of perforations in
a horizontal well in the Eagle Ford formation. The diverter used
was commercially available BioVert from Halliburton. Referring now
to FIG. 2, the x-axis is the number for clusters in one stage. The
Y axis is the percentage of fracturing fluid and slurry taken by
each clusters. During the job, the total fluid and slurry volume
were divided into two portions. The first portion was pumped as a
regular fracturing procedure. The solid line indicates the
percentage of fluid and slurry taken by each cluster during the
first portion of the treatment calculated from fiber optic
temperature sensor data. The results show that during the first
portion of the treatment, there are four clusters taking fluid and
slurry, one cluster was taking more than the others. Two clusters
did not take any fluids. A diverter slug was pumped after the first
portion of treatment. The second portion of the treatment was then
pumped. The dotted line shows the percentage of fluid and slurry
taken by each cluster during pumping the second portion. The
results show that the second portion of the treatment opened
cluster 6 and improved the fracturing efficiency.
* * * * *