U.S. patent application number 13/667845 was filed with the patent office on 2013-06-20 for recovery from a hydrocarbon reservoir.
The applicant listed for this patent is Russell M. Bacon, George R. Scott. Invention is credited to Russell M. Bacon, George R. Scott.
Application Number | 20130153215 13/667845 |
Document ID | / |
Family ID | 48608951 |
Filed Date | 2013-06-20 |
United States Patent
Application |
20130153215 |
Kind Code |
A1 |
Scott; George R. ; et
al. |
June 20, 2013 |
Recovery From A Hydrocarbon Reservoir
Abstract
Embodiments described herein provide systems and methods for
improving production of hydrocarbon resources. A method for
improving recovery from a subsurface hydrocarbon reservoir includes
drilling a well comprising a horizontal segment through a reservoir
interval and installing a pipe string in the horizontal well
segment, wherein the pipe string comprises a plurality of screen
assemblies. Each of the plurality of screen assemblies is located
and a hole is drilled in the pipe string at a portion of the
plurality of screen assemblies. Each hole is drilled at a desired
orientation to a radial axis of the drill string.
Inventors: |
Scott; George R.; (Calgary,
CA) ; Bacon; Russell M.; (Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Scott; George R.
Bacon; Russell M. |
Calgary
Calgary |
|
CA
CA |
|
|
Family ID: |
48608951 |
Appl. No.: |
13/667845 |
Filed: |
November 2, 2012 |
Current U.S.
Class: |
166/252.1 ;
166/255.1; 166/66 |
Current CPC
Class: |
E21B 43/2406 20130101;
E21B 43/088 20130101 |
Class at
Publication: |
166/252.1 ;
166/255.1; 166/66 |
International
Class: |
E21B 47/09 20120101
E21B047/09; E21B 43/12 20060101 E21B043/12 |
Foreign Application Data
Date |
Code |
Application Number |
Dec 16, 2011 |
CA |
2762439 |
Claims
1. A method for improving recovery from a subsurface hydrocarbon
reservoir, comprising: drilling a well comprising a horizontal
segment through a reservoir interval; installing a pipe string in
the horizontal well segment, wherein the pipe string comprises a
plurality of screen assemblies; locating each of the plurality of
screen assemblies; and drilling a hole in the pipe string at a
portion of the plurality of screen assemblies, wherein each hole is
drilled at a desired orientation to a radial axis of the drill
string.
2. The method of claim 1, comprising: drilling a plurality of
injection wells through the reservoir interval; and drilling a
plurality of production wells through the reservoir interval.
3. The method of claim 1, comprising determining locations for the
plurality of screen assemblies from reservoir data.
4. The method of claim 3, wherein the reservoir data comprises
geologic data, seismic data, open hole log data, or any
combinations thereof.
5. The method of claim 1, comprising identifying the portion of the
plurality of screen assemblies at which to drill the hole.
6. The method of claim 1, comprising: identifying a hole that has
failed in a screen assembly; plugging the hole; and drilling a new
hole.
7. The method of claim 2, comprising: drilling a first size of hole
in each of the plurality of injection wells; and drilling a second
size hole in each of the plurality of production wells.
8. The method of claim 1, comprising increasing a flow area in the
pipe string at a screen assembly.
9. The method of claim 8, comprising drilling additional holes at a
screen assembly.
10. The method of claim 1, comprising locating the screen assembly
using a gamma ray tool.
11. The method of claim 1, comprising locating the screen assembly
using a density detector.
12. The method of claim 1, comprising locating the screen assembly
using a profile segment of pipe installed at a known location in a
pipestring.
13. The method of claim 1, comprising orienting the drilled holes
vertically downward.
14. The method of claim 1, comprising orienting the drilled holes
within about 20.degree. of vertically downward.
15. The method of claim 1, comprising drilling a hole in at least
one of the plurality of screen assemblies after production has
commenced.
16. The method of claim 1, comprising plugging a hole by squeezing
cement into the hole.
17. The method of claim 1, comprising plugging a hole using a low
profile casing patch.
18. The method of claim 1, comprising plugging a hole using a scab
liner.
19. A system for improving the recovery of resources from a
reservoir, comprising: a reservoir; a horizontal well drilled
through the reservoir, wherein the horizontal well comprises a
plurality of pipe joints that have a screen assembly mounted
thereon; a detection apparatus configured to locate a screen
assembly on a pipe joint; and a drilling device configured to drill
a hole in a pipe joint at a selected orientation to the
vertical.
20. The system of claim 19, comprising two horizontal wells,
wherein one horizontal is an injection well and a second horizontal
well is a production well.
21. The system of claim 19, wherein a portion of the plurality of
pipe joints that have a screen assembly have a hole drilled in the
pipe joint underneath the screen assembly.
22. A method for harvesting hydrocarbons from an oil sands
reservoir, comprising: drilling a steam assisted gravity drainage
(SAGD) well pair through the oil sands reservoir; placing a pipe
string in each of the wells of the SAGD well pair, wherein the pipe
string comprises a plurality of screen assemblies, and wherein the
pipe string has no holes prior to placement; selecting a portion of
the screen assemblies at which to drill holes in a base pipe
underneath the screen assembly; drilling the holes at a selected
orientation to the radial axis of the base pipe; injecting steam
into an injection well in the SAGD well pair; and producing fluids
from a production well in the SAGD well pair.
23. The method of claim 22, comprising: identifying a screen
assembly that has failed; determining the reason for the failure;
if the failure is due to a hole failing: drilling a new hole under
the screen assembly; and, if the failure is due to the screen
assembly failing: plugging the hole under the screen assembly; and
drilling a new hole under a new screen assembly.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the priority benefit of Canadian
Patent Application 2,762,439 filed Dec. 16, 2011 entitled IMPROVING
RECOVERY FROM A HYDROCARBON RESERVOIR, the entirety of which is
incorporated by reference herein.
FIELD
[0002] The present techniques relate to harvesting resources using
gravity drainage processes. Specifically, techniques are disclosed
for placing holes in the bottom of wells within a reservoir.
BACKGROUND
[0003] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present techniques. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present techniques. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
[0004] Modern society is greatly dependant on the use of
hydrocarbons for fuels and chemical feedstocks. Hydrocarbons are
generally found in subsurface rock formations that can be termed
"reservoirs." Removing hydrocarbons from the reservoirs depends on
numerous physical properties of the rock formations, such as the
permeability of the rock containing the hydrocarbons, the ability
of the hydrocarbons to flow through the rock formations, and the
proportion of hydrocarbons present, among others.
[0005] Easily harvested sources of hydrocarbon are dwindling,
leaving less accessible sources to satisfy future energy needs.
However, as the costs of hydrocarbons increase, these less
accessible sources become more economically attractive. For
example, the harvesting of oil sands to remove hydrocarbons has
become more extensive as it has become more economical. The
hydrocarbons harvested from these reservoirs may have relatively
high viscosities, for example, ranging from 8 API, or lower, up to
20 API, or higher. Accordingly, the hydrocarbons may include heavy
oils, bitumen, or other carbonaceous materials, collectively
referred to herein as "heavy oil," which are difficult to recover
using standard techniques.
[0006] Several methods have been developed to remove hydrocarbons
from oil sands. For example, strip or surface mining may be
performed to access the oil sands, which can then be treated with
hot water or steam to extract the oil. However, deeper formations
may not be accessible using a strip mining approach. For these
formations, a well can be drilled to the reservoir and steam, hot
air, solvents, or combinations thereof, can be injected to release
the hydrocarbons. The released hydrocarbons may then be collected
by the injection well or by other wells and brought to the
surface.
[0007] A number of techniques have been developed for harvesting
heavy oil from subsurface formations using thermal recovery
techniques. Thermal recovery operations are used around the world
to recover liquid hydrocarbons from both sandstone and carbonate
reservoirs. These operations include a suite of steam based in situ
thermal recovery techniques, such as cyclic steam stimulation
(CSS), steam flooding, and steam assisted gravity drainage
(SAGD).
[0008] For example, CSS techniques includes a number of enhanced
recovery methods for harvesting heavy oil from formations that use
steam heat to lower the viscosity of the heavy oil. The steam is
injected into the reservoir through a well and raises the
temperature of the heavy oil during a heat soak phase, lowering the
viscosity of the heavy oil. The same well may then be used to
produce heavy oil from the formation. CSS is generally practiced in
vertical wells, but systems are operational in horizontal wells.
CSS and other steam flood techniques have been utilized worldwide,
beginning in about 1956 with the utilization of CSS in the Mene
Grande field in Venezuela and steam flood in the early 1960s in the
Kern River field in California.
[0009] Solvents may be used in combination with steam in CSS
processes, such as in mixtures with the steam or in alternate
injections between steam injections. These techniques are described
in U.S. Pat. No. 4,280,559 to Best, U.S. Pat. No. 4,519,454 to
McMillen, and U.S. Pat. No. 4,697,642 to Vogel, among others.
[0010] Another group of techniques is based on a continuous
injection of steam through a first well to lower the viscosity of
heavy oils and a continuous production of the heavy oil from a
lower-lying second well. Such techniques may be termed "steam
assisted gravity drainage" or SAGD. Various embodiments of the SAGD
process are described in Canadian Patent No. 1,304,287 to Butler
and its corresponding U.S. Pat. No. 4,344,485.
[0011] In SAGD, two horizontal wells are completed into the
reservoir. The two wells are first drilled vertically to different
depths within the reservoir. Thereafter, using directional drilling
technology, the two wells are extended in the horizontal direction
that result in two horizontal wells, vertically spaced from, but
otherwise vertically aligned with the other. Ideally, the
production well is located above the base of the reservoir but as
close as practical to the bottom of the reservoir, and the
injection well is located vertically 10 to 30 feet (3 to 10 meters)
above the horizontal well used for production.
[0012] Each of the wellbores is assembled from pipe segments, for
example, of about 30 feet in length. Each pipe segment has exterior
threads at one end and interior threads at the opposite end that
couple the segments together. Variations in the threading can
result in slight variations of the orientation of each segment to
the next segment in the string.
[0013] The upper horizontal well is utilized as an injection well
and is supplied with steam from the surface. The steam rises from
the injection well, permeating the reservoir to form a vapor
chamber that grows over time towards the top of the reservoir,
thereby increasing the temperature within the reservoir. The steam,
and its condensate, raise the temperature of the reservoir and
consequently reduce the viscosity of the heavy oil in the
reservoir. The heavy oil and condensed steam will then drain
downward through the reservoir under the action of gravity and may
flow into the lower production well, whereby these liquids can be
pumped to the surface. At the surface of the well, the condensed
steam and heavy oil are separated, and the heavy oil may be diluted
with appropriate light hydrocarbons for transport by pipeline.
[0014] Solvents may be used alone or in combination with steam
addition to increase the efficiency of the steam in removing the
heavy oils. As the solvents blend with the heavy oils and bitumens,
they lower the viscosity, allowing the materials to flow towards a
production well. The mobility of the heavy oil obtained with the
steam and solvent combination is greater than that obtained using
steam alone under substantially similar formation conditions.
[0015] The techniques discussed above may have uneven or even
limited injection of steam into the reservoir, for example, due to
the random orientation of the pipe segments to each other in the
reservoir. Further, conventional slotted liners, meshrite, and
wirewrap screen assemblies have openings that allow fluids to flow
into the liner from 360 degrees. With these liners in SAGD, steam
coning will occur when the steam chamber is proximal to top of the
liners. This can lead to lower efficiency for steam injection as
well as early steam breakthrough.
SUMMARY
[0016] Some embodiments of the present invention provide variations
of method for improving recovery from a subsurface hydrocarbon
reservoir. The method includes drilling a well with a horizontal
segment through a reservoir interval, installing a pipe string
having a plurality of screen assemblies in the horizontal well
segment, locating each of the plurality of screen assemblies, and
drilling a hole in the pipe string at a portion of the plurality of
screen assemblies, wherein each hole is drilled at a desired
orientation to a radial axis of the drill string.
[0017] Other embodiments of the invention include variations of a
system for improving the recovery of resources from a reservoir.
The system includes a reservoir, a horizontal well drilled through
the reservoir, wherein the horizontal well comprises a plurality of
pipe joints that have a screen assembly mounted thereon; a
detection apparatus configured to locate a screen assembly on a
pipe joint; and a drilling device configured to drill a hole in a
pipe joint at a selected orientation to the vertical.
[0018] Yet other embodiments of the invention include variations of
a method for harvesting hydrocarbons from an oil sands reservoir.
The method includes: drilling a steam assisted gravity drainage
(SAGD) well pair through the oil sands reservoir; placing a pipe
string in each of the wells of the SAGD well pair, wherein the pipe
string comprises a plurality of screen assemblies, and wherein the
pipe string has no holes prior to placement; selecting a portion of
the screen assemblies at which to drill holes in a base pipe
underneath the screen assembly; drilling the holes at a selected
orientation to the radial axis of the base pipe; injecting steam
into an injection well in the SAGD well pair; and producing fluids
from a production well in the SAGD well pair.
DESCRIPTION OF THE DRAWINGS
[0019] The advantages of the present techniques are better
understood by referring to the following detailed description and
the attached drawings, in which:
[0020] FIG. 1 is a drawing of a steam assisted gravity drainage
(SAGD) process used for harvesting hydrocarbons in a reservoir;
[0021] FIG. 2 is a drawing of a screen assembly, showing a location
of a hole;
[0022] FIG. 3 is a cross section of a blast joint section of the
screen assembly of FIG. 2;
[0023] FIG. 4 is a cross section of a wirewrap screen section of
the screen assembly of FIG. 2;
[0024] FIG. 5 is a drawing of a pipe segment that includes a
wirewrap screen;
[0025] FIG. 6 is a drawing of a pipe segment, showing a build-up in
condensate due to non-vertical hole locations;
[0026] FIG. 7 is a drawing of a pipe segment, showing complete
drainage of condensate when the holes are located at the bottom of
a segment;
[0027] FIG. 8 is a plot showing the use of gamma ray logging to
locate blast joints to allow the positioning of holes;
[0028] FIG. 9(A) is a drawing of a series of screen assemblies
placed on a pipe segment;
[0029] FIG. 9(B) is a drawing of a series of screen assemblies
placed on a pipe segment;
[0030] FIG. 9(C) is a drawing of a series of screen assemblies
placed on a pipe segment; and
[0031] FIG. 10 is a method of improving the harvesting of
hydrocarbons from a reservoir by drillings holes after the well is
lined.
DETAILED DESCRIPTION
[0032] In the following detailed description section, specific
embodiments of the present techniques are described. However, to
the extent that the following description is specific to a
particular embodiment or a particular use of the present
techniques, this is intended to be for exemplary purposes only and
simply provides a description of the exemplary embodiments.
Accordingly, the techniques are not limited to the specific
embodiments described below, but rather, include all alternatives,
modifications, and equivalents falling within the true spirit and
scope of the appended claims.
[0033] At the outset, for ease of reference, certain terms used in
this application and their meanings as used in this context are set
forth. To the extent a term used herein is not defined below, it
should be given the broadest definition persons in the pertinent
art have given that term as reflected in at least one printed
publication or issued patent. Further, the present techniques are
not limited by the usage of the terms shown below, as all
equivalents, synonyms, new developments, and terms or techniques
that serve the same or a similar purpose are considered to be
within the scope of the present claims.
[0034] As used herein, the term "base" indicates a lower boundary
of the resources in a reservoir that are practically recoverable,
by a gravity-assisted drainage technique, for example, using an
injected mobilizing fluid, such as steam, solvents, hot water, gas,
and the like. The base may be considered a lower boundary of the
payzone. The lower boundary may be an impermeable rock layer,
including, for example, granite, limestone, sandstone, shale, and
the like. The lower boundary may also include layers that, while
not completely impermeable, impede the formation of fluid
communication between a well on one side and a well on the other
side.
[0035] "Bitumen" is a naturally occurring heavy oil material.
Generally, it is the hydrocarbon component found in oil sands.
Bitumen can vary in composition depending upon the degree of loss
of more volatile components. It can vary from a very viscous,
tar-like, semi-solid material to solid forms. The hydrocarbon types
found in bitumen can include aliphatics, aromatics, resins, and
asphaltenes. A typical bitumen might be composed of:
[0036] 19 wt. % aliphatics (which can range from 5 wt. %-30 wt. %,
or higher);
[0037] 19 wt. % asphaltenes (which can range from 5 wt. %-30 wt. %,
or higher);
[0038] 30 wt. % aromatics (which can range from 15 wt. %-50 wt. %,
or higher);
[0039] 32 wt. % resins (which can range from 15 wt. %-50 wt. %, or
higher); and
[0040] some amount of sulfur (which can range in excess of 7 wt.
%).
In addition bitumen can contain some water and nitrogen compounds
ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. The
percentage of the hydrocarbon types found in bitumen can vary. As
used herein, the term "heavy oil" includes bitumen, as well as
lighter materials that may be found in a sand or carbonate
reservoir.
[0041] As used herein, two locations in a reservoir are in "fluid
communication" when a path for fluid flow exists between the
locations. For example, the establish of fluid communication
between a lower-lying serpentine well and a higher injection well
may allow material mobilized from a steam chamber above the
injection well to flow down to the serpentine well from collection
and production. As used herein, a fluid includes a gas or a liquid
and may include, for example, a produced hydrocarbon, an injected
mobilizing fluid, or water, among other materials.
[0042] As used herein, a "cyclic recovery process" uses an
intermittent injection of injected mobilizing fluid selected to
lower the viscosity of heavy oil in a hydrocarbon reservoir. The
injected mobilizing fluid may include steam, solvents, gas, water,
or any combinations thereof. After a soak period, intended to allow
the injected material to interact with the heavy oil in the
reservoir, the material in the reservoir, including the mobilized
heavy oil and some portion of the mobilizing agent may be harvested
from the reservoir. Cyclic recovery processes use multiple recovery
mechanisms, in addition to gravity drainage, early in the life of
the process. The significance of these additional recovery
mechanisms, for example dilation and compaction, solution gas
drive, water flashing, and the like, declines as the recovery
process matures. Practically speaking, gravity drainage is the
dominant recovery mechanism in all mature thermal, thermal-solvent
and solvent based recovery processes used to develop heavy oil and
bitumen deposits, such as steam assisted gravity drainage (SAGD).
For this reason the approaches disclosed here are equally
applicable to all recovery processes in which at the current stage
of depletion gravity drainage is the dominant recovery
mechanism.
[0043] "Facility" as used in this description is a tangible piece
of physical equipment through which hydrocarbon fluids are either
produced from a reservoir or injected into a reservoir, or
equipment which can be used to control production or completion
operations. In its broadest sense, the term facility is applied to
any equipment that may be present along the flow path between a
reservoir and its delivery outlets. Facilities may comprise
production wells, injection wells, well tubulars, wellhead
equipment, gathering lines, manifolds, pumps, compressors,
separators, surface flow lines, steam generation plants, processing
plants, and delivery outlets. In some instances, the term "surface
facility" is used to distinguish those facilities other than
wells.
[0044] "Heavy oil" includes oils which are classified by the
American Petroleum Institute (API), as heavy oils, extra heavy
oils, or bitumens. In general, a heavy oil has an API gravity
between 22.3.degree. (density of 920 kg/m.sup.3 or 0.920
g/cm.sup.3) and 10.0.degree. (density of 1,000 kg/m.sup.3 or 1
g/cm.sup.3). An extra heavy oil, in general, has an API gravity of
less than 10.0.degree. (density greater than 1,000 kg/m.sup.3 or
greater than 1 g/cm.sup.3). For example, a source of heavy oil
includes oil sand or bituminous sand, which is a combination of
clay, sand, water, and bitumen. The thermal recovery of heavy oils
is based on the viscosity decrease of fluids with increasing
temperature or solvent concentration. Once the viscosity is
reduced, the mobilization of fluids by steam, hot water flooding,
or gravity is possible. The reduced viscosity makes the drainage
quicker and therefore directly contributes to the recovery
rate.
[0045] A "hydrocarbon" is an organic compound that primarily
includes the elements hydrogen and carbon, although nitrogen,
sulfur, oxygen, metals, or any number of other elements may be
present in small amounts. As used herein, hydrocarbons generally
refer to components found in heavy oil, or other oil sands.
[0046] As used herein, "poorer quality facies" are intervals in a
reservoir that can have poor drainage, often due to a difficulty in
establishing a counter-current flow. In an oil sands reservoir,
poorer quality facies may include IHS layers above the higher
quality sands of a clean pay interval.
[0047] "Permeability" is the capacity of a rock to transmit fluids
through the interconnected pore spaces of the rock. The customary
unit of measurement for permeability is the millidarcy. The term
"relatively permeable" is defined, with respect to formations or
portions thereof, as an average permeability of 10 millidarcy or
more (for example, 10 or 100 millidarcy). The term "relatively low
permeability" is defined, with respect to formations or portions
thereof, as an average permeability of less than about 10
millidarcy.
[0048] "Pressure" is the force exerted per unit area by the gas on
the walls of the volume. Pressure can be shown as pounds per square
inch (psi). "Atmospheric pressure" refers to the local pressure of
the air. "Absolute pressure" (psia) refers to the sum of the
atmospheric pressure (14.7 psia at standard conditions) plus the
gauge pressure (psig). "Gauge pressure" (psig) refers to the
pressure measured by a gauge, which indicates only the pressure
exceeding the local atmospheric pressure (i.e., a gauge pressure of
0 psig corresponds to an absolute pressure of 14.7 psia). The term
"vapor pressure" has the usual thermodynamic meaning. For a pure
component in an enclosed system at a given pressure, the component
vapor pressure is essentially equal to the total pressure in the
system.
[0049] As used herein, a "reservoir" is a subsurface rock or sand
formation from which a production fluid, or resource, can be
harvested. The rock formation may include sand, granite, silica,
carbonates, clays, and organic matter, such as bitumen, heavy oil,
oil, gas, or coal, among others. Reservoirs can vary in thickness
from less than one foot (0.3048 m) to hundreds of feet (hundreds of
m). The resource is generally a hydrocarbon, such as a heavy oil
impregnated into a sand bed.
[0050] As discussed in detail above, "Steam Assisted Gravity
Drainage" (SAGD), is a thermal recovery process in which steam, or
combinations of steam and solvents, is injected into a first well
to lower a viscosity of a heavy oil, and fluids are recovered from
a second well. Both wells are generally horizontal in the formation
and the first well lies above the second well. Accordingly, the
reduced viscosity heavy oil flows down to the second well under the
force of gravity, although pressure differential may provide some
driving force in various applications. Although SAGD is used as an
exemplary process herein, it can be understood that the techniques
described can include any gravity driven process, such as those
based on steam, solvents, or any combinations thereof.
[0051] "Substantial" when used in reference to a quantity or amount
of a material, or a specific characteristic thereof, refers to an
amount that is sufficient to provide an effect that the material or
characteristic was intended to provide. The exact degree of
deviation allowable may in some cases depend on the specific
context.
[0052] As used herein, "thermal recovery processes" include any
type of hydrocarbon recovery process that uses a heat source to
enhance the recovery, for example, by lowering the viscosity of a
hydrocarbon. These processes may use injected mobilizing fluids,
such as hot water, wet steam, dry steam, or solvents alone, or in
any combinations, to lower the viscosity of the hydrocarbon. Such
processes may include subsurface processes, such as cyclic steam
stimulation (CSS), cyclic solvent stimulation, steam flooding,
solvent injection, and SAGD, among others, and processes that use
surface processing for the recovery, such as sub-surface mining and
surface mining. Any of the processes referred to herein, such as
SAGD, may be used in concert with solvents.
[0053] A "wellbore" is a hole in the subsurface made by drilling or
inserting a conduit into the subsurface. A wellbore may have a
substantially circular cross section or any other cross-sectional
shape, such as an oval, a square, a rectangle, a triangle, or other
regular or irregular shapes. As used herein, the term "well," when
referring to an opening in the formation, may be used
interchangeably with the term "wellbore." Further, multiple pipes
may be inserted into a single wellbore, for example, as a liner
configured to allow flow from an outer chamber to an inner
chamber.
Overview
[0054] Current throttle-flow liner designs often use screen
assemblies on pipe segments, such as wirewrap screens, wirewrap
screens with blast joints, and the like, to improve the contact of
wellbores with a reservoir. As used herein, a liner is a portion of
a well used for recovering resources from a reservoir. The liner
may often have a base pipe with attached screen assemblies for
allowing fluid flow into and out of the base pipe. Before
installation, a limited number of holes may be drilled in the base
pipe, behind the screen assemblies, to regulate the flow to or from
the reservoir.
[0055] In an embodiment, the screen assemblies are located and the
holes are drilled after the screen assemblies have been installed
in the reservoir. This allows the holes to be positioned at any
selected angle to the radial axes of horizontal pipe segments. For
example, the holes can be positioned to point downward into the
screen assembly. A low position, combined with a "V shape" drainage
profile, can reduce the quantity of injectant vapor, such as steam,
solvent vapor, or combinations, than may be coned into a production
well, e.g., being produced as vapor. By reducing the liquid sump
above the depth of the producer, it can also increase the height of
the pay interval that is exposed to the injectant vapor, further
increasing the production rates and recovery.
[0056] For the purposes of this description, SAGD is used as the
recovery process. Those ordinarily skilled in the art will
recognize that the approaches disclosed here are equally applicable
to all thermal, thermal-solvent and solvent based recovery
processes in which gravity drainage is the dominant recovery
mechanism.
[0057] FIG. 1 is a drawing of a steam assisted gravity drainage
(SAGD) process 100 used for accessing hydrocarbon resources in a
reservoir 102. In the SAGD process 100, steam 104 can be injected
through injection wells 106 to the reservoir 102. As previously
noted, the injection wells 106 may be horizontally drilled through
the reservoir 102. Production wells 108 may be drilled horizontally
through the reservoir 102, with a production well 108 underlying
each injection well 106. Generally, the injection wells 106 and
production wells 108 will be drilled from the same pads 110 at the
surface 112. This may make it easier for the production well 108 to
track the injection well 106. However, in some embodiments the
wells 106 and 108 may be drilled from different pads 110.
[0058] The injection of steam 104 into the injection wells 106 may
result in the mobilization of hydrocarbons 114, which may drain to
the production wells 108 and be removed to the surface 112 in a
mixed stream 116 that can contain hydrocarbons, condensate and
other materials, such as water, gases, and the like. As described
herein, screen assemblies may be used on the injection wells 106,
for example, to throttle the inflow of injectant vapor to the
reservoir 102. Similarly, screen assemblies may be used on the
production wells 108, for example, to decrease sand
entrainment.
[0059] The hydrocarbons 114 may form a triangular shaped drainage
chamber 118 that has the production well 108 at located at a lower
apex. The mixed stream 116 from a number of production wells 108
may be combined and sent to a processing facility 120. At the
processing facility 120, the water and hydrocarbons 122 can be
separated, and the hydrocarbons 122 sent on for further refining.
Water from the separation may be recycled to a steam generation
unit within the facility 120, with or without further treatment,
and used to generate the steam 104 used for the SAGD process
100.
[0060] An interval 126 of the reservoir 102 may include poorer
quality facies, such as an IHS layer, which drains poorly. The
poorer quality facies are not limited to intervals 126 at the top
of a reservoir 120, but may include lenses 128 or other places in
the reservoir 102. As described herein, cycling the pressure of the
reservoir 102 may increase the drainage from the interval 126 and
lenses 128, allowing increases in production of hydrocarbons from
these locations.
Screen Assemblies
[0061] FIG. 2 is a drawing 200 of a screen assembly 202 mounted on
a base pipe 204. In this example, a center section of the screen
assembly 202 has a blast joint 206, which is joined to wirewrap
screens 208 along each outer edge of the blast joint 206. The
wirewrap screens 208 are joined to the base pipe 204 by welds 210,
for example, to prevent injectant from escaping around the wirewrap
screens 208 or sand from infiltrating beneath the wirewrap screens
208. A hole 212 is drilled below the blast joint 206 to allow
injectant vapor to escape from injection wellbores or production
fluids to enter production wellbores.
[0062] A design criterion for conventional liners, such as slotted
liners, wirewrap screens, or meshrite screens, is to ensure that
sufficient open area is present in the to prevent the liner from
being a flow restriction. However, this design approach can make
the screens of the liners susceptible to sand influx damage such as
erosion or plugging. For example, this may occur if high fluid
velocities are present at one or more locations along a
wellbore.
[0063] FIG. 3 is a cross section of the blast joint 206 of the
screen assembly 202 of FIG. 2. The blast joint 206 is a single
metal pipe, for example, made from iron or steel. The hole 212 in
the base pipe 204 opens behind the blast joint 206. In this
example, the hole 212 is oriented along the vertical axis 304 of
the base pipe. In an injection well, the injectant, such as steam,
is released into the annulus 302 between the blast joint 206 and
the base pipe 204. This protects the more fragile wirewrap screens
208 from erosion caused by the influx of injectant vapor. The
injectant vapor flows through the annulus 302 to the wirewrap
screens 208, as discussed with respect to FIG. 4. Further, the
presence of the blast joints 206 directly outside the locations of
the holes 212 will deflect the injectant vapor exiting the holes,
thereby ensuring that it will not adversely affect the operation of
any underlying production well.
[0064] FIG. 4 is a cross section of a wirewrap screen 208 of the
screen assembly 202 of FIG. 2. For a production well, the injectant
vapor that exits the base pipe 204 through the hole 212 into the
annulus 302 between the base pipe 204 and the blast joint 206 flows
to the annulus 402 between the wirewrap screens 208 and the base
pipe 204. From there, the injectant vapor flows into the reservoir
through slots in the wirewrap screen 208. Similarly, for a
production well, production fluids can flow through the slots in
the wirewrap screen 208 into the annulus 402 between the wirewrap
screens 208 and the base pipe 204 and then into the annulus 302
between the base pipe 204 and the blast joint 206. The production
fluids can then flow into the base pipe 204 of the production well
through the hole 212.
[0065] The throttled-flow liner design for the screen assembly 202,
illustrated in FIGS. 2-4, can improve the robustness of the screen
assembly 202 to damage by creating a flow restriction in a base
pipe 204, for example, by limiting the number of holes 212. In
contrast, previous systems had the flow restriction occur across
the wirewrap screen 208. When the throttled flow liner is the
screen assembly 202 used for injection wells, the number of screen
assemblies 202 and their specific locations along the wellbore are
based on the requirements of the specific thermal, thermal-solvent
or solvent based recovery process. However, the orientation of the
holes 212 for each of the segment a string of pipe is random and,
thus, may not be optimal in all services, as discussed with respect
to FIG. 5.
[0066] FIG. 5 is a drawing of a pipe segment (or joint) 502 that
includes a screen assembly 202 and a pre-drilled hole 504. The pipe
segment 502 has male threads 506 at one end and female threads 508
at the opposite end. The pipe segment 502 is installed into the
formation as a part of a pipe string that is formed by joining pipe
segments 502 in an end-to-end configuration in which the male
threads 506 of each pipe segment 502 are joined to the female
threads 508 of the next pipe segment. Depending on the reservoir,
every pipe segment 502 may have a screen assembly 202. In some
embodiments, blank joints, which are pipe segments with no screen
assembly 202, may be inserted into the pipe string. The orientation
of each predrilled hole 504 is then determined by the orientation
of the pipe segment 502 when the threads are completely joined to
the next pipe segment. Thus, the predrilled holes 504 may be
somewhat randomly oriented to the vertical axis of the pipe segment
502, which may lower the flow through the pipe.
[0067] FIG. 6 is a drawing of a pipe string 600, showing a build-up
of liquid 602 that can result when the holes 604 are not located at
the bottom of the pipe string 600. The level 606 of the liquid 602
is controlled by the distance of the holes 604 from the bottom of
the vertical axis 608. In this example, the holes 604 are located
about half way up from the bottom of the pipe string 600 and, as a
result, the lower half of the pipe string 600 is filled with liquid
602, effectively reducing the cross-sectional area available for
vapor flow 610 by about 50%. This can result in a substantial
pressure drop. FIG. 6 illustrates that liquid 602, or other fluids,
can accumulate in the injector wellbore when using a design with a
restricted number of holes 604 that are drilled prior to the pipe
string 600 being installed, such as is the case with a
throttled-flow liner design.
[0068] FIG. 7 is a drawing of a pipe string 700, showing complete
drainage of condensate when the holes are located at the bottom of
the pipe string 700. In an embodiment, the pipe string 700 is
installed without pre-drilling holes behind the screen assemblies.
After installation, the locations of the screen assemblies 202 can
be determined. For example, blast joints 206 that may be integral
to each screen assembly 202 can be found using various techniques,
as discussed further with respect to FIG. 8. The holes 702 can then
be drilled in the pipe string 700 behind the screen assemblies 202,
allowing the holes 702 to be drilled substantially downwards with
respect to the radial axis 704 of the pipe string 700.
[0069] In addition to lowering the amount of liquid that may build
up in an injection well, the downward orientation of the holes 702
makes production wells more resistant to the coning of vapor, which
causes reproduction of the vapor from the production wells. As the
production of steam or other vapors can be a significant operating
cost for thermal enhanced oil recovery (EOR) operations, preventing
vapor reproduction can improve the project economics.
[0070] FIG. 8 is a plot 800 showing the use of gamma ray logging to
locate blast joints to allow the positioning of holes. The x-axis
802 represents the distance down the wellbore from the surface
location (in meters), while the y-axis 804 represents the intensity
806 of gamma rays received at a detector. As the gamma ray logging
is measuring gamma rays emitted by natural sources in the
surrounding rock, a lower value can represent a higher density for
the surrounding pipe. The gamma logging tool can identify the
increased density of the blast joints located above the base pipe.
Each of the low points can then be used to identify a location for
drilling a hole 808.
[0071] In embodiments, any number of other techniques may be used
to locate screen assemblies for drilling the holes. For example, a
thicker wall section of pipe can be installed at a known offset
from each screen assembly for location by the gamma ray logging.
Portions of the ring or base pipe itself can be tagged, such as
with a radioactive source, allowing the accurate positioning of the
tool for drilling each hole. Further, a weak radioactive tag may be
directly included at each location, for example, in a blast joint,
to accurately locate the tool for the drilling of each hole.
[0072] In an embodiment, a profiled section of the base pipe, for
example, about 0.5 to 1 cm narrower than the base pipe, may be
included in proximity to the planned hole location to locate the
tool. Similarly, a profile section may be included in the segment
that provides an indentation for an accurately positioning of the
tool for the drilling of each hole. To move past the indentation,
the tool can be rotated to disengage the indentation and then
moved. A segmented ring may be included to function in a similar
manner. The segmented ring can engage the tool at one orientation
and disengage when the tool is rotated to a different
orientation.
[0073] Once the locations are determined, specialized drilling
tools can be used to drill the required number of holes with the
desired locations and orientations. For example, such tools can
include the MaxPERF Drilling Tool, available from Penetrators
Canada, Inc. of Red Deer, Alberta, Canada. For injection wells, the
preferred hole orientation is vertically downward as this can help
to ensure that any liquids present, such as condensate, can be
easily removed from the pipe string. As discussed previously, if
the hole orientation allowed these liquids to accumulate within the
liner, the liquids would effectively reduce the hydraulic diameter
of the liner, increasing the pressure drop along the injection
liner. In some instances, the holes may be slightly offset from the
vertical axis at the bottom of the pipe. For example, this may be
done in a production well to provide a sump for sand that
infiltrates the well bore. Not all of the screen assemblies have to
be placed into production at the time of installation as discussed
with respect to FIGS. 9(A)-(C).
Sparing Screen Assemblies
[0074] FIG. 9(A) is a drawing of five installed screen assemblies
202 placed on a pipe string 900. Spare screen assemblies 202, for
example, which are not opened to flow immediately after
installation, can be installed during the initial installation of
the pipe string 900. Accordingly, if one or more of the initial
screen assemblies 202 fail, or if a determination is made to change
the distribution of steam or solvent along the pipe string 900, the
holes leading to some screen assemblies 202 can be obstructed and
holes may be drilled at one or more of the spare screen assemblies
202. As a result, the pipe string 900 can be refurbished at a
significantly lower cost than redrilling either the horizontal
section or the entire well.
[0075] FIG. 9(B) is a drawing of the five installed screen
assemblies 202 on the pipe string 900, in which three of the screen
assemblies 202, labeled A, C, and E, have been accessed by drilling
holes 902. Two remaining screen assemblies 202, B and D have been
left closed as spares for futures use. As the field matures, it may
be found that some of the screen assemblies 202 have failed, for
example, allowing sand to accumulate in the pipe string 900 of a
production well or to have become intervals of excess steam
communication in an injection well. The screen assemblies 202
involved can be identified by surveying the well for sand
accumulations or intervals of reduced sub-cooling.
[0076] FIG. 9(C) is a drawing of the series of screen assemblies
202 placed on a pipe segment, showing the plugging of a hole 904
and drilling of a new hole 906. In this example, screen assembly
202C was blocked and a hole 906 was opened behind screen assembly
202B to replace screen assembly 202C. The hole 904 in the failed
screen assembly 202C can be obstructed, for example, using a cement
squeeze, a scab liner, or any number of other techniques.
[0077] In addition to repairing failed screen assemblies 202, as
the recovery process matures, it may become valuable to change the
openings to screen assemblies 200 along either the injection or
production wells. The same techniques described herein can be used
to locate and drill additional holes 908 at a desired subset of the
open screen assemblies 200. Using these techniques, a well can be
effectively repaired and rejuvenated for less cost than it would
cost to drill a replacement well.
[0078] FIG. 10 is a method of improving the harvesting of
hydrocarbons from a reservoir by drillings holes after the well is
lined. The method 1000 begins at block 1002 with a mapping of the
locations of resources in a reservoir and a plan for harvesting
those resources. The mapping can include locating positions for
injection wells and production wells, as well as locating initial
and subsequent positions for screen assemblies. Generally, the
mapping will be performed in the initial planning stages of the
recovery scheme. For example, prior to the start of recovery
operations, a geologic model can be created for the development
area. This geologic model is usually constructed using a geologic
modeling software program. Available open hole and cased hole log,
core, 2D and 3D seismic data, and knowledge of the depositional
environment setting can all be used in the construction the
geologic model. The geologic model and knowledge of surface access
constraints can then be used to complete the layout of the recovery
process wells, e.g., the injection and production wells, and the
surface pads.
[0079] At block 1004, a series of performance predictions can be
made using a reservoir simulation program, such as Computer
Modeling Group's STARs program, in order to identify useful
locations to open screen assemblies. The simulations can also help
identify how the screen assembly locations should be changed, for
example, by plugging old screen assemblies or drilling holes at new
screen assemblies, as the field matures.
[0080] The process needs to consider both the needs of individual
well pairs and the overall pattern needs. For example, changes in
geology and well design may result in different approaches for
different wells within the development. It may also be possible to
use simple empirical or analog based models for performance
predictions. Further, in many developments, one or more follow-up
recovery processes, such as the drilling of in-fill wells, can be
used to further enhance the recovery of the hydrocarbons. The
options to extend recovery can be considered during the pressure
cycling planning phase, in addition to any operating pressure and
production rate limitations associated with the installed lift
system to be used in the production wells.
[0081] At block 1006, the wells, such as SAGD well pairs, used to
harvest the hydrocarbon from the reservoir can be drilled. After
the well pairs have been drilled, data collected during their
drilling as well as data collected during the operation of the
recovery process, such as cased hole logs including temperature
logs, observation wells, additional time lapse seismic or other
remote surveying data, can be used to update the geologic model.
This may be used to map the evolution of the depletion patterns as
the recovery process matures. The depletion patterns within the
reservoir will be influenced by well placement decisions,
geological heterogeneity, well failures, and day to day operating
decisions. The depletion patterns may determine the optimum
locations to open new screen assemblies.
[0082] At block 1008, the holes may be drilled behind the screen
assemblies that are to be initially opened. At block 1010,
hydrocarbon resources can be harvested from the reservoir using the
wells. For example, steam, solvent, or combinations of these agents
can be injected into the reservoir through the open screen
assemblies along the injections wells. Fluids including
hydrocarbons, injectants, water, and the like, can be produced from
the production well through the open screen assemblies along the
production well.
[0083] At block 1012, a determination can be made as to whether any
screen assemblies have failed. This may also mark the point in
production that planned changes in the open or closed screen
assemblies can be made. If any screen assemblies have failed or
changes are planned, process flow may proceed to block 1014.
[0084] At block 1014, any holes into screen assemblies that have
failed, or desired to be closed, may be blocked. This may not be
needed, if the change is determined to merely be drilling a new
hole under a blast joint in the same screen assembly. At block
1016, new holes may be drilled in pipe strings, for example, at
locations under new screen assemblies and under currently open
screen assemblies that need increases in flow. Process flow can
then return to block 1010 to continue production until another
screen assembly fails.
[0085] While the present techniques may be susceptible to various
modifications and alternative forms, the embodiments discussed
above have been shown only by way of example. However, it should
again be understood that the techniques is not intended to be
limited to the particular embodiments disclosed herein. Indeed, the
present techniques include all alternatives, modifications, and
equivalents falling within the true spirit and scope of the
appended claims.
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