U.S. patent application number 11/043825 was filed with the patent office on 2006-07-27 for mobile gas separation unit.
This patent application is currently assigned to Dominion Oklahoma Texas Exploration & Production, Inc.. Invention is credited to Robert E. Blevins, Alan C. McNally, Michael R. Percifull.
Application Number | 20060162924 11/043825 |
Document ID | / |
Family ID | 36695498 |
Filed Date | 2006-07-27 |
United States Patent
Application |
20060162924 |
Kind Code |
A1 |
Blevins; Robert E. ; et
al. |
July 27, 2006 |
Mobile gas separation unit
Abstract
The mobile gas separation unit is transportable from well site
to well site. The mobile gas separation unit will separate CO.sub.2
from natural gas at the well site where the natural gas is
produced. The CO.sub.2 may be a part of a fracturing fluid that is
used to fracture the formation from which natural gas is to be
produced. The CO.sub.2 will be produced up the Well with the
natural gas rather than venting or flaring the gas stream that
includes the CO.sub.2 in the atmosphere. The mobile gas separation
unit will separate CO.sub.2 from the gas stream so that a sales gas
stream can be communicated to a natural gas sales pipeline or
gathering system.
Inventors: |
Blevins; Robert E.;
(Oklahoma City, OK) ; McNally; Alan C.; (Edmond,
OK) ; Percifull; Michael R.; (San Angelo,
TX) |
Correspondence
Address: |
MCAFEE & TAFT;TENTH FLOOR, TWO LEADERSHIP SQUARE
211 NORTH ROBINSON
OKLAHOMA CITY
OK
73102
US
|
Assignee: |
Dominion Oklahoma Texas Exploration
& Production, Inc.
|
Family ID: |
36695498 |
Appl. No.: |
11/043825 |
Filed: |
January 26, 2005 |
Current U.S.
Class: |
166/267 ;
166/305.1; 166/308.2 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 43/34 20130101; E21B 43/164 20130101 |
Class at
Publication: |
166/267 ;
166/305.1; 166/308.2 |
International
Class: |
E21B 43/34 20060101
E21B043/34; E21B 43/26 20060101 E21B043/26 |
Claims
1. A method of producing natural gas from a subterranean formation
intersected by a wellbore extending from a well surface at a well
site comprising: fracturing the formation with a treating fluid
that includes at least CO.sub.2; flowing a production stream to the
surface, the production stream comprising CO.sub.2 along with
hydrocarbon fluids including at least natural gas to the well
surface; transporting a mobile separation unit to the well site;
and separating CO.sub.2 from the production stream at the well site
with the mobile separation unit.
2. The method of claim 1, further comprising removing liquids from
the production stream to form a production gas stream prior to the
separating step.
3. The method of claim 2, wherein the separating step comprises
separating the production gas stream into a first gas stream and a
second gas stream with the mobile separation unit, wherein the
concentration of CO.sub.2 in the first gas stream is lower than the
concentration of CO.sub.2 in the production gas stream, and the
concentration of CO.sub.2 in the second gas stream is higher than
the concentration of CO.sub.2 in the production gas stream.
4. The method of claim 2, further comprising delivering a gas
stream from the mobile separation unit to a natural gas sales
pipeline after the separating step.
5. The method of claim 2, wherein the separating step comprises
separating the production gas stream into first and second gas
streams, the first gas stream comprising less than 3 percent
CO.sub.2.
6. The method of claim 1, further comprising moving the mobile
separation unit from the well site to a second well site to
separate CO.sub.2 from a stream flowing from a wellbore at the
second well site.
7. The method of claim 6, wherein the moving step occurs after the
CO.sub.2 concentration in the production gas stream is at or below
a level specified by a purchaser of the natural gas.
8. The method of claim 6, wherein the moving step occurs after the
CO.sub.2 concentration in the production gas stream is less than
about 3 percent.
9. A method of removing CO.sub.2 from a production stream
comprising at least CO.sub.2 and natural gas produced from a
formation intersected by a wellbore extending from a well surface
at a well site comprising: transporting a mobile separation unit to
the well site; removing liquids from the production stream to form
a production gas stream; communicating the production gas stream to
the mobile separation unit; and removing CO.sub.2 from the
production gas stream to form a sales gas stream having a CO.sub.2
concentration less than the CO.sub.2 concentration in the
production gas stream.
10. The method of claim 9, wherein the concentration of CO.sub.2 in
the sales gas stream is less than about five percent.
11. The method of claim 9, wherein the concentration of CO.sub.2 in
the sales gas stream is less than about three percent.
12. The method of claim 9, further comprising delivering the sales
gas stream to a natural gas sales pipeline.
13. The method of claim 9, wherein the CO.sub.2 comprises CO.sub.2
used to treat the formation.
14. The method of claim 13, wherein the treatment comprises
fracturing the formation.
15. The method of claim 9, further comprising mounting the mobile
separation unit to a trailer and moving the mobile separation unit
to a second well site.
16. A method for optimizing production from a wellbore extending
between a downhole producing formation and an associated well
surface comprising: treating the downhole producing formation with
a treating fluid that includes CO.sub.2 to improve production of
hydrocarbon fluids including natural gas from the downhole
producing formation; flowing a stream of the treating fluid and
hydrocarbon fluids including natural gas from the downhole
producing formation through the wellbore to the well surface;
separating liquids from the stream of treating fluid and
hydrocarbon fluids at the well surface to form a production gas
stream including at least CO.sub.2 gas and natural gas; and
separating the production gas stream at the well surface into first
and second gas streams, the first gas stream having a higher
natural gas to CO.sub.2 ratio than the production gas stream and
the second stream having a lower natural gas to CO.sub.2 ratio than
the production stream.
17. The method of claim 16, wherein the concentration of CO.sub.2
gas in the first gas stream is less than three percent.
18. The method of claim 16, further comprising directing the first
gas stream to a natural gas gathering system.
19. The method of claim 16, further comprising directing the first
gas stream to a natural gas sales pipeline.
20. The method of claim 16, further comprising using a mobile gas
separator at the associated well surface to separate the production
gas stream into the first gas stream and the second gas stream.
21. A method for optimizing production of natural gas at a well
site from a downhole producing hydrocarbon formation comprising:
injecting treating fluids including CO.sub.2 through at least one
wellbore into the hydrocarbon producing formation to increase fluid
flow from the hydrocarbon producing formation; flowing fluid
including CO.sub.2 and natural gas from the hydrocarbon formation
through the at least one wellbore to an associated well surface at
the well site; separating liquid from the fluid at the well
surface; directing all gases from the fluid, including natural gas
and CO.sub.2, to a gas separation unit; removing CO.sub.2 gas from
the gases; and directing natural gas to a natural gas sales
pipeline.
22. The method of claim 21, further comprising transporting the gas
separation unit to the well site to perform the removing step.
23. The method of claim 21, further comprising moving the gas
separation unit to the well site on a trailer.
24. The method of claim 21, the removing step comprising removing
CO.sub.2 gas to form a sales gas stream comprising at least natural
gas and CO.sub.2, the CO.sub.2 comprising less than 3 percent of
the sales gas stream.
25. The method of claim 21, further comprising: continuing the
removing step until the concentration of CO.sub.2 in the gases in
the fluid flowing from the at least one wellbore is within a range
specified by a buyer of the natural gas; and moving the gas
separation unit from the well site to a second well site, or to a
holding location for storage until the gas separation unit is to be
moved to and used at a second well site.
Description
BACKGROUND OF THE INVENTION
[0001] This invention relates to a method for separating CO.sub.2
from a gas stream and more specifically to separating CO.sub.2 gas
from a gas stream including natural gas produced from a downhole
formation at a well site.
[0002] It is well known in the oil and gas industry that wells
drilled to intersect one or more subterranean hydrocarbon-producing
formations are treated in a variety of ways for various purposes
including to increase production from the formation(s). One
well-known treatment procedure comprises fracturing wells to
increase the deliverability of a formation. Fracturing of a
formation is generally accomplished by injecting a fracturing fluid
into the formation via the wellbore and applying sufficient
pressure to initiate a fracture in the formation. Fracturing fluid
may also be referred to as a stimulation fluid. Carbon dioxide
(CO.sub.2), is often used in fracturing fluids, particularly in a
natural gas bearing formation. The amount of CO.sub.2 used to
fracture a formation will vary depending upon a variety of factors,
including, but not limited to, the thickness of the formation,
nature of the formation and the desired fracture length. In most
cases, large quantities of CO.sub.2 are used. Propping agents, also
referred to as proppants, may also be displaced into the induced
fracture. The proppants will hold the fractures open after pressure
on the formation is released. Generally, after the
hydrocarbon-bearing formation has been fractured, there is a time
period in which fracturing fluid is produced through the well to
the surface, along with hydrocarbons from the formation. This time
period may be referred to as a flow-back or cleanup stage in which
the stimulation fluids are recovered from a well. Hydrocarbons, for
example, natural gas, will also be produced, during the flow-back
stage. If the fluid used to fracture the formation includes
CO.sub.2, the gas produced during the cleanup stage may be
contaminated with high concentrations of CO.sub.2 gas. Purchasers
of natural gas have limits with respect to the amount of CO.sub.2
content that may exist in a gas stream intended for sale. Natural
gas that is contaminated with an unacceptable amount of CO.sub.2 is
typically vented or flared to the atmosphere until the CO.sub.2
content in the gas stream diminishes to a point that is acceptable
to the natural gas purchaser. During the cleanup stage large
volumes of natural gas are lost to the atmosphere. There is no
known economical way to separate the CO.sub.2 used in a fracturing
fluid from the natural gas produced during the flow-back stage at
the well site so that the natural gas produced during the flow-back
stage may be sold rather than lost to the atmosphere.
SUMMARY OF THE INVENTION
[0003] The current invention is directed to a method of producing
natural gas from a subterranean formation, and more specifically to
a method for optimizing production from a subterranean producing
formation by capturing natural gas produced during the flow-back
stage of a well rather than venting or flaring the natural gas to
the atmosphere. The method may comprise treating a downhole
producing formation with a treating fluid that includes at least
CO.sub.2. The treatment method may comprise fracturing the downhole
formation with a fracturing fluid that includes CO.sub.2 to improve
production of hydrocarbon fluids including natural gas from the
downhole formation. The stream produced from the well, which during
the flow-back stage may include the treating fluid and hydrocarbon
fluids may be referred to as a production stream.
[0004] Liquids and solids may be separated from the production
stream to form a production gas stream, and a mobile separation
unit may be transported to the well site to separate CO.sub.2 from
the production gas stream at the well site. The mobile separation
unit may separate the production gas stream into a first gas stream
containing a lower CO.sub.2 concentration than the production gas
stream and a second gas stream containing a higher CO.sub.2
concentration than the production gas stream. The first gas stream,
which may be referred to as a sales gas stream, will include
natural gas and will have a concentration of CO.sub.2 that is
acceptable to a natural gas purchaser, and will likely be less than
5 percent and will preferably be less than 3 percent.
[0005] The mobile separation unit will be utilized to separate
CO.sub.2 from the production gas stream until the CO.sub.2
concentration in the production gas stream (i.e., the gas stream as
it exists prior to the time it enters the mobile separation unit)
is at an acceptable level and thus, is preferably less than 3
percent. Once the CO.sub.2 concentration in the production gas
stream is at an acceptable level, the mobile separation unit may be
transported from the well site and housed at a storage location or
may be immediately moved to a second well site and used in
accordance with the method described herein for separating CO.sub.2
used in a fracture treatment process from natural gas produced from
a well. The mobile separation unit may therefore comprise a skid
mounted mobile separation unit that is small enough in size and
weight so that it may be placed on a trailer and transported over
roadways from well site to well site.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] FIG. 1 is a schematic diagram of a well site that has been
drilled for the production of natural gas where CO.sub.2 has been
used as a fracturing fluid to fracture a hydrocarbon-bearing
formation.
[0007] FIG. 2 is a schematic diagram of a mobile gas separation
unit mounted to a trailer.
[0008] FIG. 3 shows a hydrocarbon-bearing formation intersected by
a well.
DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT
[0009] The current invention is directed to a method of producing
natural gas from a subterranean formation intersected by a wellbore
extending from the surface of the earth through the formation, and
more particularly to a method of optimizing production of natural
gas from a well. The method generally comprises fracturing the
formation with a treating fluid that includes at least carbon
dioxide (CO.sub.2) and flowing a stream that includes treating
fluid and natural gas from the formation through the well to the
surface. The stream flowing from the well may be referred to as a
production stream. Liquids and solids are removed from the
production stream to form a production gas stream that will contain
at least natural gas and CO.sub.2. Typically, the CO.sub.2 will be
injected as a liquid, and may be mixed with other fluids. The
CO.sub.2 will flow from the well as a gas. A mobile gas separation
unit may be transported to the well site, and the method may
further comprise separating CO.sub.2 from the production gas stream
at the well site with the mobile separation unit to form a gas
stream with a low concentration of CO.sub.2. The production gas
stream preferably has a low enough concentration of CO2 gas to be
saleable to a natural gas purchaser.
[0010] FIGS. 1 and 3 schematically show a well site 5 with a
mobile, or transportable separation unit 10 at the well site. Well
15 has been drilled from the surface 18 to intersect a downhole
hydrocarbon-producing formation 20, from which hydrocarbons, for
example, natural gas may be produced. Well 15 may comprise wellbore
22 having a casing 25 cemented therein. Hydrocarbons may be
produced up casing 25 or as is known in the art may be produced
through a production tubing, such as production tubing 30. Casing
25 may be perforated to create perforations 32. Hydrocarbon fluids
from formation 20 will be communicated into casing 25 through
perforations 32 so that hydrocarbon fluids may be produced to the
surface. Fluid from formation 20 may be produced at well site 5
using equipment known in the art. It is understood that FIGS. 1 and
3 are schematic representations, and equipment known in the art is
used to produce fluids to associated well surface 18 at well site
5. The fluids produced to the surface may be referred to as a
production stream, or production fluids. At the surface, the
production stream may be communicated to a piping system
represented by a flow line 36 in FIG. 1, and directed to a
separation system 38. Separation system 38 may be, for example, a
two-phase separator of a type known in the art used to separate
liquids and/or solids from a gas stream. If any solids are produced
with the production stream, those solids will likely comprise a
small amount of proppant.
[0011] The gas stream leaving separation system 38 is substantially
a dry gas stream that may include very small amounts of trace
liquids. As is known in the art, additional separators may be used
to make certain that all liquids are removed from the production
stream. Thus, separation system 38 may include more than one
separator. The gas stream exiting separation system 38 will be a
dry gas stream, and may be referred to as a production gas stream.
The production gas stream may be, for example, a natural gas stream
produced from the hydrocarbon-producing formation that can be
communicated to a gathering system or a natural gas sales pipeline.
The solids and liquids are generally directed from separation
system 38 to a holding vessel through a piping system represented
by flow line 42.
[0012] There are limitations on the impurities that can be present
in the natural gas, and in some instances the limitations are
placed on natural gas producers by purchasers of natural gas. One
particular limitation is directed to the amount of CO.sub.2 that
can be present in the production gas stream. If the CO.sub.2
concentration is at an unacceptable level, the natural gas is not
saleable. Because wells drilled for production of natural gas are
often treated with CO.sub.2, the production stream may have, for a
period of time, a level of CO.sub.2 that is too high. For example,
CO.sub.2 may be used as in a fracturing fluid to fracture formation
20. Fracturing fluid may be communicated through well 15 and into
formation 20 through perforations 32. The amount of CO.sub.2
utilized to fracture the formation will vary depending upon a
number of factors including but not limited to the thickness of the
formation, the length of the desired fracture, and whether a single
or multiple formations are being treated. By way of example only,
it would not be unusual to pump about 100 tons of CO.sub.2 into a
downhole formation with a thickness of between approximately twenty
to thirty feet to create fractures with a length of about 200 to
300 feet. In many cases several hundred tons of CO.sub.2 are
utilized to treat formations intersected by a well. Pressure is
generally applied to urge the fracturing fluid into the formation,
or formations, to create the desired fractures. Proppants may also
be displaced into the well to hold the fractures open.
[0013] After the well has been subjected to the fracturing
treatment and pressure on the well is released, CO.sub.2 gas will
be produced up the well to the surface 18 along with natural gas
from the formation or formations. The production stream from the
formation, which may include liquids, CO.sub.2 gas and natural gas
will pass through flow line 36 into separation system 38.
Typically, liquids and solids are separated from the production
stream in separation system 38, and the production gas stream is
communicated into a piping system represented by flow line 40.
During the initial stages of production, the fracturing fluid,
specifically CO.sub.2 gas, will be produced along with natural gas.
As set forth herein, this stage may be referred to as the
flow-back, or cleanup stage. During the flow-back stage, the
concentration of CO.sub.2 in the production gas stream will
generally be at an unacceptably high level, so the natural gas
cannot be delivered to a natural gas sales pipeline or a gathering
system. In the current state of the art, the production gas stream
flowing in flow line 40 must therefore be vented, or flared, until
the CO.sub.2 level in the production stream is at the desired
level, which is less than 5 percent, and preferably less than 3
percent, and more preferably about 2 percent or less. The
concentration of CO.sub.2 in the production gas stream in flow line
40 is monitored until the production gas stream has an acceptable
concentration of CO.sub.2. It is not unusual for the production gas
stream to be vented or flared for a period of several days, or even
several weeks until the concentration of CO.sub.2 in the production
gas stream leaving separation system 38 is at a low enough
concentration to be accepted by a gas purchaser.
[0014] In the current invention the production gas stream from
separation system 38 is directed through flow line 40 to mobile gas
separation unit 10. Mobile gas separation unit 10 will separate the
production gas stream into first and second gas streams. The first
gas stream may be directed through a piping system represented by
flow line 44 and the second gas stream may be communicated from the
mobile separation unit 10 through a piping system represented by
flow line 46 in FIG. 1. The concentration of CO.sub.2 in the first
gas stream is less than the concentration of CO.sub.2 in the
production gas stream flowing through flow line 40. The CO.sub.2
concentration in the first gas stream will be at a desired level,
for example less than 5 percent, and preferably less than 3
percent, and more preferably about 2 percent. The first gas stream
will meet the requirements of gas purchasers and thus is acceptable
for purchase so that flow line 44 may be connected to a natural gas
sales pipeline to direct the natural gas to a purchaser, or
communicated to a gathering system. The second gas stream has a
higher concentration of CO.sub.2 than the production gas stream in
flow line 40 and will be communicated to a piping system
represented by flow line 46. The second gas stream will be vented
to the atmosphere or may be directed as desired for a later desired
use. The production gas stream flowing through flow line 40 may be
continuously monitored and communicated into mobile separation unit
10 during the flow-back or cleanup stage until such time as the
concentration of CO.sub.2 in the gas stream in flow line 40
dissipates and reaches the desired level. When the CO.sub.2 level
in the production gas stream in flow line 40 reaches the desired
level, the production gas stream can be communicated directly to a
natural gas sales pipeline or gathering system.
[0015] When the production gas stream in flow line 40 is at a
desired level, mobile separation unit 10 may be moved to another
well site and used in the same manner described herein. Mobile
separation unit 10 is preferably a skid mounted mobile separation
unit 10 and thus includes skids 48. The overall size of skid
mounted mobile separation unit 10 is such that it can be mounted to
a trailer 50 and driven from well site to well site and used to
separate CO.sub.2 from a production gas stream so that the gas
stream exiting the mobile separation unit 10 has a CO.sub.2
concentration acceptable to gas purchasers. Generally, the maximum
size of a skid that can be trailered is approximately 102 inches
wide, eight feet tall and forty feet long. The maximum weight is
approximately 50,000 pounds. Thus, such dimensions are the maximum
dimensions for skid mounted mobile separation unit 10. Preferably,
however, mobile separation unit 10 is much smaller than the maximum
acceptable size set forth herein. Mobile separation unit 10 is
preferably a self-contained unit that can be transported on a
single trailer, and requires minimal assembly, other than making
connections to piping systems, at the well site. In other words,
the mobile separator 10 is preferably a unit that is a stand-alone
unit that can be moved on a single trailer from well site to well
site to separate CO.sub.2 used as a fracturing fluid from natural
gas produced from a well.
[0016] Utilizing the method of the current invention creates an
economic advantage, and provides for the optimization of production
of natural gas in wells where CO.sub.2 is used as a fracturing
fluid. Natural gas that normally would be lost may be captured and
sold, which creates both an economic and an environmental
advantage. For example, a well that was treated with approximately
200 tons of CO.sub.2 as a fracturing fluid, initially had a
production gas stream flow rate of approximately 2 MMSCFD, during
the flow-back stage. The production gas stream was vented for a
period of 20 days. After 20 days, the CO.sub.2 concentration was at
a low enough level, about 2%, so that the natural gas could be
sold. During the time the production gas stream was vented,
approximately 50 MMSCF of natural gas was lost. Utilizing the
current method, the gas lost to the atmosphere could have been
sold.
[0017] Thus, the present invention is well adapted to carry out the
objects and attain the ends and advantages mentioned as well as
those inherent therein. While numerous changes may be made by those
skilled in the art, such changes are encompassed within the spirit
of this invention as defined by the appended claims.
* * * * *