U.S. patent application number 11/300802 was filed with the patent office on 2007-06-14 for liquefaction of associated gas at moderate conditions.
This patent application is currently assigned to Chevron U.S.A. Inc.. Invention is credited to Jeremiah Daniel, Carolyn J. Ritchie, Arif Shipchandler.
Application Number | 20070130991 11/300802 |
Document ID | / |
Family ID | 38137934 |
Filed Date | 2007-06-14 |
United States Patent
Application |
20070130991 |
Kind Code |
A1 |
Shipchandler; Arif ; et
al. |
June 14, 2007 |
Liquefaction of associated gas at moderate conditions
Abstract
A method is proposed for converting a portion of associated gas
generated during crude oil production into a liquid form which
permits the transport of a large amount of methane at moderate
temperatures.
Inventors: |
Shipchandler; Arif; (Katy,
TX) ; Ritchie; Carolyn J.; (Conroe, TX) ;
Daniel; Jeremiah; (Houson, TX) |
Correspondence
Address: |
CHEVRON TEXACO CORPORATION
P.O. BOX 6006
SAN RAMON
CA
94583-0806
US
|
Assignee: |
Chevron U.S.A. Inc.
|
Family ID: |
38137934 |
Appl. No.: |
11/300802 |
Filed: |
December 14, 2005 |
Current U.S.
Class: |
62/613 ;
62/620 |
Current CPC
Class: |
C10L 3/10 20130101; F25J
2240/02 20130101; F25J 3/061 20130101; C10L 3/12 20130101; F25J
2270/90 20130101; F25J 2290/72 20130101; F25J 3/0635 20130101; F25J
3/064 20130101; F25J 2290/62 20130101 |
Class at
Publication: |
062/613 ;
062/620 |
International
Class: |
F25J 1/00 20060101
F25J001/00; F25J 3/00 20060101 F25J003/00 |
Claims
1. A method for producing a methane containing liquid at moderate
temperature, the method comprising the steps of: a. recovering an
associated gas from a crude oil production process; b. drying the
associated gas to remove water; c. chilling the dried associated
gas; d. separating the chilled dried associated gas at a target
temperature and target pressure in a vapor-liquid separator into a
methane lean liquid stream and a methane rich vapor stream, the
methane lean liquid stream containing at least 30% C.sub.2-; and e.
storing the methane lean liquid stream.
2. The method of claim 1 wherein the target temperature is between
5.degree. F. and -55.degree. F. and the target pressure is less
than 750 psia.
3. The method of claim 2 wherein the target temperature is greater
than -55.degree. F.
4. The method of claim 2 wherein the pressure is less than 500
psia;
5. The method of claim 2 wherein the pressure is in the range of
between 220 psia to 450 psia.
6. The method of claim 1, wherein the methane lean liquid stream
contains between 30% and 70% C.sub.2- components.
7. The method of claim 6, wherein the methane lean liquid stream
contains between 40 and 60% C.sub.2- components.
8. The method of claim 1 wherein the methane rich vapor stream
comprises less than 30% C.sub.2+ hydrocarbons.
9. The method of claim 6 wherein the methane rich vapor stream
comprises less than 15% C.sub.2+ hydrocarbons.
10. The method of claim 1 wherein the associated feed gas comprises
greater than 30% C.sub.2+ hydrocarbons.
11. The method of claim 8, wherein the associated feed gas
comprises greater than 40% C.sub.2+ hydrocarbons.
12. The method of claim 1 wherein the dew point of the dried
associated gas is less than the target temperature.
13. The method of claim 1, further comprising using the methane
rich vapor as a utility fuel for the uses selected from the group
consisting of to drive gas turbine generators, to supply power
requirements for living quarters and other utilities and to
energize process support equipment and gas fired heaters
14. The method of claim 1, further comprising using the methane
rich vapor as a utility fuel to provide power for dynamic position
thrusters installed on a dynamically positioned FPSO.
Description
TECHNICAL FIELD
[0001] The present invention resides in the methods for recovering,
treating and using natural gas.
BACKGROUND OF INVENTION
[0002] The present invention relates to a method for enhancing the
value of associated gas produced in a remote location. Frequently,
a quantity of gaseous hydrocarbons is produced during the
production of crude oil from a crude oil resource. Historically,
these gaseous hydrocarbons were often flared at the well during
production of the crude, particularly when the well was in a remote
location, and liquid products (such as crude oil) from the well
were transported large distances to the refinery or to the market
for the products.
[0003] Flaring of the gases is not acceptable, both from a resource
standpoint and from an environmental standpoint, and other methods
for dealing with the gases is required. When the gas quantities are
large enough to make large scale gas processing economically
feasible, the associated gas may be liquefied in an LNG process,
compressed to high pressures in a CNG process or converted to
liquid hydrocarbons in a GTL process.
[0004] U.S. Pat. No. 6,793,712 teaches forming C.sub.2.sup.+ rich
liquid in a cooling stage during the liquefaction of natural gas,
and removing the C2+ rich liquid via gas-liquid separation means.
As taught, the sequential cooling of the natural gas in each stage
is generally controlled so as to remove as much as possible of the
C.sub.2 and higher molecular weight hydrocarbons from the gas to
produce a gas stream predominating in methane and a liquid stream
containing significant amounts of ethane and heavier
components.
[0005] Natural gas typically contains up to 15 vol. % of
hydrocarbons heavier than methane. Natural gas liquids (NGL) are
comprised of ethane, propane, butane, and minor amounts of other
heavy hydrocarbons. Liquefied natural gas (LNG) is comprised of at
least 80 mole percent methane; it is often necessary to separate
the methane from the heavier natural gas hydrocarbons. It is
desirable conventionally to recover the NGL because its components
have a higher value as liquid products, where they are used as
petrochemical feedstocks, compared to their value as fuel gas. NGL
is typically recovered from LNG streams by many well-known
processes including "lean oil" adsorption, refrigerated "lean oil"
absorption, and condensation at cryogenic temperatures. The most
common process for recovering NGL from LNG is to pump and vaporize
the LNG, and then redirect the resultant gaseous fluid to a typical
industry standard turbo-expansion type cryogenic NGL recovery
process.
[0006] The present process is directed to the recovery and
preparation of associated gas from crude oil resources which
contain relatively small amounts of gas, such that the large scale
gas processing methods are uneconomical. In the process, a crude
liquefied gaseous mixture is prepared to be stable at relatively
moderate temperatures and pressures, while containing a high amount
of valuable methane (C.sub.1), ethane (C.sub.2) and propane plus
(C.sub.3.sup.+) components.
SUMMARY OF THE INVENTION
[0007] The present invention provides a method for converting a
portion of associated gas generated during crude oil production
into a liquid form which permits the transport of a large amount of
methane at moderate temperatures. Thus, a method is provided for
producing a methane containing liquid at moderate temperature, the
method comprising the steps of: recovering an associated gas from a
crude oil production process; drying the associated gas to remove
water; chilling the dried associated gas; separating the chilled
dried associated gas at a target temperature and target pressure in
a vapor-liquid separator into a methane lean liquid stream and a
methane rich vapor stream, the methane lean liquid stream
containing at least 30% C2-; and storing the methane lean liquid
stream.
[0008] At the target temperature of the methane lean liquid stream
which is pre-selected to permit the handling and shipping of the
liquid stream at temperatures and pressures normally encountered
with liquefied petroleum gas (LPG), the liquid stream contains
between 30% and 70% C2- components. In this way, large amounts of
methane can be shipped from a remote location to a market or
refinery without requiring the extreme cryogenic conditions of LNG.
In one embodiment, the methane that remains as a methane rich vapor
stream may be suitably used as a utility fuel for the uses selected
from the group consisting of to drive gas turbine generators, to
supply power requirements for living quarters and other utilities
and to energize process support equipment and gas fired heaters.
The methane rich vapor may further or alternatively be used as a
utility fuel to provide power for dynamic position thrusters
installed on a dynamically positioned FPSO.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] FIG. 1 illustrates the process of the invention for
recovering a methane-containing liquid stream from an associated
gas feed stream. The liquid stream has the properties permitting it
to be stored and transported at relatively moderate temperature and
at a relatively low pressure.
DETAILED DESCRIPTION OF THE INVENTION
[0010] In the present method, an associated gas is treated to
prepare a liquefied gas stream, containing a high amount of C2-
components, which can be stored at relatively mild conditions of
temperature and pressure. Thus, in one embodiment, the liquefied
gas stream produced in an offshore facility may be conveyed through
commercially available hoses and transported to shore in a
conventional LPG tanker and/or a modified supply boat and/or a
modified crude oil shuttle tanker. For example, LPG tankers
typically have the capability of transporting liquefied gases at
conditions of temperatures greater than -55.degree. F. and at
pressure below 500 psia.
[0011] As used here, C1 refers to a hydrocarbon molecule containing
one carbon atom. Methane is an illustrative example. C2 refers to a
hydrocarbon molecule containing two carbon atoms. Ethane is an
illustrative example. C3 refers to a hydrocarbon molecule
containing three carbon atoms. Propane is an illustrative example.
C4 refers to a hydrocarbon molecule containing four carbon atoms.
Butane is an illustrative example. C5 refers to a hydrocarbon
molecule containing five carbon atoms. Pentane is an illustrative
example. C6 refers to a hydrocarbon molecule containing six carbon
atoms. Hexane is an illustrative example. Molecules with larger
numbers of carbon atoms are defined accordingly. As used here, LPG
is a term of art referring to a liquid phase mixture comprising
primarily C3 and C4 components. LNG is a term of art referring to a
liquid phase mixture comprising primarily C1 components, with
lesser amounts of C2 components. Natural gas liquids, NGL, is a
term of art referring to a liquid phase mixture comprising
principally C4+ components.
[0012] As used herein, C2+ represents hydrocarbons containing two
or more carbon atoms per molecule. Non-limiting exemplary C2+
hydrocarbons include ethane (C2H6), propane (C3H8), butane (C4H10),
pentane (C5H12), hexane (C6H14), heptane (C7H16), octane (C8H18),
and cyclic or unsaturated variants thereof. C2- represents
hydrocarbons containing two or fewer carbon atoms per molecule.
C3+, C4+ are defined accordingly.
[0013] As an overview, FIG. 1 illustrates a preferred exemplary
embodiment utilizing the method of the present invention. An
associated gas is recovered in step 10 from a crude oil production
process. Typically, gas stream 15 is delivered to the gas
processing system at a pressure greater than 250 psia, or greater
than 500 psia, or even greater than 1000 psia. These pressures can
be obtained naturally from a gas well or obtained by adding energy
through the use of one or more compressors. Thus, in one
embodiment, the entire process is maintained without no additional
pressurization of the gas or liquid streams during the; process. In
a separate embodiment, a pump or compressor is installed in the
process. For example, the compressor (not shown in FIG. 1) may be
installed to pressurize, for example, the gas in stream 15, or in
stream 25 or in stream 45. The choice of stream is an engineering
choice. However, it is preferred that the produced gas 15 prior to
dehydration, or the dried stream 25 prior to chilling, be increased
in pressure up to a target pressure. In an embodiment of the
invention, the target pressure is selected to ensure that a liquid
methane lean stream be produced in the process having a temperature
in the range of between -55.degree. F. and 5.degree. F., and a
pressure of less than 500 psia.
[0014] The associated gas (15) is then dried to remove water in
step 20. The dried associated gas (25) is pressurized in step 30
and then chilled in step 40 to liquefy a portion thereof. The
chilled stream (45) comprising both a liquid portion and a gaseous
portion is separated in step 50 into a methane rich vapor stream
(55) and a methane lean liquid stream (57), which is stored in
storage vessel (60). As shown in the embodiment illustrated in FIG.
1, at least a portion of the chilled methane rich vapor stream (55)
is passed to the chilling step (40) to cool the incoming dried
associated gas prior to its chilling. The methane lean stream (57)
has a lower concentration of methane than the associated gas feed
(15), and the methane rich stream (55) has a higher concentration
of methane than the associated gas feed (15). In one embodiment,
the methane lean stream is a liquid stream containing at least 40%
C2-, while remaining stable to volatilization at the moderate
temperatures and pressures of the process. Thus, the methane lean
stream can be stored in insulated containers and transported at
relatively mild conditions without significant loss to evaporation.
The methane rich vapor stream may be used, for example, for
providing power, for reinjection into the reservoir, and the
like.
[0015] Among other factors, the present invention is based on the
discovery that heavy gaseous hydrocarbons condensed from an
associated gas can be used to absorb light gaseous hydrocarbons,
such as methane and ethane, while maintaining a relatively low
vapor pressure. The naturally occurring heavy ends in the condensed
stream allow methanes and ethanes to condense and be stored as
liquids in a multi-component mixture at moderate pressures and
temperatures. At such conditions, CO2 removal, complex
chilling/cold recovery process, distillation/fractionation process
and handling of ultra-low temperature cryogenic liquids (such as
LNG) is avoided, making the offshore (and/or) remote facility
simple and safe to operate and maintain. This unfinished liquid
product called "Liquefied Heavy Gas" can be easily transported from
a remote (and/or) offshore location and processed further at an
onshore processing facility into finished products such as LPG,
natural gas liquids and pipeline export gas. The remaining
uncondensed hydrocarbons are useful for satisfying internal fuel
requirements.
[0016] For example, the feed gas to the process can contain CO2 at
levels up to 5% when the heavy liquid product is prepared at the
target temperature and pressure, with CO2 levels of up to 2% being
preferred.
[0017] Associated gas is a natural gas which is found in
association with crude oil, either dissolved in the oil or as a cap
of free gas above the oil. Associated gas typically separates from
the crude oil during production, and is recovered as a separate
gaseous phase from the crude oil liquid phase. The characteristics
of the associated gas depends on the field from which it is
recovered, the nature of the crude oil with which it is produced,
and the temperature and pressure of the crude oil as it is produced
and stored. In general, associated gas comprises C1+ components,
and may include trace amounts of hydrocarbons up to C10 or even
higher. Most of the hydrocarbons in associated gas are in the C1-C6
range.
[0018] Associated gas is separated from the produced crude at any
time during the production, handling and storage of the crude,
though most is recovered as a separate phase during crude
production from the reservoir. Methods for recovering associated
gas are well known and practiced in most producing wells.
[0019] The present process is beneficially practiced for processing
associated gas produced in a remote location. Such remote locations
are sufficiently separated from the market that delivering the gas
to market through a pipeline is expensive and/or technically
difficult relative to transporting the associated gas by water,
including ships, barges, tankers and the like or by overland
vehicle, including by trucks, trains and the like.
[0020] In general, associated gas contains water vapor, which is
preferably removed prior to chilling. Methods for removing water
from associated gas are well known. In one illustrative embodiment,
the water is removed using glycol as the absorbent, optionally in
combination with a molecular sieve to reduce the water to the
levels required by the process. Thus, water is removed from natural
gas upstream of the cryogenic plant by glycol dehydration
(absorption) followed by a molecular sieve (adsorption) bed.
Alternatively, a molecular sieve bed alone, or in combination with
other conventional methods, may be used to remove the water.
Molecular sieve dehydration units are normally installed upstream
of the cryogenic plant to eliminate the water before the gas enters
the cooling train. An exemplary molecular sieve which is useful for
this drying step is an X-type zeolite adsorbent.
[0021] The dried associated gas is chilled to condense a portion of
the gas, forming a partially liquid phase product. The temperature
to which the associated gas is chilled depends on a number of
factors, including the amount of the methane rich vapor phase
component needed for power, and the temperature and pressure of the
methane lean liquid component which can be tolerated while the
liquid component is being transported from the remote site. In one
embodiment of the process, the associated gas is chilled to a
target temperature, which is pre-selected to produce a liquid phase
methane lean product which can be shipped to a shuttle tanker (or
supply boat) using commercially available marine hoses. Associated
gas chilling is achieved using, for example, an adiabatic process
(such as Joule Thomson process), an isentropic process
(turbo-expander) or an external refrigeration process. Storing and
shipping the methane lean liquid component is facilitated when the
component is stored under pressure. As with the temperature, a
target pressure is pre-selected to maintain the methane lean
component in the liquid phase during storage and shipping.
Pressurizing the associated gas is typically done prior to the
chilling step. In another embodiment, the temperature and pressure
conditions of the separator are set such that the volumetric rate
of methane rich gas leaving the separator corresponds to the
flowrate required to satisfy internal fuel gas consumption, with
the remainder being condensed as liquefied heavy gas which is
stored in pressurized vessel(s) or containers and transported to
consumers.
[0022] The chilled stream from the chilling step is then separated
into a methane lean liquid stream and a methane rich vapor stream
using a liquid vapor separator. The temperature and pressure of the
separation are set by targets desired for shipping the liquid
stream. In one embodiment, the target temperature of the methane
lean liquid phase is greater than -55.degree. F., and typically
ranges from 5.degree. F. to -50.degree. F. (depending upon the
demand of the internal fuel gas requirement). Likewise, while the
process can be used to prepare a methane lean liquid phase having a
pressure of less than 750 psia, a pressure of less than 500 psia is
preferred, and a pressure in the range of 220 psia to 450 psia is
preferred. A higher internal fuel gas demand can be met by
increasing the separator temperature, thereby producing more gas
and correspondingly less liquefied heavy gas. In one embodiment,
the separator pressure is set at a pressure lower than the storage
vessel/container maximum allowable operating pressure to account
for possible increases in pressure over time due to boil off gas
generated from heat ingress into the system.
[0023] In one embodiment, the separation is performed in a single
stage vapor liquid separation, and without fractional distillation.
Gravity separators, centrifugal separators and the like are ideal
for the separation. Though having a reduced methane content
relative to the associated gas feed to the process, the methane
lean liquid phase contains a significant amount of C2- material.
Generally, the methane lean liquid contains at least 30% C2-, more
preferably in the range of 30% to 65% C2-, and most preferably in
the range of 40 to 60% C2-. The methane rich vapor contains less
than 30% C2+, preferably less than 25% C2+ and most preferably less
15% C2+. As used herein, percentage amounts are referenced to molar
percentages, unless stated otherwise. The storage vessel/container
is generally thermally insulated to minimize heat ingress and
thereby delay the rise in pressure over time. The naturally
occurring C3+ heavy components in the liquids assist in condensing
the methane and ethane components at relatively moderate
temperatures which may then allow the use of commercially available
flexible marine hoses to unload the liquefied heavy gas from an
offshore facility to supply boats/shuttle tanker.
[0024] The methane lean liquid phase is stored at a target
temperature and at a target pressure. In one embodiment, the target
temperature of the methane lean liquid phase is greater than
-55.degree. F., and typically ranges from 5.degree. F. to
-50.degree. F. (depending upon the demand of the internal fuel gas
requirement). Likewise, while the process can be used to prepare a
methane lean liquid phase having a pressure of less than 750 psia,
a pressure of less than 500 psia is preferred, and a pressure in
the range of 220 psia to 450 psia is preferred.
[0025] The gaseous portion which is separated from the chilled
associated gases is methane rich relative to the dried associated
gases. In this preferred exemplary embodiment, this chilled gas
portion is used to cool incoming dried associated gas which is to
be sent to the chilling step. After removing heat, this methane
rich gas portion may then be used to energize the production
facility, such as by installing gas turbine based power generators
and/or gas engine/turbine based compressor drivers and/or gas fired
heaters to satisfy process heat load. To maximize use of gas as
internal fuel for floating offshore facilities such as a
Dynamically Positioned FPSO, all marine power requirements
(including dynamic positioning thrusters) under operations using
the methane rich stream are sourced from topsides gas turbine
generators (in lieu of utilizing the ship's marine fuel oil fired
power generators) which also provide power to the production
facilities. These power generators may have dual fuel capability to
support start-up and other off design cases. Alternatively, if
surplus gaseous methane rich stream still exists after satisfying
internal fuel consumption then a portion of gas may be converted to
CNG. Or surplus gas is converted to additional power and exported
to third party else, a portion could be used for needed energy
purposes with remainder converted to CNG. Moreover, a portion of
the gaseous portion could be reinjected in a subterranean
formation.
[0026] The liquefied heavy gas is an unfinished product which
contains a mixture of components ranging from methane to C5+
components which is then transported to an onshore gas processing
facility or a refinery which fractionates the liquefied heavy gas
into finished products such as pipeline specification gas, LPG and
stabilized NGL.
* * * * *