Note: Descriptions are shown in the official language in which they were submitted.
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Liquefaction of Associated Gas at Moderate Conditions
Technical Field
The present invention resides in the methods for recovering, treating and
using natural gas.
Background of Invention
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.
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.
US Patent No. 6,793,712 teaches forming C2+ 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 C2 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.
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
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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.
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 (C1), ethane (02) and propane plus (C3+)
components.
Summary of the Invention
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.
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
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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.
In accordance with another aspect, there is provided 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 between 30% and 70% C2- components and at least 30% 03+
heavy components and other gases wherein the target temperature is greater
than -55 F; and
e. storing the methane lean liquid stream wherein the C3+ heavy
components in the methane lean liquid stream assist in condensing the 02-
components.
In accordance with a further aspect, there is provided 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;
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d. separating the chilled dried associated gas at a target temperature
and target pressure into a methane lean liquid stream and a methane rich
gaseous stream vapor stream, the methane lean liquid stream containing
between 30% and 70% C2- components and at least 30% C3+ heavy
components and other gases wherein the target temperature of the methane
lean liquid stream is greater than -55 F;
e. storing the methane lean liquid stream; and
f. conveying the methane lean liquid stream to a supply boat without
the use of cryogenic hoses.
Brief Description of the Drawings
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
In the present method, an associated gas is treated to prepare a
liquefied gas stream, containing a high amount of 02- 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 F and at pressure below 500 psia.
As used here, Cl refers to a hydrocarbon molecule containing one
carbon atom. Methane is an illustrative example. 02 refers to a hydrocarbon
molecule containing two carbon atoms. Ethane is an illustrative example. 03
refers to a hydrocarbon molecule containing three carbon atoms. Propane is
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an illustrative example. C4 refers to a hydrocarbon molecule containing four
carbon atoms. Butane is an illustrative example. 05 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 03 and 04 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 04+ components.
As used herein, 02+ represents hydrocarbons containing two or more
carbon atoms per molecule. Non-limiting exemplary 02+ hydrocarbons include
ethane (C2H6), propane (03H8), butane (C4H10), pentane (C5H12), hexane
(C6H14), heptane (C7H16), octane (C8H18), and cyclic or unsaturated variants
thereof. 02- represents hydrocarbons containing two or fewer carbon atoms
per molecule. 03+, 04+ are defined accordingly.
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
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liquid methane lean stream be produced in the process having a temperature in
the range of between --55 F and 5 F, and a pressure of less than 500 psia.
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% 02-, 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.
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
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liquids and pipeline export gas. The remaining uncondensed hydrocarbons are
useful for satisfying internal fuel requirements.
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.
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 Cl components, and may include trace
amounts of hydrocarbons up to 010 or even higher. Most of the hydrocarbons
in associated gas are in the 01-06 range.
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.
The preserit 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.
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
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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.
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.
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
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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 F, and
typically ranges from 5 F to -50 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.
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 02- material.
Generally, the methane lean liquid contains at least 30% C2-, more preferably
in the range of 30% to 65% 02-, and most preferably in the range of 40 to 60%
02-. The methane rich vapor contains less than 30% 02+, preferably less than
25% C2+ and most preferably less 15% 02+. 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 03+ 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.
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
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lean liquid phase is greater than -55 F, and typically ranges from 5 F to -50
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.
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.
The liquefied heavy gas is an unfinished product which contains a
mixture of components ranging from methane to 05+ 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.
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