U.S. patent application number 13/578491 was filed with the patent office on 2012-12-20 for system and method for creating flowable hydrate slurries in production fluids.
Invention is credited to Jason W. Lachance, Douglas J. Turner.
Application Number | 20120322693 13/578491 |
Document ID | / |
Family ID | 44542491 |
Filed Date | 2012-12-20 |
United States Patent
Application |
20120322693 |
Kind Code |
A1 |
Lachance; Jason W. ; et
al. |
December 20, 2012 |
SYSTEM AND METHOD FOR CREATING FLOWABLE HYDRATE SLURRIES IN
PRODUCTION FLUIDS
Abstract
Methods and systems are provided for producing hydrocarbons from
production fluids that have water as an external phase. An
exemplary embodiment provides a method that comprises producing a
production fluid having water as the external phase and injecting
an amount of a thermodynamic hydrate inhibitor into the production
fluid, wherein the amount is adjusted to allow hydrate formation to
occur while retaining liquid water as the external phase. The water
and thermodynamic hydrate inhibitor may be separated from the
production fluid and a purified hydrocarbon stream may be
produced.
Inventors: |
Lachance; Jason W.;
(Pearland, TX) ; Turner; Douglas J.; (Humble,
TX) |
Family ID: |
44542491 |
Appl. No.: |
13/578491 |
Filed: |
January 6, 2011 |
PCT Filed: |
January 6, 2011 |
PCT NO: |
PCT/US11/20383 |
371 Date: |
August 10, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61311034 |
Mar 5, 2010 |
|
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|
Current U.S.
Class: |
507/90 ; 137/602;
585/15 |
Current CPC
Class: |
F17D 3/12 20130101; E21B
37/06 20130101; C09K 2208/22 20130101; F17D 3/14 20130101; F17D
3/10 20130101; C09K 8/52 20130101; Y10T 137/0318 20150401; Y10T
137/87571 20150401; E21B 43/40 20130101; E21B 43/34 20130101; F17D
1/14 20130101; F17D 1/17 20130101; E21B 43/017 20130101; Y10T
137/8376 20150401 |
Class at
Publication: |
507/90 ; 585/15;
137/602 |
International
Class: |
C07C 7/20 20060101
C07C007/20; A23G 9/28 20060101 A23G009/28; C09K 8/52 20060101
C09K008/52 |
Claims
1. A method for forming a flowable hydrate slurry in a production
fluid that has water as an external phase, comprising: injecting an
amount of a thermodynamic hydrate inhibitor (THI) into the
production fluid, wherein the amount of the THI added is controlled
to allow formation of a hydrate while retaining the water as the
external phase.
2. The method of claim 1, further comprising monitoring a phase
behavior of the production fluid after the hydrate forms to
determine that the water is the external phase.
3. The method of claim 2, further comprising adjusting the amount
of the THI injected into the production fluid to select the water
as the external phase.
4. The method of claim 1, further comprising adding an
anti-agglomerate agent (AA) to the production fluid.
5. The method of claim 1, further comprising adding a kinetic
hydrate inhibitor to the production fluid.
6. The method of claim 1, wherein the THI comprises glycols,
alcohols, salts, or any combinations thereof.
7. The method of claim 1, further comprising passing the production
fluid through a static mixer after injecting the THI.
8. The method of claim 1, wherein the amount of the THI injected
into the production fluid is less than about 5% by wt. in the water
phase before the formation of the hydrate.
9. A system for producing a production fluid in which water is an
external phase, comprising: a pipeline configured to carry the
production fluid; and an injector configured to inject an amount of
a thermodynamic hydrate inhibitor (THI) into the production fluid,
wherein the amount of the THI added will allow formation of a
hydrate while retaining the water as the external phase.
10. The system of claim 9, further comprising a static mixer in the
pipeline downstream of the injector.
11. The system of claim 9, further comprising an analyzer to
determine a phase behavior of the production fluid.
12. The system of claim 11, further comprising an addition system
configured to change the amount of the THI added in order to select
the water as the external phase.
13. The system of claim 9, comprising a processing facility
configured to remove the water and the THI from the production
fluid.
14. The system of claim 9, comprising a processing facility
configured to process the hydrocarbon for shipping in a
pipeline.
15. The system of claim 9, comprising a hydrocarbon field
configured to produce the production fluid.
16. The system of claim 15, wherein the production fluid comprises
a natural gas.
17. The system of claim 15, wherein the production fluid comprises
an oil.
18. A method for producing a hydrocarbon, comprising: producing a
production fluid having water as an external phase; injecting an
amount of a thermodynamic hydrate inhibitor (THI) into the
production fluid, wherein the amount is adjusted to allow hydrate
formation to occur while retaining water as the external phase;
separating out the water and the THI from the production fluid; and
producing a purified hydrocarbon stream.
19. The method of claim 18, further comprising monitoring a phase
behavior of the production fluid after the injection of the
THI.
20. The method of claim 18, wherein producing the purified
hydrocarbon stream comprises producing a liquefied natural gas.
21. The method of claim 18, further comprising separating the THI
from the water and reinjecting the THI into the production fluid.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the priority benefit of U.S.
Provisional Patent Application 61/311,034 filed 5 Mar. 2010
entitled SYSTEM AND METHOD FOR CREATING FLOWABLE HYDRATE SLURRIES
IN PRODUCTION FLUIDS, the entirety of which is incorporated by
reference herein.
FIELD
[0002] Exemplary embodiments of the present techniques relate to
increasing the flowability of hydrocarbons in an external water
phase by allowing the formation of hydrates to occur.
BACKGROUND
[0003] The presence of water in production fluids may cause
problems while transporting a hydrocarbon due to the formation of
clathrate hydrates with the hydrocarbons. Clathrate hydrates
(commonly called hydrates) are weak composites formed from a water
matrix and a guest molecule, such as methane or carbon dioxide,
among others. Hydrates may form, for example, at the high pressures
and low temperatures that may be found in pipelines and other
hydrocarbon equipment. While forming, the hydrates can agglomerate,
leading to plugging or fouling of the equipment. Various techniques
have been used to lower the ability for hydrates to form or cause
plugging or fouling. Exemplary, but non-limiting techniques include
insulation of lines, dehydration of the hydrocarbon, and the adding
of thermodynamic hydrate inhibitors (THIs), kinetic hydrate
inhibitors (KHIs), and/or anti-agglomerates (AAs).
[0004] Insulation, active heating, and dehydration can be
expensive, especially for subsea systems. Even with insulation,
cool-down of production fluids can limit the distance of a
producing pipeline. For example, the contents of the pipeline may
cool down during shut-in periods and form a hydrate plug. If a
hydrate blockage does occur, insulation can be detrimental by
preventing heat transfer from the surroundings that is needed for
hydrate melting.
[0005] Thermodynamic hydrate inhibitors, such as methanol,
monoethylene glycol, diethylene glycol, triethylene glycol, and
potassium formate, among others, lower the hydrate formation
temperature, which may inhibit the formation of the hydrate under
the conditions found in a particular process. Thermodynamic
inhibitors can be very effective at hydrate prevention, but the
quantities required for total inhibition are large and proportional
to the amount of water produced, leading to increasing and even
prohibitive quantities late in field life. See Valberg, T.,
"Efficiency of Thermodynamic Inhibitors for Melting Gas Hydrates,"
Master's Thesis, Norwegian University of Science and Technology,
Trondheim, Norway (2006). Low dosage hydrate inhibitors (LDHIs)
exist, including kinetic hydrate inhibitors (KHIs) and
anti-agglomeration agents (AAs).
[0006] KHIs slow the formation of hydrates, but not by changing the
thermodynamic conditions. Instead, KHIs inhibit the nucleation and
growth of the hydrate crystals. Such materials may include, for
example, Poly(2-alkyl-2-oxazoline) polymers (or poly(N-acylalkylene
imine) polymers), poly(2-alkyl-2-oxazoline) copolymers, and others.
See Urdahl, Olav, et al., "Experimental testing and evaluation of a
kinetic gas hydrate inhibitor in different fluid systems,"
Preprints from the Spring 1997 Meeting of the ACS Division of Fuel
Chemistry, 42, 498-502 (American Chemical Society, 1997).
[0007] For example, U.S. Pat. No. 6,359,047 discloses a gas hydrate
inhibitor. The inhibitor includes, by weight, a copolymer including
about 80 to about 95% of polyvinyl caprolactam (VCL) and about 5 to
about 20% of N,N-dialkylaminoethyl(meth)acrylate or
N-(3-dimethylaminopropyl)methacrylamide. As another example, U.S.
Pat. No. 5,874,660 discloses a method for inhibiting hydrate
formation. The method is used in treating a petroleum fluid stream,
such as natural gas conveyed in a pipe, to inhibit the formation of
a hydrate restriction in the pipe. The hydrate inhibitor used for
practicing the method is selected from the family of substantially
water soluble copolymers formed from N-methyl-N-vinylacetamide
(VIMA) and one of three comonomers, vinylpyrrolidone (VP),
vinylpiperidone (VPip), or vinylcaprolactam (VCap). VIMA/VCap is
the preferred copolymer. These copolymers may be used alone or in
combination with each other or other hydrate inhibitors.
Preferably, a solvent, such as water, brine, alcohol, or mixtures
thereof, is used to produce an inhibitor solution or mixture to
facilitate treatment of the petroleum fluid stream.
[0008] Another type of low dosage hydrate inhibitor (LDHI) uses
surface active agents (surfactants) that may function both as KHIs
and as AAs. AAs may prevent the agglomeration, or self-sticking, of
small hydrate crystals into larger hydrate crystals or groups of
crystals. For example, U.S. Pat. Nos. 5,841,010 and 6,015,929
disclose the use of surface active agents as gas hydrate inhibitors
for inhibiting the formation (nucleation, growth and agglomeration)
of clathrate hydrates. The methods comprise adding into a mixture
comprising hydrate forming substituents and water, an effective
amount of a hydrate inhibitor selected from the group consisting of
anionic, cationic, non-ionic and zwitterionic hydrate inhibitors.
The hydrate inhibitor has a polar head group and a nonpolar tail
group not exceeding 12 carbon atoms in the longest carbon chain.
The AAs may allow for the formation of a flowable slurry, i.e.,
hydrates that can be carried by a flowing hydrocarbon without
sticking to each other.
[0009] Although smaller dosages of LDHIs are generally used to
manage hydrates than for THIs, LDHIs may be expensive. At high
water quantities, these inhibitors may be uneconomical. Further,
AAs begin to lose their effectiveness at moderate water volumes
(greater than about 50 vol. %) because there is not enough liquid
hydrocarbon remaining in the system to transport the particles.
Further, research studies on system containing water in an
oil-external phase indicate that the addition of too low an amount
of inhibitor, either THI or KHI, may actually increase the
likelihood of plugging. See Hemmingson, P. V., Li, X. and Kinnari,
K, "Hydrate Plugging Potential in Underinhibited Systems", Proc. of
the 6th ICGH, Vancouver, Canada, Jul. 6-10, 2008. In the Hemmingson
system, the aqueous phase was about 20 volume % of the liquids in
liquid hydrocarbon. The results showed an increase in the plugging
potential for under-inhibited system which was attributed to
increased hydrate formation rates.
[0010] Related information may be found in U.S. Pat. Nos.
6,957,146; 5,936,040; 5,841,010; and 5,744,665. Further information
may be found in: U.S. Patent Application Publication Nos.
2004/0133531, 2006/0092766, 2008/0312478 and 2007/0129256; Sloan,
E. D., "Gas Hydrate Tutorial," Preprints from the Spring 1997
Meeting of the ACS Division of Fuel Chemistry, 42(2), 449-56
(American Chemical Society, 1997); and in Talley, L. D. and
Edwards, M., "First Low Dosage Hydrate Inhibitor is Field Proven in
Deepwater," Pipeline and Gas Journal 44, 226 (1999).
[0011] An alternative to the use of THIs and KHIs is cold flow
technology, in which hydrate can be formed in a manner that
prevents hydrate particles from sticking to each other without the
use of chemical inhibitors. International Patent Application
Publication No. WO 2007/095399 discloses a method of generating a
non-plugging hydrocarbon slurry. In one aspect, the method includes
seeding a cold-flow reactor before startup operation with dry
hydrate particles, creating a dry hydrate sidestream by diverting a
portion of wellstream of hydrocarbons into the reactor, wherein the
wellstream hydrocarbons contain water, and feeding the dry hydrate
sidestream into the main pipeline to be transported to a
destination with the full wellstream.
[0012] As another example, International Patent Application
Publication No. WO 2007/025062 discloses a method and system for
transporting a flow of fluid hydrocarbons containing water. In the
method and system, a pump is used to recycle a fluid containing
hydrate particles in a line back to a reactor. The pump may
advantageously be of a type which crushes the hydrate particles
into more and smaller particles.
[0013] Cold flow has been demonstrated to be successful in systems
where oil is the external phase in a water-oil system. The external
oil phase is important to this process since cold flow depends on
the generation of small water droplets that can be converted to
hydrate particles. Following hydrate formation sufficient liquid
should be present to mobilize the hydrate particles. Therefore, at
high water cuts, current cold flow strategies may be
inadequate.
[0014] At high water cuts, where the water phase is external,
uninhibited hydrate will continue to form until the water or the
gas is exhausted, which may lead to plugging. International Patent
Application Publication No. WO 2005/058450 discloses a method and
system for preventing clathrate hydrate blockage formation in flow
lines by adding water. In this method, water is added to a
hydrocarbon containing fluid to produce a water cut enhanced
hydrocarbon containing fluid. Sufficient water may be added such
that the hydrocarbon containing fluid is converted from a water in
oil emulsion to a water continuous emulsion. However, at large gas
production rates, the amount of water injected may be significant,
for example, similar to production rates. This may require the use
of large pumps and extra pipelines, as well as the production of
large quantities of additional water that would require treating
and disposal.
[0015] Hydrate formation is one of the most common flow assurance
issues. Hydrates that form in production pipelines can cause
blockages that shut-in production. As deepwater production
increases, the need to adequately handle hydrates is consequently
increasing. Also, as a field matures, it will produce more water. A
field may eventually produce primarily water which can limit
hydrate remediation strategies and often dictates the end of
profitable field production. Thus, research is continuing to
identify techniques for preventing hydrate plugging during
hydrocarbon transport.
SUMMARY
[0016] An exemplary embodiment of the present techniques provides A
method for forming a flowable hydrate slurry in a production fluid
that has water as an external phase. The method includes injecting
an amount of a thermodynamic hydrate inhibitor (THI) into the
production fluid, wherein the amount of the THI added is controlled
to allow a formation of a hydrate while retaining the water as the
external phase.
[0017] The method may also include monitoring a phase behavior of
the production fluid after the hydrate forms to determine that the
water is the external phase. The amount of the THI injected into
the production fluid may be adjusted to select the water as the
external phase. An anti-agglomerate agent (AA) may be added to the
production fluid. Further, a kinetic hydrate inhibitor (KHI) may be
added to the production fluid.
[0018] The THI may include glycols, alcohols, salts, or any
combinations thereof. The production fluid may be passed through a
static mixer after injecting the THI. The amount of the THI
injected into the production fluid may be less than about 5% by wt.
in the water phase before the formation of the hydrate.
[0019] Another exemplary embodiment provides a system for producing
a production fluid in which water is an external phase. The system
includes a pipeline configured to carry the production fluid and an
injector configured to inject an amount of a THI into the
production fluid, wherein the amount of the THI added will allow
the formation of the hydrate while retaining the water as the
external phase.
[0020] The system may include a static mixer in the pipeline
downstream of the injector. The system may also include an analyzer
to determine a phase behavior of the production fluid. An addition
system may be configured to change the amount of the THI added in
order to select the water as the external phase. A processing
facility may be configured to remove the water and the THI from the
production fluid. A processing facility configured to process the
hydrocarbon for shipping in a pipeline.
[0021] The system may include a hydrocarbon field configured to
produce the production fluid. The production fluid may include
natural gas. Further, the production fluid may include oil.
[0022] Another exemplary embodiment provides a method for producing
a hydrocarbon. The method includes producing a production fluid
having water as an external phase, and injecting an amount of a THI
into the production fluid, wherein the amount is adjusted to allow
hydrate formation to occur while retaining water as the external
phase. The method also includes separating out the water and the
THI from the production fluid and producing a purified hydrocarbon
stream.
[0023] The method may include monitoring a phase behavior of the
production fluid after the injection of the THI. Producing the
purified hydrocarbon stream may include producing a liquefied
natural gas. The THI may be separated from the water and reinjected
into a production fluid.
DESCRIPTION OF THE DRAWINGS
[0024] The advantages of the present techniques are better
understood by referring to the following detailed description and
the attached drawings, in which:
[0025] FIG. 1 is a diagram of a subsea natural gas field that can
be protected from hydrate plugging;
[0026] FIG. 2A is a diagram of THI molecules in a production fluid
having water as the external phase;
[0027] FIG. 2B is a diagram showing the increase in concentration
of the THI molecules as a hydrate forms;
[0028] FIG. 3 is a process flow diagram of a method for producing a
production fluid that has water as the external phase;
[0029] FIG. 4 is a graph of calculated equilibrium curves for a
hydrate formation at a series of THI levels; and
[0030] FIG. 5 is a graph that shows how the equilibrium temperature
changes as a function of the quantity of hydrate formed for the
system that is initially under-inhibited with 5 wt. % of THI.
DETAILED DESCRIPTION
[0031] 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.
[0032] 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.
[0033] As used herein, "clathrate" is a weak composite made of a
host compound that forms a basic framework and a guest compound
that is held in the host framework by inter-molecular interaction,
such as hydrogen bonding, Van der Waals forces, and the like.
Clathrates may also be called host-guest complexes, inclusion
compounds, and adducts. As used herein, "clathrate hydrate" and
"hydrate" are interchangeable terms used to indicate a clathrate
having a basic framework made from water as the host compound. A
hydrate is a crystalline solid which looks like ice, and forms when
water molecules form a cage-like structure around a
"hydrate-forming constituent."
[0034] A "hydrate-forming constituent" refers to a compound or
molecule in petroleum fluids, including natural gas, that forms
hydrate at elevated pressures and/or reduced temperatures.
Illustrative hydrate-forming constituents include, but are not
limited to, hydrocarbons such as methane, ethane, propane, butane,
neopentane, ethylene, propylene, isobutylene, cyclopropane,
cyclobutane, cyclopentane, cyclohexane, and benzene, among others.
Hydrate-forming constituents can also include non-hydrocarbons,
such as oxygen, nitrogen, hydrogen sulfide, carbon dioxide, sulfur
dioxide, and chlorine, among others.
[0035] "Exemplary" is used exclusively herein to mean "serving as
an example, instance, or illustration." Any embodiment described
herein as "exemplary" is not to be construed as preferred or
advantageous over other embodiments.
[0036] A "facility" as used herein is a representation of a
tangible piece of physical equipment through which hydrocarbon
fluids are either produced from a reservoir or injected into a
reservoir. In its broadest sense, the term facility is applied to
any equipment that may be present along the flow path between a
reservoir and the destination for a hydrocarbon product. Facilities
may comprise production wells, injection wells, well tubulars,
wellhead equipment, gathering lines, manifolds, pumps, compressors,
separators, surface flow lines and delivery outlets. In some
instances, the term "surface facility" is used to distinguish those
facilities other than wells. A "facility network" is the complete
collection of facilities that are present in the model, which would
include all wells and the surface facilities between the wellheads
and the delivery outlets.
[0037] A "formation" is any finite subsurface region. The formation
may contain one or more hydrocarbon-containing layers, one or more
non-hydrocarbon containing layers, an overburden, and/or an
underburden of any subsurface geologic formation. An "overburden"
and/or an "underburden" is geological material above or below the
formation of interest.
[0038] The term "FSO" refers to a Floating Storage and Offloading
vessel. A floating storage device, usually for oil, is commonly
used where it is not possible or efficient to lay a pipe-line to
the shore. A production platform can transfer hydrocarbons to the
FSO where they can be stored until a tanker arrives and connects to
the FSO to offload it. A FSO may include a liquefied natural gas
(LNG) production platform or any other floating facility designed
to process and store a hydrocarbon prior to shipping.
[0039] The term "gas" is used interchangeably with "vapor," and
means a substance or mixture of substances in the gaseous state as
distinguished from the liquid or solid state. Likewise, the term
"liquid" means a substance or mixture of substances in the liquid
state as distinguished from the gas or solid state. As used herein,
"fluid" is a generic term that may include either a gas or
vapor.
[0040] 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 organic materials that are transported by pipeline, such
as any form of natural gas or oil. A "hydrocarbon stream" is a
stream enriched in hydrocarbons by the removal of other materials
such as water and/or THI.
[0041] "Kinetic hydrate inhibitor" refers to a molecule and/or
compound or mixture of molecules and/or compounds capable of
decreasing the rate of hydrate formation in a petroleum fluid that
is either liquid or gas phase. A kinetic hydrate inhibitor can be a
solid or liquid at room temperature and/or operating conditions.
The hydrate formation rate can be reduced sufficiently by a kinetic
hydrate inhibitor such that no hydrates form during the time fluids
are resident in a pipeline at temperatures below the hydrate
formation temperature.
[0042] For the inhibition of hydrate formation by thermodynamic or
kinetic hydrate inhibitors, the term "minimum effective operating
temperature" refers to the temperature above which hydrates do not
form in fluids containing hydrate forming constituents during the
time the fluids are resident in a pipeline. For thermodynamic
inhibition only, the minimum effective operating temperature is
equal to the thermodynamically inhibited hydrate formation
temperature. For kinetic hydrate inhibitors, the minimum effective
operating temperature is lower than the thermodynamically inhibited
hydrate formation temperature. For a combination of thermodynamic
and kinetic inhibition, the minimum effective operating temperature
may be even lower than the thermodynamically inhibited hydrate
formation temperature by itself.
[0043] "Liquefied natural gas" or "LNG" is natural gas that has
been processed to remove impurities (for example, nitrogen, water
and/or heavy hydrocarbons) and then condensed into a liquid at
almost atmospheric pressure by cooling and depressurization.
[0044] The term "natural gas" refers to a multi-component gas
obtained from a crude oil well (termed associated gas) or from a
subterranean gas-bearing formation (termed non-associated gas). The
composition and pressure of natural gas can vary significantly. A
typical natural gas stream contains methane (CH.sub.4) as a
significant component. Raw natural gas will also typically contain
ethylene (C.sub.2H.sub.4), ethane (C.sub.2H.sub.6), other
hydrocarbons, one or more acid gases (such as carbon dioxide,
hydrogen sulfide, carbonyl sulfide, carbon disulfide, and
mercaptans), and minor amounts of contaminants such as water,
nitrogen, iron sulfide, wax, and crude oil.
[0045] "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
gage 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).
[0046] "Production fluid" refers to a liquid and/or gaseous stream
removed from a subsurface formation, such as an organic-rich rock
formation. Produced fluids may include both hydrocarbon fluids and
non-hydrocarbon fluids. For example, production fluids may include,
but are not limited to, oil, natural gas and water.
[0047] "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.
[0048] "Thermodynamic hydrate inhibitor" refers to compounds or
mixtures capable of reducing the hydrate formation temperature in a
petroleum fluid that is either liquid or gas phase. For example,
the minimum effective operating temperature of a petroleum fluid
can be reduced by at least 1.5.degree. C., 3.degree. C., 6.degree.
C., 12.degree. C., or 25.degree. C., due to the addition of one or
more thermodynamic hydrate inhibitors. Generally the THI is added
to a system in an amount sufficient to prevent the formation of any
hydrate.
[0049] "Well" or "wellbore" refers to a hole in the subsurface made
by drilling or insertion of a conduit into the subsurface. The
terms are interchangeable when referring to an opening in the
formation. A well may have a substantially circular cross section,
or other cross-sectional shapes (for example, circles, ovals,
squares, rectangles, triangles, slits, or other regular or
irregular shapes). Wells may be cased, cased and cemented, or
open-hole well, and may be any type, including, but not limited to
a producing well, an experimental well, an exploratory well, or the
like. A well may be vertical, horizontal, or any angle between
vertical and horizontal (a deviated well), for example a vertical
well may comprise a non-vertical component.
Hydrate Inhibition in a Production System by Limited THI
Addition
[0050] As previously noted, the formation of hydrates can be a
problem in the harvesting and transportation of hydrocarbons. For
example, production fluids harvested from a formation may contain a
substantial amount of water, which may increase over time as the
hydrocarbons in the formation are produced. A production fluid
containing a high amount of water may be termed a high water cut,
and may have water as the continuous, or external, phase, with
hydrocarbons forming droplets or bubbles in the water phase. The
production fluid from the formation may be at a sufficiently high
temperature that hydrate formation is not favored, but cooling of
the production fluid during production or shipping may allow
formation of hydrates and plugging of lines.
[0051] An exemplary embodiment of the present techniques provides a
method for generating a flowable hydrate slurry in a water external
mixture of water and hydrocarbon, such as at a high water cut. This
can be performed by controlling the hydrate concentration through a
limited addition of thermodynamic hydrate inhibitor (THI). During
formation, the hydrate incorporates a host molecule, such as a
hydrocarbon or other molecule, but may exclude impurities that may
be dissolved in the water. As the THI is an impurity in the water
with respect to the hydrate, formation of the hydrate increases the
concentration of the THI in the remaining water. When the
concentration of the THI in the water reaches a sufficient
quantity, further hydrate formation will be inhibited. In a water
external system, this may result in the formation of a flowable
slurry of hydrates in water, carrying the hydrocarbon droplets to
the destination.
[0052] FIG. 1 is an illustration of a subsea natural gas field 100
that can be protected from hydrate plugging. However, the present
techniques are not limited to subsea fields or natural gas
harvesting, but may be used for the mitigation of plugging in the
production or transportation of oil, oil from oil sands, natural
gas, or any number of liquid or gaseous hydrocarbons from any
number of sources.
[0053] As shown in FIG. 1, the natural gas field 100 can have a
number of wellheads 102 coupled to wells 104 that harvest natural
gas from a formation (not shown). As shown in this example, the
wellheads 102 may be located on the ocean floor 106. Each of the
wells 104 may include single wellbores or multiple, branch
wellbores. Each of the wellheads 102 can be can be coupled to a
central pipeline 108 by gathering lines 110. The central pipeline
108 may continue through the field 100, coupling to further
wellheads 102, as indicated by reference number 112. A flexible
line 114 may couple the central pipeline 108 to a collection
platform 116 at the ocean surface 118. The collection platform 116
may, for example, be a floating processing station, such as a
floating storage and offloading unit (or FSO), that is anchored to
the sea floor 106 by a number of tethers 120. The collection
platform 116 may have equipment for dehydration, purification, and
other processing, such as liquefaction equipment to form liquefied
natural gas (LNG) for storage in vessels 122. The collection vessel
116 may transport the processed gas to shore facilities by pipeline
(not shown).
[0054] Prior to processing of the natural gas on the collection
platform 116, the collected gas may cool and form hydrates in
various locations, such as the collection pipeline 108, the
gathering lines 110, or the flexible line 114, among others. The
formation of the hydrates may lead to partial or even complete
plugging of the lines 108, 110, and 114. Similarly, in on-shore
fields, hydrates can plug wells, gathering lines, and collection
lines. A THI may be added to mitigate the formation of hydrates,
for example, from the collection vessel 116 by a line 124 to one or
more injection points, such as at injector 126. Although the line
124 is shown as being independent of the flexible line 114, the
line 124 may be incorporated along with the flexible line 114 and
any other utility or sensor lines into a single piping bundle. In
various embodiments, the injector 126 may be located on the
collection pipeline 108, the gathering lines 110, the flexible line
114, or on any combinations thereof.
[0055] In an exemplary embodiment, the THI is injected into the
collection line 108 in an amount that is less than required to
completely inhibit the formation of hydrates. For example, although
the amount needed to fully inhibit hydrate formation may be 10%,
20%, 30%, 50%, or higher, by weight of the water phase in the
production fluid, depending on the water cut, the amount of THI
injected in embodiments may be only 15%, 10%, 5%, or lower, by
weight of the water phase in the production fluid. As discussed
below, the formation of hydrates concentrates the THI, which
remains in the water phase.
[0056] The amount of THI to be used may be determined by analyzing
or monitoring the water content of the production fluid. The amount
may be controlled so that the production fluid is still in a water
external condition at the point where the THI is concentrated
enough to inhibit further formation of hydrates. One or more static
mixers 128 can be placed in the lines, for example, in the
collection line 108 downstream of the entry points 130 for each of
the gathering lines 110. The placement of the static mixers 128 is
not limited to the collection line 108, as static mixers 128 may be
placed in the flexible line 114, the gathering lines 110, the
wellheads 102, or even down the wells 104. Placing a THI line 124
and an injector 126 down a well, for example, upstream of a static
mixer 128, may be useful for mitigating hydrate formation in
wellbores.
[0057] The phase behavior of the production fluid brought up the
flexible line 114 from the connection pipe 108 may be monitored,
for example, by an analyzer 132 located at the collection vessel
116 or at any number of other points in the natural gas field 100.
The analyzer 132 may determine the concentration of the hydrate,
the concentration of the external phase in the production fluid,
the amount of hydrocarbon present, or any combinations of these
parameters. For example, a particle size analyzer may be included
to analyze the different refracting items in the production fluid,
such as the hydrate particles and the hydrocarbon droplets. The
output from the analyzer 132 may be used to control an addition
system 134, which may be used to adjust the amount of THI, as well
as other additives, sent to the injector 126. In an exemplary
embodiment, the configuration discussed above may be used to
control the phase behavior by controlling the amount of THI
injected in order to select the water as the external phase. The
arrangement of the facility network is not limited to that shown in
FIG. 1, as any number of configurations may be used.
Hydrate Formation Concentrating a Thermodynamic Hydrate
Inhibitor
[0058] FIG. 2A is an illustration 200 of THI molecules 202 in a
production fluid having water as the external phase. In the
illustration 200, the THI molecules 202, such as methanol, are
dissolved in a water phase 204. A hydrocarbon phase 206 can be
carried as droplets or bubbles in the water phase 204.
[0059] FIG. 2B is an illustration 208 showing the increase in
concentration of the THI molecules 202 as a hydrate forms. The THI
molecules 202 may be excluded from the hydrate particle 210 as it
forms, and, thus, the THI molecules 202 may consequently be
concentrated in the water phase 204. As the concentration of the
THI molecules 202 increases, the hydrate subcooling may be
decreased, eventually preventing additional growth or formation of
hydrate particles 210. As nucleation time can be inversely
correlated with subcooling, the residence time prior to hydrate
nucleation will also be increased. Accordingly, the THI may also be
performing as a weak KHI.
[0060] Under certain concentration conditions, such as in an
external water phase 204, the hydrate particles 210 may be
flowable, since capillary attractive forces between hydrate
particles 210 may not be present in a dispersion in the water phase
204. Flowloop tests have indicated that rapid hydrate formation
without sufficient shear may cause increased potential for
blockages, possibly due to the formation of water bridges between
hydrate particles 210. The water bridges may be converted to
hydrate, which can cementing the bridged hydrate particles 210
together. In an external water phase 204, these water bridges may
not occur.
[0061] However, the hydrocarbon phase 206 is also concentrated by
the formation of hydrate particles 210 in the water phase 204. In
an exemplary embodiment of the present techniques, the phase
behavior of the system is monitored and controlled to keep an
external water phase 204, as a phase inversion to an oil external
phase may lead to formation of hydrate agglomerates and the
plugging of lines.
[0062] In an exemplary embodiment, the use of limited thermodynamic
inhibitors can be combined with limited amounts of anti-agglomerate
(AA) to aid in keeping the hydrate particles 210 separated. Smaller
quantities of each class of inhibitor may be needed as a result of
the concentration by the formation of the hydrate particles
210.
[0063] FIG. 3 is a flow chart of a method 300 for producing a
production fluid that has water as an external phase. The method
300 begins at block 302 with the production of a production fluid
having water as the external phase. Such a stream may result late
in the life of a hydrocarbon field, when high water cuts (such as
20%, 40%, 50%, 60%, 80%, or more, by weight of the production
fluid) may be produced. Depending on the chemical composition of
the hydrocarbon, a water external phase may result even at
relatively low water concentrations, such as at 20% by weight of
the production fluid or even lower. At block 304, a thermodynamic
hydrate inhibitor can be injected into the production fluid. As
discussed above, the amount of THI injected may be determined by an
analysis of the water and hydrocarbon amounts in the production
fluid, so that water remains as the external phase. For example,
the amount injected may be about 5%, 10%, 15%, or more, by weight
of the water phase in the production fluid.
[0064] At block 306, the concentration of the phases and hydrate
particles in the production fluid may be monitored by an analyzer.
At block 308, the amount of THI added to the stream can be adjusted
based on the results from the analysis. This control may be used,
for example, to prevent phase inversion of the system into an oil
external phase, which may result in plugging of the lines. At block
310, the water, which generally includes the hydrophilic THI is
separated from the hydrocarbon, and any further processing of the
hydrocarbon is performed, such as the purification, cooling, and
condensation used to produce LNG.
Example of Concentration of THI Limiting Further Hydrate
Formation
[0065] FIG. 4 is a graph 400 of calculated equilibrium curves for a
hydrate formation at a series of THI levels. The x-axis 402
represents the temperature of the composition in degrees
Fahrenheit, while the y-axis 404 represents the pressure of the
system in psia. The calculations were performed for a gas with
composition of 90% CH.sub.4, 5% C.sub.2H.sub.6, 4% C.sub.3H.sub.8,
and 1% n-C.sub.4H.sub.10, which is in a hydrate stabile region 406
at about 900 psia and about 50.degree. F. (assuming less than about
16% methanol), as indicated at point 408. In the graph 400, the gas
is assumed to be in contact with any amount of water containing the
weight percentage amount of methanol shown.
[0066] Equilibrium curves for four different concentrations of the
THI, methanol, are shown in the graph 400: 0 wt. % 410 in the water
phase, 10 wt. % 412 in the water phase, 20 wt. % 414 in the water
phase, and 30 wt. % 416 in the water phase. As can be seen from
these curves, thermodynamic inhibition of the formation of hydrate
at point 408 would require a concentration of methanol greater than
about 16 wt % in the water phase. As the concentration of
thermodynamic inhibitor in water increases, the hydrate subcooling
is more significant such as is shown in FIG. 5 for a gas
composition of 90% CH4, 5% C2H6, 4% C3H8, and 1% n-C4H10.
[0067] FIG. 5 is a graph 500 that shows how the equilibrium
temperature changes as a function of the quantity of hydrate formed
for the system that is initially under-inhibited with 5 wt. % THI.
In the graph 500, the x-axis 502 represents the fraction of hydrate
formed. The first y-axis 504 shows the hydrate equilibrium
temperature, i.e., the temperature below which the formation of
hydrate is favored. The second y-axis 506 shows the amount of
subcooling in the system, i.e., the difference between the hydrate
equilibrium temperature 504 and the ambient temperature 508. The
third y-axis 510 shows the methanol concentration in the water
phase as hydrate is formed.
[0068] As shown in the graph 500, the hydrate subcooling
temperature 512 (read on the second y-axis 506) decreases as
hydrate is formed. This is caused by the concurrent increase in the
methanol concentration 514 (read on the third y-axis 510) in the
water phase as the hydrate forms. As discussed previously, the
increase in concentration is caused by the exclusion of methanol
from the hydrate particles. When the hydrate fraction reaches 11
wt. %, as indicated at reference number 516, the hydrate subcooling
temperature 512 reaches zero, and no additional hydrate is formed.
As indicated by dotted line 518, this is the point at which the
inhibitor concentration in the water phase reaches 16 wt. %, which
inhibits further hydrate formation.
[0069] While the present techniques may be susceptible to various
modifications and alternative forms, the exemplary embodiments
discussed above have been shown only by way of example. However, it
should again be understood that the techniques are 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.
* * * * *