Note: Descriptions are shown in the official language in which they were submitted.
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INJECTION SYSTEM FOR ENHANCED OIL RECOVERY
FIELD OF THE INVENTION
[0001] The invention relates generally to mobile systems and methods for
delivering
additives to high pressure gas lines used in enhanced oil recovery (EOR). More
specifically, the
invention relates to mobile systems and methods for the dispensing of
surfactant into high
pressure CO2 streams used for enhanced oil recovery applications.
BACKGROUND OF THE INVENTION
[0002] . Enhanced oil recovery (EOR) has become a significant industry
practice in the last
twenty years. Of all the known FOR techniques, CO2 injection is more popular
due to high
displacement efficiency of CO2. Unfortunately even when in a supercritical
state, CO2 has a low
viscosity and suffers from poor conformance, mobility, and ultimately low
sweep efficiency.
One method that has been developed to alleviate this problem is the use of
surfactants to
emulsify the supercritical CO2 in water (brine) as an emulsion. This creates
an apparent viscosity
in the CO2 and improves the mobility and conformance of the CO2 as it
propagates through the
strata in an oil field.
[0003] Although much work has been done to determine the best surfactants and
injection
strategies, little has been published on how to implement supercritical CO2
surfactant foam
solutions. Several key problems arise in the economical implementation of
these techniques. For
instance, one method of implementing this solution is to utilize a CO2 soluble
surfactant injected
directly into the CO2 line. Most CO2 injection lines are maintained at 1500-
2500 psi and have
variable rates of flow. A complex high-pressure pump and delivery system is
needed to
accommodate these variables. Further given that these surfactants are
generally added on an
alternating cycle, the system is only utilized for short amounts of time on a
given well. This adds
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to the complexity of the operation, and is also an inefficient, i.e. a costly,
application of
equipment.
[0004] Some examples of prior processes and machines include W02008081048
which
describes a system for another form of enhanced oil recovery, alkaline
surfactant polymer (ASP)
flooding. A new grinding apparatus for improving the dissolution time of the
polymer is
provided. W02008071808 describes an entire system for implementing an ASP
solution in the
field. W02007011812 describes a mobile unit for another method of FOR by
nitrogen flooding.
The unit is comprised of a nitrogen generating unit and a pumping system that
can deliver the
generated nitrogen to the wellbore. Further it teaches the pumping of other
well fluids
concurrently with the nitrogen. US2004/034521 describes a three in one
nitrogen, chemical,
coiled tubing system on a mobile unit. U.S. Patent No. 6702011 describes a
mobile unit for
delivery of nitrogen through coiled tubing.
[0005] Thus there is a need for a mobile technology which enables the
injection of surfactant
at a controlled concentration into a high pressure stream of liquid or
supercritical C02-
SUMMARY OF THE INVENTION
[0006] In accordance with one aspect of the invention, there is provided an
enhanced oil
recovery apparatus for creating a wellbore fluid comprising supercritical CO2
and a surfactant.
The apparatus comprises a storage tank for containing a surfactant which is
injected into the CO2
stream, a pump for delivering surfactant to the CO2 stream, means for
injecting the surfactant
into the CO2 stream, and a feedback control for maintaining a constant
concentration of
surfactant in the supercritical CO2 stream.
[0007] In accordance with a further aspect of the invention there is provided
a method of
enhancing oil recovery by creating a wellbore fluid for injection into an oil
field by a mobile
enhanced oil recovery apparatus comprising a storage tank, means for injecting
surfactant into
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the supercritical CO2 stream, and a feedback control for maintaining a
constant concentration of
surfactant in the supercritical CO2 stream. The method comprises the steps of
transmitting a
surfactant to the injection pipe, injecting the surfactant into a
supercritical CO2 stream at a
controlled rate, creating a wellbore fluid comprising the CO2 and the
surfactant, and injecting the
wellbore fluid into the oil field. In the context of the invention, the
wellbore fluid comprises the
surfactant and a gas. The gas may be any number of gases commonly used for
this purpose.
Supercritical carbon dioxide is used as an example in the specification. In
this context it should
also be understood that the carbon dioxide may also be liquefied.
[0008] The invention provides a mobile method of delivering additives into
high pressure
supercritical CO2 streams that can be employed as needed in the field. More
specifically the
invention relates to a mobile unit encompassing one or more surfactant storage
tanks, high
pressure pumps, a feedback control system for maintaining the desired
surfactant injection rate
based on the flow rate of the CO2, a pressure relief system, heated surfactant
storage, injection
line and high pressure connection devices, and an electric generator, and fuel
container. The
surfactant may be thermally treated up to the point at which it is injected
into the stream of
supercritical CO2.
[0009] Mobility, whether on land or at sea, is a great advantage to the
claimed invention.
Numerous benefits are provided, for example, prior to deployment to a new
injection well
location, this equipment can be loaded with fuel and surfactant at a central
storage facility then
deployed for the desired length of time on the given well. This significantly
reduces the cost of
large scale implementation of equipment dedicated to each and every injection
well, and it
minimizes environmental risks by, for example, conducting fuel and surfactant
replenishment at
a central, fit for purpose transload facility.
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BRIEF DESCRIPTION OF THE FIGURES
[0010] Figures 1A through ID are schematic depictions of a method of injecting
a wellbore
fluid into an oil field in accordance with one embodiment of the invention.
[0011] Figure 2 is a schematic depiction of one embodiment of the invention
depicted in
Figure 1 as alternatively shown as a mobile unit.
[0012] Figure 3 is a graphical representation of the injection rate of CO2
versus time, for two
CO2 injection cycles.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0013] As can be seen in Figures IA through 1D, wherein all numbers designate
like parts
throughout several views of the invention there is shown one embodiment of a
method of
enhancing oil recovery by creating a wellbore fluid for injection into an oil
field by a mobile
enhanced oil recovery apparatus. The apparatus comprises a storage tank 12,
means for injecting
fluid 14 into a gas stream, and a pump having a feedback control for
maintaining a constant
concentration of fluid in a gas stream 16, Fig. 113. The apparatus may also
comprise a fuel tank
20. The various elements of the apparatus of the invention may be
interconnected by any number
of tubing and piping systems.
[0014] As can be seen in Figure 1 A, tubing, piping and hose may be used in
accordance with
the invention. Inner diameters may range from less than an inch to two inches
or greater. Also,
the tubing, piping or hose may be heated or cooled as necessary to prepare the
surfactant for
injection.
[0015] The method comprises the steps of injecting a surfactant into a
supercritical CO2
stream at a controlled rate creating a wellbore fluid comprising the
supercritical CO2 and
surfactant and injecting the fluid into the oil field.
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Containment
[0016] Generally, the invention comprises one or more containment vessels 12,
Figure 1A.
The function of the container is to store surfactant. The container may also
function to provide a
site for processing the surfactant. Processing in this context means heating,
cooling, agitating,
pressurizing, etc. The containers may also be used as a site for the addition
of any other
constituents which may be desired to be intermixed with the surfactant.
[0017] To this end, the container may take any number of shapes and sizes.
Some
considerations which are relevant to the size and shape of the containment
vessel include
transportability, discharge and refill, material of construction, pressure
relief protection, the
overall function of the tank (containment and/or mixing), and the necessity
for thermal
processing among other factors.
[0018] Using a container that is portable enables transport. Consideration has
to be given to
the means of transport (for example rail or truck). The practical limitations
of highway and rail
line passage limit the size of certain containment vessels. Additionally,
government regulations
dictate that certain fill volume restrictions during transport also need to be
complied with.
[0019] The size and shape of the vessel may also be determined by the use
level of surfactant
at the site of injection. Presently, vessels ranging in size from about 300
gallons to 36,000
gallons have been contemplated for use. Generally, containers of the size of
about 500 to 6,000
gallons have been found most desirable. Containment vessels which provide
agitation (stirring),
heating and/or cooling may also be useful in accordance with the invention.
When applying any
type of thermal affect to a container, the size of the container has to be
considered. Mixing times
are also relevant. Heating may be conducted through use of resistance
elements. Alternatively,
closed loop heating and cooling systems may be used for circulating
coolant/refrigerants or
heating fluids.
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[0020] Containment vessels which are preferred include portable containers
that may be on
and off loaded from any number of wheeled vehicles including flat bed trailers
and railcars,
Figure 2. These types of containers are widely regarded as "isotainers" and
can take any number
of shapes, styles, and sizes.
Surfactant Infection
[0021] The invention comprises a surfactant injection system 14, Figure I C.
Generally the
surfactant injection system comprises an injection quill. The purpose of the
injection quill is to
facilitate mixing between the two process fluids, in this case surfactant and
supercritical C02,
delivered by the main header pipe and the quill. The quill generally injects
surfactant at the
center of the main header pipe in the form of a solid jet or spray. This
processing of fluids (such
as gases and/or supercritical liquids) allows the scCO2 and surfactant to mix
thoroughly.
[0022] Generally, quills useful in the invention are those commercially
available from any
number of known sources. Materials used in the manufacture of quills tend to
be alloys such as
high alloy steel, carbon steel and stainless steel including Iconel , Incolloy
, and Hastelloy .
Relevant considerations in choosing quills of any different material include
corrosion resistance,
thermal properties, acid resistance, flame resistance and overall strength.
Material to these
concerns are the types of fluids to be dispensed and the rate at which these
fluids are dispensed
from the quill.
[0023] Quills which have been found useful in accordance with the invention
include Kenco
Injectors such as models KINJ, and KINJM. The fluid velocity should be less
than that which
will damage the quill. For example, to avoid damage to the quill, fluid
velocity in a 2" line
should remain below 900 gals/min (assuming a 3" length from thread to tip). A
common set of
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injection well parameters includes about 7000 bpd water in a 2" line with a
flow rate of about
204 gals/min. With 20 MMscfd of CO2 in a 2" line, the flow rate is about 200
gals/min.
[0024] An exemplary surfactant injection rate through a Kenco injector is
about 240 gph. At
a surfactant concentration of about 0.1 wt-%, and a supercritical CO2 rate of
20 MMscfd, the
quantity of surfactant injected will be approximately 13 gph.
[0025] Generally, the quill may be installed in relationship to the main
header pipe in any
number of fashions. Preferably, the quill is installed in the first %2 inch
tie point upstream of the
wellhead, prior to any flowline disruptions such as inline screens or inline
chokes. Generally,
quills such as Kenco KINJ-50 (1/2" NPT), -S6 (316 SS Steel), -L2 (2" length)
and Kenco KINJ-
S6-L3 have been found useful at this location. Generally, the quill length
with a tip that most
closely centers in the header pipe is preferred. Generally, the preferred
quill is installed with a
preferred orientation with the longest side of the quill upstream and with the
quill tip at the
center of the CO2 line.
[0026] As shown in Figure I C, the quill is used to mix surfactant with
supercritical CO2. It is
contemplated that the quill may be positioned in accordance with the invention
in any number of
configurations. For example, the quill may be positioned proximate the well
head to inject
surfactant into the supercritical CO2 as close as possible to the wellhead.
Alternatively, the quill
may be positioned up stream from the wellhead, causing additional mixing of
the surfactant with
supercritical CO2 well before the mixture enters the production/injection
tubing. Also, as
contemplated quills can be installed, either permanently or temporarily, at
each well and can be
connected to the pumping system when required. The quill does not need to be
transported with
the truck. In instances where more than one well is fed by a single tank 12,
multiple lines may be
used through multiple quills 14.
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Flow Control
[0027] In one further aspect of the invention, an embodiment of the mobile FOR
apparatus is
provided which comprises a surfactant flow controller 16. The surfactant flow
controller 16
functions to monitor and maintain the flow of the surfactant into the
supercritical C02-
[0028] Flow of the supercritical CO2 may vary or otherwise occur at an
intermittent rate.
Accordingly, to provide a wellbore fluid having a constant concentration of
surfactant and
supercritical CO2 for permeating the oil field strata, the flow rate of the
surfactant injected into
the supercritical CO2 need also be varied accordingly. Any number of devices
may be used
which provide this function.
Typical devices monitor surfactant flow rates in parts per million of flow
rate and allow manual
or automatic entry of set points. Any variety of flow meters may be used with
the invention. The
surfactant injection flow meters require a CO2 flowrate signal from the
supercritical CO2 header
in order to ratio the surfactant in the proper concentration to the varying
rate of supercritical CO2
being delivered to the well. The calibration procedure for such a unit is
known to those of skill in
the art. The surfactant flow rate will be dependent upon the supercritical CO2
flow rate. Two
useful flow controllers are those produced and sold by Baker Hughes under the
Sentry II and
Sentry Net 3 trademarks.
Pump and Power Supply
[0029] The invention also comprises a pump 16 and a source of power such as a
generator
18, Figure 1D. Any type of pump may be used which is capable of providing
pressure ranging
from about 1000 psi to 3500 psi. The power source powers the surfactant
injection pumps
injecting the surfactant into the gas stream through the quill. Any type of
generator may be used
depending upon portability, power requirements, refueling, and running time,
among other
factors.
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[0030] One generator which has been found useful is the 36 KW diesel powered
generator
made by Mulitquip Inc (supplied by Carrier). When fueled this generator weighs
over 4000 lbs
and consumes fuel at 2.7 gph @ 100% prime. A generator such as this usually
has an internal
fuel tank and may be provided with an auxiliary tank for less frequent
resupply. In operation, the
generator may provide from about 240 volts to about 480 volts at currents
ranging from about
108 amps to 54 amps.
PROCESSING & EXPERIMENTAL
[0031] To enhance the effectiveness of the supercritical CO2 flooding process,
it has been
suggested that a surfactant be added to the supercritical carbon dioxide to
generate a foam in the
formation. A foam can generate an apparent viscosity of about 100 to about
1,000 times that of
the injected gas. Therefore, the foam can inhibit the flow of the
supercritical CO2 into that
portion of the oil reservoir that has previously been swept. In other words,
the foam can serve to
reduce the tendency for the supercritical CO2 to channel through highly
permeable flissures,
cracks, or strata, and direct it toward previously unswept portions of the
subterranean formation.
As such, the foam can force the supercritical CO2 to drive the recoverable
hydrocarbons from the
less depleted portions of the reservoir toward the production well.
[0032] Nonionic surfactants are usually organic compounds that are
amphiphilic, meaning
they contain both hydrophobic groups (alkylated phenol derivatives, fatty
acids, long-chain
linear alcohols, etc.) and hydrophilic groups (generally ethylene oxide,
propylene oxide and/or
butylenes oxide chains of various lengths), therefore they can be soluble in
both organic solvents
(non-polar) and polar solvents such as water. For example, the nonionic
surfactants useful in the
invention can lower the interfacial tension between carbon dioxide (such as
carbon dioxide in a
supercritical state) and water. Nonionic surfactants are capable of dissolving
in scCO2 in dilute
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concentrations, where they can help to stabilize carbon dioxide-in-water
emulsions and/or foams
(referred to herein as "foam"), discussed herein.
[0033] Examples of nonionic surfactants for the present disclosure include,
but are not
limited to, branched alkyphenol alkoxylates, linear alkylphenol alkoxylates,
and branched alkyl
alkoxylates. Specific examples of such nonionic surfactants can be found in
"C02-Souble
Surfactants for Improved Moblity Control" authored by Xing et al. (Society of
Petroleum
Engineers, SPE 129907, presented at the 2010 SPE Improved Oil Recovery
Symposium, Tulsa
OK, 24-28 April 2010), which is incorporated herein by reference in its
entirety.
[0034] In one or more embodiments, examples of surfactants useful with the
present
disclosure can also be found in U.S. Pat. Nos. 6,686,438 to Beckman and
5,789,505 to
Wilkinson, and the U.S. Pat. Application entitled "Compositions for Oil
Recovery and Methods
of Their Use," U.S. Pat. Application Serial No. 61/196,235, which are
incorporated herein by
reference.
[0035] Generally this surfactant may be stored at the site of use in a
containment vessel 12.
In storage, the surfactant may be in solution ranging in concentration from
about 40 wt-% to 100
wt-%. Depending upon the ambient temperature of application any number of
diluents may be
used to protect the surfactant from freezing. If an appropriate diluent is not
used for the ambient
conditions, it may be necessary to provide auxiliary heating to the surfactant
storage vessel and
any lines through which the surfactant flows to avoid freezing. For example,
diluents may be
used to adjust the freeze point of the surfactants to range from about -40 F
to 50 F.
[0036] While the rate of injection of the surfactant into the scCO2 stream may
vary,
generally, surfactant is injected into the scCO2 stream at a rate creating a
concentration of liquid
(surfactant) in the wellbore fluid ranging from about 100 to 5,000 ppm.
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[0037] The injection system that will be utilized will be flexible in its
surfactant volume
capability. It should be designed to pump surfactant in varying concentrations
to allow for
reservoir respouse. In one example, at the minimum expected CO2 rate of
7MMscfd, up to 3
times the recommended surfactant concentration can be delivered.
[0038] One example of a scheme for correctly determining the pump sizing for a
given
injection well is provided in Table 1 in the figure below.
[0039] The table lists the gallon per hour rates that need to be delivered to
the C02 stream to
maintain the desired concentration in ppm. The maximum C02 flow rate of the
injection well as
well as the expected minimum rate will determine the range of pump rates
necessary. As is
understood in the art the C02 rate is determined based on standard temperature
and pressure, and
the surfactant concentration may need to be adjusted for diluents. This table
is an example and
other flow rates and concentrations are not excluded.
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[0040] On the graph in Figure 3 the injection rate of C02 is plotted vs time
for two C02
injection cycles in the same injection well following injections of water of
equal length for
comparison. The top line is typical of the C02 response after a water cycle.
The C02 rate
quickly increases upon switching and then gradually ascends over the course of
about 10 days to
plateau.
[0041] The lower line shows the effect of the foam/emulsion surfactant in
accordance with
the inventions. By injecting 1200 ppm of surfactant in the CO2 the injection
rate starts off by
decreasing as the foam bank is established. Then a very slow steady rise
occurs in the injectivity
as the foam is propagated away from the well bore in a radial fashion. The
variability in CO2
injection rate is also evident from the graph on Figure 3.
[0042] Although the present invention has been described by reference to its
preferred
embodiment as is disclosed in the specification and drawings above, many more
embodiments of
the present invention are possible without departing from the invention. Thus,
the scope of the
invention should be limited only by the appended claims.
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