BACKGROUND OF THE INVENTION
[0001] The invention relates to a method for an integrated system for acid gas-lift and
Enhanced Oil Recovery(EOR) by miscible or sub-miscible displacement from a crude oil
containing formation by injecting acid gas into the formation.
[0002] US patent 5,337,828 discloses a method of using CO
2 for gas lifting heavy oil, wherein the CO
2 is injected into an heavy crude oil production well through an injection conduit
arranged within a crude oil production tubing within the well, thereby avoiding injection
of CO2 into an annulus between the production tubing and well casing and inhibiting
formation of a corrosive mixture of CO2 and water within the annulus.
[0003] It is also known to inject acid gas at high pressure into a crude oil containing
formation to enhance oil recovery from the formation by miscible or sub-miscible displacement.
Enhanced Oil Recovery (EOR) projects using miscible gas, such as CO
2 and/or H
2S, for injection usually require the production of reservoirs at high watercuts. Flowing
producers under these conditions require some form of artificial lift (e.g. electric
submersible pumps (ESPs), hydraulic submersible pumps (HSPs), jet pumps or gas lift).
[0004] In CO
2 EOR projects, CO
2 is typically injected in slugs alternating with periods of water injection. Initially
the producers usually flow at very high watercuts and require artificial lift. As
injected CO2 progressively breaks through at the producers together with incremental
oil production, the lift performance of the wells improve as the column density is
reduced. This is mainly due to the expanding CO
2 in the production tubing when it travels up from the bottom of the well to surface.
Eventually the producers reach a point of autolift, where no artificial lift is any
longer needed. During the time when back produced CO2 builds up, significant fluctuations
in gas rate can occur (depending on the detail of the geology), so the well may experience
periods of autolift followed by periods when artificial lift is required to maximise
offtake rates and project economics. At the end of the CO
2 WAG (Water Alternating Gas) injection period, a water post-flush is implemented to
recover mobile CO2 for recycling to new patterns and to continue producing incremental
oil. During this period the produced gas rate decreases to a point where once again
artificial lift may be needed to fully exploit the last stages of pattern production.
[0005] During CO
2 assisted EOR operations a significant fraction of the total injected CO
2 is back produced and needs to be recycled. This means that surface facilities must
be able to handle large volumes of gas and recompress these to high enough pressures
to re-inject in the reservoir. In the early years of a CO
2 EOR project the recycled volumes of CO
2 are small and there is typically spare compression capacity available.
[0006] It is an object of the present invention to provide an integrated method for gas
handling for artificial lift and miscible/sub-miscible Enhanced Oil Recovery from
a crude containing formation, thereby simplifying surface facilities, reducing capital
and operational costs and increasing uptime.
[0007] During the lifetime of a project the combined gas stream of the fresh acid gas and
the recycled gas will become contaminated with hydrocarbon gas, with the allocation
principles between injection gas for EOR and lift gas remaining the same.
SUMMARY OF THE INVENTION
[0008] In accordance with the invention there is provided a method of enhancing crude oil
recovery from a crude oil containing formation using an integrated acid gas injection
system which injects a first fraction of an available volume of acid gas into the
formation and a second fraction of the available volume of acid gas as a lift gas
into a crude oil production well traversing the formation.
[0009] As the lift gas is returned to the surface the recycle compression may be used to
reinject it in the reservoir or use it for ongoing gas lift.
[0010] The first acid gas fraction may be injected slugwise into the formation, and injection
of acid gas slugs may be alternated by injection of water slugs into the formation.
[0011] The acid gas may comprise CO
2 and/or H
2S with together with hydrocarbon gas or other contaminants obtained from a natural
or industrial source and the first fraction may be injected into the formation through
an injection well traversing the formation at a distance from the production well
such that the first fraction mixes with and displaces crude oil within the pores of
the formation by a miscible or sub-miscible process and flows towards the production
well.
[0012] At least some part of the first acid gas fraction may be produced through the production
tubing and then recycled with the fresh acid gas obtained from natural or industrial
sources.
[0013] The rate and/or pressure at which the second acid gas fraction is injected into the
injection conduit may be adjusted on the basis of one or more of the following parameters:
- target and/or fluctuation of crude oil production of the production well(s);
- fluctuation of gas production of the production well(s);
- density and/or watercut of the well effluents in the production tubing of the production
well(s);
- available acid gas (or produced gas and acid gas mixture) volume and/or acid gas (or
produced gas and acid gas mixture) compressor capacity:
- bottom hole pressure in the production well.
[0014] When used in this specification and claims the term acid gas shall mean a gas which
contains more than 1 mole% of hydrogen sulfide (H
2S) and/or more than 5 mole% carbon dioxide (CO
2), wherein the acid gas may be obtained from an industrial source (e.g. extracted
from furnace or turbine flue gas) and/or natural sources, and may comprise a mixture
of CO
2, H
2S and natural gas produced from the crude oil containing formation.
[0015] The integrated acid gas-lift and EOR method according to the invention may be applied
to reservoirs where continuous acid gas injection is the preferred secondary recovery
method.
[0016] These and other features, embodiments and advantages of the method according to the
invention are described in the accompanying claims, abstract and the following detailed
description of non-limiting embodiments depicted in the accompanying drawing, in which
description reference numerals are used which refer to corresponding reference numerals
that are depicted in the drawing.
BRIEF DESCRIPTION OF THE DRAWING
[0017]
Figure 1 is a schematic view of an oil containing formation and production well in
which the integrated system for acid gas-lift and acid gas enhanced EOR method according
to the invention is applied.
DETAILED DESCRIPTION OF THE DEPICTED EMBODIMENT
[0018] Figure 1 shows a crude oil containing formation 1, which is located underneath an
overburden 2 and is traversed by an acid gas injection well 3 and a crude oil production
well 4. The crude oil production well 4 comprises a well casing 5, which is perforated
near the bottom of the well to enable influx of crude oil into the well 4 as illustrated
by arrows 6.
[0019] A volume of acid gas obtained from a natural or an industrial acid gas source 7 is
distributed to the field well pads or well head platforms through a distribution network
22 and split at a manifold 21 into a first fraction 11, which is injected into the
formation 1 through perforations 13 in a well casing 14 within the acid gas injection
well 3 as illustrated by arrow 15, and a second fraction 12, which is injected as
lift gas into a lift gas injection conduit 16 that is arranged within the interior
of a production tubing 17, which is suspended within the well casing 5 from the wellhead
18 of the production well 4. If required, a conventional downhole safety valve 28
can be installed below the lift gas injection string 16 and above a production packer
19. The rate of lift gas injection is controlled by a choke 23. The packer 19 is arranged
near the bottom of an annular space 20 between the production tubing 17 and well casing
5 to inhibit crude oil and/or acid gas lift gas to flow into the annular space 20.
[0020] Produced fluids comprising crude oil, brine (mixture of formation water and injected
water), associated hydrocarbon gas, acid gas back produced from the reservoir and
acid gas injected directly into the producer for gas lift are produced back to a Processing
Facility(s) 24 through a flowline 28. The Processing Facility(s) comprises facilities
25 to separate crude oil from brine and the produced gas (largely comprising acid
gas with a level of hydrocarbon gas contamination). This produced gas 27 (possibly
after extraction of some of the hydrocarbon content) is compressed 26, where it is
raised to high pressure for injection into the reservoir or for use in gas-lifting
producers. The high pressure gas 30 is combined with the fresh acid gas imported from
the industrial source 7 and routed once more to the wells 3 for injection into the
reservoir for Enhanced Oil Recovery and to the producers 4 for acid gasgas lift.
[0021] An advantage of the integrated system is that the second fraction 12 is used for
acid gas lift without significant additional CAPEX (Capital Expenditure) using the
basic system of surface facilities infrastructure (22, 28 and 24) required for acid
gas Enhanced Oil Recovery. Over the lifetime of a crude oil production project at
most a small increase in the compression capacity can accommodate all the acid gas
lift gas requirements within the same operating mode as is required in any case for
the EOR project itself. Since the gas has to be compressed to inject into the formation
1, there is always sufficient pressure to operate a gas lift system without the need
for conventional (potentially leaking) gas lift valves. By allocating the volume of
lift gas using chokes 23, the artificial lift capacity can be progressively adjusted
to match the wells potential and can respond to short term changes in gas production
rate from the reservoir.
[0022] A principle drawback of conventional annular acid gas gas-lift is the corrosive nature
of acid gas in the presence of brine. Conventional annular gas lift risks corrosion
in the annulus 20 and leakage through gas lift valves, making this option less practical
on account of the material that would be required for the well casing 5. Even if the
lift fluid would be dehydrated there will always be a "dead volume" below the deepest
injection valve and above the production packer 19 where due to leakage corrosive
fluids can accumulate.
[0023] The method according to the invention benefits from synergies between the EOR produced
fluids processing facilities and acid gas lift in a fully integrated system using
concentric lift strings to contain the acid gas (or any other configuration that protect
the integrity of the well, including but not restricted to the use of a separate tubing
within the annulus to convey acid gas to a deep injection point in the production
tubing or full CRA casing), to reduce CAPEX and operational complexity compared to
artificial lift schemes based on ESPs (or any other artificial lift method requiring
a separate supporting surface system).
[0024] Principal benefits of the method according to the invention are summarized in the
following paragraphs 1-9:
1. Significant saving in CAPEX and OPEX compared to use of Electrical Submersible
Pumps (ESPs) which require a completely separate system with its own operational issues:
- Additional electrical generation capacity
- Variable speed drive for each ESP
- Power lines to each well head
- Modified well design for ESPs
Especially in case the acid gas EOR operations are carried out offshore the required
VSD units and additional electrical generation capacity (if power is generated offshore)
will demand significant platform space and weight requirements.
In contrast acid gas gas-lift requires only limited modification to the surface facilities
- Possible capacity adjustment on required EOR recycle compression, if "spare compression"
early in life is insufficient
- lift gas drawn from the acid gas injection lines to each well pad/ wellhead platform
are required in any case for EOR
- modified well design with concentric insert string
2. Corrosion risk minimised through use of a concentric completion that consists of
an insert lift gas string of Glass Reinforced Epoxy (GRE) dual lined or Corrosion
Resistant Alloy (CRA) within a GRE lined or CRA production tubing. No access to annulus
through gas lift mandrels.
3. Tapered production string below the depth of the insert string to maximise lift
performance and possibility to remove (and potentially re-use) insert string once
well autolifts, maximizing well potential.
4. Possibility of installing a conventional downhole safety valve below the insert
string and above the production packer
5. Increased flexibility to manage uncertainty:
- Well rates are uncertain and if acid gas is from a fixed capacity source (e.g. dedicated
CO2 capture plant from flue gas, or associated acid gas from contaminated gas production),
sufficient wells must be operating to take available acid gas at all times to maximize
project returns. In a low productivity realisation more wells are needed. With an
acid gas gas-lift system, the lift gas can easily be reallocated to a larger number
of wells (each of which requires a lower lift gas rate). With ESPs the requirement
for a VSD for each well means that additional CAPEX is needed, and in an offshore
environment there may not be flexibility to add additional drives.
- A key uncertainty is the speed at which back produced gas builds up and the overall
recycling requirement. The gas lift system intrinsically manages this. In a downside
outcome with earlier gas breakthrough, more recycling of acid gas is needed, but the
extra gas handling is partly offset by the reduced requirement for gas lift as wells
move to autolift sooner. Conversely in an upside outcome of reduced gas cycling, more
gas lift is needed which exploits the consequent ullage in compression capacity.
5. Reduced operational complexity. The acid gas gas-lift rate can be constantly adjusted
to match the back produced gas and production target rate, responding rapidly to fluctuations
in produced gas. In contrast ESPs have more restricted operating ranges and may require
change out to handle the evolving back produced gas rates.
6. Gas lift has high uptime, effectively driven by the availability of the recycle
compression. Once acid gas has broken through, production would usually be shut-in
when the recycle is down, irrespective of the lift system. In contrast ESP requires
a separate system, and each ESP is itself prone to failure, requiring the use of a
rig offshore to workover the well, leading to higher downtime and additional cost.
7. At the well level gas lift with a concentric string is a highly reliable and robust
system. ESPs require a higher level of operator awareness and are more susceptible
to mishandling. For example, careful startup is needed, potentially handling significant
transients arising from segregation of fluids within the wellbore after a shutdown.
8. Use of the spare compression capacity early in the Enhanced Oil Recovery project
for acid gas gas-lift reduces the levels of turn down required and improves energy
efficiency.
9. Intelligent or Smart well systems may be deployed in producers to improve the efficiency
of the acid gas Enhanced Recovery(EOR) method according to the invention. The acid
gas gas-lift system is more compatible with Intelligent or Smart well systems as there
is no planned requirement to pull the production tubing. In contrast the need to replace
ESPs means that a Smart completion requires a wet-connect which is repeatedly used,
increasing the risk of failure and therefore loss of the additional data gathering
and inflow control afforded by an Intelligent or Sart well system.
1. A method of enhancing crude oil recovery from a crude oil containing formation using
an integrated acid gas injection system which injects a first fraction of an available
volume of acid gas into the formation and a second fraction of the available volume
of acid gas as a lift gas into a crude oil production well traversing the formation.
2. The method of claim 1, wherein the acid gas comprises a mixture of produced gas and
an acid gas from a natural or industrial source.
3. The method of claim 1, wherein the first fraction is injected slugwise into the formation,
and injection of acid gas slugs is alternated by injection of water slugs into the
formation.
4. The method of claim 1, wherein the production tubing is tapered.
5. The method of claim 1, wherein the lift gas is injected using a lift gas injection
conduit arranged within a production tubing in the production well.
6. The method of claim 5, wherein use is made of a concentric completion and the lift
gas is injected through the inner string of this concentric completion and the produced
fluids with the lift gas is produced through the annulus between the insert string
and the main tubing of the concentric completion.
7. The method of claim 1, wherein a conventional downhole safety valve is set below the
bottom of the insert string of the concentric completion and above the production
packer.
8. The method of claim 1, wherein the available volume of acid gas comprises acid gas
obtained from a natural or industrial acid gas source and the first fraction is injected
into the formation through an acid gas injection well traversing the formation at
a distance from the production well such that the first fraction mixes with and displaces
crude oil within the pores of the formation and flows towards the production well.
9. The method of claim 4, wherein at least some acid gas of the first fraction is produced
through the production tubing and at least part of the first and/or second fraction
is recycled into the available volume of acid gas.
10. The method of any preceding claim, wherein the rate and/or pressure at which the second
fraction is injected into the acid gas injection conduit is adjusted on the basis
of one or more of the following parameters:
- target and/or fluctuation of crude oil production of the production well(s);
- density and/or watercut of the well effluents in the production tubing of the production
well(s);
- available acid gas volume and/or acid gas compressor capacity:
- bottom hole pressure in the production well.
11. The method of claim 10, wherein the rate and/or pressure at which the second fraction
is injected into the acid gas injection conduit is adjusted in relation to bottom
hole pressure in the production well such that injection of the second fraction into
the formation is inhibited.
12. The method of claim 1, whereby the injected acid gas comprises significant mole fractions
of H2S and CO2.