U.S. patent application number 10/716064 was filed with the patent office on 2005-05-19 for downhole flow control apparatus, super-insulated tubulars and surface tools for producing heavy oil by steam injection methods from multi-lateral wells located in cold environments.
Invention is credited to Gondouin, Michel.
Application Number | 20050103497 10/716064 |
Document ID | / |
Family ID | 34574347 |
Filed Date | 2005-05-19 |
United States Patent
Application |
20050103497 |
Kind Code |
A1 |
Gondouin, Michel |
May 19, 2005 |
Downhole flow control apparatus, super-insulated tubulars and
surface tools for producing heavy oil by steam injection methods
from multi-lateral wells located in cold environments
Abstract
Large reservoirs of Heavy Oil have been discovered in the
Alaskan Arctic, below a thick Permafrost zone. Others are located
Offshore, in deep water, another cold environment. The very low
temperature of those reservoirs greatly increases the Heavy Oil
viscosity. In warmer environments, Steam Injection from the surface
is the method of choice for economically recovering Heavy Oil. To
be effective, wet Steam injection in Arctic wells or in deep
Offshore wells, requires minimum heat losses through well tubulars
carrying Steam or heated Heavy Oil. This is done by a combination
of improvements in the Multi-lateral well configuration and
patented process of Reference (1): a) by using two dedicated and
"super-insulated" vertical tubulars, co-axially carrying wet Steam,
at the center, surrounded by Heated Oil, through the coldest part
of their environment, b) by maintaining almost un-changed the
temperature of the co-axial outer casing, with a circulation of
cold oil-lifting fluid, c) by connecting a plurality of
multi-lateral "quasi-horizontal" wells to the same two
"super-insulated" vertical tubulars, by means of Downhole flow
control Modular Systems, including 3-way valves, float valves and
other Oil-lifting devices, so that each "quasi-horizontal" well may
be sequentially switched, from the surface, from the cyclic Steam
Injection mode to that of Oil Production, and vice versa, d) by
providing control means and easy access to logging or cleaning
tools, from the surface to any one of the "quasi-horizontal" wells,
during the life of the Multi-lateral well.
Inventors: |
Gondouin, Michel; (San
Rafael, CA) |
Correspondence
Address: |
Michel Gondouin
32 San Marino Drive
San Rafael
CA
94901
US
|
Family ID: |
34574347 |
Appl. No.: |
10/716064 |
Filed: |
November 17, 2003 |
Current U.S.
Class: |
166/302 ;
166/57 |
Current CPC
Class: |
E21B 43/305 20130101;
E21B 41/0042 20130101; E21B 43/121 20130101; E21B 36/003 20130101;
E21B 43/24 20130101 |
Class at
Publication: |
166/302 ;
166/057 |
International
Class: |
E21B 036/00 |
Claims
I claim:
1-12. (canceled)
13. A Downhole Flow Control Apparatus, including various
pre-fabricated elements, shipped to and installed, on-site from the
surface, within the casing and well head of a substantially
vertical Heavy Oil well, crossing a cold environment, and said
vertical well casing, from the surface, connects, in its lower
part, downhole, below said cold environment, to the perforated,
nearly horizontal, portion of a Liner-equipped Lateral well, via a
non-perforated, cemented curved part of the Liner string of said
Lateral well, and wherein, said Apparatus includes two main
connecting Modular elements, installed by means of a Conventional
rig: respectively, the first element within said curved part of
said Liner string, and the second element within a portion of said
Casing, said casing portion being dedicated to said Lateral well,
for providing Downhole flow connecting means: to connect both said
Modular elements with a quasi-horizontal tubing string hung in said
Lateral well's Liner and with the annular space surrounding said
horizontal tubing string, in said Liner, to connect both said
elements with a vertical "Super-insulated" tubing string, dedicated
to conveying downwards a stream of wet Steam from said vertical
well's well head to the most distant end of said horizontal tubing
string, to connect both said elements with a vertical
"Super-insulated" tubing string, dedicated to transporting upwards
the hot fluids, produced from said Lateral well, to said vertical
well's well head, to connect both said elements with one or more
vertical feeder tubing string, dedicated to transporting downwards
a Cold stream of Oil-Lifting fluid, from the vertical well head via
the casing annular space around said "Super-insulated" tubings, to
said elements, and for providing Downhole flow-interrupting means:
to periodically interrupt, with surface-operated Valves, or with
retrievable plugs, in said Apparatus, the respective flow-streams
of: a) Steam from the surface into said quasi-horizontal tubing
string, b) of Oil-Lifting fluid from the surface into said
Apparatus, and c) of reservoir fluids produced from said Lateral
well into said Apparatus.
14. A plurality of Downhole Flow Control Apparatus of claim 13, in
a Multi-lateral vertical cased Well, connected to each of the
cemented Liner stubs of a plurality of side-way, quasi-horizontal,
Lateral wells, drilled into a Heavy Oil reservoir, below a cold
environment, and operated in Sequential Cyclic Steam Injection and
Production modes, wherein, one or more of said Lateral wells
injects wet Steam, from a Generator at the surface, via a dedicated
and shared "Super-insulated" Steam tubular assembly, coaxially
located within said vertical cased Well, into said Heavy Oil
reservoir, or wherein, previously injected Steam in other Lateral
wells soaks and rises into said reservoir, heating the Oil, in said
reservoir, wherein, previously Steam-soaked Lateral wells produce
said heated Oil, from said reservoir and convey said Oil to the
surface, by means of a continuous Oil-Lift flow system, located, in
part, within the Apparatus of each previously soaked Lateral well,
wherein, Cold dry Oil-lifting fluid at the surface, circulates
downward into said feeder tubings, located within said vertical
casing and within said curved Liners and returns back to the
surface, mixed with said heated Oil, and with Steam condensate,
from all the producing Lateral wells, via their respective
Apparatus' and via a dedicated, shared, "Super-insulated" vertical
coaxial Production tubular assembly, with minimum heat losses to
said Cold environment, wherein, each said Lateral well successively
operates first in the Steam injection mode, second in the Steam
soak and rise mode and third in the Oil Production mode, for
repeated cycles, initiated from the surface, by means of
remotely-controlled Valves, of wireline plugs, of Oil-lifting fluid
valves, of float valves or other Artificial-lift devices and of
associated tubular pipes, included in each said Downhole Flow
Control Apparatus pre-fabricated and assembled into modular
elements, transported to the Well site and respectively installed
in the cemented curved Liner of each said Lateral well, or in a
dedicated portion of said cemented Well casing, by means of
auxiliary tools, used in a Service rig.
15. The pre-fabricated Apparatus of claim 13, installed in each
Lateral well and in a dedicated portion of said vertical Well
casing includes a First Modular element, and a Second Modular
element, wherein, said First Modular element includes means: to
connect to a conventional tubing, installed in the quasi-horizontal
part of said Lateral well, to connect to the annular space around
said conventional tubing, within said Lateral well, to deliver
Steam into said annular space, from said Second Modular element,
for the subsequent injection and soaking of said Steam into said
Heavy Oil reservoir, to connect to said Second Modular element of
said Apparatus, located above said First Modular element, primarily
within said portion of the vertical Well casing dedicated to said
Lateral well, to convey a heated Oil stream flowing from said
reservoir into said conventional tubing and into said tubing's
annular space, via the First Modular Assembly element, to said
Second Modular Assembly element, by means of natural Steam-lift and
Artificial Oil-lifting systems.
16. The Apparatus of claim 15, wherein each said Lateral well
includes a quasi-horizontal portion, equipped with a perforated
Liner string, cemented or not, coupled to a larger diameter curved
Liner string, cemented from its lowest point to a side-way Liner
stub, of larger diameter, always cemented and sealed into the large
Casing of the vertical Multi-lateral well, and containing the
hanger-packer, sealing the upper end of said curved liner string,
into said Liner stub, wherein said Liner string contains, in in its
quasi-horizontal portion, a centralized single tubing string, hung,
at its proximate end and via a thermal expansion joint, into the
bottom part of said curved Liner string, and terminated by a First
Polished Bore Receptacle, above a cup packer, used as back-flow
preventer, and a First landing nipple and its matching retrievable
plug, wherein, the First Modular element of said Apparatus includes
two parallel curved tubing strings, coupled together, at their
lower ends, to the upper branches of an H, or Y, connector, whereas
a lower branch of said First H, or Y, connector, leading to a first
tubular Stinger, equipped with seals, and inserted in said First
Polished Bore Receptacle, and the other lower branch of said H
connector is plugged off, wherein, one of said two parallel curved
tubings is dedicated to supplying a lighter Oil-Lifting fluid to
Oil-lifting devices respectively delivering said Oil-Lifting fluid
to the other curved tubing string, used as Production tubing, and
to the annular space between said curved Liner and said curved
tubings, wherein, the upper end of said curved Production tubing is
equipped with a Second Polished Bore Receptacle, wherein, the upper
end of said curved Oil-Lifting fluid supply tubing is equipped with
a Third Polished Bore Receptacle.
17. The Apparatus of claim 16, wherein a Second Modular Assembly
element, comprising parts two and three of said Apparatus, and
connected to the First Modular Assembly element of said Apparatus,
includes, in its Part Two: a Production tubing, equipped, at its
bottom end, with a Second sealing stinger, matching the Second
Polished Bore receptacle, an Oil-Lifting fluid supply tubing,
equipped, at its bottom end, with a Third sealing Stinger, matching
the Third Polished Bore Receptacle, and connected to a third part
of said Second Modular Assembly element of the Apparatus for said
Lateral well; and said Apparatus includes, in its Part Three, from
the bottom up, means for establishing the following branch flow
connections: first, from the casing annular space to a coaxial,
un-insulated, Production collector pipe, when said casing annular
space is mostly filled with liquids (Oil and Water), second, from
said Production tubing to a central, insulated Steam tubing, during
the Steam injection period, in said Lateral well, third, from said
Production tubing to said central Production Collector pipe, during
the Lateral well's production period, fourth, from said Production
tubing to an Oil-lifting fluid supply tubing, parallel to the
Production tubing, and located in a different radial plane than
said Production tubing, fifth, from said Oil-lifting fluid supply
tubing to a vertical string of Oil-lifting fluid feeder tubings,
rising through the multi-tubular packer at the top of said casing
annular space's portion, dedicated to said Second and Third
elements of said Lateral well's Apparatus, and crossing those
portions of the casing annular space, stacked above that of said
Lateral well, and dedicated to other Lateral wells; means for
remotely operating said Natural Steam-lift and Artificial Oil-lift
systems in the Sequential Steam injection, Steam soak and Oil
Production modes, using various combinations of said branch flow
connections, means for, automatically, closing said first branch
flow connection, when said annular space is filled with lower
density fluids, such as Steam or Oil-Lifting fluid.
18. The Apparatus of claim 17, wherein said means for remotely
operating said Steam-lift and Oil-lifting systems in the Sequential
Steam injection, Steam soak and Oil Production modes, using said
branch flow connections include, from the top down: a retrievable
plug, located in a Second landing nipple, in the Production tubing,
closing said Fifth branch flow connection, except when logging or
cleaning tools are to be introduced into said Lateral well's
Production tubing, a surface-operated conventional "on-off" valve
opening or closing said Fourth branch flow connection of said
Oil-Lifting fluid supply tubing with said Oil-Lifting fluid feeder
tubing string, a surface-operated 3-way valve, vertically located
in the Production tubing, below said Second landing nipple and
plug, either directing a Production fluids stream upwards into said
Third branch flow connection to the Production Collector pipe, or
directing Steam downwards from said Insulated Steam tubing, via
said Second branch flow connection, into the Lateral well's
Production tubing; and wherein said means for, automatically,
closing said First branch flow connection, from said casing annulus
portion to said Production Collector pipe, include: a float valve,
or a standing valve, set in a gas-lift valve mandrel within said
Oil-lifting fluid supply tubing, which valve automatically directs,
by an Artificial Oil-lifting process, a Production fluids stream
from the casing annulus portion, via said First branch flow
connection, to the Production Collector pipe, when the high density
Produced liquids level is high within said casing annulus portion,
and said float valve or standing valve also closes said First
branch flow connection, when said Produced liquids level is low,
due to the accumulation of Steam, of gas, or of Oil-lifting fluid
within said casing annulus portion, during the Steam injection
period and by a natural Steam-lift, during the Steam soak
period.
19. A dedicated "Super-insulated" tubular assembly, for conveying
wet Steam, with minimum heat losses, from a Generatr at the
surface, to one or more of a plurality of Lateral wells, connected
to a single large cemented Oil well casing pipe, hung from a single
well head, wherein, said tubular assembly includes, radially, from
the axis of said casing pipe: a pressure-resistant, leak-proof,
metallic central tubing string, made-up of joints coupled together,
end to end, by threaded couplings, and hung in the well head, a
coaxial annular layer of porous "Super-insulating" fibrous or
granular materials, of very low density, presenting a very fine
pore space at near atmospheric pressure, a coaxial sealed
insulation cover and support tubing string, also hung in the well
head, made-up of thin-gauge metal joints, welded or brazed
together, surrounding said annular layer of "Super-insulating"
material and said thin-gauge metal joints presenting a flexible
annular support welded respectively to the outer surface of said
central tubing and to the inner surface of said insulation cover
tubing, at the respective two ends of each joint of said tubings, a
plurality of wire-type metal centralizers, affixed to each joint of
said central tubing, within its associated thin-gauge metal joint
and each said centralizer presenting a radial extension, sliding
into a rail guide affixed to the inner surface of said thin-gauge
metal tube, parallel to its axis, a coaxial pressure-resistant
protective metallic tubing string, made up of tight joints, coupled
by metal to metal threads at each of their two ends, also hung in
the well head and presenting an inner diameter slightly greater
than that the outer diameter of said sheet metal tubing string, two
coaxial stinger tubes, equipped with heat-resistant seals, for
insertion of each of them into a matching Polished Bore Receptacle,
respectively at the lower ends of said central metallic tubing
string and of said coaxial outer protective metallic tubing
string.
20. Metal wire centralizers, radial extensions, longitudinal
guides, thin-gauge metal tubulars and flexible annular supports of
claim 19, making, together with either the outer surface or the
inner surface of an adjacent steel tubular, the sealed annular
enclosure of said "Super-insulating" materials, wherein, said
metals are selected alloys including two or more metals from the
following alphabetic list: Aluminum, Antimony, Cadmium, Copper,
Chrome, Iron, Manganese, Molybdenum, Nickel, Silicon, Silver,
Titanium, Vanadium and Zinc, for their cost and respective
compatibilities, and for their main relevant properties, within the
temperature range of 100 C to 300 C, listed below: ease of assembly
by welding or brazing, maximum elongation, by cold working in dies,
high structural strength, ductility, and fatigue resistance, low
thermal conductivity and thermal expansion, relative to those of
the steel or of plating metals of said steel tubular and said
thin-gauge metal tubular.
21. A modified version of the "Super-insulated" Steam tubular
assembly joints of claim 19, also pre-fabricated, wherein, said
outer protective tubing joint, is used as the main structural
support of the Super-insulation and of said insulation cover tube,
made of thin-gauge metal, and as a substitute to the inner Steam
tubing, wherein, a jointless coiled tubing string, later inserted
by conventional means, within said insulation cover tube, replaces
the jointed Steam tubing string, and wherein, said wire-type
centralizers are now affixed on the inner surface of said
Protective tubing joint, with their radial extensions pointing
inward, said extensions are now sliding in rail guides affixed to
the outer surface of the thin-gauge metal cover tube, of diameter
only slightly larger than that of said coiled tubing, said flexible
annular end supports of the thin-gauge metal cover tube are now
affixed respectively on the inner surface of the protective
tubular, and on the outer surface of said thin-gauge metal cover
tube, thereby sealing the insulation inside a thin-gauge metal
annular enclosure, fully protected from external shocks, by the
thick outer protective pipe, the annular space between said coiled
tubing outside diameter and the drift diameter of said thin-gauge
metal insulation cover tubes, is very small, a low-pressure
slip-stream of dry Oil-Lifting fluid, fills said annular space,
carrying away and preventing any potential moisture leak, from
contacting said insulation.
22. The coiled tubing, used as the Steam tubing string in claim 21,
is preferably made of a seamless tube of Titanium alloy, wherein,
said coiled tubing is equipped at its lower end with a sealing
stinger matching an associated Polished Bore Receptacle above the
packer of the uppermost Apparatus, leading to the central insulated
Steam tubing, previously hung within the stack of all the Lateral
wells'Apparatus.
23. The "Super-insulated" coaxial production tubular string of
claim 14, conveying heated Oil to the surface, together with Steam
condensate and Oil-Lifting fluid, including all the elements of the
Steam tubular assembly of claims 19 or 21, built on a much larger
radial scale, so that the annular space between the inside diameter
of the production tubing, in said production coaxial tubular
assembly, exceeds, by two inches or more, the outside diameter of
the Steam tubular assembly's protective tubing string, which hangs,
coaxially, within said production tubing string, wherein, in view
of the heavy weight of the production tubing joints, the preferred
configuration of said coaxial production tubular string of
pre-fabricated joints is that of claim 21, wherein, "slick"
production tubing joints, of outside diameter slightly smaller than
the drift diameter of the "Super-insulation" thin-gauge metal cover
tubes, are separately shipped to the well site, coupled together on
the rig and the resulting production tubing string is run into said
pre-installed and, graphite-lubricated, insulation cover tubes,
firmly supported within their outer protective tubular string, by
wire centralizers and their radial extensions sliding in
longitudinal guides, by flexible end collars and by seam welds at
the junction of each thin-gauge metal joint, wherein, a slip stream
of scavenging dry Oil-lifting fluid of low density, circulates in
the very thin annular space between the outer surface of said
protective tubular string and the inner surface of said insulation
cover string, to dilute and carry away to the surface any
accidental entry of moisture into said very thin annular space, to
prevent said moisture from potentially breaking through the
thin-gauge metal of the sealed insulation cover string, and
wherein, the lower end of the outer protective tubular string of
the production tubular assembly is closed by a welded ring,
equipped on the inside with circular seals, through which slides
the production tubing string, above its lower-end stinger, sealed
within a matching Polished Bore Receptacle, affixed to the top end
of the un-insulated production collector pipe, affixed to the
uppermost multi-tubular packer of all the stacked Apparatus, set
within the vertical well casing.
24. Auxiliary Surface tools for protecting sealed
"Super-insulation" thin-gauge metal cover tube joints from external
shocks, during their transport, from the factory in which they are
pre-fabricated, to a well site, and during their subsequent
handling, and assembly into one or two strings, by a conventional
service rig, at the well site, including: load-bearing, reinforced,
thread protectors for single pin ends of said joints, wherein, said
"single pin" thread protectors present a box of threads, matching
those of said joints pin, and a central, coaxial plug fitting
within the lower end of said "Super-insulation" cover tube joints,
presenting a strength sufficient for holding the combined weights
of said "Super-insulation", of its said cover tube, of its
internals and of its end collars, both vertically and horizontally,
under predicted accelerations, and with reasonable safety factors,
during transport of said joints to the well site and during their
handling by the rig, load-bearing thread protectors for single box
ends of said joints, wherein, said "single box" thread protectors
present a threaded pin matching those in said joint's box, and a
coaxial plug fitting within said insulation cover tube, presenting
a strength sufficient for said joint to be handled by spiders and
elevators in said rig; said single box or single pin thread
protectors are used when the inside tubing joint of the
"Super-insulated" tubular assembly is independently transported to
said well site, by trucks on rough roads, or by ship, and run-in
within the pre-installed insulation cover tubing, load-bearing
thread protectors for dual pins ends of said joints, used when the
completely assembled "Super-insulated" tubular joint is transported
from the factory to the well site, including both the Steam tubing
joint and the outer protective joint, assembled together by means
of said dual pins, at their lower ends, wherein, said "dual pin"
thread protectors present a dual box of threads, matching those of
the outermost pin of the protective tubing and those of the central
pin of the inner tubing joint, either for Steam or for the
Production fluids, providing a strength sufficient for limited
transport and handling, and when the expected accelerations are
quite low, such as with helicopters, the companion load-bearing
thread protectors for "dual box" ends of said joints, presenting a
dual threaded pin and a plug inserted within the innermost tubing
joint; said auxiliary surface tools also include: modified "seam
welding" machines for joining and sealing together the respective
ends of the insulation cover thin-gauge metal tubes of two
superposed joints held in the slips and in the top drive of the
rig, prior to running-in of the coupled joint of the
"Super-insulated" tubular assembly, for conveying either Production
fluids or Steam, monitoring tools for measuring the concentration
of any moisture carried to the surface by said slip streams of
low-pressure lift-gas circulating around said insulation cover
thin-gauge metal tubes, while operating said "seam welding"
machines and, later, while the multi-lateral well is in full
operation.
25. The Apparatus of claim 13 wherein the cold Oil-lifting fluid is
mostly composed of water-free, mixed, light hydrocarbons, miscible
with the heated and produced Heavy Oil.
26. The Apparatus of claim 14 wherein the said Oil-lifting fluids
are in a gas phase and said Artificial lift devices are
conventional, wireline-retrievable gas-lift valves, set in regular
gas-lift valve mandrels and operated by the density difference of
said gas phase with respect to the densities of said heated Oil and
said Steam condensate.
27. The Apparatus of claim 14 wherein the said Oil-lifting fluids
are in a liquid phase and said Artificial lift devices are
wireline-retrievable hydraulic or jet pumps, set in suitably
modified gas-lift valve mandrels and anchored in a landing nipple
included in said Oil-lifting fluids feeder tubing and operated by
the differential pressure of said Oil-lifting fluids, across said
Artificial lift devices.
Description
FIELD OF THE INVENTION
[0001] Very large volumes of Heavy Oil (API gravity=<19 Degrees)
have been discovered in the Alaskan Arctic, Onshore, below a 1,800
ft-thick Permafrost zone, which are in reservoir rocks at
un-usually low temperature, because of their proximity to the
overlaying Permafrost.
[0002] The viscosity of the Heavy Oil in those reservoirs is known
to be, correspondingly, very high, which, by consequence, restricts
its natural in-flow rate into conventional production wells to
mostly un-economic values. This explains that only a very small
portion (5 to 10%) of those huge Domestic oil resources (up to 40
Billion Barrels estimated Original Oil In Place) has been
developed, more than 25 years after their discovery.
[0003] More recently, other very large Heavy Oil resources were
found, Offshore, in deep water, off the coasts of Trinidad, Brasil
and West Africa, in equally cold reservoir rocks. These world-wide
oil resources are still un-developed, for the same reason as those
in the Arctic: an excessive viscosity of the Heavy Oil, limiting
the rate of production.
[0004] Large volumes of Heavy Oil from warmer reservoir rocks,
however, are being economically produced, Onshore, by means of
Steam Injection, in California, in Indonesia, in Canada, etc . . .
.
[0005] The present Invention improves upon U.S. Pat. No. 5,085,275,
Ref.(1), by the same Inventor, which teaches a Process in which:
"the degradation of Steam quality, due to heat losses prior to its
injection into a Heavy Oil reservoir, is reduced by utilizing the
heat contained in a stream of reservoir fluids, produced from the
same reservoir, following a cycle of steam injection".
[0006] FIG. 5 and FIG. 6, from Ref.(1) and re-named here as FIG. A
and B, specifically, address the case of Arctic multi-lateral
wells.
[0007] In this case, it is essential to prevent any significant
heat loss, through the wall of the vertical casing, to the
surrounding Permafrost, so as to avoid melting the Permafrost. Such
melting would, ultimately, cause the casing to drop down,
shearing-off the connecting tubulars to the well head, destroying
the well, causing an oil spill and a potential well fire,
especially difficult to control in an Arctic climate.
[0008] The validity of the Inventor's 1990 prediction of such a
potential catastrophic hazard is confirmed by FIG. C, taken from
Ref. (5), published in 1991, by a group of Engineers from the Oil
Operating Companies (ARCO and BP) in the Alaskan Arctic.
[0009] FIG. C is the result of a numerical simulation of the heat
loss and Permafrost melting radius around a cased well containing a
single coaxial Steam tubing, either bare or Insulated, based upon
the known characteristics of commercially-available,
vacuum-insulated, tubings. It shows that, even with such Steam
tubing insulation, and a gas-filled casing-tubing annular space,
the Permafrost at 1700 ft is melted inside a circle of 6 ft radius
at the end of First cycle of Steam Injection. That radius increases
to 8.5 ft in cycle 2 and reaches 10.5 ft after cycle 6. Without any
insulation, the melting radius is 20 ft after the First cycle. This
illustrates the advantage of using higher-performance,
"Super-insulation", materials.
[0010] The main objective of the present Invention is to combine
the use of "Super-insulated" tubulars with a Downhole Flow Control
Apparatus and with Surface Tools to, safely and economically,
implement Ref.(1) Process. This Process is based upon the simple
idea of reducing Total Steam heat losses by placing an additional
"free" heat source around the Steam tubulars, thereby lowering the
temperature gradient across the insulation layer. Such an approach
was numerically analyzed in Ref. (6) and verified in 1989 by a
field test, made by Texaco, in a Kern County, Calif., Heavy Oil
well, under Dual Steam and hot water injection, in two Oil
zones.
[0011] The application of this Downhole Apparatus and of the
required Surface tools to the known Heavy Oil reservoirs in the
Alaskan Arctic will significantly increase Domestic Oil reserves
from Onshore fields, without any impact to the environment, over
the next 30 years.
[0012] The same technology, applied Offshore to Heavy Oil in deep
water, will also make it possible to drastically reduce heat losses
from the Steam injection tubulars, to the surrounding cold Ocean,
thereby reducing Steam consumption, an important cost factor in any
Thermal Oil recovery project, in a cold environment.
[0013] Multi-Lateral Well Casing-Liner Completion by Prior Art
[0014] In an Onshore cold environment, a large-diameter well Casing
pipe, or, in deep cold water Offshore, a large Conductor pipe is
installed through the total thickness of said cold environment, in
a borehole above a targeted Heavy Oil reservoir. The well Casing or
the Conductor pipe presents a plurality of windows, precisely
cut-out at various depth intervals and oriented in selected
directions, below the thick Permafrost zone when in an Onshore
Arctic well, or below the Ocean bottom, when in a deep sea Offshore
well.
[0015] This type of liner to casing connection, taught in Ref. (4),
is preferred to those through the casing shoe, as in FIG. B and
FIG. C, when a relatively large number (4 to 8) of lateral wells
have to be connected to the same casing. This is an important
requirement for lateral wells operated under "Sequential Cyclic
Steam Injection", in a cold environment. In that most efficient
Mode of Operation, one of the wells is under Steam injection, while
most of the others are in the Production mode. The optimum
Injection cycle duration, however, is much shorter than that of the
Production cycle, by a factor of 1/3 to {fraction (1/7)} in most
reservoirs. This difference might result in excessive down-time of
boilers. In warm environments, Onshore, this difficulty is very
easily overcome by the use of Mobile Steam Generators, which are
quickly moved from well site to well site, with little down-time,
or by using an Insulated Steam Distribution pipes network,
connected to a distant Co-generation Plant.
[0016] Such approaches, however, are not cost-effective in the
Arctic, nor Offshore, because of excessive heat losses in the
distribution pipes or because of excessive cost of frequently
moving boilers at sea, from one platform to another.
[0017] In FIG. 1, the side-way connection of a lateral well to a
vertical well casing allows to stack-up a much greater number of
multi-lateral wells to the same casing than the schematic
connections, through the casing shoe, shown on FIG. B and C.
[0018] A pre-cut short pipe, called a Liner Stub, equipped at its
upper end with a sealing collar and closed at its lower end, is
inserted, through the matching Casing Window, guided and
extended-out, into a pre-drilled side-pocket hole, at a
pre-determined orientation and at a small angle from the
substantially vertical axis of the Casing or Conductor pipe, as
taught in Ref. (4).
[0019] A method of fabrication, from blank pipe elements, of the
Casing Window and of both ends of the matching Liner Stub is taught
in Ref.(3).
[0020] Each fully-extended Liner Stub is cemented in its respective
side pocket, and cleaned-out of excess cement and of any drillable
debris.
[0021] It is through each cemented Liner Stub, starting from the
lowermost, that a medium to short radius lateral hole is then
drilled, following a pre-selected, curved trajectory, reaching the
lower part of the Heavy Oil zone. The hole diameter in this curved
trajectory is close to the inside diameter of the Liner Stub.
[0022] Due to relatively shallow burial depths of Heavy Oil
reservoirs, the curved hole stability may be limited, requiring
that a Liner be run-in, installed and cemented into the curved
hole, as quickly as possible. The Curved Liner's upper end is
equipped with a conventional hanger/packer, set within the cemented
liner stub. Each lateral hole is then continued by a small-diameter
hole, quasi-horizontal, but with a slightly upward slope, which
traverses most of the Heavy Oil zone thickness, as determined by
known logging tools and directional surveying tools, preferably
used in open hole.
[0023] A small-diameter Liner pipe string, inserted in each lateral
hole, at the end of a work string, is sealed or coupled to the
lower end of the larger cemented Curved Liner, forming a Tapered
Liner String.
[0024] It comprises, from the distant end of the lateral well:
[0025] a perforated small-diameter Liner string, equipped with sand
screens and centralizers, or gravel-packed, in the hole's
quasi-horizontal portion, within the reservoir,
[0026] a retrievable plug nipple, to be used for isolating the
Curved Liner from the quasi-horizontal Liner and an expansion
joint; they are located at the proximate end of the small-diameter
Liner string, near the lower end of the cemented Curved Liner's
shoe, and just below its junction with the larger-diameter cemented
Curved Liner string,
[0027] The composition of the small-diameter Liner string depends
upon the reservoir rock characteristics and heterogeneity. It may
include:
[0028] "notched" perforations in the event of future hydro or acid
fracs,
[0029] retrievable plug mandrels, for eventual future treatment or
gravel-packing of segments of the lateral well,
[0030] sand screens or pre-packed sand filters of various
kinds,
[0031] "blank" pipe segments equipped with cement diverter valves,
to allow the future cementation of portions of the Liner string, to
reduce water production, etc . . . .
[0032] In situations where the formations separating the cold
environment from the Heavy Oil zone are un-fractured and fully
consolidated, the lateral hole drilling and its completion with a
Tapered Liner string may, of course, proceed without interruption,
so that the cementation of the Curved Liner and its connection to
the Liner Stub may then take place at the very end of the
completion operations, rather than earlier. In such a case, the
coupled Tapered Liner String also presents a cement diverter valve
at the base of the Curved Liner, used for its cementation.
[0033] Most elements of such a Multi-lateral Well are
"Non-retrievable", nearly all of them being cemented in place, or,
permanently affixed to to other cemented elements.
SUMMARY OF THE INVENTION
[0034] The present Invention deals with the addition of
"Retrievable" Multi-tubular Downhole Apparatus, to be installed
within the Casing and Liners (cemented or not) of the above
described Multi-lateral Well, so as to produce Heated Heavy Oil, at
high rate, from said Multi-Lateral Well, when operated under the
"Cyclic Steam Injection and Production Mode", by the Process taught
in Ref.1 (U.S. Pat. No. 5,085,275).
[0035] The present Apparatus includes, for each lateral well:
[0036] A) A DOWNHOLE FLOW-CONTROL APPARATUS, and,
[0037] shared between all lateral wells:
[0038] B) TWO COAXIAL "SUPER-INSULATED" TUBING STRINGS,
[0039] C) SURFACE TOOLS FOR COUPLING "SUPER-INSULATED"JOINTS.
Flow Control Apparatus
[0040] The Flow-Control Apparatus of each lateral well, which is
part of the present Invention, is made-up of three parts,
corresponding respectively to items 19, 18, and 17, used in
relevant parts of the Process of Ref.(1):
[0041] Part 1), a pre-fabricated Dual Tubing Assembly:
[0042] It is located in the Curved Liner string of the selected
Lateral well. It is terminated at its lower end by a sealing
stinger pipe, inserted into the Polished Bore Receptacle (PBR),
coupled to the proximate end of the lateral well's Production
tubing, hung in the proximate part of the quasi-horizontal liner.
Said Assembly is terminated, at its upper end by two similar PBR's,
hung in part 2 of the Flow Control Apparatus; It also includes:
[0043] a) a cup-packer, used as back-flow preventer,
[0044] b) a H or Y connector at the base of said Dual tubings,
[0045] c) two modified gas-lift mandrels and their respective
retrievable gas-lift valves and, or, check valves,
[0046] d) a thermal expansion joint, at the upper end of said
curved Production tubing, to offset the differential thermal
expansion within said Dual tubings Assembly;
[0047] Part 2), is a Modular tubulars and Connectors Section.
[0048] It is located in a section of the annular space between the
vertical Casing and the coaxial Production Collector tubing, which
includes the Liner Stub space of the selected Lateral well. Said
section contains a plurality of vertical tubings, all connected to
Part 1), by means of sealing stingers at Part 2)'s lower end, and
to Part 3) by PBR's at Part 2)'s upper end. It is closed at its
lower end by either the Casing shoe or by the multi-tubular Packer
associated with the top part of the previously-installed Lateral
well. It comprises:
[0049] a) a substantially vertical tubular extension of the curved
Lift-gas tubing of Part 1), located in a different radial plane
than that of a vertical tubular extension of the curved Production
tubing. The Lift-gas tubular extension is terminated at its upper
end by the slanted branch of an inverted Y connector and at its
lower end by a sealing stinger inserted in the matching PBR at the
top end of Part 1). The Lift-gas tubular extension also presents at
least two branch flow connectors, within said section of the Casing
annular space.
[0050] b) a vertical tubular extension of the curved Production
tubing, terminated at its upper end by PBR, located above a
multi-tubings packer, dedicated to the specific Lateral well, and,
at its lower end by a sealing stinger matching the PBR of the
curved Production tubing in Part 1). The Production tubular
extension also presents at least three branch flow connectors,
within said section of the Casing annular space.
[0051] Part 3), is a Modular flow control system, using various
plugs or valves of various types, controlled from the surface, or
automatically actuated by variations of pressure or of fluids
density, within the various tubulars in said section of the Casing
annular space, and linking, or closing, the respective branch flow
connectors of Part 2) with:
[0052] the casing annular space,
[0053] the coaxial Production Collector pipe,
[0054] the central Insulated Steam tubing,
[0055] the Production tubing extension,
[0056] the Lift-gas extension tubular.
[0057] The use of plugs, valves, branch flow connectors and
tubulars depends upon the three sequential modes of operation of
the Lateral well, namely: Steam injection, Steam soak and Oil
Production by Gas-lift or Steam-lift processes.
[0058] An example of the specific use of each plug, each valve,
each branch flow connector and each tubular or annular space will
be disclosed in detail by FIG. 3 and by Table 1.
[0059] It will be apparent to those skilled in the Art that
wireline retrievable plugs and valves may be used for the same
purposes and that there are many shapes of manifolds or branch flow
connectors, which may be used, interchangeably, at different costs,
safety factors, reliability or ease of operation and maintenance.
To the extent that it is possible to adapt "off the shelf"
equipment and devices described in Prior Art, for similar purposes,
the Invention extends beyond the specific combination, presented as
an example, on FIG. 3 and Table 1, below, to all other
configurations and devices capable of achieving the same purposes,
by similar means, under various well conditions of temperature,
pressure, corrosion risks, sand production, etc . . . .
[0060] Parts 2 and 3 of the Flow Control Apparatus may be assembled
together, run-in and installed as a single Module.
[0061] The same system of stacked Downhole Flow Control Apparatus
is also applicable to Lateral wells connected through the shoe of a
vertical Casing, as in FIG. A or FIG. B, when the Multi-lateral
Well has fewer than four Lateral wells. In such a configuration,
said shoe presents two or three large traversing holes,
substantially vertical, serving the same functions as the same
number of side-way Liner Stubs, at a somewhat lower cost.
[0062] In very thick Heavy Oil zones, separated by a
sufficiently-thick overburden layer, from the Cold environment, it
is also possible to combine two or three Lateral wells, connected
through the Casing shoe, and associated with two or three of said
stacked Apparatus, with eight Lateral wells, connected to the
Casing via Side-way Liner Stubs, similarly associated with a stack
of eight said Apparatus. This results in a total of ten to eleven
Lateral wells, connected to the same Multi-lateral Well. Each of
said Lateral wells is, at any time, independently operable, either
in Steam Injection or in Oil Production, or subject to logging, or
cleaning operations using conventional tools.
[0063] It is also possible to connect a pair of quasi-horizontal
Lateral wells with an inverted Y connector to a single cemented
curved liner, and to operate both wells in the pair in the same
mode of Sequential Cyclic Injection and Oil Production. This
approach inceases the drainage area of the Multi-lateral well,
while sharing the cost of all the Downhole elements of the present
invention, thereby reducing the per-Barrel of Oil, Capital and
Operating costs.
"Super-Insulated" Tubulars
[0064] The other parts of the present Invention, required for the
implementation of Ref.(1) in Cold environments, are two co-axial
strings of "Super-insulated" tubulars, to be handled and assembled
on conventional Drilling or Service rigs, from pre-fabricated and
factory-tested tubular joints. Each inner string consists of a
sealed, dual-wall, coaxial tubular joints, in which the annular
space between the two walls is factory-filled with a
"Super-insulating" Material, the pore-space of which is gas-filled
and kept at a pressure not exceeding that of the atmosphere, within
a sealed metal enclosure.
[0065] The inner string is then inserted into a conventional
protective, pressure-resistant, outer tubular string, also
air-filled at atmospheric pressure, to complete the
"Super-insulated" Tubular Assembly, dedicated to the conveyance of
either Steam or of Hot produced fluid streams.
[0066] The inner wall of the inner string is also
pressure-resistant, but its outer wall, enclosing the
"Super-insulating" Material, and placed within the air-filled
enclosing outer string, is made of a thin-gauge metal presenting a
higher thermal expansion coefficient than that of steel, such as
Zinc and its alloys, so as to minimize the differential expansion
between the hot enclosing outer string and the hotter inner
string.
[0067] Because the thin outer wall is exposed to a lower
temperature than that of the fluid within the thick inner string,
the low-density "Super-insulating" Material in each joint of said
inner string is, in effect, covered by a thin outer tubular wall
presenting at least one thermal expansion device, welded, or
brazed, to the thick inner string.
[0068] As taught in Ref.(1), for applications in cold environments,
two coaxial "Super-insulated" Tubular Assemblies are required in
the vertical casing. The Injection Steam (wet, at 80% quality)
flows downward in the smallest-diameter tubular and remains at a
nearly constant temperature, determined by the injection pressure,
which is slightly higher than reservoir pressure, but safely lower
than the reservoir's frac pressure.
[0069] The annular space between the outer diameter of the thick
protective string of the "Super-insulated" Steam tubular and the
inner diameter of the largest-diameter "Super-insulated" tubular
string carries the gas-lifted stream of Heated Oil and Steam
Condensate from the Production Collector pipe to the Well Head. The
temperature of that stream is about 180 F below that of Injected
Steam. It is further reduced, on its way-up, primarily by the
cooling effect of the expanding, cold, gas-lift gas, by about 40 to
70 F, for a Heavy Oil reservoir such as the Ugnu, on the North
Slope of Alaska.
[0070] The total heat loss transferred to the casing is then
negligible, even for a Total Production of 1,000 BO/D and 2,000
BW/D, both hot, following a Steam injection of up to 3,000 B/D,
during 20 days, in each of four Lateral wells, followed by a 10
days-period of "Steam Soak".
Tools for Downhole Installation, Maintenance and Well
Work-Overs
[0071] All 3 parts of the Flow Control Apparatus, relative to the
selected lateral well, are connected to each other on the Service
rig, using existing or modified surface tools, run-in at the end of
a work string, and set, by conventional means.
[0072] The pre-fabricated Modular elements for all the lateral
wells connected to the vertical well are, in fact, individually
oriented, stacked upon each other, connected, hung and packed
within the vertical well casing. They provide direct access to
logging, cleaning or remedial tools, into each lateral well, after
removal of a single retrievable plug, by wireline or by coiled
tubings.
[0073] During a well work-over, the various elements of the well
head, "Super-insulated" Steam string, "Super-insulated" Production
tubing string and of the Flow Control Apparatus of each lateral
well above the selected lateral well have to be dis-assembled and
pulled-out prior to the work-over of the selected lateral well.
They are, all, disconnected and pulled-out with a Service rig and
using conventional or modified SURFACE TOOLS.
BRIEF DESCRIPTION OF THE FIGURES
[0074] FIG. A and B are vertical schematic cross sections taken
from Ref.(1), U.S. Pat. No. 5,085,275, issued to the present
Inventor. Captions for each of the elements have only been added,
to make them self-explanatory.
[0075] They, both are also labeled "Prior Art", offered for Clarity
only.
[0076] They both relate to a Process for which the present
Invention of various said Apparatus and "Super-insulated" Tubular
Assemblies are required, for the same functions, under specific
environmental conditions for two or more lateral wells connected to
the casing shoe.
[0077] FIG. C is taken from Ref.(5), an SPE Publication. It is not
part of Invention, but is offered for Clarity only. This Figure is
labeled "Prior Art". It is self-explanatory.
[0078] FIG. 1 is a vertical cross section of the borehole
trajectory and typical completion equipment of one of several
multi-lateral wells connected to a vertical cased well, through its
side window, for its operation under "Sequential Cyclic Steam
Injection", in a Cold environment, Onshore or Offshore.
[0079] FIG. 2 is a vertical cross section of Part 1 of the Downhole
Flow Control Apparatus, showing its bottom connections, below the
casing window of the lateral well of FIG. 1, and its top
connections, above said window, which are in two different radial
vertical planes, designated I and II and at two different
elevations.
[0080] FIG. 2A is a perspective top view of the gas-lift tubing
guide of Part 1, showing its location with respect to the
Production tubing, in the Packer at the top of said Apparatus, for
the same lateral well.
[0081] FIG. 3 is a vertical cross section of Parts 2 and 3 of the
Downhole Flow Control Apparatus, within the vertical well casing,
below the "Super-insulated" Production tubular assembly. They are
both re-assembled, run-in together, oriented and connected together
to Part 1 of the Downhole Flow Control Apparatus, for each lateral
well.
[0082] FIG. 4 is a Schematic flow diagram, for Steam, Lift-gas and
Production fluids, within two Flow Control Apparatus, stacked on
top of each other, for connection to two of a plurality of lateral
wells, at different depths and respectively operated under
Production and under Steam Injection.
[0083] FIG. 5 is a vertical cross-section of the "Super-insulated"
tubular assembly for injecting Steam.
[0084] FIG. 6 is a horizontal cross section showing the two coaxial
"Super-insulated" tubular assemblies, carrying respectively Steam
in the center and the Production within the annular space between
both of the "Super-insulated" tubular assemblies.
[0085] FIG. 6A is a schematic vertical cross-section of the
Multi-lateral well head, showing the connections of both of the
"Super-insulated" tubing strings, with respect to the Casing.
[0086] FIG. 7 is a perspective schematic view of Surface Tools,
used for sequentially coupling, first, a new joint of the sealed
inner pipe of a "Super-insulated" tubing string and, second, for
inserting said inner pre-insulated pipe string into its associated
outer protective pipe string, preferably by means of a Service rig,
equipped with a conventional "Top drive" system, in addition to the
regular rotating table.
DETAILED DESCRIPTION OF THE FIGURES (OTHER THAN "PRIOR ART")
[0087] FIG. 1 shows the vertical cross section of one of the
Multi-lateral wells connected to one of stacked joints of a
vertical Casing. For Clarity, it includes elements belonging to
Prior Art, in which the cross-hatching was made lighter than that
of the present Apparatus, so as to, easily, differentiate them. The
same approach also applies to some of the elements of FIG. 2.
[0088] The "quasi-horizontal" portion of the Lateral hole (1),
located within the Heavy Oil zone (2) of the reservoir, is
completed with the small-diameter Liner (3), equipped with
centralizers (4). This portion of the Liner includes some
perforated joints (5), some blank joints (6), some joints equipped
with sand screens (7), some landing nipples (8) for
wireline-retrievable plugs (not shown), at selected locations
within the reservoir. The Liner (3) is terminated at its proximate
end (9) by a thermal expansion joint (10), below a hanger/packer
(11) set within the lower part of the Curved Liner (12), cemented
within the larger curved hole portion of the lateral well. The
upper end of the larger Curved Liner (12) is equipped with a
hanger/packer (13), set within the cemented Liner Stub (14), held
within and sealed to the edge of the Casing Window (15) of one of
the cemented joints of the well Casing (16). Within the Tapered
Liner String of the lateral well, is the Production tubing string
(17), equipped with centralizers (18) with a thermal expansion
joint (19), below a hanger (20), set within the lower part of the
Curved Liner (12). The proximate end of the Lateral well liner is
equipped with a cup-packer (21), a landing nipple (22), containing
a wireline-retrievable plug (23) and a PBR (24). The function of
the cup packer (21) is to prevent back-flow of the Steam-lifted
Produced Fluids from the annular space between Liner (3)-tubing
(17), at the start of each Steam Injection Cycle.
[0089] This is the status of one of the Lateral wells, filled with
a solids-free completion fluid, before beginning to drill the hole
for the next Lateral well, connected to a Casing joint above that
of (16).
[0090] FIG. 2 is a vertical cross section of Part 1) of the Modular
Flow Control Apparatus, prior to its full insertion into the Curved
Liner of FIG. 1. It includes two quasi-parallel curved strings of
tubing, (25) and (26), joined together at their lower ends by the
upper branches of an H, or Y, welded connector (34), which brings a
slip stream of Lift-gas from tubing (26), via gas-lift valve (36),
into the produced fluids stream of tubing (25).
[0091] Curved tubing (25), the Lateral well's Production tubing, is
equipped with a sealing stinger (27), matching the PBR (24), hung
within the lower part of the Curved liner of FIG. 1).
[0092] The other curved tubing, (26), is the lift-gas tubing. Its
lower part is equipped with two modified gas-lift mandrels (28) and
(29) suitable for standard 1"OD wireline-retrievable gas-lift
valves. The gas-lift mandrel (28) carries a partial stream of dry
Lift-gas (30), via its gas-lift valve (31), to Production tubing
(25). The other modified gas-lift mandrel (29) carries another dry
lift-gas (30), via its gas-lift valve (32), to the annular space
within the Curved Liner (12), so as to lift said other produced
fluids stream, flowing from the Lateral well Liner annulus upwards
to the annulus between Casing (16) and the Collector Production
tubing (35). The bottom end of the H connector (34), below tubing
(26), is closed with a retrievable plug (36) set within a Landing
nipple (37), thus making the H connector (34) equivalent to a Y
connector. Temporary retrieval, by wireline, of plug (36) and
permanent removal of the plug in Landing nipple (22) allow to fully
displace completion fluid from the Lateral well to the surface, by
Lift-gas, in order to start Oil production operations from said
Lateral well.
[0093] The upper end of the Production tubing (25) is equipped with
a PBR (38), located within the Liner Stub (14), outside of the
window in Casing (16).
[0094] The Lift-gas tubing (26) extends within the annular space
between casing (16) and the coaxial Collector pipe (35), to be
installed with Parts 2 and 3 of said Apparatus.
[0095] It is also equipped at its upper end with a PBR (39)
supported by a guide (40), set within the casing joint (16). Tubing
(26) is connected to a traversing hole (41) in the lower surface of
the guide (40), hung within the Casing (16). A plug's landing
nipple (42a) and a PBR (43) are successively connected on the upper
end of traversing hole (41a), for future isolation of the
Production collector pipe (35) from or connection to matching
stingers in Part 2) of the Modular Flow Control Apparatus.
[0096] FIG. 2A shows a perspective top view of the multi-tubular
Packer (44), used in Part 2) of the Apparatus for a lateral well
and a comparative top view of the guide (40), used, in Part 1) of
said Apparatus, as support of the Lift-gas curved tubing (26) and
of its PBR (39). Respectively the PBR (38) and the curved
Production tubing (25), in Part 1), are in a different radial
vertical plane, than that of Lift-gas tubing (26) and PBR (39),
below the plane surface of guide (40). Packer (44) and guide (40),
however, are both anchored in casing (16), at a short distance
(=<50 ft) from each other.
[0097] The Y, or T, flow connection (49) between tubings (25) and
(26a) is controlled from the surface by the "on-off"valve (53),
open during the Production cycle of the selected Lateral well, as
shown on FIG. 2A. Valve (53) is closed, however, during the Steam
injection and Steam soak periods of that Lateral well.
[0098] Correspondingly, above each multi-tubular. Packer (44),
there is a plurality of PBR's for distributing Lift-gas from the
Casing annulus, through the uppermost Packer, to the lowermost
Packer, in all the stacked-up Apparatus, except in the lowest one,
which requires only one, stinger-equipped, Lift-gas tubing (26a),
hung from a lateral branch of tubing (25a), below Packer (44) and
above a retrievable plug (51). Said plug, when removed, provides
full access to the specific Lateral well's production tubing (25),
via a stack of parallel extension tubings (26a), normally used for
conveying Lift-gas from the Casing annular space, all the way down
to each of the other Lateral wells.
[0099] FIG. 3 shows a vertical cross section of the Modular
Assembly of Parts 2) and 3) of the Flow Control Apparatus, combined
for a specific Lateral well.
[0100] Part 2) is a welded Assembly of a plurality of
quasi-vertical pipes, each one with a sealing stinger (43) at its
lower end, matching a PBR (39) of the upper ends of Part 1) of the
Flow Control Apparatus, and any of those above each Packer (44)
shown on FIG. 2. These pipes are arranged around a central joint of
the shared Collector pipe (35), which belongs to Part 3),
pre-installed on the axis of the vertical Casing (16).
[0101] These pipes, dedicated to the specific Lateral well,
include, from the bottom-up:
[0102] a sealing stinger (38a) of the lower end of an extension of
Production tubing (25a), matching PBR (38), at the top of Part 1)
of said Apparatus,
[0103] an extension of the Lateral well Production tubing (25a),
covering the interval between said stinger (43a) and a traversing
hole through the multi-tubular Packer (44), leading to PBR (52), at
the top of the Modular Assembly and, from there, to a stack of
Lift-gas feeder supply pipes, through all the Modular Assemblies
stacked above Packer (44), and carrying Lift-gas from the casing
annular space, all the way down to PBR (39), at the top of Part 1)
of the Modular assembly, in FIG. 2,
[0104] in said extension (25a) of the Production tubing, the
retrievable 3-way Valve (45), primarily used to switch the Lateral
well from Steam injection to Oil Production, and
[0105] three lateral Y, or T, branch tubular connectors, all
originating from tubing (25a), and located below the retrievable
plug (51).
[0106] Said branch connectors include, from the top down:
[0107] a) the slanted branch of the inverted Y connector (49)
leading, via an "on-off" valve (53), below Packer (44), to the
upper end of a Lift-gas extension pipe (26a), within Part 3 of the
Modular Assembly, and, above said Packer (44), via said stack of
Lift-gas feeder supply pipes (58) in all the super-imposed Modular
Assemblies, ultimately leading, via the gas-filled Casing Annulus,
to the well head Lift-gas supply line, at the surface,
[0108] b) the Upper lateral Y, or T, branch (46), leading to the
axial Collector pipe (35), when the 3-way Valve (45) is closed to
the shared Steam tubing (48), and open to Production fluids,
[0109] c) between said Upper lateral branch (46) and said 3-way
Valve (55), a first Float valve (32a), set in a standard gas-lift
mandrel (29a) to allow the entry of a Production fluids slip stream
into tubing (25a), from the casing annular space below packer (44),
only when the level of the liquid phases. (Oil and water) of said
Production fluids is high in said annular space (i.e. during the
Lateral well's Production cycle}, but not when said liquids level
is low (i.e. during the Steam injection and Steam soak
periods),
[0110] d) the Lower lateral Y, or T, branch (47), which leads, via
the side inlet of the 3-way valve (45), to the Insulated Steam
tubing joint (48), coaxially located within the bare Production
Collector pipe (35).
[0111] Conversely, a Lift-gas feeder extension pipe (26a), leading
from said slanted branch (49) of the Y connector, above said
"on-off" valve (53), via an extension of Lift-gas tubing (26a) to
another gas-lift mandrel (28) and, via a second Float valve (31),
to the Bottom Lateral branch (57) of a Y, or T, connector, delivers
Lift-gas from (26a) to carry a slip stream of Production liquids
from the Casing annular space to the Production Collector pipe
(35). This transfer of Production liquids from the casing annular
space into pipe (35) only takes place during the Steam soak period.
It automatically stops when the liquid level in the casing annular
space has dropped below the 3-way valve (45), when Steam rising
into the reservoir has sufficiently reduced the casing pressure,
before the start of a new Production cycle.
[0112] Table 1 summarizes the position of each type of plug or
valve in each of the three parts of the Flow Control Apparatus, for
each of the three modes of operation of the Lateral well, as an
example of the Flow Control Apparatus.
[0113] Of all the Part 3) tubulars dedicated to the specific
Lateral well, only PBR (52) is above Packer (44); the other
tubulars above (44) are either shared by all wells, such as (35)
and the Insulated Steam tubing, or they belong to the Lift-gas
distribution systems of other Lateral wells.
[0114] This disposition limits the number of peripheral traversing
holes through the Packer (44) to one, for the lowermost Packer, and
to a maximum of eight, through the uppermost Packer of the eighth
Lateral well.
[0115] The conventional "on-off" Valve (53), hydraulically-operated
from the surface, and retrievable by wireline, is set in a mandrel
(53a), above the stinger of the Lift-gas feeder extension, located
just below the retrievable plug (51). When Valve (53) is open, the
partial Lift-gas stream, distributed to the selected Lateral well,
flows down from a gas-filled Casing annulus to the Lift-gas
extension pipe (26a) and from there to the curved tubing (26) and
back-up to the surface, via the gas-lift Valve (31) in its mandrel
(28) to the Production tubing (25) and its extension (25a), into
the Production Collector pipe (35) and, from there, via the
"Super-insulated" Production tubular, to the surface.
[0116] Conversely, the Production stream from the annulus between
the "quasi-horizontal" Liner (3) and tubing (17) is lifted-up by
Lift-gas delivered by the curved tubing (26) to the annular space
between the Curved liner (12) and the twin tubings (25) and (26),
via the gas-lift Valve (32) in Mandrel (29).
[0117] The resulting lightened stream is then delivered, first to
the annular space of Casing joint (16) and, from there to the
Production Collector pipe (35) via an open Float Valve or Standing
Valve (31a), preferably retrievable from a modified gas-lift
mandrel forming a welded H joint with Collector pipe (35).
[0118] This arrangement of parallel pipes in the Casing annulus,
below the "Super-insulated" Production tubular, reduced their
number from one, in the lowermost Modular Assembly, to a maximum of
8 for the uppermost Modular Asssembly, for a maximum stack of 8
lateral wells.
[0119] Each lateral well tubing string (17) is accessible via its
own Production tubing (25), after removal of the single retrievable
plug (51) by wireline tools, from the surface, through the stacked
Lift-gas feeder extension tubings (26a) and the gas-filled Casing
annular space.
[0120] The connection, by means of a sealing stinger in a PBR, of
each of the stacked Lift gas extension pipes (26a) provides
flexibility when the length of the much hotter Production Collector
pipe (35) increases, from the fluids heat.
[0121] The same type of flexible sealed connection is used for each
Production Tubing (25), in addition to the Thermal expansion joint
(19) at the upper end of the "quasi-horizontal" tubing string
(17).
[0122] The entire tubing completion, described above and in FIG. 1
to 3, is run-in, oriented and installed by conventional means,
using a standard Service rig.
[0123] Each Lateral well may be temporarily isolated by two
wireline retrievable plugs, respectively closing its Production
tubing and its Lift-gas tubing. The completion fluid in the casing
above the uppermost Apparatus is displaced out and replaced by dry
air or gas, at atmospheric pressure. The vertical well is then
ready to receive, first, the protective tubing string of the
Production tubular, second, the Production coaxial
"Super-insulated" tubular, third, the protective tubing string of
the Steam coaxial "Super-insulated" tubular and, finally, the Steam
coaxial "Super-insulated tubular.
[0124] During the life of any Lateral well, for any repairs, the
tubing completion may be dis-assembled by conventional means, using
a Service rig. The procedure is the reverse of that used for its
installation.
[0125] FIG. 4 is a Schematic Block Diagram showing, with arrows,
the flow paths of the various Fluid Streams of 2 Lateral wells,
simultaneously operated respectively under Steam injection, on the
Right side, and under Production on the Left side. A legend shows
the symbols used respectively for:
[0126] the Production Flow Stream, from both the Lateral well's
annular space and from its Production tubing.
[0127] the Steam Flow Stream, within the Lateral well
[0128] the Lift-gas Flow Stream, before and after it is mixed with
the Production Stream.
[0129] This Block Diagram illustrates and summarizes the previous
description of Part 1), Part 2), and Part 3) of the Downhole Flow
Control Modules of two of the Lateral wells, in relation with the
shared facilities: the gas-filled upper Casing annular space, the
"Super-insulated" Production tubular assembly, and the
"Super-insulated" Steam tubular assembly.
[0130] FIG. 5 is a vertical and radial cross section, showing the
upper coupling end of the "Super-insulated" Steam tubular. It
includes the Box (54) of a lower joint of the inner tubing (55),
designed for always carrying Steam, under the selected mode of
Operation of the Multi-lateral Well.
[0131] The Box (54) is located on the same vertical axis as a
matching pin (56) of the next Steam tubular joint (55a) above
tubing (55).
[0132] The threads (59), in Box (54), are of one of the
conventional types which provide a metal to metal seal, against the
male threads of the pin (56a) to which they will be tightly
coupled, after a specified torque has been applied to their
coupling.
[0133] Below the Box (54), a thin corrugated metal collar (60) has
been affixed and sealed, by welding or brazing, to the outer
surface of the Steam tubular (55), along the entire circumference
of tubing (55). At a short distance below Collar (60), a
Centralizer metal guide (61), also affixed to the outer surface of
(55), presents a plurality of radial extensions (62), sliding
within matching longitudinal guides (63), affixed to the inner
surface (64), of the outer tubing (65).
[0134] Both tubings (55) and (65) are coaxial and the guides (63)
are parallel to the common axis of tubings (55) and (65).
[0135] It will be apparent to the Man of the Art that this
combination of the metal centralizer extensions (62) and guides
(63), in which they slide, prevents the outer tubing (65) from
rotating around its coaxial inner tubing (55). The only relative
motion allowed by such devices, between the two tubings (65) and
(55) is that of a translation along their common axis. The number
of such devices per joint is also not limited to two. All other
means for achieving the same goals, are also included in the
present Invention.
[0136] The metals of collar (60) and centralizer guide (61) are
chosen for their relatively low thermal conductivity, low thermal
expansion and high strength, such as those of alloys containing two
or more metals taken from the alphabetic list of: Aluminum,
Antimony, Cadmium, Copper, Chrome, Iron, Manganese, Molybdenum,
Nickel, Silicon, Silver, Titanium, Vanadium and Zinc.
[0137] The metals of the insulation cover tubing (65) are chosen
primarily for their ease of assembly, by welding or brazing, with
the alloys of collars (60) and for their thermal expansion, higher
than that of steel, such as Zinc or Aluminum alloys, in order to
minimize the difference between their thermal expansion with that
of the inner steel tubular (55), which operates at a much higher
temperature than the insulation cover tubing (65).
[0138] The annular space between (65) and (55) is factory-filled
with fibrous "Super-insulation" (66). The outer edge of extended
Collar (60) is also affixed and sealed, preferably by welding or
brazing, to the inner surface of the outer thin tubing (65).
[0139] In a First Embodiment of the Invention, the twin tubings
(55-65) and (55a-65a) of two superposed joints of factory-assembled
"Super-insulated" Steam or Production tubulars, (the index "a"
meaning "above") respectively present similar coaxial systems
including, but not limited to:
[0140] a Centralizer metal guide (61a), with radial wire-type
extensions (62a) sliding into matching guides (63a),
[0141] two circularly corrugated metal collars (60),(60a), closing
the top and the bottom of the annular space between the coaxial
tubings (55-65) and (55a-65a) and supporting the fibrous
"Super-insulation" (66a).
[0142] a granular "Super-insulation" ring (69), pre-packed in metal
foil at the factory, and fitted, on the rig, over the collar (60),
so as to fill the annulus between the ends of tubing joints (55)
and (65), prior to making-up, by conventional means, the coupling
operation of the upper and lower joints of either Steam or
Production tubulars strings:
[0143] The lower joint (55), or (65), is held in Slips, and the
upper joint (55a), or (65a), is held in the rig's Top-drive. They
are then coupled together, in the rig, by a standard, pin to box,
threaded, welded or brazed connection.
[0144] The joints are inserted into their respective thick,
protective, air-filled, tubular string (70), for Steam, or (71),
for Production fluids, previously run-in and assembled, at their
lower ends, into their corresponding PBR or threaded coupling,
located at the top end of the uppermost Flow Control Apparatus. All
six coaxial tubular strings, (73), (72), (71), (70), (65), (55), at
their upper ends, are sequentially hung in the well head and held
in tension, by means of conventional devices.
[0145] FIG. 6 is a horizontal cross section of the two coaxial
"Super-insulated" tubulars,(65/55) used for carrying, respectively,
Injection Steam, at the center, and the surrounding Production
tubular (70/72), also "Super-insulated". The Production stream
flows in counter-current to that of Steam. The insulation thickness
of of the Steam tubular is based upon the Steam temperature (nearly
constant), which is related to reservoir depth. The temperature of
the Production tubular, which is much lower and declines, from the
bottom-up, allowes the use of a different fibrous, lower-cost,
"Super-insulation" material.
[0146] FIG. 6A is a schematic vertical cross section of the
Vertical well head and casing, showing the surface connections
(some of them them hot) of both of the "Super-insulated" well
tubulars, in relation the cold Casing (16).
[0147] The length of the "Super-insulated" Steam tubular (55)
extends almost to the base of the vertical Casing, but that of the
"Super-insulation" in the Production tubular string (71) stops a
short distance above the uppermost multi-tubular Packer (44).
[0148] The inner (71) and outer (72) tubings of the
"Super-insulated" Production tubular string, and their Protective
tubing string (73) are all respectively hung to the Well head and
remain under tension, so as to prevent buckling.
[0149] On FIG. 6A, the bottom end of (73), which remains relatively
cold, is directly coupled to the hot bottom end of (71) by a
modified thermal expansion joint (74), which provides a
pressure-resistant annular barrier to protect the
"Super-insulation" compartment (71/72) from any fluid entry from
either the pressurized gas-filled Casing annulus or from any
accidental leak of Production fluids into said Casing annulus, from
the Stinger-PBR connection of tubing (71) with the uppermost joint
of the Production Collector pipe (35). Similarly, the Protective
tubing string (70) of the "Super-insulated" Steam tubular string
(55/65) is hung in the well head and connected, at its bottom end,
to the Apparatus' tubing (55), via a modified thermal expansion
joint (75), so as to protect the "Super-insulation" in the annular
compartment (55-65) from any entry of Production fluids or of any
high pressure Steam, possibly leaking from the Stinger-PBR
connection of the inner tubular string (55) with the Production
Collector pipe (35), at the top of the uppermost Packer (44). The
modification of the thermal expansion joints (74) and (75) and of
the seals in the Stinger/PBR connections includes the addition of
one or more Graphite ring seal (76), under compression.
[0150] In a Second Embodiment of this Invention, it is the outer
Protective tubing string (70) which supports "Super-insulation"
(66). Corrugated collars (60, 60a) and the insulation cover tubing
(65) are now affixed, by welding or brazing, to the outer tubing
(70), thereby providing a sealed enclosure to the fibrous
"Super-insulation". The inner diameter of the insulation cover
tubing (65) is only slightly larger than the Steam tubing outside
diameter. It is also coated with a graphite suspension lubricant.
The inner Steam tubing threaded string (55), in this case, may
advantageously be replaced by a coiled tubing string, inserted
within the insulation cover tubing (65), and sealed within the
Apparatus' PBR matching the Protective tubing (70), as the last
step of the vertical cased well tubing completion. This
substitution totally eliminates the risk of damage or contamination
of the "Super-insulation" by any high-pressure Steam leak, since
there are now no joints in the Steam tubing string (55). In
addition, a film of dry, low pressure Lift-gas circulates in the
very thin annular space between the coiled tubing (55) and the
insulation cover tubing (65), as a further shield from the entry of
moisture into the sealed insulation space via the welded or brazed
joints of tubing (65).
[0151] The metals of choice for that small-diameter coiled string
is then Titanium and its alloys, which are also corrosion resistant
and subject to a lower thermal expansion than steel. The higher
cost of Titanium is partially offset by a reduction in the cost of
tubing (65), which has a smaller diameter than in the First
Embodiment.
[0152] The thin-gauge metal of the insulation cover tubing (65),
now being at a higher temperature than its support, namely the
protective tubing (70), is now selected for its lower thermal
expansion coefficient than that of the steel of tubing (70), in
order to reduce their differential expansion. Such low thermal
expansion alloys are found among high Nickel alloy steels, such as
"Invar", as well as among, more costly, Titanium alloys.
[0153] The designs of the "Super-insulated" Production tubulars
(71), (72) and (73), associated with the new (55), (65) (70) could,
perhaps, remain as in the First Embodiment, thereby combining both
embodiments in the same vertical well, as shown on FIG. 6A. A
circulation of a slip stream of dry Lift-gas within the thin
annular between (71) and (72) remains very advantageous, however,
when (71) is a threaded pipe string, more prone to water vapor
leaks than the coiled tubing string of (55).
[0154] FIG. 7 is a perspective drawing and radial cross section of
some tools to be used at the factory and on the rig, for centering
each joint of Steam tubing (55) and its insulation cover tube (65),
in the First Embodiment.
[0155] Both ends are equipped with corrugated collars (60), at the
factory, where they are inserted and slide freely within their
thick protective tubing (70). To facilitate such insertion,
graphite-based lubricants coat the inside surface of of tubing
(70).
[0156] A box-type thread-protector (77), presenting a central plug,
is inserted within the lower end of tubing joint (55) and screwed
around the pin of the tubing joint (70). Conversely, a pin-type
thread-protector (78) is simultaneously inserted into the boxes at
the upper end of tubing joints (55) and (70), thereby insuring that
the temporary assembly of the "Super-insulated" joint (55), within
its Protector tubing joint (70) can be laid down, shipped to the
well-site and handled by the rig as a single element, without any
damage to the "Super-insulation" nor to its thin-gauged, sealed,
protecting cover tube (65). With this element vertical and tubing
(70) firmly held in slips, the upper pin-type thread-protector (78)
is then removed, the box-type upper end of tubings (55) and its
insulation, sealed within its cover tube (65) is grabbed by the Top
drive's pipe handler and handled as a whole to the vertical rack,
for temporary storage. After removal of (77), the remaining
protector tubing joint (70) held in the slips is then added to the
string of previous joints (70) and run-in and set in the previously
installed "Super-insulated" Production tubing (73/72/71), using the
same means.
[0157] Thread-protectors (77) and (78) are surface tools provided
by the factory licensed to supply all the "Super-insulated"
tubings.
[0158] Most Top Drive rigs already include a Torque Wrench,
equipped with a Torque Indicator, which insures that torque applied
to each of the coaxial threaded couplings of pipe joints (73),
(71), (65) and (55) have specified decreasing values.
[0159] Additional surface tools, used on the rig, also include
welding or brazing machines for sealing the "Super-insulation" of
threaded couplings, respectively used in both embodiments of the
Invention.
[0160] In the First Embodiment, the circular edges of the Steam
tubular joints (55) and (55a), respectively held stationary in a
coaxial position by the slips of the rotating table and by the Top
Drive, are used for guiding the roller electrodes (79), (79a) of a
conventional rotating "seam welding" machine, around the circular
edges of the sheet metal of the insulation cover tubings (65) and
(65a), which are pressed together by said rollers (79) and (79a),
prior to the insertion of the coupling of the insulated tubing
joint of (55) within its pre-installed Protective tubing string
(70).
[0161] In the Second Embodiment, a similar type of welding, or
brazing machine is inserted within each joint of the tubular string
(65), and guided around to seal the circular edges of the "slick"
box and pin sheet metal coupling of the "Super-insulation" cover
tubing joints (65) and (65a), after the associated coaxial
Protective joints (70) and (70a) have been coupled together and
torqued, prior to being run-in.
[0162] In view of the importance of keeping the "Super-insulation"
very, dry, the leak-proof quality of each "seam weld" is monitored
first during the welding operation of each joint of said insulation
cover tube. This is done by checking the absence of moisture in a
very dry, light gas, such as Helium, injected, at low pressure, by
a wireline-retrievable small gas tank within the temporarily
plugged end of each of the two sealed insulation cover tubular
assemblies, while the string is being run-in. The same instrument
is later used as a surface tool, throughout the lifetime of the
multi-lateral well, using a slip-stream of dry lift-gas (mostly
Methane) under permanent circulation, from the casing annulus, back
to the surface, to detect any moisture content, picked-up either
from defects in said "seam welds", or due to any leaks of Steam or
of Steam Condensate, or of formation water in the system, while in
operation.
[0163] While certain embodiments and materials of the invention
have been specifically disclosed, it should be understood that the
invention is not limited thereto, as many variations will be
apparent to those skilled in the Art and the invention is to be
given the broadest possible interpretation.
1TABLE 1 POSITIONS OF FLOW CONTROL APPARATUS DEVICES DURING VARIOUS
PERIODS Devices: # Valves/ Apparatus: * Pumps Position during
Periods: Part FIG. No. Type Steam Injection Soak Oil Production 3
2a (53) On-off Closed Closed Open 3 3 (32a) Gas-lift, Float/ Closed
Closed Open Hydraulic, Jet 3 3 (45) 3-way Axis Closed/ Axis Open/
Axis Open/ Side Open Side Closed Side Closed 3 3 (31a) Gas-lift,
Float/ Closed Opening Open Hydraulic, Jet 2 2 (31) Gas-lift, Float/
Closed Open Open Hydraulic, Jet 1 2 (32) Gas-lift Closed Open Open
DEVICE: # Valves I * pumps I PRIOR ART: Reference 1, FIG. 6 I
Reference 1, FIG. 3 I OIL-LIFT FLUID: Natural Gas, C1-C3+ I Natural
Gas Liquids, C3-C5+ I FLUID ORIGIN: Locally-available I Imported I
FLUID END-USE: On-site Fuel I Re-cycled I TARGETED SITE: Alaskan
Arctic I Deep Offshore
* * * * *