U.S. patent application number 13/556458 was filed with the patent office on 2014-01-16 for methodology and system for producing fluids from a condensate gas reservoir.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is WAEL ABDALLAH, MOHAMMED BADRI, REZA TAHERIAN. Invention is credited to WAEL ABDALLAH, MOHAMMED BADRI, REZA TAHERIAN.
Application Number | 20140014327 13/556458 |
Document ID | / |
Family ID | 49912949 |
Filed Date | 2014-01-16 |
United States Patent
Application |
20140014327 |
Kind Code |
A1 |
BADRI; MOHAMMED ; et
al. |
January 16, 2014 |
METHODOLOGY AND SYSTEM FOR PRODUCING FLUIDS FROM A CONDENSATE GAS
RESERVOIR
Abstract
A method of producing reservoir fluids from a condensate gas
reservoir traversed by a production well includes the formation of
a protrusion into natural gas bearing rock along a producing
interval of the reservoir. A heater element is placed into the
protrusion and configured for operation. Reservoir fluids are
produced from the producing interval while the heater element heats
the natural gas bearing rock proximate the heater element. The heat
supplied by the heater element reduces condensate build up in the
natural gas bearing rock adjacent the production well during
production. The heater element is configured to heat the natural
gas bearing rock that is proximate the heater element to a
temperature that is sufficient to vaporize and/or reduce the
viscosity of condensate that is proximate the heater element. A
related system is also described.
Inventors: |
BADRI; MOHAMMED; (AL-KHOBAR,
SA) ; ABDALLAH; WAEL; (AL-KHOBAR, SA) ;
TAHERIAN; REZA; (AL-KHOBAR, SA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
BADRI; MOHAMMED
ABDALLAH; WAEL
TAHERIAN; REZA |
AL-KHOBAR
AL-KHOBAR
AL-KHOBAR |
|
SA
SA
SA |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
49912949 |
Appl. No.: |
13/556458 |
Filed: |
July 24, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61671509 |
Jul 13, 2012 |
|
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|
Current U.S.
Class: |
166/248 ;
166/250.01; 166/298; 166/302; 166/55; 166/57; 175/2 |
Current CPC
Class: |
E21B 43/32 20130101;
E21B 43/24 20130101 |
Class at
Publication: |
166/248 ;
166/302; 166/298; 175/2; 166/250.01; 166/57; 166/55 |
International
Class: |
E21B 43/24 20060101
E21B043/24; E21B 29/06 20060101 E21B029/06; E21B 43/26 20060101
E21B043/26; E21B 43/11 20060101 E21B043/11; E21B 43/12 20060101
E21B043/12; E21B 36/00 20060101 E21B036/00; E21B 43/116 20060101
E21B043/116 |
Claims
1. A method of producing reservoir fluids from a condensate gas
reservoir traversed by a production well, comprising: forming at
least one protrusion in or adjacent to a producing interval of the
gas reservoir, wherein the protrusion is configured to receive a
heater element; placing the heater element into the protrusion and
configuring the heater element for operation; and producing
reservoir fluids from the producing interval while operating the
heater element.
2. A method according to claim 1, wherein: the heater element is
configured to raise the temperature of reservoir adjacent to the
protrusion to vaporize the condensate that is proximate the heater
element.
3. A method according to claim 1, wherein: the protrusion
configured to receive the heater element is formed by a device
selected from the group consisting of a perforation gun, a high
power laser, a casing drilling instrument, and a direction drilling
tool.
4. A method according to claim 1, further comprising: forming a
production protrusion in the producing interval of the gas
reservoir, wherein the production protrusion is located proximate
to an associated protrusion for the heater element.
5. A method according to claim 4, wherein: the production
protrusion is formed by a device selected from the group consisting
of a perforation gun, a high power laser, a casing drilling
instrument, and a direction drilling tool.
6. A method according to claim 4, wherein: said forming a
production protrusion comprises hydraulic fracturing.
7. A method according to claim 1, wherein: the heater element
comprises a resistive heater element.
8. A method according to claim 1, wherein: the heater element
comprises an antenna that directs electromagnetic radiation.
9. A method according to claim 8, wherein: said electromagnetic
radiation is generated by a downhole source of electromagnetic
radiation together with conductors or a waveguide that supplies
electromagnetic energy generated by the source to the antenna.
10. A method according to claim 1, wherein: the heater element is
supplied with heat from an external heat source.
11. A method according to claim 1, further comprising: injecting
metal particles into the reservoir adjacent to the protrusion.
12. A method according to claim 11, wherein: said metal particles
are metal nanoparticles.
13. A method according to claim 1, further comprising: monitoring
the flow rate of produced reservoir fluids.
14. A method according to claim 1, further comprising: monitoring
at least one temperature and pressure of the condensate reservoir
as a function of location along the producing interval.
15. A method according to claim 1, further comprising: monitoring
at least one temperature and pressure of the condensate reservoir
in the vicinity of the heater element as a function of radial
offset away from the borehole wall.
16. A method according to claim 1, further comprising: measuring a
rate at which the reservoir fluids are produced and controlling the
heating element in order to control said rate.
17. A system for producing reservoir fluids from a condensate gas
reservoir traversed by a production well, the system comprising: at
least one heater element that is configured for disposition inside
a protrusion in or adjacent to a producing interval of a gas
reservoir; equipment coupled to and configured to operate the at
least one heater element; and wherein the heater element is
configured to heat the reservoir proximate the heater element,
reducing condensate build up.
18. A system according to claim 17, wherein: the heater element is
configured to heat the natural gas bearing rock that is proximate
the heater element to a temperature that is sufficient to vaporize
the condensate that is proximate the heater element.
19. A system according to claim 17 further comprising: a perforated
casing, wherein the protrusion for the at least one heater element
is located below and proximate to at least one perforation in the
casing located along the producing interval of the production well,
the perforation providing fluid communication between the natural
gas bearing rock and the producing interval of the production
well.
20. A method of producing reservoir fluids from a condensate gas
reservoir traversed by a production well, comprising: forming at
least one protrusion into a rock bearing natural gas along or
adjacent a producing interval of the gas reservoir, the protrusion
extending in a substantially radial direction away from the central
axis of the production well into the rock, wherein the protrusion
is configured to receive a heater element; placing the heater
element into the protrusion and configuring the heater element for
operation by surface located equipment; and producing reservoir
fluids from the producing interval of the gas reservoir while
operating the heater element to heat the natural gas that is
proximate the heater element, whereby heat supplied by the heater
element reduces condensate build up in the rock during the
production of reservoir fluids from the producing interval.
21. A method according to claim 20, further comprising: forming a
production protrusion in the producing interval, wherein the
production protrusion is located proximate to an associated
protrusion for the heater element.
22. A method according to claim 21, further comprising: perforating
a casing to form at least one perforation along the producing
interval, the perforation providing fluid communication between the
production protrusion and the production well, wherein the
perforation is located above and proximate to an associated
protrusion for a respective heater element.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This application claims benefit of U.S. Provisional Patent
Application Ser. No. 61/671,509 filed Jul. 13, 2012, the contents
of which are incorporated herein by reference.
FIELD
[0002] This case relates to wells that produce gas and
condensate.
BACKGROUND
[0003] Condensate blocking is a common problem in gas wells. The
techniques used to cope with this problem can include fracturing,
drilling new wells, injecting solvents, etc. It is well known that
the pressure and temperature play an important role in the phase
behavior of a compound; variation of these parameters can cause the
compound to transition between gas phase, liquid phase, and solid
phase.
SUMMARY
[0004] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
[0005] According to one aspect, a method of producing reservoir
fluids from a condensate gas reservoir traversed by a production
well includes forming at least one protrusion into natural gas
bearing rock along a producing interval of the production well. The
protrusion extends in a radial direction away from the central axis
of the production well into the natural gas bearing rock, and the
protrusion is configured to receive a heater element. The heater
element is placed into the protrusion and configured for operation
by surface located equipment. While producing reservoir fluids from
the producing interval of the production well, the respective
heater element is operated to heat the natural gas bearing rock
that is proximate the heater element. The heat supplied by the
heater element reduces buildup of condensate in the natural gas
bearing rock adjacent the producing interval of the production well
during the production of reservoir fluids from the producing
interval.
[0006] In one embodiment, the heater element is configured to heat
the natural gas bearing rock that is proximate the heater element
to a temperature that is sufficient to vaporize and/or reduce the
viscosity of condensate that is proximate the heater element. The
protrusion can be formed by a device selected from the group
consisting of a perforation gun, a high power laser, a casing
drilling instrument, and a directional drilling tool. The
protrusion may also be formed by any other desirable means.
[0007] In one embodiment, the reservoir fluids are produced through
at least one perforation in a casing. The at least one perforation
can extend into the natural gas bearing rock along the producing
interval of the production well. The at least one perforation
provides fluid communication between the natural gas bearing rock
and the producing interval of the production well.
[0008] In one embodiment, a perforation in a casing is located
above and proximate to an associated protrusion for a respective
heater element. The heat supplied by the respective heater element
can vaporize condensate to form a gas that flows to the associated
perforation for production of the gas therethrough. The heat
supplied by the respective heater element can also reduce the
viscosity of liquid phase condensate that is proximate the heater
element to promote the flow of the liquid phase condensate to the
associated perforation for production of the liquid phase
condensate gas therethrough.
[0009] The at least one perforation can be formed by a device
selected from the group consisting of a perforation gun, a high
power laser, a casing drilling instrument, and a direction drilling
tool. The at least one perforation can be formed or enhanced by
hydraulic fracturing.
[0010] In another method embodiment, the heater element is supplied
with heat from an external heat source and transfers the heat into
the gas bearing rock matrix that is proximate to the heater
element.
[0011] The method can further include injecting metal nanoparticles
into the gas bearing rock in the vicinity of the heater element to
promote localized heating of such gas bearing rock. The metal
nanoparticles are injected into the gas bearing rock in an area
where condensate forms or is likely to form during production.
[0012] The method can also include monitoring operations, such as
monitoring the flow rate of produced reservoir fluids, monitoring
temperature and/or pressure of the condensate reservoir as a
function of location along the producing interval, and monitoring
temperature and/or pressure of the condensate reservoir in the
vicinity of the heater element as a function of radial offset away
from the producing interval.
[0013] In another aspect of the present application, a system for
producing reservoir fluids from a condensate gas reservoir
traversed by a production well includes at least one heater element
that is configured for disposition inside a respective protrusion
into natural gas bearing rock along a producing interval of the
production well. The protrusion and corresponding heater element
extend in a radial direction away from the central axis of the
production well into the natural gas bearing rock. Equipment,
surface located, is configured to operate the at least one heater
element. The heater element is configured to heat the natural gas
bearing rock that is proximate the heater element. Heat supplied by
the heater element reduces the buildup of condensate in the natural
gas bearing rock adjacent the producing interval of the production
well during the production of reservoir fluids from the producing
interval. In one embodiment, the heater element is configured to
heat the natural gas bearing rock that is proximate the heater
element to a temperature that is sufficient to vaporize and/or
reduce the viscosity of condensate that is proximate the heater
element.
[0014] The protrusion for a respective heater element can be
located below and proximate to at least one perforation in a casing
that can extend into the natural gas bearing rock along the
producing interval of the production well. The perforation provides
fluid communication between the natural gas bearing rock and the
producing interval of the production well. The heat supplied by the
respective heater element can vaporize condensate to form a gas
that flows to the perforation for production of the gas
therethrough. The heat supplied by the respective heater element
can also reduce the viscosity of liquid phase condensate that is
proximate the heater element to promote the flow of the liquid
phase condensate to the perforation for production of the liquid
phase condensate gas therethrough.
[0015] In one embodiment, the heater element is realized by a
resistive heater element.
[0016] In another embodiment, the heater element is realized by an
antenna that directs electromagnetic radiation into the natural gas
bearing rock. A downhole source of electromagnetic radiation can be
provided (in the producing interval of the production well)
together with cables or a waveguide that supplies the
electromagnetic radiation generated by the source to the
antenna.
[0017] In yet another embodiment, the heater element is supplied
with heat from an external heat source and transfers the heat into
the gas bearing rock matrix that is proximate to the heater
element.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] FIG. 1 is a phase diagram of a typical gas condensate.
[0019] FIG. 2 is a cross sectional view of a gas condensate
reservoir traversed by a vertical gas producing well.
[0020] FIG. 3 shows the pressure measurements of a production well
for a sequence of first draw down cycle (labeled "1DD") followed by
a first build up cycle (labeled "2BU") followed by a second drawn
down cycle (labeled "3DD") followed by a second build up cycle
(labeled "4BU").
[0021] FIGS. 4A and 4B are graphs of condensate saturation (the
percent of formation porosity filled with condensate) for gas
condensate reservoirs, where the condensate saturation is plotted
against radius into the respective formation.
[0022] FIG. 5 is a flow chart outlining a methodology for producing
reservoir fluids from a condensate gas reservoir.
[0023] FIG. 6 is a schematic diagram of a condensate gas production
well that employs the condensate heating methodology of FIG. 5.
[0024] FIG. 7 is a schematic diagram that illustrates the heating
profile of the heater element of FIG. 6.
[0025] FIG. 8 is a schematic diagram of a condensate gas production
well that carries out monitoring operations in conjunction with the
condensate heating methodology of FIG. 5.
DETAILED DESCRIPTION
[0026] FIG. 1 shows the phase diagram of a typical gas condensate
(also called retrograde gas). This diagram shows how gas condensate
can transition back and forth between gas phase and liquid phase.
Point 1 in FIG. 1 corresponds to a gas phase. The line from point 1
to 3 is an isotherm wherein the temperature is kept constant while
the pressure is reduced. When the pressure becomes equal to that of
point 2 (on the saturation line), liquid starts to form and coexist
with the gas phase. Continuing to reduce the pressure, as indicated
by point 3, further liquid is formed. Point 2 is referred to as the
dew point or condensation point if it is located above the critical
point, and is referred to as the bubble point if it is located
below the critical point.
[0027] Reservoir hydrocarbons are a mixture of different
hydrocarbon species that are present as either a liquid phase or
gaseous phase depending on location from the critical point at the
saturation line. For natural gas reservoirs, the industry
distinguishes between two different types, dry gas reservoirs and
condensate gas reservoirs (also referred to wet gas reservoirs).
Dry gas reservoirs contain more than 90% methane and traces of
C.sub.2-C.sub.5 which will remain in the gas phase for all
practical cases. The dry gas reservoirs do not produce condensates.
Condensate gas reservoirs are composed of C.sub.1 to C.sub.12
hydrocarbon species (where Ci is a hydrocarbon with i carbon atoms
and the corresponding hydrogen atoms). Since the hydrocarbon
species with carbon numbers greater than 4 have the potential of
liquefying, the gas components with Cn (n>4) from these
reservoirs can condense into liquid under the appropriate
temperature and pressure; thus, the name condensate gas (or wet
gas). Condensate gas reservoirs normally have high enough
temperature and pressure that, before the production starts, all
components are in the single (gas) phase. Once production starts,
it causes the pressure to decline, causing the temperature and
pressure to touch the saturation line, as shown in point 2 of FIG.
1. As a result, the gas begins to condense and liquid begins to
form. At this point, the heaviest component of fluid mixture
constitutes the liquid phase. At point 2, vapor and liquid coexist
within the two phase region of the phase envelope. Further pressure
reduction causes the next heavier component to liquefy, and this is
followed by the next heavy component, etc. The majority of the
produced fluid is typically gas; generally a gas condensate
reservoir produces less than 25% liquid condensate. The liquid
dropout (condensate) does not flow as fast as the gas and falls
behind. As this trend continues the volume of condensate increases
and can interfere with gas production.
[0028] FIG. 2 is a cross sectional view of a gas condensate
reservoir traversed by a vertical gas producing well, where
production from the well has resulted in build-up of condensate at
the bottom of the reservoir. The condensate is expected to build up
from the bottom because as a liquid it has higher density than the
gas phase. It is common to divide part of the reservoir close to
the production well into three cylindrical zones (zone 1, zone 2
and zone 3) as shown in FIG. 2. Zone 3, which is far away from the
well, is the unperturbed reservoir and is characterized by a single
(gas) phase. In this zone the gas pressure and temperature are
above the dew point preventing any phase change. Unless any liquid
has been present initially, there will not be any condensate or
liquid formed as a result of production (yet). This is in contrast
with zones 2 and 1 wherein the temperature and pressure are such
that the system is already below the dew point and two phases
(liquid and gas) coexist. As more and more gas is produced, the
pressure drops and the boundaries between the zones shift. In the
intermediate zone 2, only the gas flows while the condensate
remains low but stagnant. In zone 1, which is adjacent to the
borehole wall, both condensate and the gas flow, although the
condensate flows at a slower rate, and accumulates as a function of
time. The condensate volume in zone 1 reduces the flow rate of the
gas and eventually can completely block the flow of the gas into
the well.
[0029] Details about these zones and the reservoir can be obtained
from pressure measurements on the well. FIG. 3 shows the pressure
measurements for a sequence of a first draw down cycle (labeled
"1DD") followed by a first build up cycle (labeled "2BU") followed
by a second drawn down cycle (labeled "3DD") followed by a second
build up cycle (labeled "4BU"). During the first and second build
up cycles, the production is stopped (usually completely) leading
to a pressure increase. The well is kept at that condition for a
period of time to allow all zones to come to an equilibrium state.
During the first and second drawn down cycles, production occurs
from the well, which causes the pressure to drop. The pressure
variation over time can be analyzed to determine the reservoir
properties.
[0030] For example, it is common to analyze the pressure
measurements obtained from a sequence of draw down cycles and build
up cycles (such as the sequence of FIG. 3) to characterize the size
of the reservoir, the pressure at different zones, the size of
different zones, etc. Two such results are shown in FIGS. 4A and 4B
where the condensate saturation (the percent of formation porosity
filled with condensate) is plotted against radius into the
formation. In these figures, far enough away from the borehole
(about 40 ft in FIG. 4A, and about 100 ft in FIG. 4B--note the
logarithmic x axis) the liquid saturation goes to zero marking the
boundary for Zone 3. The boundary between zones 1 and 2 is assigned
based on an abrupt change of slope in saturation which is at about
5 ft for FIG. 4A and at about 20 ft for FIG. 4B. The different
saturation behavior for the draw-down and build up cycles are also
seen to happen mostly at depth closer to the borehole (Zone 1). As
expected, during draw-down, gas is produced and more condensate is
formed. In FIG. 4A there is an increase in liquid saturation from 0
to 1 foot into the borehole (compared draw-down DD5 to buildup BU6)
while the remainder of zone 1 stays unchanged. Similarly, in FIG.
4B there is an increase in liquid saturation in Zone 1 and to a
lesser extent in Zone 2 for the draw-down as compared to the
buildup. In both Figures the liquid saturation is larger at radial
distances closer to the borehole. These observations are consistent
with more condensate being formed closer to the borehole wall. The
measurements of FIGS. 4A and 4B also imply that to the extent that
condensate is formed in zone 3, it will be produced closest to the
well. This is expected since the pressure drop between the
reservoir and the borehole is greatest in that region. However,
with time, the condensate redistributes along this zone causing the
average level to go up along the entire length of zone 3 (see FIG.
4B). Turning to FIG. 5, there is shown a method for producing
reservoir fluids from a condensate gas reservoir. The method begins
in step 101 by drilling a borehole that traverses the condensate
gas reservoir. The borehole can be vertical, multi-lateral or
horizontal. The condensate gas of the reservoir is a single-phase
fluid at original reservoir conditions. It consists predominantly
of methane and other short chain hydrocarbons, but it also contains
long chain hydrocarbons, termed heavy ends. Under certain
conditions of temperature and pressure, this fluid will separate
into two phases, a gas and liquid that is called a retrograde
condensate. As a reservoir produces, pressure decreases. The
largest pressure drops occur near the producing well. When the
pressure in the condensate gas reservoir decreases to a certain
point, called the saturation pressure or dewpoint, a liquid phase
rich in heavy ends drops out of solution and the gas phase is
slightly depleted of heavy ends. A continued decrease in pressure
increases the volume of the liquid phase up to a maximum amount.
Pressure decreases beyond this point decrease liquid volume.
[0031] In step 103, the borehole is cased. Typically, the casing
includes multiple intervals of casing successively placed within
the previous casing run. Cement can fill the annulus between the
casing and the borehole for stability and sealing the rock
formations containing liquids or gases. The casing includes
production casing that extends to a producing interval of the
borehole that traverses the condensate gas reservoir.
[0032] In step 105, the producing interval of the borehole is
completed to allow for inflow of condensate gas at one or more
locations along the producing interval. The completion of step 105
can be an open hole completion (where no casing or liner is
cemented in place across the producing interval), a cased hole
completion (where a casing or a liner extends through the producing
interval and is cemented in place) or other suitable well
completion.
[0033] The common options for open hole completions for condensate
gas wells are pre-holed liners (also often called pre-drilled
liners) or slotted liners. The pre-holed liner is prepared with
multiple small drilled holes, and set across the producing interval
to provide wellbore stability and an intervention conduit. The
slotted liner is machined with multiple longitudinal slots, for
example 2 mm.times.50 mm, spread across the length and
circumference of each joint. The open hole completions can be
combined with open hole packers, such as swelling elastomers,
mechanical packers or external casing packers, to provide zonal
segregation and isolation. Multiple sliding sleeves can also be
used in conjunction with open hole packers to provide considerable
flexibility in zonal flow control for the life of the well.
[0034] For cased hole completions, connection between the annulus
of the production casing and the formation is made by perforating.
Because the perforations can be precisely positioned, this type of
completion affords good control of fluid flow, although it relies
on the quality of the cement to prevent fluid flow behind the
casing/liner. The perforating can be accomplished by a perforating
gun that is positioned as desired in the annulus of the production
casing. The gun carries shape charges that are detonated to punch a
pattern of perforations through the production casing and
surrounding cement into the gas-bearing rock matrix that surrounds
the casing. Typical perforating guns can form perforations that
extend radially into the rock matrix, typically in a range of 6
inches to 20 inches in length relative to the outer wall of the
production casing. It is also contemplated that the perforating can
be accomplished by other means, such as with high power laser
energy (possibly in conjunction with liquid jet pulses). The cased
hole completions can be combined with cased hole packers to provide
zonal segregation and isolation.
[0035] As part of step 105, the perforation into the rock matrix
adjacent the producing interval can be formed (or enhanced)
utilizing hydraulic fracturing where the fracturing fluid is
supplied to the rock matrix at pressures that exceed that of the
fracture gradient of the rock matrix. The fracture gradient is
defined as the pressure required to induce fractures in rock matrix
at a given depth and is usually measured in pounds per square inch
per foot or bars per meter. The pressurized fracturing fluid flows
through holes or voids in the production casing causing the rock to
crack, and the fracture fluid continues farther into the rock
matrix, extending the crack still farther, and so on. Operators
typically try to maintain "fracture width," or slow its decline. A
proppant (such as grains of sand, ceramic, or other particulates)
can be introduced into the fracture. The proppant is intended to
prevent the fracture from closing when the injection is stopped and
the pressure of the fracturing fluid is reduced. The fracturing
fluid can include an acid (typically hydrochloric acid). The acid
tends to etch the fracture faces in a non-uniform pattern, forming
conductive channels that remain open without a propping agent after
the fracture closes.
[0036] In an alternate embodiment, as part of step 105, the
perforation into the rock matrix adjacent the producing interval
can be formed by other suitable methods. For example, a casing
drilling instrument (such as the Cased Hole Dynamics Tester offered
commercially by Schlumberger) can be used to form a perforation
into the rock matrix adjacent the producing interval. The Cased
Hole Dynamics Tester can be delivered to the location of interest,
anchored, and a drill bit from the tool body is used to drill into
the casing (if presented) and formation. In another example, a
direction drilling tool (such as the Extreme tool offered
commercially by Schlumberger) can be used to form a perforation
(lateral branch) into the rock matrix adjacent the producing
interval of the borehole. The directional drilling can also be done
by coiled-tubing as is well known in the industry. These techniques
offer flexibility in the diameter and depth of the perforation.
[0037] The perforation of step 105 extends into the rock matrix in
a radial direction away from the central axis of the borehole of
the well and promotes migration of natural gas from the rock matrix
into the well annulus for production. It is also contemplated that
such perforation can be treated with an acid. For carbonate rock
matrix, the acid can dissolve the matrix to extend the length of
the perforation.
[0038] The perforation operations of step 105 can be performed at
different radial directions for a given producing location adjacent
the natural gas bearing rock matrix. The perforation operations of
step 105 can also be carried out at multiple locations that are
separated from one another along the central axis of the borehole
of the well.
[0039] In step 107, at a location proximate the production
location(s) of step 105, a heater protrusion is formed into the
rock matrix. The heater protrusion can be formed by a perforating
gun that is positioned as desired in the annulus of the well. The
gun carries a shape charge that is detonated to punch a perforation
(through production casing and surrounding cement, if present) into
the adjacent gas-bearing rock matrix. Typical perforating guns can
form perforations that extend radially into the rock matrix in a
range of 6 inches to 20 inches in length relative to the outer wall
of the production casing, although this application is not limited
thereto. In the event that the section of interest is not cased by
steel casing and cement, the shape charge does not have to
penetrate through the steel casing and cement, and the energy of
the shape charge will penetrate even deeper into the rock matrix
beyond 20 inches. It is also contemplated that the heater
protrusion can be formed by other means, such as: a high power
laser energy (possibly in conjunction with liquid jet pulses); a
casing drilling instrument (such as the Cased Hole Dynamics Tester
offered commercially by Schlumberger), where the Cased Hole
Dynamics Tester can be delivered to the location of interest,
anchored, and a drill bit from the tool body can be used to drill
into the casing (if presented) and formation; and a direction
drilling tool (such as the Extreme tool offered commercially by
Schlumberger) that can be used to form the heater protrusion
(lateral branch) into the rock matrix (the directional drilling can
also be done by coiled-tubing as is well known in the industry.)
These techniques offer flexibility in the diameter and depth of the
heater protrusion.
[0040] The heater protrusion of step 107 extends into the rock
matrix in a radial direction away from the central axis of the
borehole of the well. The heater protrusion 107 is sized to receive
a heater element as described below with respect to step 109. In
one embodiment, the heater protrusion extends from the borehole in
a direction parallel to that of the proximate production
perforation of step 107.
[0041] The operations of step 107 can be performed at different
radial directions for corresponding perforations that extend into
the matrix as a result of step 105. The operations of step 107 can
also be carried out at multiple locations in or adjacent the
producing interval that is separated from one another along the
central axis of the borehole of the well for corresponding
production perforations that result from step 105.
[0042] In step 109, a heater element is placed into the heater
protrusion formed in step 107, and the heater element (or support
equipment for the heater element) is coupled to surface control
equipment. In one embodiment the heater element operates under
control of the surface control equipment to heat the adjacent rock
matrix to a temperature that mobilizes (and/or vaporizes)
condensate near the producing interval of the well in order to
limit the buildup of condensate near the producing interval of the
well. The operations of step 109 can be repeated for multiple
heater elements to place and configure the multiple heater elements
in the heater protrusion formed in step 107.
[0043] The heater element of step 109 can be realized by a
ruggedized resistance heating element suitable for the downhole
environment. The resistance heating element can be energized by
electrical energy generated by the surface control equipment and
supplied to the heater element by conductors that extend
therebetween. The conductors can pass down through completion pipe
or through a dedicated completion pipe. It is also possible to
place the conductors in a small metal tube on the outside of the
casing inside the surrounding cement zone.
[0044] In an alternate embodiment, the heater element of step 109
can employ electromagnetic radiation to heat the adjacent rock
matrix. This technology employs a downhole source of
electromagnetic radiation (for example, a magnetron), a waveguide
or cable (depending on the frequency) to deliver the
electromagnetic radiation to an antenna (such as horn or dipole
antenna) that is positioned in the heater protrusion. The antenna
radiates the energy into the adjacent rock matrix to heat the
adjacent rock matrix. The downhole source can be placed inside the
annulus of the well (in the producing interval in close proximity
to the antenna) and controlled by surface control equipment via
conductors that extend therebetween. The conductors can pass down
through completion pipe or through a dedicated completion pipe. It
is also possible to place the conductors in a small metal tube on
the outside of the casing inside the surrounding cement zone.
[0045] Electromagnetic heating has the advantage that with proper
design of the antenna, the energy can be directed to the direction
of interest. For example, the energy can be directed to the end of
the heater protrusion such that it penetrates beyond the physical
size of the heating protrusion. Alternatively, it can be directed
above or below the heater protrusion if desired. The frequency of
the electromagnetic energy is another parameter that can be
advantageously used. When the electromagnetic radiation enters a
medium such as a rock, its intensity decreases exponentially as a
function of travel distance into the rock matrix. Thus, the depth
of penetration is defined as the depth into the medium wherein the
intensity has reduced to 1/e of the initial intensity, where e=2.7
is the base of natural logarithm. This depth of penetration
(.delta.) is known as the skin depth and is given by the following
equation:
.delta. = 2 2 .pi. f .sigma. .mu. Eqn . ( 1 ) ##EQU00001##
where f is the frequency, .sigma. is the conductivity of the
medium, and .mu. is the magnetic permeability (which for normal
rocks is equal to that of free space).
[0046] As the equation shows, lowering the frequency increases the
skin depth and one can use the electromagnetic radiation to heat
the rock matrix at a greater distance from the heater
protrusion.
[0047] Metal particles have a large cross section for absorbing the
electromagnetic radiation produced by the antenna. This causes a
metal particle that is in the field of the antenna to
preferentially absorb the radiation such that is gets hotter than
its environment. Use of metal particles is one way of concentrating
the heat and creating locally higher temperatures compared to the
surrounding medium. Note that the amount of energy is not changed,
but it is distributed differently.
[0048] In one embodiment, metal particles are injected into the
rock matrix in an area where condensate forms (or is likely to
form) during production. Metal particles have a large cross section
for absorbing the electromagnetic radiation produced by the
antenna. This causes a metal particle that is in the field of the
antenna to preferentially absorb the radiation such that is gets
hotter than its environment
[0049] Where metal particles are injected into the rock matrix, the
metal particles are distributed over the area of condensate
formulation in a uniform manner and operate to absorb the
electromagnetic energy emitted by the antenna and raise the
temperature locally, thus serving as the local hot points with
higher temperature than the surroundings. The high temperature of
the metal particles induced by the electromagnetic energy emitted
by the antenna can aid in vaporizing condensate. The gas can form
gas pockets that can push the remaining condensate to the producing
interval of the well. This process is specifically effective in
positions far enough away from the antenna that the average heating
temperature is below the temperature that vaporizes the
condensate.
[0050] The metal particles should be small enough to pass through
the rock pore size. In one embodiment metal particles having sizes
in the nano-meter range (so called nanoparticles) are utilized.
There are well-known methods of generating these particles. The
particles can be made in a distribution of sizes so that they
penetrate different throat sizes. The metal nanoparticles can be
treated with one or more bonding agents that help them to attach to
the pore walls of the rock matrix. For pore walls that are oil wet,
such bonding agents can include an organic group that
preferentially bonds to the oil wet pore walls. For pore walls that
are water wet, such bonding agents can include polar groups (such
as carboxylates, for example) that preferentially attach to the
water wet pore walls. In operation, the wettability of the pore
walls of the rock matrix is measured and based on this measurement
one or a combination of these particles are introduced into the
rock matrix. By way of example only, the interval of interest can
be isolated by two packers and a solution containing these
solubilized metal particles can be introduced in the isolated
interval at a pressure that is higher than the formation pressure.
The excess pressure pushes the particles into the rock matrix where
they bond to the pore wall. The pressure is then removed allowing
the formation fluid to flow normally.
[0051] The metal particles can also concentrate heat from other
heating methods. For example if a resistive heating element is used
to generate the heat, the dispersed metal particles can concentrate
heat and aid with condensate vaporization. Thus, the metal
particles are not limited to electromagnetic heating although they
can be more efficient when used in conjunction with electromagnetic
heating.
[0052] The heater element of step 109 can also be a heat exchanger
or other suitable heat conducting element that distributes heat
generated by other means, such as steam generated at the surface
and supplied to the heat exchanger, steam generated by a downhole
steam generator, or heat generated by a downhole combustor (for
example, oxygen gas can be delivered downhole to the combustor and
used to burn some of the gas or condensate that is produced by the
well).
[0053] In step 111, production tubing is installed that extends
from the producing interval to the wellhead.
[0054] In step 113, the production tubing is used to produce
natural gas (and possibly condensate) from the completed producing
interval of the well while concurrently using the surface control
equipment to operate the heater element(s) to heat the adjacent
rock matrix to a temperature that mobilizes (and/or vaporizes)
condensate near the completed producing interval of the well in
order to limit buildup of condensate near the completed producing
interval of the well. The heater element can be controlled by a
device located in the vicinity of the production zone. In this case
one of the production parameters, such as the rate of gas or
condensate production is monitored and is compared with a target
value. This can be done by having a microprocessor or a similar
device located downhole. Based on the comparison, the device may
increase or decrease the current into the heater element(s). For
example if the gas production rate is the parameter of interest and
the measurement shows a decreased rate compared to the target
value, it implies that the extent of heating is not sufficient and
more current needs to be supplied to the heater element. This
adjustment can be done by the downhole device (not shown).
[0055] In one embodiment, the heater element is adapted to heat the
adjacent rock matrix to a temperature that vaporizes condensate
near the producing interval of the well. This effect is shown
graphically in FIG. 1 where the liquid phase condensate of point 3
is heated to cause a horizontal shift. Heating to point 4 causes
the condensate to vaporize into a gas phase all the way to the
dew-point line where there is almost zero liquid drop-out. Heating
to a lesser temperature (such as point 5 along this line) causes
the liquid condensate to vaporize to the gas phase while allowing
some remaining liquid phase condensate (about 6%). Once gas is
generated, it will flow in the direction of low pressure, which in
this case, is the completed producing interval of the well. In
addition to vaporization, the temperature increase can also reduce
the viscosity of the liquid phase condensate, thus improving the
mobility of the liquid phase condensate and causing it to flow into
the completed producing interval of the well. Both these mechanisms
reduce the amount of condensate and help increase the gas flow
rate.
[0056] FIG. 6 shows a condensate gas production well with a
production casing 201 that lines a production interval 203 of a
borehole that traverses a gas-bearing rock matrix 205. The
production casing 201 includes a protrusion 207 into the
gas-bearing rock matrix 205 adjacent the producing interval 203 as
described above with respect to step 105. The protrusion 207
extends into the rock matrix 205 in a generally radial direction
away from the central axis of the borehole and promotes migration
of natural gas and possibly condensate from the rock matrix 205
into the well annulus for production. The production casing 201
also includes a heater protrusion 209 that is located proximate to
the protrusion 207. The heater protrusion 209 extends into the rock
matrix 205 in a radial direction away from the central axis of the
borehole (e.g., in a direction substantially parallel to that of
the proximate production protrusion 207). The heater protrusion 209
is sized to receive a resistive heater element 211 as described
above with respect to step 109. The resistive heater element 211 is
operated under control of the surface (or downhole) control
equipment 213 to heat the adjacent rock matrix 205 to a temperature
that mobilizes (and/or vaporizes) condensate near the producing
interval of the well in order to limit the buildup of condensate
near the producing interval of the well. Production tubing (not
shown) extends from the producing interval to the wellhead (not
shown). The production tubing is used to produce natural gas (and
possibly condensate) from the producing interval of the well while
concurrently using the surface control equipment 213 to operate the
heater element 211 to heat the adjacent rock matrix 205 to a
temperature that mobilizes (and/or vaporizes) condensate near the
completed producing interval 203 of the well.
[0057] FIG. 6 also shows a graph that depicts the level of
condensate as a function of position in the rock matrix 205
relative to the heater protrusion 209 for the case where the heater
element 211 is not used to heat the rock matrix 205 as well as the
case where the heater element 211 is used to heat the rock matrix
205. The heating of the rock matrix 205 is sufficient to cause
condensate to vaporize into gas. Once gas is generated, it will
flow in the direction of low pressure, which in this case, is the
producing interval 203 of the well. In addition to vaporization,
the temperature increase can also reduce the viscosity of the
liquid phase condensate, thus improving the mobility of the liquid
phase condensate and causing it to flow into the completed
producing interval 203 of the well. Both these mechanisms reduce
the amount of condensate and help increase the gas flow rate.
[0058] The protrusion 207 of FIG. 6 cooperates with the heating of
the rock matrix 205 by the proximate heater element 211 to
facilitate production of the condensate. For the case where the
liquid phase condensate in the rock matrix 205 is heated to a
temperature that is sufficient to cause the condensate to vaporize
into gas, the gas moves in the direction of the completed producing
interval 203 and up at the same time. Once the gas reaches the
protrusion 207, the gas can easily travel to the producing interval
and be produced. In this case, the liquid phase condensate in the
rock matrix 205 can be heated to sufficient temperature that will
lower the viscosity and density of the liquid phase condensate and
thus improve its mobility. These factors work together to move the
liquid phase condensate in the direction of the completed producing
interval 203 as well as up. Once this liquid phase condensate
reaches the perforation 207, it can easily travel to the completed
producing interval and be produced.
[0059] The rock matrix 205 conducts the heat generated by the
heater element 211 within its own body and transfers it to
condensate by means of convection. In one embodiment, the heat
transferred to the condensate is sufficient to vaporize the
condensate (i.e., overcome its phase boundary for its vapor
pressure). Depending on the thermal diffusivity (a) of the
formation material, heat can be transferred either quickly or
slowly to the condensate. As shown from the following equation 2,
in a substance with high thermal diffusivity, heat moves rapidly
through because the substance conducts heat quickly relative to its
volumetric heat capacity:
.alpha. = k .rho. c p Eqn . ( 2 ) ##EQU00002##
where .kappa. is the thermal conductivity (W/(mK)) of the rock
matrix, .rho. is density (kg/m.sup.3) of the rock matrix, c.sub.p
is the specific heat capacity (J/(kgK)) of the rock matrix, and
thus .rho. c.sub.p is the volumetric heat capacity (J/(m.sup.3K))
of the rock matrix.
[0060] Sandstone formation has a thermal diffusivity of
1.81.times.10.sup.-6 m.sup.2/s.sup.-1 while limestone formation has
thermal diffusivity of 1.14.times.10.sup.-6 m.sup.2/s; therefore,
it is expected sandstone to transfer heat much quicker than
limestone. Once the heat source is switched on, one would expect
heat flux in all directions from the protrusion which will generate
temperature gradients in all directions. To calculate such
temperature distributions within the reservoir and wellbore,
thermal exchanges due to conduction and convection need to be
considered as well the effects of heating the condensate. The
expected temperature profile close to the wellbore compared to the
energy source is shown in FIG. 7.
[0061] Approximately 2.2 kJ is required to raise a unit mass of
condensate by 1.degree. C. at constant pressure. Assuming the heat
is being transferred from the rock surface to the condensate, the
amount of heat transferred into the condensate during a period of
time equals the increase in the energy of the condensate during the
time period according to:
hA.sub.s(T.sub.s-T.sub..infin.)=mc.sub.p(T.sub..infin.-T.sub.i)
Eqn. (3)
where T.sub.i is condensate initial temperature, T.sub.s is rock
surface temperature, T.sub..infin. is finite/equilibrium
temperature, m is condensate mass in kg, c.sub.p is the specific
heat capacity (J/(kgK)) of the rock matrix, h is the heat transfer
coefficient between rock and condensate in W/m.sup.2.degree. C.,
and A.sub.s is the surface cross-section area in m.sup.2. If the
dew point temperature is known at reservoir pressure, then the
energy requirements can be calculated using equation 2. Then from
equation 3, the surface rock temperature is calculated and can be
related to energy required to be transferred within the rock body
itself. More particularly, via geometrical modeling of the
formation and identifying the boundary conditions, either
analytical or numerical solutions for the targeted zone can be
applied and temperature profiles can be calculated within this
zone.
[0062] According to one embodiment, a monitoring method to measure
the flow rate of produced fluids is disclosed. The flow rate of
produced fluids without heating can be measured, and the flow rate
of produced fluids with heating can be measured. The enhancement of
the flow rate with heating relative to the flow rate without
heating can be attributed to the heating treatment. The flow rates
can be measured downhole or uphole. The uphole measurement will
generally integrate the flow rate from different parts of the
reservoir and can lead to loss of depth information while the
downhole measurement can usually be more resolved. Standard flow
meters such as a venturi or a spinner can be used for this purpose.
Commercial tools exist that can perform these measurements. If the
flow rate is measured downhole by a flow meter 251 as shown in FIG.
8, it is possible to place the flow meter 251 (or multiple flow
meters) at different depths relative to the condensate reservoir
and record the flow measurements at the data recording and analysis
system 253 with more information content. For example, the flow
meter 251 and data recording and analysis system 253 can cooperate
to record flow rate measurements at different points ranging from
below the heating element 211 to the top of the reservoir, which
should provide a good indication of where the gas is coming from
and at what rate.
[0063] Another monitoring method measures the pressure and
temperature in the condensate reservoir as a function of depth from
below the heating element to the top of the reservoir. This can be
done by placing temperature sensors and pressure sensors (such as a
fiber optic distributed temperature and pressure sensor 255) behind
the production casing 201 at the time of completion as shown in
FIG. 8. The sensors cooperate with a system 257 to measure the
pressure and temperature in the condensate reservoir as a function
of depth from below the heating element to the top of reservoir.
The measurements can be recorded by system 253. The temperature and
pressure of the condensate reservoir in the vicinity of the heater
element 211 can be measured as a function of lateral distance
(offset) into the formation by placing temperature sensors and
pressure sensors (such as a fiber optic distributed temperature and
pressure sensor 259) into the formation in the vicinity of the
heater element 211 as shown.
[0064] It should be appreciated that FIG. 8 shows one embodiment
wherein a hole has been drilled in the radial direction and a
temperature sensor has been inserted into the hole. A cased hole
dynamics tester CHDT tool of the assignee can be used to drill the
hole. As previously suggested, the temperature sensor is a
distributed temperature sensor that can sense the temperature
variation as a function of depth into the formation. In another
embodiment, the measurements from a plurality of temperature
sensors distributed along the axis of the well can be used to
determine a radial dependence of temperature. In embodiments, the
sensors cooperate with the system 257 to measure the pressure and
temperature in the condensate reservoir in the vicinity of the
heater element 211 as a function of lateral distance (offset) into
the formation. The measurements are recorded by system 253. The
temperature and pressure measurements recorded by system 253 can be
analyzed to characterize the temperature and pressure of the
condensate reservoir as needed. Such analysis can involve
continuous monitoring. In alternate embodiments, the temperature
and pressure measures can be measured and transmitted to the
surface; this may include wireless telemetry, or a cable.
Alternatively, the measurements can be made by a recording unit
that is positioned in the well as desired.
[0065] It is contemplated that the methodology and system as
described herein can be utilized in a new production well for a
condensate gas reservoir. It is also contemplated that the
methodology and system can be used to add condensate heating
capability to an existing production well for a condensate gas
reservoir in which case some of the steps in FIG. 5, such as
drilling the well and completion, do not need to be performed at
the time of this treatment.
[0066] The amount of thermal energy injected into the formation can
be adjusted based on preset objectives. At one extreme, the
objective may be to evaporate most of the condensate by injecting a
relatively large thermal energy into the formation for a relatively
short time. At another extreme, the objective may be to use a
minimum amount of thermal energy. In this case the condensate will
increase as a function of time, although at a slower rate compared
to the case where there is no heating. Between these extremes there
are many scenarios where thermal energy is adjusted to increase (or
keep constant) the level of gas production and then kept at that
level. These scenarios can be implemented by adjusting the
electrical current into the heating elements using an uphole
control or a control device located downhole.
[0067] There have been described and illustrated herein several
embodiments of a methodology and apparatus for producing fluids
from a condensate gas reservoir. While particular embodiments of
the invention have been described, it is not intended that the
invention be limited thereto, as it is intended that the invention
be as broad in scope as the art will allow and that the
specification be read likewise. Thus, while particular
configurations for a vertical production well have been disclosed,
it will be appreciated that other similar configurations for
horizontal production wells and multilateral production wells as
well. In addition, while particular types of completion equipment
of the production well have been disclosed, it will be understood
that other suitable completion equipment can be used. It will
therefore be appreciated by those skilled in the art that yet other
modifications could be made. Accordingly, all such modifications
are intended to be included within the scope of this disclosure as
defined in the following claims. In the claims, means-plus-function
clauses, if any, are intended to cover the structures described
herein as performing the recited function and not only structural
equivalents, but also equivalent structures. It is the express
intention of the applicant not to invoke 35 U.S.C. .sctn.112,
paragraph 6 for any limitations of any of the claims herein, except
for those in which the claim expressly uses the words `means for`
together with an associated function.
* * * * *