CA3057354A1 - Re-deployable well-pad facility and method therefor - Google Patents

Abstract

A well-pad facility for removably deploying on a well pad having one or more well pairs, each well pair having an injection well for steam injection and a production well for hydrocarbon production. The well-pad facility has one or more injector/producer wellhead equipment modules each having an injector wellhead and a producer wellhead for coupling to the injection well and the production well of one of the well pairs, respectively; a test separator and residue-gas heater module for testing the production wells and heating residue gas; a start-up production/annulus-gas pump module for start-up production and annulus-gas pumping of the well pairs; and a plurality of pipeline modules for coupling to the injector/producer wellhead equipment module, the test separator and residue-gas heater module, and the start-up production/annulus-gas pump module. Each of these modules comprises one or more isolation valves for interconnecting with other modules and/or devices on the well pad.

Description

RE-DEPLOYABLE WELL-PAD FACILITY AND METHOD THEREFOR
FIELD OF THE DISCLOSURE
The present disclosure relates generally to a re-deployable well-pad facility and a method therefor, and in particular to a well-pad facility that may be deployed at a first hydrocarbon (such as crude oil, bitumen, and/or natural gas) production site, and may be removed and redeployed to a second hydrocarbon production site for reuse when the first site reaches the end of oil & gas production.
BACKGROUND
Steam Assisted Gravity Drainage (SAGD) is an enhanced hydrocarbon recovery method for producing heavy crude oil and bitumen, which uses an advanced form of steam stimulation to improve the hydrocarbon production. A SAGD well pad usually comprises one or more pairs of horizontal wells drilled into the subterranean hydrocarbon reservoir. In each well pair, one well is usually used as an injection well for continuously receiving High Pressure (HP) steam and residue gas from a central plant and injecting received HP steam and residue gas into the subterranean hydrocarbon reservoir. The other well of the well pair is usually used as a production well for collecting hydrocarbon from the subterranean reservoir and delivering collected hydrocarbon to the surface.
On the surface, a typical SAGD well pad generally comprises the wellheads of the well pairs (including an injector wellhead and a producer wellhead) and a plurality of pad-processing facilities.

CAL_LAW\ 3427429\3 Hitherto, almost all pad-processing facilities in SAGD well pads are fixed equipment and are not removable. Usually, the production-life span of a well pair is about 15 years or less. On the other hand, the pad facilities may be used for as long as 40 to 50 years.
Thus, once a well pair enters its final stage of life cycle with significantly reduced hydrocarbon production or stopped hydrocarbon production, maintaining regular operation of the related pad-processing facilities may become uneconomical. As the pad-processing facilities are fixed equipment, they are often abandoned even though they are still in good operation conditions, thereby causing huge waste of equipment.
Therefore, there is always a desire for re-deployable well-pad facilities that may be removed and redeployed to another hydrocarbon production site for reuse.
SUMMARY
According to one aspect of this disclosure, there is provided a well-pad facility for removably deploying on a well pad having one or more well pairs, each well pair comprising an injection well for steam injection and a production well for hydrocarbon production. The well-pad facility comprises:
one or more first modules each comprising an injector wellhead and a producer wellhead for coupling to the injection well and the production well of one of the well pairs, respectively; a second module for testing the production wells of the well pairs and heating residue gas; a third module for start-up production and annulus-gas pumping of the injection wells and the production wells of the well pairs;
and a plurality of pipeline modules for coupling to the first, second, and third modules.

2 CALLAW\ 3427429\3 In some embodiments, each of the first, second, and third modules comprises one or more isolation valves for interconnecting with other modules and/or devices on the well pad.
In some embodiments, the plurality of pipeline modules comprises: a high-pressure (HP) steam pipeline module for transporting high-pressure steam at least to the one or more first modules for injection into the well pairs; an emulsion pipeline module for transporting emulsion from well pairs via the one or more first modules; and a residue-gas pipeline module for transporting the residue gas.
In some embodiments, each of the plurality of pipeline modules comprises one or more pipelines; and the well-pad facility further comprises: one or more pipe racks for accommodating the pipelines of the plurality of pipeline modules.
In some embodiments, each of the one or more pipe racks comprises a supporting structure demoutably coupled to a plurality of supporting piles.
In some embodiments, the supporting structure of at least one of the one or more pipe racks comprises only one supporting level for accommodating the pipelines of the plurality of pipeline modules.
In some embodiments, said testing the production wells of the well pairs and heating residue gas comprises measuring the hydrocarbon production of the production wells of the well pairs.
In some embodiments, the second module comprises: a test separator for receiving the emulsion and separating vapor and liquid phases from the received emulsion.
In some embodiments, the second module further comprises: a residue-gas heater for heating the residue gas.

3 CAL_LAW\ 3427429\3 In some embodiments, the residue-gas heater is located on a skid of the test separator.
In some embodiments, the second module further comprises: a sampler for sampling the separated liquid phase.
In some embodiments, the third module comprises: a start-up production aerial cooler; a start-up/annulus-gas pump inlet cooler; a start-up/annulus-gas pump; and a start-up/annulus-gas pump discharge separator.
In some embodiments, the start-up production aerial cooler comprises at least two fans.
In some embodiments, the well-pad facility further comprises: a fourth module for generating instrument-quality air from atmosphere air.
In some embodiments, the fourth module comprises: at least one compressors; a wet air receiver; a pre-filter; a dryer; an after-filter; a dry air receiver; and a cooler.
In some embodiments, the pre-filter has a filter specification of 0.01 micron.

In some embodiments, the after-filter has a filter specification of 1 micron.
In some embodiments, the fourth module further comprises: a dew-point analyzer for measuring a dew-point at the dryer, and a dew-point indicator for generating a high-dew-point alarm when the measured dew-point is higher than a predefined dew-point threshold.

4 CALLAW 3427429\3 BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic diagram of a well pad, according to some embodiments of this disclosure, wherein the well pad comprises an injector/producer wellhead equipment module, a test separator &
residue-gas heater package, a start-up production/annulus-gas pump package, an instrument air (IA) package, and a plurality of pipeline modules;
FIG. 2 is a process flow diagram of the well pad shown in FIG. 1 in a Steam Assisted Gravity Drainage (SAGD) mode;
FIGs. 3 and 4 are perspective views of a one-level pipe rack for accommodating the pipelines of the pipeline modules of the well pad shown in FIG. 1, wherein the one-level pipe rack comprises a supporting structure having a plurality of supporting piles for supporting the pipelines thereon;
FIG. 5 is a schematic side-view of a portion of a pipeline demountably coupled to a pile of the supporting structure of the one-level pipe rack shown in FIG. 3;
FIG. 6 is a schematic diagram showing a horizontal well coupled to the well pad shown in FIG. 1;
FIG. 7 is a schematic diagram showing the detail of the injector/producer wellhead equipment module of the well pad shown in FIG. 1 in the SAGD mode;
FIGs. 8 and 9 are perspective views of a control module of the injector/producer wellhead equipment module of the well pad shown in FIG. 1, for coupling to the one-level pipe rack shown in FIG. 3;

5 CAL_LAW\ 3427429\3 FIG. 10 is a schematic diagram showing the detail of the test separator &
residue-gas heater package of the well pad shown in FIG. 1;
FIG. 11 is a schematic diagram showing the detail of the start-up production/annulus-gas pump package of the well pad shown in FIG. 1;
FIG. 12 is a schematic diagram showing the detail of the IA package of the well pad shown in FIG. 1;
FIG. 13 is a plot plan of the well pad shown in FIG. 1; and FIG. 14 is a perspective view of the well pad shown in FIG. 1.
DETAILED DESCRIPTION
Well Pad Overview Embodiments disclosed here in relate to a reusable and re-deployable well-pad facility which may in installed in a well-pad for hydrocarbon production, and may be removed from the well-pad as needed or at the final stage of hydrocarbon production thereof and redeployed to another well-pad.
In the following, the re-deployable well-pad facility is described with examples for Steam Assisted Gravity Drainage (SAGD) hydrocarbon-production well pads. However, those skilled in the art will appreciate that in various embodiments, the re-deployable well-pad facility disclosed herein may also be used for other types of hydrocarbon-production well pads.
=

6 CAL_LAW\ 3427429\3 As is known in the art, the production-life span of a well pair is about 15 years or less, ,and the pad facilities may typically be used for as long as 40 to 50 years. Therefore, the re-deployable well-pad facility disclosed herein may be used through two or three production-life spans of well pairs thereby leading to extended life span of well-pad facilities, significant reduction of the waste of otherwise abandoned used facilities, and significant cost-savings.
Moreover, the re-deployable well-pad facility disclosed herein provides a modularized design having a plurality of interconnectable modules, thereby leading to saving of design/construction time in deploying well-pad facilities in new well pads.
Turning now to FIGs. 1 and 2, a well-pad facility removably deployable on a hydrocarbon-production well pad is shown and is generally identified using reference numeral 100. As shown, the well-pad facility 100 comprises an injector/producer wellhead equipment module 102, a test separator & residue-gas heater package or module 104, a start-up production/annulus-gas pump package 106, an instrument air (IA) package or module 108, and a plurality of pipeline modules 110 to 114.
The wellhead equipment module 102 comprises one or more pairs of wellheads installed on one or more well pairs drilled into adjacent subterranean hydrocarbon reservoir or formation (not shown). Each well pair comprise an injection well for steam injection and a production well for hydrocarbon production. Correspondingly, each pair of wellheads comprise an injector wellhead installed on the injection well of the corresponding well pair and a producer wellhead installed on the production well of the corresponding well pair.
For example, in the embodiments shown in FIG. 1, the well-pad facility 100 comprises four (4) well pairs (I0n, POn) where n=1, 2, 3, 4, with a production rate of 2000 Barrels per operational day (BPOD). Correspondingly, the wellhead equipment module 102 comprises four pairs of

7 CALLAW\ 3427429\3 wellheads (also denoted as IOn and POn where n=1, 2, 3, 4, with IOn representing the n-th injector wellhead and POn representing the n-th producer wellhead). For ease of description, the injection and production wells shown in FIGs. 1 and 2 are also denoted as IOn and POn.
Those skilled in the art will appreciate that the well-pad facility 100 in other embodiments may comprise different numbers of well pairs and may have different production rates.
Correspondingly, the wellhead equipment module 102 may comprise different numbers of wellhead pairs.
As shown in FIGs. 1 and 2, a central plant (or central processing facility (CPF); not shown) delivers high-pressure (HP) steam 120 through the HP steam pipeline 110 and a piston valve 152 into the injector wells IOn. The central plant also delivers residue gas 124 through the residue-gas pipeline module 114 into the test separator & residue-gas heater package 104.
Each well pair and correspondingly each wellhead pair (IOn, POn) may operate in different modes including a circulation mode and a SAUD mode. In the circulation mode, the injector well IOn and the producer well POn of the well pair (IOn, POn) are connected by a crossover piping (not shown) such that both wells IOn and POn may be heated using the HP steam 120. In'the SAGD mode, the HP
steam 120 is injected into the injection well IOn, and hydrocarbon such as bitumen is produced through the producer well POn.
The well-pad modules 102 to 114 are configured to allow the produced bitumen to be processed in a manner similar to the conventional oil producer. For example, the liquids (including bitumen and water) and gases 122 (collectively denoted as "emulsion"
hereinafter) produced from the producer wells POn are delivered through the emulsion pipeline 112 to the central plant where the liquids and gases 122 are treated and tested prior to being collected into an emulsion pipeline and an

8 CALLAW\ 3427429\3 annulus-gas pipeline. The annulus gas is also delivered to the start-up production/annulus-gas pump package 106. Moreover, each producer well POn is periodically put on a test separator 130 of the test separator & residue-gas heater package 104, wherein the production stream of each producer well POn is diverted through the separator 130 in order to measure the production thereof While one producer well is being tested, the production streams of other producer wells flow through the emulsion header to the central plant.
As shown in FIG. 1, the well-pad facility 100 also comprises an IA package 108 for converting atmosphere air 132 into instrument-quality air 134 and supplying the instrument-quality air 134 to various devices of the well-pad facility 100 as needed.
In these embodiments, the injector/producer wellhead equipment module 102 comprises one or more isolation valves and flanges for start-up, maintenance, and removal thereof. Similarly, each of the test separator & residue-gas heater package 104, the start-up production/annulus-gas pump package 106, the IA package 108, and the pipeline modules 110 to 114 also comprises one or more isolation valves and flanges for start-up, maintenance, and removal thereof Thus, when needed, e.g., at the end of the production-life span of the current well pad, the well-pad facility 100, including one or more or all of the injector/producer wellhead equipment module 102, the test separator & residue-gas heater package 104, the start-up production/annulus-gas pump package 106, the IA package 108, and the pipeline modules 110 to 114, may be removed from the current well pad and redeployed to another well pad for hydrocarbon production.
Pipeline Modules In these embodiments, the HP steam pipeline module 110 is used for transporting HP steams from the central plant to the well pad. In some embodiments, the HP steam pipeline 110 has a 600#

9 CAL_LAW\ 3427429\3 pressure rating (ANSI/ASME B16.5) and is operable at 7950 kPag (k representing 1000; Pag representing the Pascal's gauge which is a gauge pressure measured relative to ambient atmospheric pressure) at 300 C. The normal operation pressure of the HP steam pipeline module 110 is about 7000 kPag into the HP steam pipeline 110.
In these embodiments, the HP steam pipeline 110 may be insulated but not heat-traced. The HP steam pipeline 110 may comprise one or more low-point drains such that in the event of an outage, the HP steam pipeline 110 may be depressurized from the vents and drain remaining liquids therein from the low-point drains.
In these embodiments, the operation of the HP steam pipeline 110 follows suitable operating procedures during start-up, and at in the event when the HP steam pipeline 110 operates at reduced steam flow rates, for preventing slugs from being carried along the HP steam pipeline 110.
For example, a steam start-up procedure comprises a slow, controlled warm-up including the draining of liquids. The steam start-up procedure also comprise a controlled ramp-up in total steam flow once normal operating temperature has been reached.
Moreover, although the velocity in the HP steam pipeline 110 under normal conditions is usually sufficient to carry water droplets condensed along the HP steam pipeline 110, potential pockets which may collect condensate may be periodically monitored and drained as otherwise the presence of such condensate may cause slogs and potential condensate-induced water-hammer events when the HP steam pipeline 110 operates at a reduced steam flow rate.
In some embodiments, the HP steam pipeline 110 (from the CPF) comprises isolation valves.
CAL_LAW\ 3427429\3 One or more pressure safety valve (PSV) may be used for pressure protection.
In these embodiments, the PSVs are usually set at 7950 kPag and located at the HP steam supply header inside the central plant. Therefore, the HP steam pipeline 110 in these embodiments may need any additional protection.
The emulsion pipeline module 112 transports emulsion, including produced water, bitumen, and some produced gas, from the injector/producer wellhead equipment module 102 to the central plant. In these embodiments, the emulsion pipeline module 112 has a 300#
pressure rating (ANSI/ASME B16.5) and is operable at 4300 kPag at 220 C.
In these embodiments, the emulsion pipeline module 112 does not comprise any control mechanism. In operation, the emulsion pipeline module 112 is maintained at about 1550 kPag or higher for preventing flashing and large slugging therein.
The emulsion pipeline module 112 is generally implemented under the same design condition as the emulsion header of the well-pad facility 100. For example, each well pair comprises an instrumented safety system for protecting the emulsion header 142 (see FIG. 2) and the emulsion pipeline module 112 from overpressure. If the emulsion pressure is higher than a predefined pressure-threshold, instrumented safety system triggers an independent high-high pressure signal at the production wellhead POn which shuts down the down-hole pump for preventing overpressure.
As described above, the emulsion pipeline module 112 in these embodiments comprises one or more isolation valves for isolating pipeline segments for start-up, maintenance, and removal as required. Each isolation valve is installed at a location adjacent the take-off to prevent dead legs (i.e., pipeline sections with ceased fluid flow).

CAL_LAW\ 3427429\3 The residue-gas pipeline module 114 transports residue gas from the central plant to the well pad. The residue-gas pipeline module 114 on the well pad may be heated and the pressure thereof may be reduced such that the residue gas may be used as lift gas, bubbler gas, or blank gas. In these embodiments, the residue-gas pipeline module 114 has a 600# pressure rating (ANSI/ASME B16.5) and is operable at 9930 kPag at 38 C.
In these embodiments, each pipeline of the residue-gas pipeline module 114 is sized for adapting to one well pair of the well pad. The residue-gas pipeline module 114 does not comprise any direct control. As described above, the emulsion pipeline module 112 in these embodiments comprises one or more isolation valves for isolating pipeline segments for start-up, maintenance, and removal as required.
The pipeline modules 110 to 114 generally comprises a plurality of pipelines which may be arranged in one or more pipe racks. In these embodiments, one or more one-level pipe racks 162 as shown in FIGs. 3 and 4 are used for accommodating the pipelines 164 of the pipeline modules 110 to 114.The one-level pipe rack 162 comprises a one-level supporting structure 166 such as a frame coupled to a plurality of supporting piles 168 wherein the supporting structure 166 comprises only one supporting level for accommodating the pipelines 164 and other necessary components. For example, the one-level supporting structure 166 shown in FIGs. 3 and 4 receives thereon seven (7) pipelines 164 and two (2) cable trays arranged in one level for simplification, low-cost, effectiveness, and ease of pipeline modules removal. The pipelines 164 include one steam line, one annulus-gas line, two emulsion lines, two residue gas lines, and one IA line.

CAL_LAW\ 3427429\3 As shown in FIG. 5, the one-level supporting structure 166 is demountably coupled to the supporting pile 168 using suitable coupling structures 170 such as nuts, bolts, screws, and/or the like such that the one-level supporting structure 166 may be removed for redeployment as needed.
Injector/Producer Wellhead Equipment Module As described above, the injector/producer wellhead equipment module 102 comprises one or more wellhead pairs. Each wellhead pair comprise an injector wellhead IOn coupled to an injection well and a producer wellhead POn coupled to a production well. Usually, the production well is parallel to the injection well and is located therebelow.
As shown in FIG. 6, in some embodiments, each of the injection well and production well is a horizontal well 202 horizontally extending in a subterranean formation 204 and is in a dual-tubing configuration having a long tubing 206 extending to the toe area 208 of the well 202 and a short tubing 210 extending to the heel area 212 thereof.
FIG. 7 shows the detail of a wellhead pair IOn and POn of the injector/producer wellhead equipment module 102 in the in SAGD mode, wherein "PC" represents "pressure controller", "FC"
represents "flow controller", "FE" represents "flow element", "NNF" represents "normally no flow", "NC" represents "normally closed", "NO" represents "normally open", numeral "3" marks lines for circulation mode only, and numeral "4" marks residue gas panel only for wells equipped with electrical submersible pumps (ESP).
In some embodiments, the injector well IOn and producer well POm share the same isolation valve in the HP steam pipeline from the CPF. In FIG. 7, the control valves in crosslines control the need of HP steam for both injector well and producer well during the circulation mode / SAGD mode.

CAL_LAW\ 3427429\3 For HP Steam pipeline from the CPF, FIGs. 8 and 9 show a control module 172 of the of the injector/producer wellhead equipment module 102 shown in FIG. 9 in some embodiments. The control module 172 comprises the HP steam header 140 and is coupled to the pipelines 164 in the one-level pipe rack 162 shown in FIGs. 3 and 4.
Similar to the HP steam pipeline 110, the wellhead steam system for each wellhead pair has a 600# pressure rating (ANSVASME B16.5) and is operable at 7950 kPag (Pascal's gauge, a gauge pressure measured relative to ambient atmospheric pressure) at 300 C. Similar to the residue-gas pipeline module 114, the residue gas piping for each wellhead pair has a 600#
pressure rating (ANSI/ASME B16.5) and is operable at 9930 kPag at 38 C.
Each of the injector wellhead IOn and the producer wellhead POn may operate in a circulation mode or a SAGD mode.
With reference to FIGs. 6 and 7, in the circulation mode, HP steam is injected at a maximum pressure of 5000 kPag from the injector welthead 1On into the injection well (denoted as 2021) and flows through the long tubing 206 to the toe area 208 of the injection well 2021. The HP steam heats the injection well 2021 and the area immediately thereabout. The condensed fluid as well as some bitumen and produced gas (denoted "returned fluid" hereinafter) flows to the heel area 210 of the injection well 2021, enters the short tubing 212, and flows uphole therein.
The returned fluid, while travelling uphole, picks up heat from the injected HP steam and drops in pressure. Typically, the returned fluid arriving the surface is mostly vapor which is directed to the annulus gas line 146 (see FIG. 2) through a crossover line 182 at a pressure ranging from 900 kPag to 1500 kPag, and then joins with the returned fluid from the production well (denoted as 202P) downstream of the emulsion line.

CALLAW\ 3427429\3 During the operation, a small amount of residue gas is injected into the casing of the injection well 2021 as the blank gas to indirectly measure the downhole pressure and safeguard the reservoir from overpressure by shutting down the HP steam supply in the event of high pressure.
In the SAGD mode, the HP steam from the HP steam pipeline module 110 is delivered to the injection well 2021 via the line connected to the HP steam header 140 (see FIG. 2) at the maximum pressure of 5000 kPag. The HP steam is flow-controlled and injected along the long tubing and short tubing into both the toe and heel areas of the injection well 2021, respectively. Flow-split between the long tubing and short tubing may be adjusted by the operator depending on reservoir performance.
The injected steam heats the bitumen in the surrounding formation and reduces the viscosity thereof. Bitumen and produced water flow to the production well 202P below the injection well 2021.
As described above, during operation, a small amount of residue gas is introduced into the injection well 2021 as blanket gas to indirectly measure the downhole pressure and safeguard the reservoir from overpressure by shutting down the HP steam supply in the event of high pressure.
In these embodiments, the spool piece will be placed either on the crossover line or on the HP
steam line, depending on the desired operation mode. For example, in the SAGD
mode, the spool piece from the crossover line may be removed and placed on the HP steam line.
The production wellhead POn may also operate in the circulation mode or the SAGD mode.
As described above, in the circulation mode, the HP steam is injected at a maximum pressure of 5000 kPag (corresponding to a temperature of 265 C) from the injection wellhead and flows through the long tubing 206 to the toe area 208 of the injection well 2021.
The HP steam also flows into the production well 202P via a crossover line 184 (which is normally closed (NC) and normally no flow (NNF)) to the toe area 208 thereof from the HP steam supply line 186 of the injection well CALLAW\ 3427429\3 2021 for HP steam injection into the short tubing.' The HP steam heats the wells and the area immediately surrounding them. The steam condensate flows to the heel of the well and up the short tubing, along with a small amount of bitumen and produced gas. The returned production from the Production Well flows through the wellhead Emulsion line. It joins the production returned from the injection well and is then sent either to the start-up production/annulus-gas pump package 106 via the annulus gas header or to the test separator 130 of the test separator &
residue-gas heater package 104.
During the circulation mode, residue gas is injected into the production well POn casing to serve as the blanket gas as well as indirectly measure the downhole pressure and safeguard the reservoir from overpressure by shutting down the HP steam supply in the event of high pressure.
During circulation mode, both HP steam and residue gas are disconnected from the annulus gas/injection production return line by placing the spool pieces on the crossover lines.
In the SAGD mode, accumulated emulsion in the production well POn is pumped into the emulsion line through the short tubing by the downhole pumps such as progressive cavity pumps (PCPs), electric submersible pumps (ESPs), and/or the like. The pumped emulsion is piped to the emulsion header and then pipelined to the central plant. Depending on testing requirements, the emulsion from a production well POn may be routed to the test separator 130 (via the test header) or to the emulsion headei directly.
In these embodiments, the annulus gas surface pressure is configured at a pressure level lower than the reservoir pressure so as to ensure that the downhole pump is submerged in fluid but high enough to limit water flashing in the emulsion. Annulus gas from the production well flows to the annulus gas header then to the start-up production/annulus-gas pump package 106 where it is cooled, CAL_LAW\ 3427429\3 partially condensed, and pressurized. The pressurized and condensed annulus gas may be tied into the emulsion header and sent to'the central plant through the emulsion pipeline.
Test Separator & Residue-Gas Heater Package FIG. 10 shows the detail of the test separator & residue-gas heater package 104 in some .. embodiments, wherein "PV" represents process variable, "ESDV" represents emergency shutdown valve, "AE" represents analysis element, "LC" represents level conductivity, "TC" represents thermocoupling, numeral "2" marks pressure control set to test well operating pressure, and numeral "3" marks a dedicated spool with larger size pipe and control valve need to be installed in circulation mode.
As shown, the test separator & residue-gas heater package 104 in these embodiments comprises a test separator 130 and a residue-gas heater expansion tank 222 having a residue gas heater 224.
In the embodiments shown in FIG. 10, the test separator 130 has an inner diameter (ID) of 1219 millimeters (mm) with a seam-to-seam length of 3048 mm. The residue-gas heater expansion tank 222 has a capacity of 0.066 m3. The residue gas heater 224 has a duty of 6.1 kW.
In the circulation mode, the flow of a well pair (I0n, POn) may be directed to the test separator 130 via the test header for monitoring the total flow rate and water cut thereof, wherein the separated vapor and liquid phases are measured and analyzed respectively.
Then, the vapor and liquid phases may be recombined and sent back to the annulus gas header. A pressure-controlled blanket gas module (using residue gas) maintains the pressure of the test separator at a pressure level about 150k Pa higher than the annulus gas header pressure so as to allow the fluid to flow therethrough.

CAL LAW\ 3427429\3 In these embodiments, the test separator & residue-gas heater package 104 also comprises a sampler or sample package 226 on the liquid outlet line to take samples for detailed laboratory analysis.
When all wells operate in the SAGD mode, the fluids from the test separator 130 may be sent to the emulsion header. The emulsion residence time in the test separator 130 is over 3 minutes when handling the maximum emulsion flow during the SAGD mode.
The residue gas heater 224 is located on the skid of the test separator 130 in the test separator & residue-gas heater package 104. In these embodiments, the residue gas heater 224 may be an electrical/oil-bath heater and comprise an expansion drum.
In these embodiments, the residue gas heater 224 is used for preheating high-pressure residue gas (output from the central plant) prior to pressure letdown to prevent the extremely low temperature that may be otherwise caused by the Joule-Thomson effect on cold days. The temperature-control located at the outlet of the residue gas heater 224 maintains the temperature at 30 C upstream of the pressure letdown station.
For example, the residue gas heater 224 in some embodiments may have a duty of 6.1 kW
with a size determine based on the maximum flow of one well's gas life, and may be suitable for heating 3000 Sm3/d (standard cubic meter per day) of residue gas from -45 C
to 30 C. Such a flow rate may be suitable for a wide range of well operations under different modes, providing the normal flow rate i.e. 1500 Sm3/d is considered under the SAGD mode.
In some embodiments wherein the well pad operates in summer time or in high-temperature areas, the residue gas heater 224 may be bypassed or omitted.

CAL_LAW\ 3427429\3 For example, in one embodiment, the residue gas heater 224 may comprise a bypass line for bypassing the residue gas heater 224 in the event when the residue gas entering the well pad has a sufficiently high temperature (e.g., a temperature higher than a predefined temperature threshold) to be letdown without any extremely-low-temperature concern.
Start-Up Production/ Annulus Gas Pump Package FIG. 11 shows the detail of the start-up production/annulus-gas pump package 106 in some embodiments, wherein numeral "2" marks the line for circulation mode only, and numeral "4" marks a moveable start-up production cooler.
As shown, the start-up production/annulus-gas pump package 106 in these embodiments comprises a start-up production aerial cooler 232, a start-up/annulus-gas pump inlet cooler 234, a start-up/annulus-gas pump 236, and a start-up/annulus-gas pump discharge separator or vessel 238.
In the embodiments shown in FIG. 11, the start-up production aerial cooler 232 has a duty of 18.1 kW. The start-up/annulus-gas pump inlet cooler 234 has a duty of 1.89 kW. The start-up/annulus-gas pump 236 has a differential pressure AP of 1678 kilo-Pascal (Differential) (kPa(d)) with a rated flow of 130 Am3/hr (actual cubic meters per hour) at the suction condition and with a sparing of 1 x 100%. The start-up/annulus-gas pump discharge separator 238 has an outer diameter (OD) of 457 mm and a seam-to-seam length of 3048 mm, and is operable at 4380 kPag at 200 C.
In the circulation mode, returned fluid from all injection wells IOn and production wells POn flows to the start-up production/annulus-gas pump package 106 via the annulus gas header. The start-up production aerial cooler 232 may be used in both circulation and SAGD modes as there is relatively high vapor content in the injection well/production well returns. The start-up production aerial cooler 232 in these embodiments is designed to handle the circulation production of four wells from CALLAW\ 3427429\3 both injection/production wells with 58% vapor fraction at the inlet. The outlet temperature is controlled to approximately 175 C.
Such a design ensures that the majority of the HP steam present in the returned fluid is condensed prior to being sent to the start-up/annulus-gas pump 236. In the SAGD mode, the start-up production aerial cooler 232 may be removed and annulus gas may be sent directly to the start-up production/annulus-gas pump package 106.
In this SAGD operation mode, the operating pressure of the start-up production/annulus-gas pump package 106 is between about 900 kPag to about 1500 kPag, which is lower than the required emulsion pressure at the well-pad edge (i.e., about 2200 kPag). Subsequently, the cooled two-phase fluid from the start-up production aerial cooler 232 flows into the start-up production/annulus-gas pump package 106 and is pumped therein into the emulsion header and then into the emulsion pipeline.
In some embodiments, the start-up production aerial cooler 232 comprises two fans. The temperature controller maintains the fluid outlet temperature at the set point by adjusting the speed of the fans. The cooler employs an external recirculation structure (to avoid overcooling or freezing) in .. which the temperature controller maintains the plenum air temperature at the set point (e.g., 40 C).
In cold conditions such as during wintertime, the temperature controller reduces the side louver opening to limit cold air intake. Meanwhile, the exhaust louver opening is reduced and the internal louver opening is increased to allow more recirculated warm air to mix with cold air.
The start-up production/annulus-gas pump package 106 may be used for all operating modes to provide pressure boost either for start-up returned fluid during circulation and gas lift modes or for annulus gas during the SAGD mode. These fluids are sent to the emulsion header.
CAL_LAW\ 3427429\3 In some embodiments, the start-up production/annulus-gas pump package 106 may be sized only for one well-pair under the circulation mode to ensure the pump turndown ratio is adequate to facilitate the start-up condition of the well pad.
IA Package FIG. 12 shows the detail of the IA package 108. In some embodiments, the IA
package 108 comprises, from inlet 242 (for injecting atmosphere air 132) to outlet 258 (for discharging instrument-quality air 134), 2x100% compressors 244, one wet air receiver 246, one pre-filter 248, 1x100% dryer 250, one after-filter 252, and one dry air receiver 254.
In the embodiments shown in FIG. 12, each of the compressors 244 has a rated capacity of 120 Sm3/hr at 1000 kPa AP with a sparing of 2x100%. The wet air receiver 246 has an OD of 762 mm with a height of 2134 mm. The pre-filter 248 has a filter specification of 0.01 micron. The dryer 250 has a rated capacity of 96 Sm3/hr with a sparing of 1 x 100%. The dryer 250 comprises suitable desiccants for removing water from the air entering the IA package 108, and is configured for lowering the air dew-point to -70 C. The after-filter 252 has a filter specification of 1 micron.
The IA package 108 has a capacity of 120 Sm3/hr and is designed for a differential pressure AP of 1000 kPa. The designed residence time of the dry air receiver is 5 minutes from normal pressure =
to low pressure.
In operation, the inlet 242 receives air at atmosphere pressure and temperature (denoted ATM
air hereinafter). The ATM air is compressed by the compressors 244, cooled, and then sent to the wet air receiver 246. The wet air from the wet air receiver 246 is filtered by the pre-filter 248, dried by the dryer 250, and then filtered again by the after-filter 252. The filtered air from the after-filter 252 is then sent to the dry air receiver 254 for output via the outlet 258. In these embodiments, the dry air CAL LAW\ 3427429\3 receiver 254 acts as a buffer and a storage area between the compressors 244 and downstream users, and provides retention and residence time (volume) of instrument air in case of usage spikes or short outages.
In these embodiments, the IA package 108 provides alarms to notify the operator of general or common alarms. A shutdown signal and a normal control signal are part of the IA package 108.
The IA package 108 also comprises a dew-point analyzer (not shown) for measuring the dew-point at the dryer 250, and a dew-point indicator for generating a high-dew-point alarm when the dew-point is higher than a predefined dew-point threshold, to notify the operator to investigate before the system fails.
Well Pad Layout FIG. 13 shows a plot plan of the well-pad facility 100 deployed on a well pad in one example, and FIG. 14 shows a perspective view of the well-pad facility 100.
In this example, the well pad comprises four well pairs (I01, P01), (102, P02), (103, P03), and (104, PO4), and correspondingly the injector/producer wellhead equipment module 102, arranged in a linear configuration along a longitudinal direction. Each wellhead pair (I0n, POn) is coupled to a corresponding pipe rack 162 via a corresponding control module 172 located therebetween. The pipe racks 162 are arranged in a linear configuration along the longitudinal direction for accommodating the pipeline modules 110 to 114. Each control module 172 is located longitudinal between the corresponding injector wellhead IOn and producer wellhead POn, and laterally between the corresponding wellhead pair (I0n, POn) and the corresponding pipe rack 162.
The test separator &
residue-gas heater package 104, start-up production/annulus-gas pump package 106, the IA package CALLAW\ 3427429\3 108, and other modules such as the start-up production aerial cooler 256 and the electrical building and VFD skid 262 are distributed beside the pipe racks 162.
Although in above embodiments, the pipe rack 162 is a one-level pipe rack, in some alternative embodiments, one or more of the pipe racks 162 may be multiple-level pipe racks each having a multiple-level supporting structure 166.
Although embodiments have been described above with reference to the accompanying drawings, those of skill in the art will appreciate that variations and modifications may be made without departing from the scope thereof as defined by the appended claims.
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CALLAW\ 3427429\3

Claims (18)

WHAT IS CLAIMED IS:

1. A well-pad facility for removably deploying on a well pad having one or more well pairs, each well pair comprising an injection well for steam injection and a production well for hydrocarbon production, the well-pad facility comprising:
one or more first modules each comprising an injector wellhead and a producer wellhead for coupling to the injection well and the production well of one of the well pairs, respectively;
a second module for testing the production wells of the well pairs and heating residue gas;
a third module for start-up production and annulus-gas pumping of the injection wells and the production wells of the well pairs; and a plurality of pipeline modules for coupling to the first, second, and third modules.

2. The well-pad facility of claim 1, wherein each of the first, second, and third modules comprises one or more isolation valves for interconnecting with other modules and/or devices on the well pad.

3. The well-pad facility of claim 1 or 2, wherein the plurality of pipeline modules comprises:
a high-pressure (HP) steam pipeline module for transporting high-pressure steam at least to the one or more first modules for injection into the well pairs;
an emulsion pipeline module for transporting emulsion from well pairs via the one or more first modules; and a residue-gas pipeline module for transporting the residue gas.

4. The well-pad facility of any one of claims 1 to 3, wherein each of the plurality of pipeline modules comprises one or more pipelines; and the well-pad facility further comprising:
one or more pipe racks for accommodating the pipelines of the plurality of pipeline modules.

5. The well-pad facility of claim 4, wherein each of the one or more pipe racks comprises a supporting structure demoutably coupled to a plurality of supporting piles.

6. The well-pad facility of claim 4 or 5, wherein the supporting structure of at least one of the one or more pipe racks comprises only one supporting level for accommodating the pipelines of the plurality of pipeline modules.

7. The well-pad facility of any one of claims 1 to 6, wherein said testing the production wells of the well pairs and heating residue gas comprises measuring the hydrocarbon production of the production wells of the well pairs.

8. The well-pad facility of any one of claims 1 to 7, wherein the second module comprises:
a test separator for receiving the emulsion and separating vapor and liquid phases from the received emulsion.

9. The well-pad facility of claim 8, wherein the second module further comprises:
a residue-gas heater for heating the residue gas.

10. The well-pad facility of claim 9, wherein the residue-gas heater is located on a skid of the test separator.

11. The well-pad facility of any one of claims 8 to 10, wherein the second module further comprises:
a sampler for sampling the separated liquid phase.

12. The well-pad facility of any one of claims 1 to 11, wherein the third module comprises:
a start-up production aerial cooler;
a start-up/annulus-gas pump inlet cooler;
a start-up/annulus-gas pump; and a start-up/annulus-gas pump discharge separator.

13. The well-pad facility of claim 12, wherein the start-up production aerial cooler comprises at least two fans.

14. The well-pad facility of any one of claims 1 to 13 further comprising:
a fourth module for generating instrument-quality air from atmosphere air.

15. The well-pad facility of claim 14, wherein the fourth module comprises:
at least one compressors;
a wet air receiver;
a pre-filter;
a dryer;
an after-filter;
a dry air receiver; and

16. The well-pad facility of claim 15, wherein the pre-filter has a filter specification of 0.01 micron.

17. The well-pad facility of claim 15 or 16, wherein the after-filter has a filter specification of 1 micron.

18. The well-pad facility of any one of claims 15 to 17, wherein the fourth module further comprises:
a dew-point analyzer for measuring a dew-point at the dryer, and a dew-point indicator for generating a high-dew-point alarm when the measured dew-point is higher than a predefined dew-point threshold.