CA2875579C - System and method for steam-assisted gravity drainage (sagd)-based heavy oil well production - Google Patents

Abstract

In one aspect there is provided a system for supporting a section of substantially linear pipe, fluidly connected to a well, and which may experiencing thermal displacement along a longitudinal axis. The system comprises at least one support structure for supporting the section of pipe and at least one flow line for fluidly connecting the section of pipe to the well. The support structure accommodates the thermal displacement of the pipe. The section of pipe may lay on the support structure or may be supported thereon by pipe shoes. A support guide system is preferably provided to support the flow line and allow displacement of the flow line in a direction that is substantially parallel to the longitudinal axis.

Description

SYSTEM AND METHOD FOR STEAM-ASSISTED GRAVITY DRAINAGE (SAGD)-BASED HEAVY OIL WELL PRODUCTION
FIELD OF THE INVENTION
The present invention relates generally to the field of producing crude oil from a reservoir of heavy oil or bitumen by steam-assisted gravity drainage (SAGD) processes and, more particularly, to SAGD wellpad piping modules used for the production of heavy oil or bitumen.
CROSS-REFERENCE TO RELATED APPLICATION
This application claims priority from US Provisional Application Ser. No.
61/981,161 filed April 17, 2014.
BACKGROUND OF THE INVENTION
Steam Assisted Gravity Drainage (SAGD) is an enhanced oil recovery technology for producing heavy crude oil and bitumen. SAGD is an advanced form of steam stimulation in which a pair of horizontal wells are drilled into an oil reservoir, one a few meters above the other. High pressure steam is injected into the upper wellbore to heat the oil and reduce its viscosity, causing the heated oil to drain into the lower wellbore where it is pumped out of the reservoir.
In the SAGD process, two substantially parallel horizontal oil wells are drilled into the formation, one about 4 m to 6 m above the other. The upper well injects steam, and the lower well collects heated crude oil or bitumen that flows out of the formation, along with any water from the condensation of injected steam. The basis of the process is that the injected steam forms a "steam chamber" that grows vertically and horizontally in the formation. The heat from the steam reduces the viscosity of the heavy crude oil or bitumen which allows it to flow down into the lower wellbore. The steam and gases rise because of their low density compared to the heavy crude oil below. The gases released, which include methane, carbon dioxide, and usually some hydrogen sulfide, tend to rise in the steam chamber, filling the void space left by the oil and, to a certain extent, forming an insulating heat blanket above the steam. Oil and water flow is by a countercurrent, gravity driven drainage into the lower well bore. The condensed water and crude oil or bitumen is recovered to the surface by pumps such as progressive cavity pumps and the like, that work well for moving high-viscosity fluids with suspended solids.
Steam Assisted Gravity Drainage (SAGD) for thermal heavy oil recovery has significant business presence in Alberta, Canada. Currently about one million barrels a day are produced, and the Alberta Energy Regulator (AER, formerly the ERCB) suggest that an additional one million barrels a day of production will be brought online over the next 10 years. Individual SAGD Well Pairs are typically grouped in clusters of 6 to 20 well pairs (12 to 40 individual wells), and connected with prefabricated surface piping packages that are designed to suit two particular aspects of the resource owner's plans; a) the physical arrangement of individual wells, including the separating distance between them, and b) the process envelope of steam injection fluid rates and production fluid rates to and from the individual SAGD well pairs over the life of the wellpad.
Wellpads typically have a life of approximately 10 years, and produce on the order of 300 to 600 or more barrels per day. If the AER's expectations are achieved for new incremental SAGD production over the next 10 years, plus consideration for replacement wellpads to maintain the existing production, there is potential application for 300 to 600 new wellpads over this interval. Individual wellpads can cost between $20 million and $120 million, depending on the complexity of the design requirements imposed by the resource

2 owner, plus the design product produced by the engineering company tasked with delivering the wellpad design. Stated in a different way, the cost to tie-in an individual SAGD well pair is generally between $2 million and $14 million, including the aboveground surface pipelines between a wellpad proper and a central production facility (CPF).
There is a wide variability in these tie-in costs, which reflects the evolving maturity of the industry. One of the more efficient designs of SAGD wellpads involves two parallel rows of wells nominally 10 m to 20 m apart, with individual, vertical wellheads spaced at 10 m to 15 m intervals. A center arrangement of pipe rack modules numbering two or more is placed between the two rows of wells approximately on center. These pipe rack modules contain the necessary steam, emulsion, produced gas, high-pressure gas and related headers, for carrying the fluids to and from a peripheral module where the flows are collected and/or tested. The piping on a module expands significantly when heated to operating temperatures (200-300 C) and the stress forces exerted by the thermally-expanding pipe must be accommodated. The designs must comply with provincial regulatory requirements to protect workers and the public.
The large majority of SAGD wellpad piping designs are general arranged with traditional piping design and pipe stress engineering practices including piping anchor loads, expansion forces, and edge-of-pipe-rack connections are arranged such that there is relatively little physical movement allowed inside the footprint of an individual pipe rack module. The modules are generally engineered to allow about 5-10 centimeters of piping displacement within each module. The required piping flexibility to accommodate these thermal expansion displacements and the resulting stresses is imparted by adding expansion loops within the piperack module between fixed anchor points. This design approach is successful and widely-applied, however, in contrast to this "controlled expansion growth, multiple expansion loops, multiple anchors and guides"
approach, the

3 individual SAGD wellheads themselves will grow thermally on the order of 0.5 m to 1 m.
The wellhead thermal growth is sufficiently large enough that mechanical swivel joints are sometimes included in the piping close to the wellhead to accommodate the required growth. This is typically done with three uniaxial swivel joints arranged in series with their axes nominally parallel, arranged at the three points of an inverted "V"
allowing only for an accommodation of the vertical wellhead thermal growth (or reduction). The swivel joints are registered pipe fittings, but as a rule are only utilized at the wellheads themselves.
Within the existing typica[ design practice, the ()Make points from the edges of the wellpad piping modules are substantially anchored and generally limited in their movement, with the thermal expansion displacements on the order of 5-10 cm (5%-10% of the expected wellhead axial growth). This design approach requires significant additional steel piping inside the footprint of the wellpad module. SAGD technology requires a significant amount of equipment, resulting in high capital costs to start a SAGD project. Some of the required equipment includes piping, valves, insulation, tracing, and electric instrumentation that is concentrated at the location of the well. Well pair tie-in costs above $4 million per wellpair are considered expensive, and some SAGD operators currently cannot obtain engineered wellpad designs that cost less than $7 million per wellpair.
Also, in current systems for producing heavy oil using SAGD operations, the piperack modules rely on separate piping loops for connecting the headers to the wellheads during a warmup phase and a production phase. The system is configured for the warmup phase and once the warmup phase in complete (typically lasting approximately 90 days), the system is reconfigured and set up for production. When the piperack modules are converted from the warmup phase to the production phase, most current systems require parts of the piperack modules to be removed and new parts put in. This causes waste product and is less economical due to the high cost of pipe in the industry.

4 U.S. Patent number 7,647,976 to Tsilevich provides a system for SAGD for heavy oil production having a first well, a second well, a first platform connected to the well head of the first well so as to inject steam into the first well, and a second platform connected to the well head of the second well for producing heavy oil from the second well.
In the arrangement of piping defined by Tsilevich, the lengths and arrangements or elbows and directional changes of piping between the first and second levels within each of the modules are necessarily devised to accommodate the required piping flexibility due to thermal expansion stresses within the longest dimension of the module. Also, at certain distances, expansion loops are required between the ends of the modules themselves.
The lateral piping connections entering and leaving the side of each module are deliberately restrained by inherent virtue of the design, and as a result, substantial structural loads are imposed into the steel that supports and fixes the piping connections.
The additional lengths of pipe and fittings required, plus the heavier structural steel elements and the welding thereof impose an additional cost that could be avoided by a more innovative design that allows unrestrained but inherently balanced forces.
The Tsilevich modules include pipe supports on six (6) meter spacing, which is necessary to support the significant extra weights and forces associated with the design.
Tsilevich claims on Figure 1, that the principal steam, emulsion and natural gas headers can be arranged on the lowermost level of the rack. This is acceptable as far as it goes, however this design approach generally requires an additional expansion loop that must be arranged close to the wells themselves. The expansion loop 37, shown in Figure 7, inherently defeats the concept of joining more than three modules in one row.
Ultimately, the consecutive linkage of the otherwise-identical modules described by Tsilevich is limited by these large diameter pipe expansion loops carried in Figure 1.

5 Furthermore, and in consideration of the current state of the art in the heavy oil industry, many piping engineers strive to maintain very minimal (on the order of centimeters, and certainly less than 5-10 cm) physical displacement of piping within a complex multidirectional piping system, to avoid pipe-to-pipe interference.
Directionally, this requires the piping engineer to add additional lengths of pipe and fittings between fixed points, to accommodate the resulting forces and moments applied to the pipe elements during the temperature and pressure cycling that will occur during use. "Until about 1967 piping design was performed primarily using the "rule of thumb" layout design procedures and pre-analyzed piping layout data in tabular form. The publication of ANSI B
31.1-1967 Power Piping Code, and the availability of analysis computer programs have introduced cost-effective piping design" (Kannappan, Introduction to Pipe Stress Analysis, ABI
enterprises 2008, foreword). By observation, where piping departs from fixed equipment, such as connection flanges on pumps, vessels, exchangers and tanks, the allowable piping movements are practically nil, however forces and moments are applied to these connection points, and negotiated between the piping engineer and the mechanical engineer responsible for the fixed equipment per se.
At the SAGD wellheads themselves, engineered flexible connections numbering two or three are commonly used to accommodate (usually) vertical thermal growth along the axis of the wellbore, and these have been applied with great success, however the corresponding connection points at the sides of the module are often configured as fixed anchor points, with very minimal (on the order of a few centimeters) allowable horizontal/vertical displacements as a consequence of thermal expansion forces.
The design philosophy described above results in a significant amount of steel and piping being incorporated into the pipe rack module to accommodate the thermal expansion forces over the full range of pipe temperature in the application.

6 Accordingly, there is a need in the oil and gas industry to develop an improved system and methodology for thermal heavy oil production.
SUMMARY OF THE INVENTION
An improved wellpad assembly is provided. The wellpad assembly comprises substantially linear headers positioned adjacent and parallel one another in a substantially straight line without the need for pipeline expansion loops for accommodating pipe stress caused by thermal expansion as is generally used in the industry. A single anchor module is provided for connecting multiple wellpad assemblies thereto. The single anchor design may improve steam-system safety by avoiding gas pockets within the pipe lines which are inherent in certain types of expansion loop designs. The guides may be used for supporting the headers and to accommodate inherent longitudinal thermal growth of injection and production headers along the length of wellpad module during operation. The present embodiments allow constant measurement of total fluids produced, as well as the relative proportion of hydrocarbon. The constant measurement ability offers personnel additional control and optimization of well production by conducting real time measurement during operations. The majority of wellpad assembly designs that are known in the art, require test separators which must be provided for every group of 12 producing wells under some oil and gas regulatory regimes.
The present embodiment is adaptable to a greater number of artificial lift methods, unlike some wellpad assembly designs known in the art, which reflects only one particular method such as gas-lift method. The present embodiment allows simultaneous gas lift, electric submersible pump, and well warm-up techniques, whereas some designs require all the well pairs be operated solely on gas lift or steam circulation. In these described arrangements in the prior art, an individual well cannot be circulated without its partner well

7 in coordination. Some designs in the prior art lack the additional headers necessary to independently operate in warmup, gas lift, and electric submersible pump (ESP) or mechanical lift production modes.
BRIEF DESCRIPTION OF THE DRAWINGS
Referring to the drawings, several aspects of the present invention are illustrated by way of example, and not by way of limitation, in detail in the figures, wherein:
Figure 1 is a perspective view of a wellpad assembly for producing heavy oil in a SAGD configuration;
Figure 2A is a perspective view of a flow line support assembly of Fig. 1;
Figure 2B is a plan view of a flow line support assembly of Fig. 1;
Figure 2C is an elevation view of a flow line support assembly of Fig. 1;
Figure 3 is a schematic of an embodiment of a header and well head assembly demonstrating the displacement of the piping structure due to thermal growth;
Figure 4A is a plan view of the wellpad assembly of Fig. 1, in a warm up configuration;
Figure 4B is a plan view of the wellpad assembly of Fig. 1, in a SAGD
production configuration;
Figure 5 is a plan view of a central module acting as an anchor point with multiple pipe rack modules extending on either side therefrom; and Figure 6 is a perspective view of the central module of Fig. 5 connected to a wellpad assembly.

8 DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
The following description is of preferred embodiments by way of example only and without limitation to the combination of features necessary for carrying the invention into effect. Reference is to be had to the Figures in which identical reference numbers identify similar components. The drawing figures are not necessarily to scale and certain features are shown in schematic or diagrammatic form in the interest of clarity and conciseness.
With reference to Figs. 1 to 5, a wellpad assembly 10 for producing heavy oil in a SAGD process having one or more injection wells and one or more production wells is provided. Embodiments described herein, preferably comprise header modules 13 of substantially linear headers 16,18,20 for accommodating flow of injection and production fluids spanning multiple such modules. The substantially linear headers 16,18,20 are free to thermally expand and contract along their longitudinal axes (within module 13) and are completely free from costly pipeline expansion loops, which are required in the prior art to accommodate thermal expansion and alleviate pipeline stress caused therein.
The substantially linear headers 16, 18, 20 are connected in series and on either side of a single anchor module 11. Injection and production fluid communicates between the substantially linear headers 16,18,20 and well heads 12,14 through flow lines 24. When the flow lines 24 connect headers 16,18,20 to a production well 12, they may be referred to as production flow lines. When flow lines 24 connect headers 16,18,20 to an injection well 14, they may be referred to as injection flow lines. The flow lines 24 may comprise of a series of pipes connected by swivel joints 30 providing flexibility to the flow lines 24 spanning between the well head 12,14 and the substantially linear headers 16,18,20 for accommodating thermal expansion of the system.

9 With reference to Fig. 1, an embodiment of a wellpad assembly 10 comprising a production well having a well head 12 and an injection well with having a well head 14 is provided. The wellpad assembly 10 is configured with three main process headers, a first substantially linear header 16, for producing heavy oil emulsion from the production well head 12 of one or more production wells, a second substantially linear header 18, for injecting steam into the injection well head 14 of the one or more injection wells , and a third substantially linear header 20 for returning either multiphase water/steam to a facility during a warm up phase (Fig. 4A) or for producing casing gas during a production phase (Fig. 4B) supported on a support structure 21 (e.g. by laying thereon or being mounted thereto). Preferably, the headers 16,18,20 are supported and guided within the header modules 13 by pipe shoes 22 such as T-Bar cradle supports, or the like, to accommodate guided expansion and contraction of the substantially linear headers 16,18,20.

Alternatively, the headers 16,18,20 are supported directly by support structure 21 (e.g. on a cross beam thereof).
Two or more flow lines 24 are provided for each wellhead 12,14 for fluidly connecting the substantially linear headers 16,18,20 to the annulus and tubing strings of the wells. The flow lines 24 have a first end 26 for connecting to the wellhead 12,14 and a second end 28 for connecting to the designated substantially linear header 16,18,20.
Vertically-oriented offtakes 25 having a header end and a flow line end may be provided.
The vertically-oriented offtakes 25 are fluidly connected to the cylindrical portion of and near or at the center of each header at the header end (see Fig. 1 and Fig.
3). The vertically-oriented offtakes 25 protrude substantially vertical opposite the ground for accepting the flow line 24 at the flow line end thereon. The vertically-oriented offtakes 25 provide fluid communication to and from the main headers and the designated wellhead connected to either the tubing or the annulus of the well. Spacing of the vertically-oriented Makes 25 to and from the main headers is arranged in a geometric pattern that incorporates the wellhead centers. This allows spool pieces and manifolds that connect the vertically-oriented offtakes 25 to the wellheads 12,14 to be interposed and arranged alternatively for both warming up the SAGD Wells and producing them in typical SAGD
configuration as is known in the oil and gas industry. Individual well pairs may be configured independently in the modes of well pair warm-up, conventional SAGD
mode, and semi-SAGD with injector on circulation and producer in conventional mode.
In one embodiment, the flow lines 24 may be flexible such as a high pressure hose, or the like. In another embodiment, the flow lines 24 may comprise a series of rigid pipes connected by flexible joints, such as a swivel joint 30. In the present embodiment, four swivel joints 30i,30ii,30iii,30iv are provided for accommodating thermal expansion of both: (i) the wellheads 12,14 and (ii) the substantially linear headers 16,18,20. The swivel joints 30i,30ii,30iii,30iv may be any combination of uniaxial, biaxial, and multiaxial joints. In the present embodiment, swivel joint 30i is a multiaxial joint allowing movement in three planes, and 30ii,30iii,30iv are uniaxial swivel joints allowing movement in one plane each.
The combination of all of the swivel joints 30i,30ii,30iii,30iv accommodate thermal expansion in all three planes for allowing vertical and horizontal growth of the wellheads 12,14 as well as longitudinal growth of the substantially linear headers 16,18,20.
In the current state of the art, as noted above, the flow lines only have uniaxial swivel joints for accommodating only the vertical thermal expansion of the wellheads.
Because prior art wellpad assemblies contain substantially all of the pipe lines within a frame and disperse pipe stresses caused by thermal expansion with a pipe line loop, there has not been a need for the flow lines to move in a third plane, e.g.
substantially horizontal plane, i.e. that being along the same plane as the headers. Advantageously, in the present embodiment, the substantial linear headers 16,18,20 are free to thermally expand along their longitudinal axis and in a different/third plane (e.g. substantially horizontal) to that of the thermally expanding wellheads 12,14 (e.g. substantially vertically).
The novel combination of the multiaxial swivel joint 30i with the forth swivel joint 30iv is provided to accommodate sufficient thermal expansion in this third plane (the longitudinal plane of the headers 16,18,20). The fourth swivel joint 30iv may be located anywhere along the flow lines 24 and in any order in conjunction with the other three swivel joints 30i,30ii,30iii to assist in reducing the pipe stress caused by the thermally expanding substantially linear headers 16,18,20.
In another embodiment, the wellpad assembly 10 may comprise a flow line support guide system 50 for reducing pipe stress on the flow lines 24 and substantially linear headers 16,18,20. With reference to Figs. 2A, 2B, and 2C, detailed views of a support guide system 50 are provided. The wellpad assembly 10 may have one or more support guide systems 50 in conjunction with each set of flow lines 24 for each wellhead 12,14.
The support guide system may be located between the substantially linear headers 16,18,20 and the wellhead 12,14 for the flow lines 24 to be structurally supported thereon.
In the present embodiment the support guide system 50 is positioned adjacent the substantially linear headers 16,18,20 and connected to the support structure 21. The support guide system 50 comprises a longitudinal structural pipe support 52, such as a box beam or the like, positioned substantially parallel to the substantially linear headers 16,18,20. A pair of angular guides 54 are preferably fixed to opposite sides of the longitudinal structural pipe support 52. One or more clamp type supports 58 are releasably attached to the flow line 24 adjacent the structural pipe support 52. The one or more clamp type supports 58 may slideably engage one or both of the pair of angular guides 54 for restricting the displacement of the flow line 24 in an axial and vertical manner at the support guide system 50 to the longitudinal axis of the structural pipe support 52 along the same plane as the headers 16,18,20. A spacer pin 62, may be provided for securing the one or more clamp type supports 58 at an even spacing when the one or more clamp type supports 58 are straddling the structural pipe support 52. Preferably, the clamp type supports 58 include adjustment features that allow variation in positioning of the clamped pipe, axially and vertically, at right angles to the angular guides 54.
In another embodiment, one or more vee groove cam follower bearings 56 may be rotatably connected to the one or more clamp type supports 58 for engaging one or both of the angular guides 54 establishing a tongue and groove arrangement, thus reducing frictional forces between the one or more clamp type supports 58 and the angular guides 54.
THERMAL EXPANSION
Fig. 3 provides a perspective view of only one header, the second substantially linear header 18, of the wellpad assembly 10. For illustrative purposes the wellpad assembly 10 is oriented in a warm up configuration. The second substantially linear header 18, absent of expansion loops, is preferably supported and guided by the pipe shoes 22, which allows the second substantially linear header 18 to longitudinally slide thereon during expansion and contraction. The flexible piping connections avoid the necessity of a second (upper) piping level necessary to fit and support additional piping necessary in the current state of the art, including the Tsilevich design as discussed above.
The additional cost of a flexible piping connection to an existing trio on each wellhead connection may provide cost savings in avoided pipe and steel fabrication for systems presently as is known in the art. Advantageously, the present invention also provides lower piping loads such that any cross-member bents may be spaced at meters instead of the more common 6 meters, which may allow a further reduction in structural steel costs. The avoided piping lengths and welds characterized by the single anchor wellpad design may also be safer for operations staff, as the conventional upper platform can be avoided completely. Having less length and mass of pipe required for the wellpad assembly also potentially saves costs by reducing the complexity of the wellpad assembly as a whole.
Those skilled in the art understand that the present embodiment does not require any thermal expansion loops. Unlike those embodiments described in Tsilevich, the headers and equipment connected directly thereon, are now free to move longitudinally (e.g. substantially horizontal) along the length of the wellpad module toward and away from a stationary anchor module 80. The embodiments disclosed herein are adaptable to a have the capability to operate wellpairs simultaneously in three distinct modes, namely semi-SAGD, SAGD warm-up circulation, and conventional electric submersible pump SAGD.
In one embodiment, the wellpad assembly 10 may comprise of the first 16 and second 18 substantially linear headers during the SAGD production phase if a method known as gas lift, semi-SAGD, or the like, is utilized to produce the heavy oil. In semi-SAGD operations such as production via gas lift, the first substantially linear header 16 produces the heavy oil via gas lift and the second substantially linear header 18 injects steam into the formation.
In another embodiment, the wellpad assembly 10 may comprise of the first, second, and third substantially linear headers 16,18,20 during the SAGD
production phase if a method using an electric submersible pump, or the like, is utilized to produce the heavy oil. The first substantially linear header 16 carries produced heavy oil from the production wellhead 12 to a field facility. The second substantially linear header 18 carries steam to the injection well 14 for heating the formation and the heavy oil therein, while the third substantially linear header 20 carries produced casing gas from the production wellhead 12 to a field facility.
In operation and seen in Fig. 3, a schematic demonstrating the kinematics of the embodiments disclosed herein is provided. The present embodiments are accommodated by having four flexible piping connections, and accommodating the thermal expansion T of both the headers and the SAGO wellhead in the same arrangement of swivels, as described above.
Two positions of a wellhead 12 and header 18 are provided. An initial, cold position, representing the pipe structure in solid lines and a final, hot position, representing the pipe structure in dashed lines. Those skilled in the art understand that under thermal expansion T, the elements undergo a range of movement between the initial and final positions. Some of the elements in Figure 3 are represented such that, the initial cold position is represented with a "C" and the final hot position is represented with an "H" at the end of the element number (e.g. swivel 30iiC is the position of swivel 30ii at a cold position, while 30iiH is the position of that swivel at a hot position). Starting at the production wellhead 12, and upon warm up operations, the production wellhead 12 thermally expands along the wells vertical axis. In the present embodiment, the production wellhead 12 would expand substantially vertical, though one skilled in the art understands that the production wellhead 12 could be oriented off vertical as well. The multi axial swivel joint 30iC and the uniaxial swivel joints 30iiC and 30iiiC accommodate for the potential pipe stresses created in the flow line 24 during vertical thermal expansion of the production wellhead 12.
Furthermore, one skilled in the art also recognizes that the swivel joints 30i, 30ii, and 30iii, also accommodate displacement of the production wellhead 12 toward and away from the substantially linear header 16 as well.
During warm up operations, as both the injection wellhead 14 and the production wellhead 12 thermally expand, so too do the substantially linear headers 16,18,20.
Referring again to Fig. 3, the second substantial linear header 18 thermally expands along its longitudinal axis over its length. In the present embodiment, an anchor end 60 of the second substantially linear header 18 is held in place by an anchor module 11,80, as discussed below. During warm up operations, the second substantially linear header 18C
thermally expands away and opposite the anchor end 60 as it is displaced along the longitudinal axis down the length of the second substantially linear header 18H.
Prior art wellpad assemblies, such as Tsilevich, accommodate the above described longitudinal thermal expansion with costly and bulky pipeline expansion loops.
Advantageously, the present embodiment provides displacement of the headers 16,18,20 without the use of pipeline expansion loops. As described above the combination of a multi axial swivel joint 30i and the uniaxial swivel joint 30iv work to allow the flow line 24 to be displaced along the same plane as the second substantial linear header 18 while maintaining potential pipe stresses to a minimum during expansion. One skilled in the art would recognize that a similar result may be accomplished with the use of only one swivel joint oriented for allowing displacement of the flow line 24 in the same plane as the second substantial linear header 18. As the substantially linear header 18H thermally expands T
along its longitudinal axis, the flow line 24 is pivoted about swivel joint 30iC,30iH and again at swivel joint 30ivC,30ivH. The flow line 24 is then connected to the vertically oriented offtake 25 at the second end.
In another embodiment, and as described above, a support guide system 50 may be provided for additional support for the flow lines 24 during warm up and SAGD
operations. Flow lines 24 must be able to extend between the wellhead 24 and the substantially linear headers 16,18,20. The distance between the wellhead 24 and the substantially linear headers 16,18,20 can be in a range of 7 m to 15 m in length. The mass of the flow line 24 and the swivel joints 30i,30ii,30iii,30iv can create undesirable pipe stresses for the wellpad assembly 10. The support guide system 50 assists in relieving some of these additional pipe stresses. The support guide system 50 provides structural support in a substantially vertical direction, limits axial and rotation and vertical displacement of the flow line 24, yet allows displacement D of the flow line 24 in the longitudinal plane of the substantially linear header 16 (see Fig. 3). Thermal pipe stress loads are absorbed by displacement through the greater population of mechanical swivel joints; consequently expansion loads imposed on structural steel are largely negligible, and the structural steel loads are imposed primarily for pipe support.
The axial growth of the individual piping headers 16,18,20, may be as much as 0.5 m to 1 m on a very long wellpad comprising multiple wells. The disclosed embodiments integrate the necessary longitudinal thermal growth of the individual headers with the vertical growth of individual wellheads by adding the fourth mechanical swivel joint close to the edge of the wellpad pipe rack. As disclosed above all four flexible piping connections 30i,30ii,30iii,30iv work in concert to accommodate growth of the headers 16,18,20 and the wells 12,14 in different directions, independently for each well.
In the field of SAGD wellpad assemblies, vertical thermal growth of the wellhead assembly (along the axis of the wellbore proper) is typically designed on the order of -100mm to +800mm below/above an initial cold position (represented by the solid lines) of the wellhead. The embodiments provided herein, allow a similar horizontal thermal growth along the pipe rack headers serving each injection and production well of SAGD

operations (again on the order of -100 mm to +800 mm horizontally from the initial cold position) along the sides of the pipe rack module.
The present embodiments described herein comprise a system for heavy oil production having horizontal process piping headers in a SAGD wellpad with only one centrally disposed piping anchor system per header, allowing guided but unrestrained thermal piping growth axially along the line of wells drilled at the wellpad.
The system further comprises only straight runs of pipe with guides and supports and no additional anchors interposed between the centrally disposed piping anchor system and the individual wellhead connections.
As seen in Figs. 4A and 4B, in the field of SAGD wellpads, the piping configuration in the pipe rack modules can be arranged as a collection of long parallel substantially linear headers 16, 18 20, without interconnection between those headers within the physical limits of the pipe rack module itself. This arrangement may comprise specific electrical, pneumatic and other such instrumentation for metering the streams to and from the SAGD
Wells. The embodiments disclosed herein, are absent solid structural interconnection, such as structural piping, between the substantially linear headers 16,18,20 within the physical limits of the support structure 21 as each substantial linear header 16,18,20 is free to expand and contract at its own rate during operation. As such, the present embodiment may require one additional regulatory approval from a local oil and gas regulator. The arrangement of individual connections may be nominally parallel on opposing sides of the wellheads 12,14 (per the current practice) and arranged that the flow direction azimuth for each well in connection is nominally parallel to a long edge of the individual wellpad pipe racks.

The spacing between individual wells 12,14 may be standardized at a distance of approximately 12 m, which is typical for SAGD wells in the oil and gas industry. The offset from an edge of the wellpad assembly 10 to the wellhead centerline may be constrained to certain minimums of approximately 4 m or more, which is typical for SAGD wells in the oil and gas industry. In an embodiment provided herein a first row of wells comprising injection wells having a wellhead 14 are located along one side of the modules, and a second row of wells comprising production wells having a wellhead 12 are positioned opposite the first row with the wellpad assembly 10 located therebetween. The first and second rows of wells may be offset, to enhance the adaptability of temporarily repositioned spools utilized during a (nominal) 90-day well pair warm-up sequence as is typical in the oil and gas industry.
WARM UP CONFIGURATION
As seen in Figs. 4A and 4B, and in one embodiment, the wellpad assembly 10 is symmetrically oriented between the production wellhead 12 and the injection wellhead 14.
This symmetry works to the advantage of the present embodiment by providing a more simplistic method for modifying that wellpad assembly 10 from a warm up orientation to a SAGD or semi SAGD orientation. In Fig. 4A a plan view of the warm up configuration is provided. During warm up operations, steam is injected into both the production wellhead 12 and the injection wellhead 14 for heating the reservoir in preparation for producing the heavy oil. Warm up operations generally commence for approximately 90 days, though one skilled in the art understands that the warm up period is a variable to be determined on a reservoir by reservoir basis. In the present embodiment, three substantially linear headers 16,18,20 are provided meaning that the wellpad assembly is configured for SAGD

operations using an electric submersible pump, or the like, as the means for producing the heavy oil from the formation through the production wellhead 12.
A section of "L" shaped piping spools 70,72,74,76 are provided. The "L" shaped piping spools 70,72,74,76 are part of the flow lines 24 and located at the second end of the flow lines 24. The "L" shaped piping spools 70,72,74,76 span the space between the fourth swivel joint 30iv of the flow lines 24 and the vertically oriented offtakes 25. In the present embodiment, piping spool 74 connected to the flow line 24 from the production wellhead 12 and piping spool 76 connected to the flow line 24 from the injection wellhead 14 are permanent and do not change between the warm up configuration (Fig. 4A) and the SAGD configuration (Fig. 4B).
In reference to Fig. 4A, warm up configuration, the third substantially linear header is a return header for returning low quality steam from the annulus of the production well through the production wellhead 12 and the annulus of the injection well through the injection wellhead 14 during warm up operations. Piping spool 70 connected to the flow 15 line 24 from the production wellhead 12 and piping spool 72 connected to the flow line 24 from the injection wellhead 14 are variable and change between the warm up configuration (Fig. 4A) and the SAGD configuration (Fig. 4B). In reference to Fig. 4A, warm up configuration, the second substantially linear header 18 is a steam header for carrying steam from a field facility to the tubing string of the production well through the production 20 wellhead 12 and the tubing string of the injection well through the injection wellhead 14 during warm up operations.
WELLPAD ASSEMBLY CONVERSION FROM WARM UP TO SAGD CONFIGURATION
The advantage of the symmetry of the wellpad assembly 10 is demonstrated during the conversion process of the wellpad assembly 10 from warm up (Fig. 4A) to SAGD

production (Fig. 4B). The conversion from warm up to SAGD production comprises removing piping spools 70 and 72 from their respective flow lines 24 at one end and their respective vertically oriented offtake 25 at the other end. In Fig. 4A, piping spool 70 extends from the flow line 24 of the production wellhead 12, and crosses the third substantially linear header 20 prior to bending at a 90 degree elbow and extending parallel along the second substantially linear header 18 and connecting to the respective vertically oriented offtake 25. Piping spool 72 extends from the flow line 24 of the injection wellhead 14 and crosses the first substantially linear header 16 and the second substantially linear header 18 prior to bending at a 90 degree elbow and extending parallel along the third substantially linear header 20 and connecting to the respective vertically oriented offtake 25. The section of the piping spools 70,72 that extend parallel the substantially linear headers 16,18 between the 90 degree elbow and the vertically oriented offtake 25 are similar in length. This symmetry provides for the piping spools 70,72 to be swapped, and reconnected to convert the present embodiment of the wellpad assembly 10 to a SAGD
configuration (Fig. 4B). For clarity, piping spool 70 which was connecting a flow line 24 of the production wellhead 12 to the vertically oriented offtake 25 of the second substantially linear header 18 in the warm up configuration (Fig. 4A) is now connecting a flow line 24 of the injection wellhead 14 to the first substantially linear header 16 in the SAGD
configuration (Fig. 4B). The piping spool 72 which was connecting a flow line 24 of the injection wellhead 14 to the vertically oriented offtake 25 of the third substantially linear header 20 in the warm up configuration (Fig. 4A) is now connecting a flow line 24 of the production wellhead 12 to the third substantially linear header 20 in the SAGD

configuration (Fig. 4B).
SAGD CONFIGURATION

In Fig. 4B a plan view of the SAGD configuration is provided. During SAGD
operations, steam is injected into only the injection wellhead 14 for maintaining heat in the reservoir for assisting production of the heavy oil. SAGD operations generally commence for the life of the reservoir which may be approximately 10 years. One skilled in the art understands that the SAGD period is variable and differs on a reservoir by reservoir basis.
In the present embodiment, three substantially linear headers 16,18,20 are provided meaning that the wellpad assembly is configured for SAGD operations using an electric submersible pump, or the like, as the means for producing the heavy oil from the formation through the production wellhead 12. A section of "L" shaped piping spools 70,72,74,76 are provided. The "L" shaped piping spools 70,72,74,76 are part of the flow lines 24 and located at the second end of the flow lines 24. The "L" shaped piping spools 70,72,74,76 span the space between the fourth swivel joint 30iv of the flow lines 24 and the vertically oriented offlake 25. In the present embodiment, piping spool 74 connected to the flow line 24 from the production wellhead 12 and piping spool 76 connected to the flow line 24 from the injection wellhead 14 are permanent and do not change between the warm up configuration (Fig. 4A) and the SAGD configuration (Fig. 4B). In reference to Fig. 4A, SAGD configuration, the third substantially linear header 20 is a return header for producing casing gas from the annulus of the well and the production wellhead 12. Flow line 24 having piping spool 72 connected thereto provides a flow path for producing heavy oil from the tubing string of the production well via the production wellhead 12 into the first substantially linear header 16 which provides the produced heavy oil to flow to a field battery. Flow line 24 having piping spool 70 connected thereto provides an additional flow path to that of the permanent piping spool 76, from the second substantially linear header 18 to the injection wellhead 14. In SAGD configuration (Fig. 4B), steam is injected into the injection well, via the wellhead 14, into both the annulus and the tubing string for maintaining the heat in the reservoir to assist with heavy oil production.
ANCHOR MODULE
Having reference to Fig. 5, an embodiment of a system for heavy oil production is provided comprising an anchor module 80 and series of wellpad assemblies 10.
Embodiments disclosed herein provide wellpad piping such that there is only a single anchor module 80 for each piping header in the series, located at a central point nominally at the center of the arrangement of well pairs. This configuration allows piping to thermally expand in either direction from the single anchor point. Nominally identical branch modules, comprising individual wellpad assemblies 10, may be attached to either side of the anchor module, for expanding the scope of the wellpad and SAGD project and reducing costs through repeatability of manufacture for the wellpad equipment. The headers may be lengthened by adding additional wellpad assemblies 10 in series and connecting them to their respective header by flange joints or other methods as known in the art.
The single-anchor concept reduces wellpad structural steel requirements by balancing loads symmetrically. Thermal pipe expansion is absorbed by displacement through the greater population of mechanical swivel joints; consequently expansion loads imposed on structural steel are minimized, and the structural steel loads are imposed primarily for pipe support. The anchor module may be a conventional design as is known in the art, where connections to main steam and emulsion pipelines from a processing facility for servicing the wellpad are made. The embodiments of a single-anchor concept described herein, allows production of wellpad manifolds under 11.5 feet in width and 78.7 feet in length overall, making the manifolds suitable for railway flatcar transportation. The dimensions allow fabrication of the manifolds to be conveniently close to railway connections over a very large area inside North America for accessible transportation.
Having reference to Fig. 6, an anchor module 80 is provided comprising an embodiment of a wellpad assembly 10 for demonstrating the connectivity and potential for a series of multiple wellpad assemblies 10 for a heavy oil production project.
The anchor module and wellpad assembly 10 are fluidly connected by their respective headers 16,18,20. The connections may be completed using common methods as is known in the art such as flange joints and the like. The anchor module performs the same operations functions as any central module does in the industry, however, in the present embodiment, the anchor module additionally acts as an "anchor" point for the multiple wellpad assemblies 10 that are connected therefrom. As the substantially linear headers 16,18,20 are thermally expanding, the anchor module prevents the substantially linear headers 16,18,20 from longitudinally displacing in two directions. Therefore, all of the substantially linear headers 16,18,20 are longitudinally displaced D opposite the anchor module when expanding.

Claims (38)

THE EMBODIMENTS OF THE INVENTION IN WHICH AN EXCLUSIVE
PROPERTY OR PRIVILEGE IS BEING CLAIMED ARE DEFINED AS FOLLOWS:

1. A system for heavy oil production comprising:
one or more injection wells having a well head;
one or more production wells having a well head;
a support structure;
a first substantially linear header supported by the support structure, said first substantially linear header being free to thermally expand and contract along a longitudinally axis, said first substantially linear header being spaced from the one or more injection wells for injecting steam into the well head of the one or more injection wells;
a second substantially linear header supported by the support structure, said second substantially linear header being free to longitudinally thermally expand and contract along a longitudinally axis, said second substantially linear header being spaced from the one or more production wells for producing heavy oil from the well head of the one or more production wells;
one or more injection flow lines, having a first end and a second end, the first end fluidly connected to the well head of the one or more injection wells, the second end fluidly connected to the first substantially linear injection header for injecting steam into the one or more injection wells; and one or more production flow lines, having a first end and a second end, the first end fluidly connected to the well head of the one or more production wells, the second end fluidly connected to the second substantially linear production header for producing heavy oil from the one or more production wells.

2. The system of claim 1 further comprising a third substantially linear header supported by the support structure, said third substantially linear header being free to thermally expand and contract along a longitudinally axis, said third substantially linear header being spaced from the one or more production wells, wherein the second end of one of the one or more production flow lines is connected to the third substantially linear header for producing gas from the well head of the one or more production wells.

3. The system of claim 1 or 2, wherein the first, the second and the third substantially linear headers do not comprise expansion loops or flexible piping connections along their full lengths.

4. The system of any one of claims 1, 2 or 3 wherein the first, the second and the third substantially linear headers are adjacent and aligned substantially parallel one another.

5. The system of any one of claims 1 to 4 wherein the support structure further comprises pipe shoes for structurally supporting and guiding the first, the second and the third substantially linear headers.

6. The system of any one of claims 1 to 5 wherein the one or more injection flow lines and the one or more production flow lines comprise one or more flexible piping connections, suitable for joining to the well head or to a swivel head of an adjacent pipe for providing corresponding movement of the flow lines in responding to thermal expansion and contraction of the substantial linear headers.

7. The system of any one of claims 1 to 6 wherein the one or more injection flow lines and the one or more production flow lines each comprise four flexible piping connections suitable for joining to the well head or to a swivel head of an adjacent pipe for providing corresponding movement of the flow lines in responding to thermal expansion and contraction of the substantial linear headers.

8. The system for heavy oil production of any one of claims 1 to 7 further comprising, a support guide system for providing structural support to the one or more production flow lines, the one or more injection flow lines, or both the one or more production flow lines and the one or more injection flow lines; and wherein said support guide system allows displacement of both the one or more production flow lines and the one or more injection flow lines along the longitudinal axis of the first, the second and the third substantially linear headers.

9. The system for heavy oil production of claim 8 wherein the support guide system further comprises:
a longitudinal structural pipe support positioned substantially parallel to the one or more production headers and one or more injection headers;
one or more clamp type supports for slideably connecting the one or more production flow lines and the one or more injection flow lines to the longitudinal structural pipe support; and wherein the one or more damp type supports secure the one or more production flow lines and the one or more injection flow lines in an axial direction.

10. The system for heavy oil production of claim 9 wherein the support guide system further comprises a pair of angular guides attached to opposite sides of the longitudinal structural pipe support.

11. The system for heavy oil production of claim 10 further comprising a pair of vee groove cam follower bearings for slideably engaging the pair of angular guides.

12. The system for heavy oil production of claim 11 wherein the pair of vee groove cam follower bearings are connected to the pair of clamp type supports, the pair of vee groove cam follower bearings are spaced along a length of the one or more production flow lines to straddle the longitudinal structural pipe support for securing the one or more production flow lines in an axial direction and to allow movement in a longitudinal direction similar to the one or more headers during thermal expansion and contraction.

13. The system of any one of claims 1 to 12 wherein one or more injection wells and the one or more production wells are consistently spaced from each other along the length of the substantially linear headers.

14. The system of any one of claims 1 to 13 further comprising control valves and electronics interactive with the substantially linear headers.

15. A system for heavy oil production comprising:
a first piping assembly having a plurality of substantially linear headers supported solely at their longitudinal centers and free to longitudinally thermally expand and contract on a single axis over their full length extending therealong, the first piping assembly being transportable and supported by a single frame;
a second piping assembly having a plurality of substantially linear headers supported solely at their longitudinal centers and free to longitudinally thermally expand and contract on a single axis over their full length extending therealong, the second piping assembly being transportable and supported by a single frame;
the plurality of substantially linear headers supported solely at their longitudinal centers and free to longitudinally thermally expand and contract on a single axis over their full length of the second piping assembly selectively connected to the plurality of substantially linear headers supported solely at their longitudinal centers and free to longitudinally thermally expand and contract on a single axis over their full length of the first piping assembly, the first piping assembly being joined in end-to-end relationship with the second piping assembly and being formed into a string of basic units connected to each other with the plurality of substantially linear headers supported solely at their longitudinal centers and free to longitudinally thermally expand and contract on a single axis over their full length, each unit being substantially parallel to a line of injection or production wells and having flow lines to the line of injection or production wells.

16. The system of claim 15 wherein the plurality of substantially linear headers supported solely at their longitudinal centers and free to longitudinally thermally expand and contract on a single axis over their full length being exposed on opposite ends thereof.

17. The system of claim 15 or 16, wherein the flow lines connecting the plurality of substantially linear headers supported solely at their longitudinal centers and free to longitudinally thermally expand and contract on a single axis over their full length to the injection or production wells further comprise, flexible piping connections, suitable for joining to a well head or to a swivel head of an adjacent pipe for providing corresponding movement of the flow lines in responding to thermal expansion and contraction of the substantial linear headers.

18. The system of claims 15, 16 or 17, further comprising control valves and electronics interactive with the substantially linear headers.

19. The system of any one of claims 15 to 18, wherein the substantially linear headers do not comprise expansion loops or flexible piping connections along their full lengths.

20. The system of any one of claims 15 to 19 further comprising, a support structure having multiple guides for structurally supporting the substantially linear headers along the entire length of each header for each piping assembly.

21. The system of any one of claims 15 to 20 further comprising, a support guide positioned between the production wells, the injection wells, or both the production wells and the injection wells, on one side, and the piping assembly on the opposite side, for providing structural support to the flow lines.

22. The system of claim 15 wherein the support guide further comprises:
a longitudinal structural pipe support positioned substantially parallel to the one or more production headers and one or more injection headers;
a pair of clamp type supports for slideably connecting the one or more production flow lines or the one or more injection flow lines, to the longitudinal structural pipe support, wherein the pair of clamp type supports are spaced along a length of the one or more production flow lines to straddle the longitudinal structural pipe support for securing the one or more production flow lines in an axial direction and to allow movement in a longitudinal direction similar to the one or more headers during thermal expansion and contraction.

23. The system of claim 22 further comprising a pair of angular guides attached to opposite sides of the longitudinal structural pipe support;

24. The system of claim 23 further comprising a pair of vee groove cam follower bearings for slideably engaging the pair of angular guides, wherein the pair of vee groove cam follower bearings are connected to the pair of clamp type supports, the pair of vee groove cam follower bearings are spaced along a length of the one or more production flow lines to straddle the longitudinal structural pipe support for securing the one or more production flow lines in an axial direction and to allow movement in a longitudinal direction similar to the one or more headers during thermal expansion and contraction.

25. The system of any one of claims 15 to 24 wherein one or more injection wells and the one or more production wells are consistently spaced from each other along the length of the substantially linear headers.

26. A method of producing heavy oil using steam assisted gravity drainage, having at least one injection well and at least one production well, the method comprising:
anchoring an anchor module to the ground;

supporting a first group of one or more linear headers on the anchoring module;
supporting a second group of one or more linear headers on at least one header module, so as to allow thermal displacement of said second group of one or more linear headers along a longitudinal axis;
connecting at least one of the second group of one or more linear headers on the header module to the first group of one or more linear headers on the anchor module;
commencing warmup operations by configuring the first and second groups of one or more linear headers for flowing steam into the at least one injection well and the at least one production well; and commencing production operations by configuring the first and second groups of one or more linear headers for flowing steam into the at least one injection well and producing heavy oil from the at least one production well.

27. A system for supporting a section of substantially linear pipe, said substantially linear pipe experiencing thermal displacement along a longitudinal axis and said substantially linear pipe being fluidly connected to at least one well having a wellhead, the system comprising:
at least one support structure (21) for supporting the section of substantially linear pipe; and at least one flow line (24) for fluidly connecting the section of substantially linear pipe to the at least one well;
wherein the at least one support structure (21) accommodates said thermal displacement of the section of substantially linear pipe along said longitudinal axis.

28. The system of claim 27 wherein the section of substantially linear pipe lays on the at least one support structure (21).

29. The system of claim 27 wherein the at least one support structure (21) further comprises at least one pipe shoe (22) to support said section of substantially linear pipe.

30. The system of any one of claims 27 to 29 further comprising, a support guide system (50) for providing structural support to the at least one flow line (24); and wherein said support guide system (50) allows displacement of the at least one flow line (24) in a direction that is substantially parallel to the longitudinal axis of the section of substantially linear pipe.

31. The system of claim 30 wherein the support guide system (50) further comprises:
a longitudinal structural pipe support (52) positioned substantially parallel to the longitudinal axis of the section of substantially linear pipe; and one or more clamp type supports (58) for slideably connecting the at least one flow line (24) to the longitudinal structural pipe support (50).

32. The system of claim 31 wherein the support guide system (50) further comprises a pair of angular guides (54) attached to opposite sides of the longitudinal structural pipe support (52).

33. The system of claim 32 further comprising a pair of vee groove cam follower bearings (56) for slideably engaging the pair of angular guides (54).

34. The system of claim 33 wherein the pair of vee groove cam follower bearings (56) are connected to the pair of clamp type supports (58); and wherein the pair of vee groove cam follower bearings (54) are spaced along a length of the at least one flow line (24) to straddle the longitudinal structural pipe support (52) for securing the at least one flow line (24) in an axial direction.

35. The system of any one of claims 27 to 34 wherein the flow lines (24) are flexible.

36. The system of any one of claims 27 to 34 wherein the flow lines (24) comprise a series of rigid pipes connected by flexible joints.

37. The system of 36 wherein the flexible joints are swivel joints (30).

38. The system of 36 wherein the flexible joints include at least one multiaxial swivel joint (30i).