CA2509268A1 - Method of collecting hydrocarbons from tunnels - Google Patents

Abstract

There are a number of problems with the existing methods of steam-assisted gravity techniques to recover oil from oil sands. The present invention provides a method for recovering viscous hydrocarbons by installing one or more tunnels in and/or below a hydrocarbon formation; drilling a plurality of wells in the hydrocarbon formation, the wells being transverse and connected to at least one tunnel; injecting steam into the hydrocarbon formation from at least one of the wells; collecting fluid hydrocarbons through at least one of the wells to at least one of the tunnels; and transporting the hydrocarbons from at least one of the tunnels to the surface.

Description

METHOD OF COLLECTING HYDROCARBONS FROM TUNNELS
BACKGROUND OF THE INVENTION
Oil is a nonrenewable natural resource having great importance to the industrialized world. Over the past century, the consumption of oil has increased dramatically and has become a strategic commodity. The increased demand for and decreasing supplies of conventional oil has led to the development of alternative sources of crude oil such as oil sands containing bitumen or heavy oil and to a search for new techniques for continued recovery of depleted conventional oil deposits. The development of the Athabasca oil sands in particular has resulted in increased proven world reserves of over 170 billion barrels from the application of surface mining and in-situ steaming technologies.
The vast majority of the world's oil sands deposits are found in Canada and Venezuela.
Collectively, oil sands deposits contain an estimated 6 trillion barrels of in-place oil. In-situ technologies which include the steam-assisted gravity drainage ("SAGD") process are typically applied by using horizontal drilling techniques and then injecting steam and collecting mobilized bitumen from these horizontal wells. It is to be understood that a reference to bitumen herein is intended to include heavy oil and vice versa.
Typically, wells are drilled from the earth's surface down into the oil sand deposit and then horizontally along the bottom of the deposit. The valuable hydrocarbons in these oil sand formations in their normal, undisturbed state are very viscous and immobile.
Many different techniques have been developed to establish both a communication path through the heavy, highly viscous bitumen-filled sand and an efficient method to recovery the bitumen from the sand. These methods include such things as steam injection, solvent flooding, gas injection, and the like. Such processes generally involve the altering of the oil sand formation to reduce the viscosity of the formation, thereby allowing removal of the resource from the formation in fluid form by hydraulic means or gravity flow.

To overcome the problems of conventional steam flooding, the steam-assisted gravity drainage ("SAGD") process was developed by professor Roger Butler and first reduced to practice at the Underground Test Facility ("UTF") in Alberta, Canada. This facility involved the construction of an access shaft through the overburden and oil sands into the underlying limestone. From this shaft, underground workings were developed in the underlying limestone from which well pairs were drilled up into the oil sands deposit and then horizontally along the bottom of the deposit.
The original SAGD process is based on a closely spaced pair of horizontal wells with a production well (producer) near the bottom of the oil sand zone and a parallel steam injection well (injector) located a few meters above the producer. Upon injection of steam through the injector ports, a steam chamber will form around and above the injector well which will heat the bitumen. The heated bitumen, with more mobility, and the condensed steam will flow along the steam chamber boundary (also called a condensation front) by gravity to the producer. The produced fluids are then directed to the surface for transport to refineries.
With the advent of horizontal drilling techniques, it became possible to install SAGD
well pairs by drilling from the surface. This is now the preferred method of implementing SAGD. Since then, several variations of this process have since been proposed and subjected to limited testing. For example, a modification to SAGD has been developed whereby the addition of a third horizontal well has improved recovery (increased bitumen production and decreased steam-oil ratio) under certain operating conditions. Other variants of gravity drain technology include the Vapor Extraction ("VAPEX") process which involves the injection of vaporized solvents such as ethane or propane to create a vapor-chamber which reduces the viscosity of the bitumen and allows to flow downward due to gravity drainage.
The patent literature includes a number of thermal and other in-situ methods.
US
4,160,481 discloses a plurality of bore holes radially extending from a central bore hole to inject steam into the oil sand formation. Steam is injected into some bore holes to drive the oil into the remaining bore hole where it is collected. In US 4,160,481, a method is described in which perforated radial tubes extend laterally into the formation from a central bore hole. That system uses a cyclic steam injection procedure. After a number of steam injection/production cycles, the process can be converted to a continuous steam drive where steam is continuously injected into one radial and oil is produced from another radial.
US 4,463,988, describes an in-situ recovery system for an oil sand deposit in which a network of horizontal production tunnels and connecting horizontal bore holes are provided. This is a complex structure and a difficult and expensive one to install and operate. This invention predates soft-ground tunneling technology and is dependent on tunnels being driven in competent ground such as the overburden or underlying basement rock.
US 3,386,508, describes a system for recovering oil in which a plurality of directional (slant) wells are drilled from the surface to intersect a central vertical well within an oil bearing formation. Both the directional wells and the vertical well bore communicate fluidly with the oil bearing formation.
In US 5,016,710, another system for recovering oil is described having a plurality of slant wells drilled from the surface to cooperate with a central vertical well within an oil bearing formation. With this design, steam may be injected into the oil bearing formation either from the central vertical well or from the plurality of slant wells.
Methods such as SAGD or VAPEX require a certain level of overburden for the process to be contained. The SAGD process is a relatively low pressure process so that the steam pressure will not fracture the formation and cause the steam chamber to break down. Typically, the SAGD process can recover 40% to 70% of the original bitumen or heavy oil in place, depending on the geologic complexity of the reservoir. The eventual net recovery rate of SAGD
and other gravity drain processes is sensitive to the presence of mud and shale layers within the deposits which can form barriers to the outward flow of steam and return flow of mobilized bitumen or heavy oil. Thus the economics of these processes are sensitive to the complex and variable natures of the reservoir geologies that are found.
SAGD requires that large quantities of steam be injected into the reservoir to heat up not only the bitumen or heavy oil but also the reservoir sand or rock matrix. The energy required to produce the steam is a significant fraction of the energy of the recovered bitumen or heavy oil, typically in the range of about 20 to about 25% of the recovered petroleum energy. Usually the energy source to produce the steam is natural gas. Thus the economics of the in-situ thermal recovery processes are sensitive to gas prices and these in-situ processes may become uneconomical if the price of natural gas increases substantially as occurs from time to time depending on weather and/or pipeline capacity.
US 6,263,965 entitled "Multiple Drain Method for Recovering Oil from Tar Sand"
describes an alternate thermal method for recovering normally immobile hydrocarbon oil from a subsurface oil sand deposit. The procedure comprises establishing at least one substantially vertical production bore hole extending from the surface of the earth to at least the bottom of a subsurface formation; providing a plurality of bore holes extending downwardly from the surface of the earth through the oil sand formation to substantially the bottom and then substantially horizontally at or near the bottom of the oil sand formation and converging radially inward to each bore hole, each radial bore hole containing a perforated or slotted tube;
continuously injecting steam downwardly through the perforated or slotted tubes whereby the steam discharges through the perforations or slots and into the oil sand formation to reduce the viscosity of the normally immobile oil, with a substantial proportion of the steam being injected into the formation via the portion of each tube extending downwardly through the oil sand formation whereby the steam reduces the viscosity of the normally immobile oil over an area extending substantially between the perforated tube and the top of the oil sand formation with this viscosity reducing area expanding radially and moving axially inwardly toward the vertical production bore hole thereby creating an expanding generally conical-shaped production chamber; and draining the less viscous oil and steam condensate thus obtained downwardly by gravity to the bottom of the production chamber and then through the horizontal tubes into the bottom of the vertical production bore hole for collection. One of the biggest problems encountered in limited field testing of single well SAGD has been plugging of the drainage perforations.
In recent years, there has been a dramatic increase in the number of machine driven soft-ground tunneling projects utilizing the proven technologies of tunneling and tunnel boring machines (TBMs). This increase is largely due to the technological development of slurry and EPB (Earth Pressure Balance) shield systems. A new generation of soft ground tunneling machines, markedly different from those of five years ago, now overcomes ground conditions that until now were too costly and impractical to undertake. This technology enjoys a very high safety and reliability record having been used in a variety of tunneling applications around the world for the last 30 years.
The civil tunneling industry has been developing soft-ground tunneling machines for use in a variety of transportation and infrastructure tunneling projects. For example, a machine manufactured in Germany measured 14.2 meters in diameter and is one of the largest soft-ground tunnel boring machines ever built. It was used to install a large transportation tunnel in the saturated clay river bottom under a river. This machine excavates by forming a slurry ahead of the rotating cutter head and then ingesting the slurry into a chamber held at the local formation pressure which, under the Elbe, reached 6 atmospheres. The entire machine is shielded and the men inside work at atmospheric pressure and are fully isolated from the exterior environment.
The German machine is a mixshield machine. This machine incorporates features of slurry machines, Earth Pressure Balance machines, pressure shield machines and some features of hard rock TBMs. The small, counter-rotating cutter head in the center of the main cutter head was employed to overcome the sticky clays encountered under the Elbe. This machine was operated within a few meters of the river bottom and control over its positioning had to be precise.
Soft ground tunneling machines have been used in a variety of complex and challenging geologic environments such as saturated clay river bottoms, gravelly, sandy, and other mixed geologic settings.
Currently, soft-ground tunnel liners are made of concrete and erected in segments. The segments may be sealed from the surrounding ground by low-cost gaskets or by more complex sealing arrangements if long lifetimes are required. Extruded concrete linings are currently being developed by the civil driven by the financial advantages of less manpower and higher TBM
advance rates. In an extruded concrete liner, the tunnel lining is embedded in the surrounding ground as fluid concrete is extruded at constant pressure directly behind the TBM supporting the exposed surface. This method of installing concrete liners also eliminates the need for sealing gaskets and may provide excellent sealing at lower costs.
Hard rock tunneling machines predate soft ground machines and have been used in most types of rock from moderately hard to very hard (over 30,000 psi). Typically, these machines are easier to operate since the rock is self supporting and there is little ground support required behind the advancing machine.
There are many well known drilling methods for use in soft ground that is not self supporting. These utilize drilling bits, augurs and rotating cutter heads for example. Typically, soft ground drilling is carried out by a form of pipe jacking. In pipe jacking, the pipe that ultimately is installed is used to push the drilling bit forward providing propulsive thrust and is simultaneously used as the conduit for circulating the drilling mud and cuttings. The principal problem in drilling in soft ground is maintaining a pressure seal between the formation and the drilling platform. When conventional drill bits or augurs are used, this seal is provided by the drilling mud which may range from a slightly viscous fluid to a plasticized drilling mud.

Micro-tunneling is a process that uses a remotely controlled micro-tunnel boring machine (MTBM) combined with the pipe jacking technique to directly install underground pipelines in a single pass. This process avoids the need to have long stretches of open trench for pipe laying.
In the U.S., micro-tunneling has been used to install pipe from twelve inches to twelve feet in diameter. Therefore, the definition for micro-tunneling in the U.S. does not necessarily include size and has evolved to describe a tunneling process where the workforce does not routinely work in the tunnel. Micro-tunneling is currently the most accurate pipeline installation method.
Line and grade tolerances of one inch are the micro-tunneling industry standard. This can be extremely important when trying to install a new pipeline in an area where a maze of underground utility lines already exists.
Micro-tunneling was developed in the early 1970's to replace open sewers in urban areas with underground gravity sewers. Although originally designed for gravity sewer construction, this technique has since been used to install a variety of utility conduits, underground crossings of highways, railroads, runways, rivers, and environmentally sensitive areas for a variety of utilities. This process has also been used to install plant intakes and out falls. Micro-tunneling is also used in the pipe arch technique of supporting large underground openings with an arch or roof made up of small tunnels.
In micro-tunneling, sealing between the formation and the operating platform.
is maintained by the cutting slurry at the rotating cutter head, as is practiced in larger manned slurry TBMs.
One of the present inventors has developed a hybrid drilling method using a modified pipe jacking process in conjunction with a augur cutting tool and a plasticized drilling mud to install horizontal wells from the bottom of a distant shaft into a river bottom formation. This technique was successfully used to develop water wells that receive potable water from the river by utilizing the river-bed as a filter for the non-potable river water.
_7_ Existing methods for recovering oil from oil sands have numerous drawbacks.
Surface mining techniques are typically only economical for shallow oil sands deposits. It is common for oil sands deposits to dip and a significant part of the ore body may be located at depths that are too deep to recover by surface mining methods. As a result, most of the oil sands deposits are unprofitable to mine. In-situ techniques are disadvantaged in that a relatively large amount of energy is consumed per unit energy recovered in the bitumen.
Other oil sands deposits are located under surface features that preclude the use of surface based recovery methods, whether by surface mining or in-situ methods. For example, oil sands deposits can be located under lakes, swamps, protected animal habitats and surface mine facilities such as tailings ponds. Estimates for economical grade bitumen in these in-between and inaccessible areas on the order of 30 to 100 billion barrels.
There are a number of problems associated with the SAGD process which are as yet unresolved. These include for example the following. Steam injection conditions can degrade over the length of the injection well, limiting the length of the well. The size of the collector wells that can be economically drilled is limited thus limiting the effective producible length of producer wells. The well pairs lose a substantial amount of heat to the formation over the lengths drilled through the overburden. There is a need to more quickly heat the formation laterally between laterally spaced wells. The steam chambers produced by pairs of SAGD wells are generally triangular in cross-section resulting in a volume of unheated and unrecovered oil left between the chambers in the lower part of the reservoir. Well pair spacing is often affected by drilling problems and the collector well cannot always be placed in the desired relation to the injector well.
It is an objective of the present invention in any of its embodiments to provide a method for installing horizontal wells suitable for SAGD and other in-situ processes which improves the _g_ accuracy of horizontal well placement, provides a more effective means of injecting steam and recovering mobilized bitumen and reduces the surface disturbance associated with surface installation of horizontal wells. It is another objective to apply a these methods to conventional oil and gas wells to allow better drainage of reservoirs that may otherwise be deemed depleted.
SUMMARY OF THE INVENTION
The present invention combines soft-ground tunneling and shaft sinking technology with proven and advanced methods of drilling wells to enable several new and versatile methods of implementing in-situ methods for recovery of heavy oil and bitumen from oil sands. The present invention can also be used in a non-thermal mode to drain pressure-depleted or low permeability conventional oil and gas reservoirs.
A Tunnel as a SAGD Well Pair In a first embodiment, the present invention discloses a method and system for recovering bitumen and heavy oil from oil sands by using one or more tunnels emplaced near the bottom of the oil sand deposit by well-known, soft-ground tunnel boring machines and tunnel liner installation methods. Each tunnel serves as a housing for a steam injection system and a fluid collection system that emulates and improves on those installed by surface-based directional drilling techniques. As such, it is a method for locating and operating a SAGD
steam chamber that does not require drilling well pairs from the surface such as currently practiced for the SAGD method in the Alberta oil sands. Further, it does not require excavation in the underlying hard rock basement such as done for the original SAGD underground test facility, also in Alberta.
The method of the present invention overcomes several problems associated with conventional SAGD in which well pairs are installed by directional drilling techniques controlled from the surface. In the present invention, the location of steam injection into the oil sand formation can be accurately controlled with respect to the fluid collection points. In addition, the steam pressure and temperature gradients associated with conventional SAGD can be eliminated so as to permit substantially longer horizontal injection/collection systems.
Further, fluids (principally mobilized bitumen and condensed water) can be collected over a larger collection area thereby increasing production rate per unit length and brought to the surface using well-known pumping techniques thereby eliminating lift problems often associated with conventional SAGD. In another aspect of this embodiment, the method described above can be modified and extended to include means to inject steam at differing locations within the oil sand deposit.
The Tunnel as a SAGD Well with Additional Drilled Wells In a second embodiment, the method can be extended by drilling well pairs into the oil sands surrounding the tunnel and/or by drilling single wells into the oil sands such as disclosed in US 6,263,965. In yet another form of the second embodiment, the method can extended to include additional horizontal wells or well pairs drilled between adjacent tunnels. This latter embodiment allows more complete areal drainage and recovery from an oil sand deposit especially near the bottom of a deposit. In yet another form of the second embodiment, tunnels are used as locations to drill horizontal wells or well pairs and, optionally, additional upwardly oriented wells or well pairs into an oil sands deposit. In this second embodiment the tunnels may or may not be used to directly inject steam and collect fluid.
The Tunnel as a Collector In a third embodiment, single well or well pairs may be drilled from the surface in a conventional manner and a lined tunnel may be used as a collector.

The Tunnel as a Drilling Platform and Collector To further illustrate methods of implementing in-situ methods for recovery of heavy oil and bitumen utilizing tunneling technology, a number of drilling variations are described for installing single wells, well pairs or combinations of the two utilizing tunnels driven into the oil sands deposits or into the underlying limestone. Tunnels installed at or near the bottom of the oil sands deposits are suitable for shallow deposits where formation pressures are generally less than about 20 bars. Tunnels installed in the underlying limestone are suitable for deeper deposits where formation pressures are generally greater than about 10 bars.
A preferred fourth embodiment of the present invention utilizes single wells drilled between tunnels and/or single wells drilled between the surface and the tunnels. Wells drilled between tunnels are generally approximately horizontal. Wells drilled from the surface have a substantial approximately horizontal portion at or near the bottom of the oil sands deposit which terminates at a tunnel and is connected to the tunnel.
The principle innovation of the present inventions is that wells may be drilled from tunnels or from the ground surface to tunnels where the tunnels are at or near the bottom of the reservoir or underneath the reservoir. These wells may be used to steam bitumen or heavy oil deposits and then drain the mobilized hydrocarbons. In the case of conventional oil deposits, oil may be drained by gravity to the tunnels for recovery.
In yet another form of the fourth embodiment, horizontal tunnels are used as locations to drill horizontal or upwardly oriented non-thermal drainage wells into conventional oil or gas reservoirs to effect a more complete drainage, especially of pressure-depleted reservoirs. This method can also be applied to conventional, low-permeability reservoirs where the oil might be light enough to flow downward under gravity.

In summary, the present invention can be used as a means to install conventional SAGD
well pairs as well as a number of known variants of in-situ thermal recovery methods. Tunnels can be used as platforms for drilling wells as well as locations for collecting hydrocarbons drained by the wells. In oil sands, these tunnel-based drilling methods may be used from tunnels emplaced in the oil sand deposit or in the rock formations underlying the oil sands. When installed directly in an oil sands deposit, one or more large lined tunnels can themselves be used as well pairs; as single injector/collector wells; or as platforms for drilling wells into the oil sands formation; or as combinations of these.
"At least one", "one or more", and "and/or" are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C", "at least one of A, B, or C", "one or more of A, B, and C", "one or more of A, B, or C" and "A, B, and/or C" means A alone, B alone, C alone, A and B together, A
and C together, B
and C together, or A, B and C together.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1, which is prior art, is a schematic representation of conventional SAGD as currently practiced.
Figure 2, which is prior art, is a schematic representation of how a SAGD
steam chamber drains bitumen.
Figure 3, which is prior art, is a schematic representation of how adjacent SAGD steam chambers coalesce.
Figure 4 is side view of a tunnel emplaced near the bottom of an oil sands deposit for SAGD.

Figure 5 is and end view of multiple tunnels emplaced near the bottom of an oil sands deposit.
Figure 6 is a plan view of multiple tunnels emplaced near the bottom of an oil sands deposit.
Figure 7 is an isometric view of tunnel segments showing possible steam injection and fluid collection locations.
Figure 8 is an end view of a tunnel showing a SAGD steam chamber.
Figure 9 shows an end view of a backfilled liner around the tunnel segments.
Figure 10 is a plan view of a configuration for steam injection and collection.
Figure 11 is an isometric view of a tunnel segment showing injector and collector ports.
Figure 12 is a plan view of a configuration of bore holes drilled horizontally from one or more tunnels.
Figure 13 is an end view of a configuration of bore holes drilled from one or more tunnels.
Figure 14 is an example of a steam chamber formed by a single injector/collector well geometry.
Figure 15 shows an example of a slotted injector/collector pipe.
Figure 16 shows another configuration where a horizontal tunnel is used for wells drilled from the surface to intercept the tunnel.
Figure 17 shows an end view of an alternate method for a backfilled liner around the tunnel segments.

Figure 18 is side view of a tunnel emplaced below or near the bottom of a conventional oil or gas reservoir for gravity drainage.
Figure 19 is a schematic end view of two tunnels in the oil sands showing all well pairs drilled from the tunnels.
Figure 20 is a schematic end view of two tunnels in the oil sands showing well pairs drilled from the tunnels and from the surface.
Figure 21 is a schematic end view of two tunnels in the oil sands showing single wells and well pairs drilled from the tunnels.
Figure 22 is a schematic end view of two tunnels in the oil sands showing single wells drilled from a tunnel and from the surface.
Figure 23 is a schematic end view of two tunnels in the limestone showing all well pairs drilled from the tunnels.
Figure 24 is a schematic end view of two tunnels in the limestone showing well pairs drilled from the tunnels and from the surface.
Figure 25 is a schematic end view of two tunnels in the limestone showing single wells and well pairs drilled from the tunnels.
Figure 26 is a schematic end view of two tunnels in the limestone showing single wells drilled from a tunnel and from the surface.

DETAILED DESCRIPTION OF THE DRAWINGS
Figure 1, which is prior art, shows a schematic representation of a well pair as installed from the surface for a conventional SAGD operation as currently practiced.
Typically, the well pair 104 and 105 are drilled from a surface pad 106 through the overburden 102 and into an oil sand deposit 101 using directional drilling techniques. The lower well 105 is the collector or producer well and is generally located near the bottom of the oil sand deposit 101 just above the underlying bedrock 103. The upper well 104 is the steam injector well and is generally located just above the producer well 105. The injector well 104 is typically drilled to be parallel to the producer well but offset 2 to 5 meters above the producer well 104 (also referred to as a collector well). This well pair geometry has been field tested and has confirmed the basic operation of the SAGD process. Steam is injected along the horizontal portion of injector 104 and rises into the oil sand deposit, heating the oil sand and mobilizing the bitumen (mobilizing means reducing the viscosity to where the bitumen becomes fluid and will flow). The steam rises and the mobilized bitumen falls under gravity and is collected in the producer well 105. The placement of the well pairs horizontally not only allows the bitumen to flow downward for collection but also presents a long length of collector well so that commercially viable production rates are achieved. In practice, an oil sands deposit might be thermally produced by a number of SAGD
well pairs ranging from about 10 well pairs to about 200 well pairs.
Figure 2, which is prior art, is a schematic representation in end view of how a SAGD
steam chamber drains bitumen. Steam is injected 204 via an injector well 202 into the oil sands where it heats the formation and mobilizes the bitumen as described previously. The steam rises 206 forming a steam chamber whose leading edge 203 represents the boundary of an interior volume in which most of the bitumen has been displaced. The leading edge 203 of the steam chamber steam is a region where the steam condenses, giving up its latent heat to complete the mobilization of the bitumen. The mobilized bitumen tends to flow downward 207 around the leading edge 203 until it reaches the collector well 201 and is carried away 205. The pressure gradient between the formation and the collector well acts to cause the bitumen to flow downward and then inward to the collector well 201.
Figure 3, which is prior art, is a schematic representation of how adjacent SAGD steam chambers grow and coalesce. Multiple steam chambers such as steam chamber 303 are formed by steam injected by several injector wells 304 shown here in end view. The injector wells 304 are typically 3 to 10 meters above the basement rock 302 and form steam chambers 303 that eventually grow to the top 301 of the oil sand deposit. Figure 3 schematically shows contours 305 which represent successive positions of the condensation surface or leading edge of the steam front as it advances in time and eventually coalesces with the condensation fronts of adjacent steam chambers.
It is one of the principal objectives of the present invention to form multiple steam chambers such as illustrated in Figures 2 and 3 by using soft-ground civil tunneling techniques rather than directional drilling techniques to install and operate one or more injector and collector well pairs. The method disclosed herein utilizes soft-ground tunneling technology to form a lined tunnel near the bottom of an oil sands deposit. In current practice, soft-ground tunneling machines are limited to formation fluid pressures of about 10 to 12 bars. This limitation is currently dictated by seal design for fluid seals on the tunnel boring machine and can be extended. For now,'the present invention is limited to oil sands deposits where ambient formation fluid pressures do not exceed about 10 bars, prior to initiating a steam chamber. There are many shallow deposits in the Alberta oil sands in which SAGD operations can be applied where formation fluid pressures are less than 10 bars. It is also possible, using known tunneling techniques, to locally drain fluids. If the formation is relatively impermeable, then this can reduce local formation fluid pressures to allow the tunneling machine to proceed without exceeding the pressure limits on its seals. Once the tunnel liner is installed, higher formation pressures can be accommodated, such as for example when steam is injected to form a steam chamber. Once a tunnel liner is installed, the pressure limitation can be considerably higher than bars as the pressure limit is now dictated by the structural integrity of the liner and/or the sealing technology used to form gaskets between liner segments (unless extruded liner technology, which does not require gaskets, is used).
Figure 4 is side view of a tunnel 400 of diameter 408 emplaced near the bottom of an oil sands deposit 401. The bottom of the tunnel 400 is on or just above the basement rock 402 which underlies the oil sand deposit 401. The overburden 403 and surface 404 are also shown.
The tunnel 400 may be formed by segments 405 which are joined together at joints 406 during the tunneling process. The segments 405 are preferably precast concrete segments but may be fabricated from other structural materials such as, for example, structural steel or composites of structural steel and concrete.. The segments are preferably formed from a high temperature concrete mix and well cured before installation. The bottom of the finished tunnel is located as shown by 407 on or just above the bedrock 402. If placed above the bedrock 402, the bottom of the tunnel liner would typically be located within about 1 to 5 meters of the bedrock 402 depending on geologic conditions such as for example a zone of high water content lying on the bedrock 402. The tunnel 400 is preferably formed by using a slurry or Earth Pressure Balance ("EPB") tunnel boring machine ("TBM") and conventional tunnel liner installation technology.
This tunneling method allows a liner to be installed while following the desired trajectory through the oil sand deposit 401. This trajectory may be designed to follow the deposit which may have been formed by a river or estuary for example. The diameter 408 of the tunnel is preferably in the range of about 3 meters to 5 meters. The length of the tunnel is dependent on the geology of the oil sand deposit 401 and may be in the approximate range of 500 meters to 10,000 meters or longer if the deposit persists or if a number of deposits are separated by short sections of barren ground. The tunnel 400 may be initiated from a portal developed at the surface or by assembling the TBM and its equipment using an access shaft excavated from the surface 404 through the overburden 403 to the bottom of the oil sands deposit 401. With currently available tunneling technology, a tunnel liner can be installed to within a few millimeters of its desired design location. This therefore places a lower limit on the accuracy of placement of steam injection and fluid collection points that is considerably more precise than is currently possible with horizontal drilling methods operated from the ground surface 404.

Figure 5 is and end view of multiple tunnels 505 emplaced near the bottom of an oil sands deposit 501. Figure 5 shows the surface 504, the overburden 503, the oil sand deposit 501 and the underlying basement rock 502. Each tunnel 505 is designed to provide a well-pair equivalent to that of a conventional SAGD well pair installed by directional drilling from the surface 504. The tunnels 505 are driven roughly parallel to each other with a spacing 506. The spacing 506 between adjacent tunnels 505 is typically in the range of about 50 to about 200 meters. This spacing is the same or slightly larger than that of typical of SAGD well pairs installed in current SAGD operations. The tunnel is formed by a structural liner 509 which is preferably constructed of approximately cylindrical segments that are gasketed and bolted together. Steam is injected at locations 507 along or near the top of the tunnel liner 509 and fluids are collected through openings 508 along both sides of the bottom half of the tunnel liner 509 or even through a single collection port (not shown) at the bottom of the tunnel liner 509.
Thus steam is injected at a controlled height above the collectors 508.
Because of the diameter of the tunnel, which is preferably in the range of about 3 meters to 5 meters, the collector area is substantially greater than the area of the collector well used in conventional SAGD.
Figure 6 is a plan view of multiple tunnels 601 emplaced near the bottom of an oil sands deposit. Each tunnel acts as a conventional SAGD well pair and consequently the spacing between adjacent tunnels will be similar to that used when installing adjacent SAGD well pairs.
Each tunnel will therefore be capable of heating and draining a width 603 of oil sand deposit on either side that is comparable to that of conventional SAGD well pairs. As described in Figure 5, the spacing between adjacent tunnels is typically in the range of about 50 to about 200 meters.
Therefore the width 603 of the region heated and drained by on either side of each tunnel will also be approximately in the range of about 50 to about 200 meters. The exact width of the lateral spacing is determined by the geology of the oil sand deposit, prior experience with conventional SAGD operations in similar deposits and experience with the present invention which may permit wider spacing because of its better recovery capability. The spacing between adjacent SAGD tunnels could be increased substantially if other more effective methods of mobilizing the bitumen are developed and field proven.
Figure 7 is an isometric view of a tunnel 700 formed by segments 701 showing possible steam injection 702 and fluid collection 703 locations. As described in Figure 4, the length of the tunnel 700 may be in the approximate range of 500 meters to 10,000 meters.
The length 704 of an individual tunnel liner segment 701 is typically in the approximate range of 1 to 2 meters.
If each tunnel segment 701 has an injection port 702 and collection ports 703, the injection of steam 705 and the collection of fluids 706, in effect, occurs along a line which corresponds to the length of the tunnel 700. Thus the tunnel 700, which need not be straight but can be sinuous as shown in Figure 10, acts as a single long horizontal well pair such as used in conventional SAGD. Because the tunnel has a diameter in the range of about 3 meters to about 5 meters, the collection area is substantially greater than the collection area of a collector well typically used in conventional SAGD. Since the rate of fluid production is proportional to the pressure and gravity gradients and to the natural logarithm of the effective diameter of the collector, the production rate per unit length of the present invention should be higher by a factor of about 2 or 3 than the production rate of a conventional SAGD collector well. One of a number of alternate methods of forming injection and collection ports is discussed later in Figure 11.
Figure 8 is an end view of a tunnel as represented by a tunnel liner 806 showing a SAGD
steam chamber as represented by its outwardly moving condensation front 805.
Figure 8 also shows the surface 802, the overburden 803, the oil sand deposit 801 and the underlying basement rock 804. The steam chamber is formed by steam injected through ports 807 spaced along the top of the tunnel liner 806 as described in Figure 7. The fluids which are comprised of mobilized bitumen and condensed steam, drain around the periphery 805 of the steam chamber and are collected through the collector ports 808 spaced along either or both sides of the bottom half of the tunnel liner 806 as also described in Figure 7. Since the characteristic size of a fully developed steam chamber is on the order of the thickness of the oil sand deposit 801, the collectors 808 are effectively along a line located at precise vertical and horizontal distances from the line formed by the injectors 807. This geometry is therefore, in effect, a steam injection well with a large collector well spaced appropriately beneath the injector well.
Figure 9 shows a side view of a backfilled tunnel liner 904 around a tunnel segments and illustrates many of the unique features of the present invention. An end view of a tunnel 900 is shown here embedded in an oil sands deposit 901 just above the underlying basement rock 902.
A tunnel structural liner 904 provides ground support for an excavated bore 903. The liner 904 is preferably fabricated well before installation (so as to properly cure the high temperature concrete) using a high-strength, high-temperature concrete to form short liner segments that can be installed, gasketed and bolted together as part of the tunneling process.
There are several well-known high temperature concretes available that (a) incorporate additives such as, for example, silica fume and high-range, water-reducing admixtures and (b) that can be mixed and cured well in advance of installation by procedures known to promote good structural performance at high temperatures in the range of approximately 200C to 400C.
The excavated bore and tunnel liner installation are preferably implemented using a soft-ground tunnel boring machine and well-known liner segment installation techniques. The annular space 905 between the liner 904 and the inner surface of the excavated bore 903 is backfilled with a low-cost, readily available material such as, for example, pea gravel, coarse sand, small rocks and/or the like or combinations of these materials. For a liner diameter in the range of about 3 meters to about 5 meters, the annular gap 905 is preferably in the range of about 25 mm to about 300 mm wide. The material in the annular space 905 serves a number of important functions. It isolates the liner 904 from direct contact with the oil sand; it provides a thermal barrier to heat transfer to the liner 904 from the heated oil sand 901; it provides a filtering action or screen to prevent oil sands material from plugging injector and collector ports; and it provides a highly permeable pathway to allow the fluids to more readily drain downward and flow to the collection ports 909.
In this figure, steam is piped down the tunnel 900 and a portion is injected at each injection port 907. The steam pipes may be wrapped with a common insulating material to minimize heat loss before injection into the formation. This is a significant advantage that the present invention has over SAGD using well pairs drilled from the surface. An injection port or ports 907 are located preferably in at least every tunnel liner segment as shown for example in Figure 7. The steam injection port 907 can inject the steam at the outside surface of the liner 904 or more preferably just beyond the annular layer 905 directly into the oil sand 901 as shown in the present figure.
Since the steam, generated on the surface or in the tunnel itself, is transported from its point of origin down the inside of the tunnel liner 904 by a piping system 906, its pressure and temperature can be readily monitored. If the steam conditions degrade with length down the tunnel, they can be returned to their desired levels by heater and compressor apparatuses located at intervals along the tunnel. This later capability is an important advantage over injector wells installed by directional drilling and allows the tunnel-based steam injection system to be as long as required by the oil sands deposit being drained. The fluids are collected through ports 909 located near the bottom of the tunnel. In this figure, two ports are shown at each cross-sectional location, although there may be any number of ports from one to many at each cross-sectional location. Along the length of the tunnel 900, collection ports 909 are located preferably in at least every tunnel liner segment as shown for example in Figure 7. The collection ports 909 feed into a piping system 908 which allows the collected fluids to be transported through the tunnel and to the surface for further processing. As with the steam injection system, the pumping pressure of the collected fluids can be boosted at intervals along the tunnel and can be further boosted, if necessary, to transport the collected fluids up an access shaft to the surface. This later capability is another important advantage over collector wells installed by directional drilling from the surface and avoids all of the lifting problems often associated with collector wells as used in currently practiced SAGD operations. In addition, the collector ports can be larger in area than those of a collector well typically installed by directional drilling. Large collector ports can still be covered with screens to prevent entry of sand from the surrounding deposit. This is an advantage that minimizes or reduces clogging of the collector ports which is known to occur in conventional SAGD operations. It is also possible to create a partial vacuum at the fluid collection ports 909 to increase the pressure gradient between the formation 901 and the collection piping system 908 by installing vacuum pumps in the tunnel near the collection points.

Figure 10 is a plan view of yet another alternate configuration for steam injection and collection. As described in Figure 4 for example, approximately parallel SAGD
tunnels may be installed while following a sinuous trajectory through the oil sand deposit such as may have been formed by a river or estuary. Figure 10 illustrates three approximately parallel tunnels 1201 that follow a hypothetical fluvial oil sand deposit. These tunnels may have their own steam injector and fluid collections systems similar to those depicted in Figures 4 through 9 for example. In addition, this figure shows horizontal connector wells or well pairs 1202 installed between adjacent tunnels 1201. These wells or well pairs may be installed by known drilling techniques operated from within the tunnels 1201. If well pairs are used to connect the tunnels 1201, steam may be injected by the upper well and fluids collected by the lower well as in conventional SAGD. The tunnels 1201 act as accessible locations for drilling SAGD well pairs from underground and as locations where steam can be provided and fluids collected for transport to the surface. Alternately, a single well 1202 can be drilled between tunnels 1201 wherein the single well serves as both a steam injector and fluid collector. Again, the tunnels 1201 act as accessible locations for drilling the connector well from underground and as locations where steam can be provided and fluids collected for transport to the surface. The connecting pipes 1202 are preferably in the diameter range of about 75 mm to about 700 mm. The lengths of the connecting pipes 1202 are determined by the separation of the tunnels 1201 which, as described previously are typically in the range of about 50 to about 1,000 meters.
In Figure 7, for example, injector and collector ports were shown as being circular holes.
These ports can be in the range of 100 mm to 400 mm in diameter. Alternately, as discussed in the following figure, the injection and collection ports can be made as long slots that can be almost as long as the tunnel liner segments but, if necessary, substantially wider than the slots used in conventional SAGD well pairs.
Figure 11 is an isometric view of a tunnel segment 1301 showing an example of a possible layout for slotted injector and collector ports. In SAGD as currently practiced, the injector well is typically made from a steel tubing with long narrow slots formed into the tubing wall. The slots are approximately 150 mm long and 0.3 mm wide. The narrow width of these slots is dictated by the requirement to prevent sand from entering into the slot when steam is not being injected. In SAGD as currently practiced, the collector well is also typically made from steel tubing with long narrow slots approximately 150 mm long and 0.3 mm wide, also to prevent sand from entering into the slot as hot fluids (principally mobilized bitumen and condensed steam) are collected. An injector port 1302 of the present invention is shown on top of the tunnel segment 1301. The injector port 1302 is a long slot through which steam is injected into the formation. The slot can be made during the fabrication of the tunnel liner segment 1301.
It can be covered by a screen or screens that allow steam to be injected while sand is prevented from entering the slot when steam is not being injected. The screen mesh is of a size that allows as much or more injection area while having openings approximately in the range of the slot widths used in conventional SAGD well pipe. The collector ports 1303 and 1304 can be made in the same way as the injector port 1302. The injector port 1302 is typically placed at or near the top of the segment 1301. One of more collector ports are typically located in the bottom half of the segment 1301 as shown for example by the location of ports 1303 and 1304.
The circumferential strength of the liner segment 1301 can be maintained for example by embedding reinforcing bar in the concrete liners across the ports in the circumferential direction.
Figure 12 is a plan view of a configuration of horizontal wells drilled or installed from one or more tunnels wherein the tunnels themselves may or may not also contain provisions for directly injecting steam and collecting fluids. As shown in Figure 12, one or more tunnels 1401 are driven substantially horizontally at or near the bottom of the oil sand deposit, approximately following the path of interest in the formation. If more than one tunnel is installed, then the tunnels are spaced approximately equally by a distance 1402 which is in the range of approximately 200 to 1,000 meters. In this embodiment, a plurality of horizontal wells 1403 are drilled outwardly from each tunnel 1401 through the oil sand formation. These boreholes are drilled from the tunnel and are designed to remain substantially within the oil sand deposit and are positioned substantially horizontally at or near the bottom of the oil sands deposit. Each bore hole 1403 contains a perforated or slotted tube for injecting steam and collecting mobilized fluids. The steam discharges through the perforations or slots and into the oil sand formation whereby the steam reduces the viscosity of the normally immobile bitumen over an area extending substantially between the perforated tube and the top of the oil sand formation with this viscosity reducing area expanding upward thereby creating an expanding generally conical-shaped production chamber as viewed from the end of the borehole such as depicted for example in Figure 14. The less viscous oil and steam condensate and drain downwardly by gravity to the bottom of the steam chamber and then through the horizontal tubes into the tunnel for collection and removal to a processing facility. As shown in Figure 12, the horizontal wells 1403 are drilled from the tunnel 1401 and terminate in the oil sand formation. The length of the horizontal wells 1403 are approximately half the distance between adjacent tunnels. The lengths of the horizontal wells 1403 are thus preferably in the approximate range of about 100 to about 400 meters. The horizontal wells 1403 may be drilled from any location along the length of the tunnels 1401 but are typically spaced in the range of approximately 50 to approximately 150 meters apart as shown by range 1405. Horizontal wells originating from adjacent tunnels may or may not overlap in lateral extent as shown by examples 1410 (non-overlapping) and 1411 (overlapping). It is obvious that this deployment of drilled horizontal wells may also be used in conjunction with the injection and collection methods applied within the tunnels themselves as shown for example in Figures 7 through 9. It is also obvious that the horizontal wells can be drilled as pairs with one well above the other to form a well pair such as used in SAGD operations where the well pairs are drilled from the surface such as shown in Figure 1.
Figure 13 is an end view of a configuration of horizontal wells originating from one or more tunnels 1501. Horizontal wells 1502 may be drilled substantially horizontally near or at the bottom of the oil sand deposit 1511 just above the basement rock 1510 and can be operated as steam injectors only or as injection/collector wells.
Figure 14 is an example of a steam chamber formed in an oil sands deposit 1603 by a single wellbore. This figure shows and end view of a steam chamber 1601 whose condensation front 1602 expands outwardly into the oil sands 1603. Steam is injected 1604 and fluids are collected 1605 through slots or perforations in a single well pipe 1606 located at or just above the basement rock 1610.
Figure 15 shows an example of a perforated and/or slotted injector/collector pipe 1701 such as described in US 6,263, 965 entitled "Multiple Drain Method for Recovering Oil from Tar Sand". The casing or pipe 1701 is installed in an oil sands deposit 1705 from a tunnel 1706. The pipe 1701 has slots and /or perforations 1702 through which steam is injected and fluids are collected simultaneously. The steam and fluids collected by the pipes 1701 are transported inside the tunnel by a system of other connected pipes represented here as 1704.
Figure 16 shows an example of another SAGD configuration where a horizontal tunnel is used in various ways and wells are drilled from the surface to intercept the tunnel. As can be appreciated, this method can be extended to include a plurality of tunnels and can be combined with any or all of the tunnel-based methods described previously. Figure 16 shows an end view of a ground surface 1801, an interface between overburden and an oil sand deposit 1802, an interface between an oil sand deposit and an underlying , typically impervious, basement rock 1803 and an oil sand deposit 1804 containing recoverable hydrocarbon, typically bitumen or heavy oil. A tunnel 1815 is shown installed at or near the bottom of the oil sand deposit 1815.
As in previous discussions, the tunnel is a lined tunnel typically in the diameter range of about 3 to 5 meters. The tunnel may be as long as required to drain a particular oil sand deposit which is typically a deposit laid down by an ancient fluvial or estuarine process. The tunnel itself may be used to inject steam and collect fluids as described for example in Figures 5 through 9. In Figure 16, a single well bore 1812 is shown where the well is drilled from the surface 1801 to the tunnel 1815. The single well 1812 is comprised of a perforated and/or slotted tubing.
Typically, steam is fed in from the surface 1801 and is discharged through the perforations and/or slots and into the oil sand formation 1804. While steam may also be injected along the horizontal portion of well 1812, most of the mobilized fluids (bitumen and steam condensate) is collected through the horizontal portion of the well 1812 and then into the tunnel 1815 where it can be pumped to the surface 1801 by well-known means. As described previously such as for example in Figure 12, wells such as 1812 can be installed into both sides of the tunnel 1815 and spaced along the tunnel length any location along the length but are typically spaced in the range of approximately 50 to approximately 150 meters apart. The horizontal wells are preferably in the diameter range of about 75 mm to about 750 mm. Alternately, a pair of wells 1810 and 1811 may be drilled from the surface 1801 to the tunnel 1815. The well 1810 is typically used for steam injection and the well 1811 is typically used for collection of fluids. This is a standard SAGD
well pair configuration but utilizes the tunnel 1815 to collect the fluids which can then be pumped to the surface 1801 again by well-known means. The size of the well bores and spacing of the well pairs along the length of the tunnel 1815 is similar to those of the single well system of 1812. In Figure 16, the arrows pointing away from the wells represent steam injection and the arrows pointing towards the wells represent fluid collection. As can be appreciated, single well or well pair systems can be used in combinations as dictated by field experience.
It is also possible, although not shown in the above figures, to use the tunnels themselves as single well systems. This can be accomplished by fabricating the tunnel liner segments with multiple perforations and/or slots and then injecting steam into the entire tunnel interior. Fluids would be collected in the bottom of the tunnel liner.
Figure 17 shows an end view of an alternate method for a backfilled liner 1904 around the tunnel segments and illustrates a means of isolating steam from mobilized fluids. An end view of a tunnel is shown here embedded in an oil sands deposit 1901 just above the underlying basement rock 1902. A tunnel structural liner 1904 provides ground support for an excavated bore 1903. As described previously in Figure 9, the liner 1904 is preferably fabricated using a high-strength, high-temperature concrete to form short liner segments that can be installed, gasketed and bolted together as part of the tunneling process. The excavated bore and tunnel liner installation are preferably implemented using a soft-ground tunnel boring machine and well-known liner segment installation techniques. The annular spaces 1905, 1911 and 1912 between the liner 1904 and the inner surface of the excavated bore 1903 are backfilled. In the bottom portion of the annular space 1905 backfill is provided by a low cost, readily available material such as, for example, pea gravel, coarse sand, small rocks and/or the like or combinations of these materials. For a liner diameter in the range of about 3 meters to about 5 meters, the annular gap 1905, 1911 and 1912 is preferably in the range of about 25 mm to about 300 mm wide. The portion of the annular space 1911 above the previously mentioned annular space 1905 is thereupon backfilled with a high-temperature grout shown as a solid grey filler.
The portion of the annular space 1912 above the previously mentioned annular space 1911 is then backfilled with a low cost, readily available material such as used in annular space 1905.
The grout in annular space 1911 serves to form a seal between the filler material in annular spaces 1905 and 1912. This is an important feature since it is necessary to prevent injected steam from communicating or short-circuiting from injector ports 1907 to collector ports 1909.
Steam may be injected through both ports 1907 and 1909 so as to heat up the oil sand formation surrounding the tunnel. Steam is not allowed past the grout in annular space 1911 and cannot go around the grout because of the un-mobilized bitumen in the formation. The steam mobilizes the bitumen around the top and bottom portions of the tunnel. At some point, steam injection through ports 1909 is stopped and the mobilized bitumen is allowed to remain in place while steam continues to be injected through injection ports 1907. As bitumen is drained from around the tunnel through ports 1909, volume is created for steam to be further injected into the formation through ports 1907. In this figure, steam is piped down the tunnel and a portion is injected at each injection port 1907. The steam pipes may be wrapped with a common insulating material to minimize heat loss before injection into the formation.
This is a significant advantage that the present invention has over SAGD using well pairs drilled from the surface.
An injection port or ports 1907 are located preferably in at least every tunnel liner segment as shown for example in Figure 7. The steam injection port 1907 can inject the steam at the outside surface of the liner 1904 or more preferably just beyond the annular layer 1912 directly into the oil sand 1901 as shown in the present figure. Since the steam, generated on the surface or in the tunnel itself, is transported from its point of origin down the inside of the tunnel liner 1904 by a piping system 1906, its pressure and temperature can be readily monitored. If the steam conditions degrade with length down the tunnel, they can be returned to their desired levels by heater and compressor apparatuses located at intervals along the tunnel. This later capability is an important advantage over injector wells installed by directional drilling and allows the tunnel-based steam injection system to be as long as required by the oil sands deposit being drained.
The fluids are collected through ports 1909 located near the bottom of the tunnel. In this figure, two ports are shown at each cross-sectional location, although there may be any number of ports from one to many at each cross-sectional location. Along the length of the tunnel, collection ports 1909 are located preferably in at least every tunnel liner segment as shown for example in Figure 7. The collection ports 1909 feed into a piping system 1908 which allows the collected fluids to be transported through the tunnel and to the surface for further processing. The ability to over cut a tunnel bore 1903, install an undersized liner 1904 and fill the resulting annular space with a number of different materials serving a number of functions, is an example of how modern tunneling technology can be used to enhance implementation of a SAGD
process.
Figure 18 is side view of a tunnel emplaced below or near the bottom of a conventional oil or gas reservoir for gravity drainage. In this figure, a conventional oil or gas reservoir 2001 is shown above a lower reservoir boundary 2002. A conventional oil or gas reservoir is taken herein to be a reservoir where the oil or gas is mobile and can flow in the formation when subjected to a pressure or gravity gradient. A tunnel 2003 may be installed, by methods described above for thermal gravity drain, in the formation below the reservoir 2001 or a tunnel 2004 may be installed at or near the bottom of the reservoir 2001. In either case, drainage wells 2006 and 2005 are drilled into the reservoir 2001 from the tunnels 2003 and 2004 respectively.
The diameters of the drainage wells, the lengths of the drainage wells and the spacing of the drainage wells around the tunnels and along the length of the tunnels are similar to those envisioned for SAGD applications. However, the lengths of the drainage wells and the spacing of the drainage wells along the length of the tunnels may be greater than described previously since the oil or gas to be drained is mobile throughout the reservoir.
There are other advantages of the present invention not discussed in the above figures.
For example, if there is a problem during the operation of the system after the steam chamber has been formed, it is still possible to perform servicing and repair. The tunnel can be strongly ventilated such that the tunnel air is cool and safe to work in even while the tunnel walls remain hot. Alternately, remotely operated robotic vehicles can be operated inside the tunnel and monitor or observe problem areas. When the steam chamber has completed recovery and has cooled down, mush of the installed equipment (piping, pumps, sumps, diagnostics, heaters and the like) can be retrieved from the tunnel for use in other tunnel-based SAGD
operations.
The following describes a preferred embodiment of the general approach of combining tunneling methods, various drilling methods and various in-situ recovery methods in ways that allow greater control over steam conditions and gravity drain conditions as well as a greater ability to effect repairs and accomplish process adjustments. The preferred embodiment described below also results in less surface disturbance and better working conditions in severe climates.
Figure 19 is a schematic end view of two tunnels 2105 in an oil sands deposit showing all well pairs 2106 and 2107 as being drilled from the tunnels 2105.
Two or more soft-ground tunnels 2105 may be driven in an oil sands deposit 2103 which is overlain by overburden 2102 that interfaces a ground surface 2101. The oil sands deposit 2103 is typically underlain by a rock formation 2104 which may be limestone for example such as is the case for the Athabasca oil sands in Alberta Canada. The spacing between tunnels 2105 is in the range of approximately 200 to 1,000 meters and is dependent on, among other factors, the nature of the deposit and the ability of the drilling technology employed to drill the well pairs 2106 and 2107. The well pairs 2106 and 2107 are typically drilled with one well approximately over the other well separated in the range of 1 to 10 meters. The diameter of the individual wells is in the diameter range of about 75 mm to 750 mm. The approximately horizontal well pairs 2106 are drilled from either tunnel 2105 to intercept the adjacent tunnel 2105, the tunnels 2105 being approximately in the range of 200 m to 800 m apart. The diameter of the tunnels 2105 is in the range of about 3 to 5 meters. In wide deposits, more than two approximately parallel tunnels 2105 may be used. The approximately horizontal blind well pairs 2107 may be drilled outwards from the tunnels 2105.
These blind well pairs 2107 are typically in the length range of approximately 100 to 500 meters but may be longer as blind drilling techniques are improved. If viewed from above in plan view such as shown in Figure 10, the spacing of well pairs along the tunnel length is in the range of about 50 to 150 meters. Blind well pairs 2107 and connected well pairs 2106 may or may not be drilled from the same location along the tunnels 2105.
The methods of drilling from within the tunnels 2105 may include, for example, conventional soft ground drilling methods using rotary or augur bits attached to lengths of drill pipe which are lengthened by adding additional drill pipe sections as drilling proceeds. Drilling methods may also include, for example, micro-tunneling techniques where a slurry excavation head is used and is advanced into the deposit by pipe jacking methods. Forms of directional drilling may be used from within a tunnel. More conventional directional drilling methods may be used for wells or well pairs drilled from the surface to intercept a tunnel such as described in subsequent discussions.
Figure 20 is a schematic end view of two tunnels 2205 in an oil sands deposit showing well pairs 2206 drilled from the tunnels and well pairs 2207 drilled from the surface 2201 to intercept the tunnels 2205. This is an alternate method to that shown in Figure 19 and can result in the same approximate layout of well pairs. An advantage of the configuration shown in Figure 20 is that well pairs 2207 and 2206 are both accessible from either end. The horizontal sections of well pairs 2207 are typically in the length range of approximately 100 to 1,000 meters but may be longer as surface drilling techniques are improved.
Otherwise, tunnel diameters and spacing and well pair diameters and spacing are the same as those described in Figure 19.
Figure 21 is a schematic end view of two tunnels 2305 in an oil sands deposit showing single wells 2306 and blind well pairs 2307 drilled from the tunnels 2305. The difference between the configuration of Figure 21 and Figure 19 is that the wells 2306 drilled between tunnels 2305 are single wells that can serve as both steam injectors and mobilized bitumen collectors. Single well injection and recovery is a less developed technology than that based on well pairs where the lower well is typically the collector and the upper well is typically the injector. The major advantage of using a single well is that less drilling is required to drain a given reservoir volume. This can result in a significant cost reduction with potentially no reduction in recovery factor. Otherwise, tunnel diameters and spacing and well pair diameters and spacing are the same as those described in Figure 19.
Figure 22 is a schematic end view of two tunnels 2405 in an oil sands deposit showing single wells 2406 drilled from a tunnel and single wells 2407 drilled from a location 2408 on a surface 2401 to intercept the tunnels 2405. This is an alternate method to that shown in Figure 23 and can result in the same general layout of wells. An advantage of the configuration shown in Figure 22 is that single wells 2407 and 2406 are both accessible from either end. The horizontal sections of wells 2407 are typically in the length range of approximately 100 to 1,000 meters but may be longer as surface drilling techniques are improved. Otherwise, tunnel diameters and spacing and well diameters and spacing are the same as those described in Figure 19.
Figure 23 is a schematic end view of two tunnels 2505 in, for example, a limestone formation 2504 showing all well pairs 2506 and 2507 drilled from the tunnels 2505. Figure 23 is similar to Figure 19 except the tunnels 2505 are driven into an underlying limestone formation 2504 and the well pairs 2506 and 2507 must be drilled upwards out of the limestone 2504 and then horizontally at or near the bottom of the oil sands 2503. The tunnel diameters and spacing and well pair diameters and spacing are the same as those described in Figure 19. In the case of the blind well pairs 2507, the techniques for drilling such well pairs from the limestone into the oil sands has been established previously during the original development of the SAGD method at the Underground Test Facility ("UTF") in Alberta, Canada. In this case the drilling of well pairs was conducted from underground workings drilled & blasted into the underlying limestone.
As illustrated in Figure 23, the well pairs are shown as being drilled from tunnels bored into the limestone. It is also possible to drill & blast small caverns at each drilling location to provide additional working space for the well drilling equipment. In the case of the well pairs 2506 drilled between adjacent tunnels 2505, the wells can be drilled from one tunnel and ultimately intercept the adjacent tunnel. This will require an innovation to presently available drilling technology. One way that this may be accomplished, for example, is to drill upwards from one tunnel out of the limestone 2504 and then horizontally at or near the bottom of the oil sands 2503 until the horizontal well passes over the adjacent tunnel. It then is possible to drill upwards from the adjacent tunnel to intercept the horizontal portion of the wells 2506 in the oil sands 2503.
The tunnels 2505 are placed in the limestone 2504 far enough below the oil sand/limestone interface to provide adequate ground support for the tunnels. The tunnels 2505 would be typically bored into the limestone by a hard rock tunnel boring machine since the limestone is typically self supporting. It is appreciated that some sections of the tunnels 2505 may require ground support where the limestone is not competent. Access to the limestone is typically by vertical shafts sunk from the surface 2501 through the overburden 2502 and oil sands 2503 and terminating in the limestone 2504. The shafts are of a sufficient diameter to accommodate ventilation, access, and the large components of the tunneling machines.
Figure 24 is a schematic end view of two tunnels 2605 in a limestone formation showing well pairs 2606 drilled from the tunnels 2605 and well pairs 2607 drilled from a surface location 2608 on a surface 2601 to intercept tunnels 2605. This is an alternate method to that shown in Figure 23 and can result in the same general layout of well pairs. An advantage of the configuration shown in Figure 24 is that well pairs 2607 and 2606 are both accessible from either end. The horizontal sections of well pairs 2607 are typically in the length range of approximately 100 to 1,000 meters but may be longer as surface drilling techniques are improved. Otherwise, tunnel diameters and spacing and well pair diameters and spacing are the same as those described in Figure 19. The methods of installing the well pairs 2606 between adjacent tunnels 2605 are the same as those described in Figure 23.
Figure 25 is a schematic end view of two tunnels 2705 in a limestone formation showing single wells 2706 and well pairs 2707 drilled from the tunnels 2705.
The difference between the configuration of Figure 25 and Figure 23 is that the horizontal portions of the wells 2706 drilled through the oil sand 2703 between tunnels 2705 are single wells that can serve as both steam injectors and mobilized bitumen collectors. Single well injection and recovery is a less developed technology than that based on using a well pairs where the lower well is typically the collector and the upper well is typically the injector. The major advantage of using a single well is that less drilling is required to drain a given reservoir volume.
Otherwise, tunnel diameters and spacing and well pair diameters and spacing are the same as those described in Figure 19.
Figure 26 is a schematic end view of two tunnels 2805 in a limestone formation showing single wells 2806 drilled between adjacent tunnels 2805 and single wells 2807 drilled from a surface location 2810 on a surface 2801 to intercept tunnels 2805. This is an alternate method to that shown in Figure 25 and can result in the same general layout of wells. An advantage of the configuration shown in Figure 26 is that wells 2807 and 2806 are both accessible from either end. The horizontal sections of wells 2808 are typically in the length range of approximately 100 to 1,000 meters but may be longer as surface drilling techniques are improved. Otherwise, tunnel diameters and spacing and well diameters and spacing are the same as those described in Figure 19.
A number of variations and modifications of the invention can be envisioned.
As will be appreciated, it would be possible to provide for some features of the invention without providing others. For example, the various inventive features can be combined in various ways with the common feature that they are installed and operated from tunnels emplaced near the bottom of the oil sand deposits.
The present invention, in various embodiments, includes components, methods, processes, systems and/or apparatus substantially as depicted and described herein, including various embodiments, sub-combinations, and subsets thereof. Those of skill in the art will understand how to make and use the present invention after understanding the present disclosure.
The present invention, in various embodiments, includes providing devices and processes in the absence of items not depicted and/or described herein or in various embodiments hereof, including in the absence of such items as may have been used in previous devices or processes, for example for improving performance, achieving ease and\or reducing cost of implementation.
The foregoing discussion of the invention has been presented for purposes of illustration and description. The foregoing is not intended to limit the invention to the form or forms disclosed herein. In the foregoing Detailed Description for example, various features of the invention are grouped together in one or more embodiments for the purpose of streamlining the disclosure. This method of disclosure is not to be interpreted as reflecting an intention that the claimed invention requires more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive aspects lie in less than all features of a single foregoing disclosed embodiment. Thus, the following claims are hereby incorporated into this Detailed Description, with each claim standing on its own as a separate preferred embodiment of the invention.
Moreover though the description of the invention has included description of one or more embodiments and certain variations and modifications, other variations and modifications are within the scope of the invention, e.g. as may be within the skill and knowledge of those in the art, after understanding the present disclosure. It is intended to obtain rights which include alternative embodiments to the extent permitted, including alternate, interchangeable and/or equivalent structures, functions, ranges or steps to those claimed, whether or not such alternate, interchangeable and/or equivalent structures, functions, ranges or steps are disclosed herein, and without intending to publicly dedicate any patentable subject matter.

Claims

What is claimed is:

1. A method for recovering viscous hydrocarbons comprising:
installing one or more tunnels in and/or below a hydrocarbon formation;
drilling a plurality of wells in the hydrocarbon formation, the wells being transverse and connected to at least one tunnel;
injecting steam into the hydrocarbon formation from at least one of the wells;
collecting fluid hydrocarbons through at least one of the wells to at least one of the tunnels; and transporting the hydrocarbons from at least one of the tunnels to the surface.