CA2886212C - Integrated liquid-to-gas artificial lift and bitumen dilution methods and systems - Google Patents

Abstract

Methods and systems for producing an oil sand slurry from subsurface reservoirs include a gas lift method to lift a slurry using a lift liquid with controlled boiling pressure and temperature range. The gas lift method utilizes phase transformation from liquid to gas by boiling or evaporation or partial evaporation to lift the slurry to the surface. The composition of the lift fluid can also be utilized to promote easier surface recovery of bitumen from oil sands by using a composition of lift fluid that would contain two groups of chemical component. The first group of chemical components would generally include lighter hydrocarbons, such as methane or ethane, that would evaporate at an appropriate pressure and temperature to lead to gas lift. A second group of chemical components could include non-evaporating solvent components which remain in liquid phase and aid in bitumen extraction during the slurry lift.

Description

INTEGRATED LIQUID-TO-GAS ARTIFICIAL LIFT AND BITUMEN DILUTION
METHODS AND SYSTEMS
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the priority benefit of U.S. Provisional Patent Application 61/727,493 filed 16 November 2012 entitled INTEGRATED LIQUID-TO-GAS
ARTIFICIAL LIFT AND BITUMEN DILUTION METHODS AND SYSTEMS.
FIELD

[0002] Embodiments of the invention relate to methods and systems for producing a dense oil sand slurry. More particularly, embodiments of the invention relate to methods and systems for artificially lifting dense oil sand slurries from oil sand formations located in a subsurface formation having an overburden.
BACKGROUND

[0003] This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0004] Bitumen is any heavy oil or tar with viscosity more than 10,000 cP
found in porous subsurface geologic formations. Bitumen is often entrained in sand, clay, or other porous solids and is resistant to flow at subsurface temperatures and pressures. Current recovery methods inject heat or viscosity reducing solvents to reduce the viscosity of the bitumen and allow it to flow through the subsurface formations and to the surface through boreholes or wellbores. Other methods breakup the sand matrix in which the heavy oil is entrained by water injection to produce the formation sand with the oil;
however, the recovery of bitumen using water injection techniques is limited to the area proximal the bore hole. These methods generally have low recovery ratios and are expensive to operate and maintain. However, there are hundreds of billions of barrels of these very heavy oils in the reachable subsurface in the province of Alberta alone and additional hundreds of billions of barrels in other heavy oil areas around the world. Efficiently and effectively recovering these resources for use in the energy market is one of the world's toughest energy challenges.
100051 Extracting bitumen from oil sand reservoirs generally leads to production of sand, limestone, clay, shale, bitumen, asphaltenes, and other in-situ geo-materials (herein collectively referred to as sand or particulate solids) in methods such as Cold Heavy Oil Production with Sand (CHOPS), Cyclic Steam Stimulation (CSS), Steam Assisted Gravity Drainage (SAGD), and Slurrified Heavy Oil Reservoir Extraction process (SHORE). The amount of sand and water produced may vary from very small to large and it depends on the type of method, stress-state within the reservoir, drawdown and depletion. In cases of CSS
and SAGD, sand production is not desirable. On the other hand, sand production is encouraged in cases of CHOPS and SHORE (International Patent Application Publication W02007/050180) processes. The SHORE process relies on artificial lift ("AL") methods to lift slurry containing bitumen to the surface. In particular, gas lift ("GL") is one of the preferred AL methods.
100061 Various artificial lift ("AL") methods for lifting oil/water/gas with some small solids content is known in the oil industry. However, lifting a dense slurry through a vertical pipe represents a unique challenge due to large slurry resistance components such as friction and hydrostatic pressure. An issue with using existing AL approaches to lift dense slurries is the high erosion rate. A dense slurry has very high sand content characterized by high erosive power characteristic of sand particles. The erosion problem is augmented by the duration of the lift process and cost and necessity to shut down the producer well associated with underground pump maintenance. In short, current AL methods are not capable of lifting such a dense slurry from any substantial depth over an extended period of time.
100071 Conventional gas lift uses compressed air, nitrogen, steam or natural gas to reduce hydrostatic weight in the well. For slurry lift, the GL has significant advantages over other AL methods. However, use of conventional GL for bitumen production may also have certain disadvantages. For example, the high production rate envisioned for SHORE together with the high density of the slurry makes gas compression expensive. Moreover, surface bitumen extraction is fairly sensitive to the chemical composition of the produced slurry which could be affected by the gas injection. Therefore, conventional GL may have a detrimental influence on bitumen extraction in certain circumstances.

SUMMARY
100081 In one embodiment of the present disclosure, a method for producing a dense slurry is provided using a proposed gas lift method to lift large production rates of slurries in vertical or near vertical well to the surface. An embodiment of the present invention uses a lift liquid with controlled boiling pressure and temperature or evaporation pressure and temperature range, instead of compressed gas. Unlike gas, liquid has very low compressibility and, therefore, it is more economical to pump downhole. In this sense, the "ideal" lift fluid would be the one which is a liquid when being pumped downhole and becomes a gas when it mixes with the production slurry. Evaporation or boiling is a natural process which fits this purpose. Therefore, an important concept of an embodiment of the present invention is a lift system which utilizes phase transformation from liquid to gas by boiling or evaporation or partial evaporation to economically lift the slurry to the surface.
100091 In one embodiment of the present disclosure, the composition of the lift fluid can also be utilized to promote easier surface recovery of final products, such as bitumen, from the reservoir fluids, such as oil sands. An embodiment of this invention may use a composition of lift fluid that would contain two groups of chemical component.
The first group of chemical components would generally include lighter hydrocarbons, such as methane, ethane, or propane, that would evaporate at an appropriate pressure and temperature to lead to gas lift. A second group of chemical components could include non-evaporating solvent components which remain in liquid phase and aid in bitumen extraction or liberation during the slurry lift, such as pentane, hexane, heptane, naptha, and/or cyclohexane.
BRIEF DESCRIPTION OF THE DRAWINGS
100101 The foregoing and other advantages of the present invention may become apparent upon reviewing the following detailed description and drawings of non-limiting examples of embodiments in which:
100111 FIG. 1 is a process flow chart for methods of producing a dense slurry in accordance with certain aspects of the disclosure;
100121 FIG. 2 is an illustration of one exemplary embodiment of a slurrified heavy oil reservoir extraction lift system using a fluid lift apparatus to provide slurry lift;

100131 FIG. 3 illustrates a schematic of an exemplary embodiment of a non aqueous extraction process of bitumen;
100141 FIG. 4 is an illustration of an exemplary embodiment of a slurrified heavy oil reservoir extraction lift system using a fluid lift apparatus to provide slurry lift according to the present disclosure;
100151 FIG. 5 illustrates a schematic of an exemplary embodiment of a non aqueous extraction process of bitumen in combination with the fluid lift apparatus of FIG. 4;
100161 FIG. 6 illustrates a schematic of another exemplary embodiment of a non aqueous extraction process of bitumen in combination with the fluid lift apparatus of FIG. 4;
100171 FIG. 7 illustrates a phase diagram for two exemplary embodiments of a power fluid used in a fluid lift apparatus to provide slurry lift;
100181 FIGS. 8A-8B illustrate a schematic of an embodiment of a gas lift and a corresponding working cycle on a phase diagram for an embodiment of a 100 m deep well;
100191 FIG. 9 illustrates a phase diagram and working cycle for another exemplary embodiment of a power fluid used in a fluid lift apparatus to provide slurry lift for an embodiment of a 300 m deep well;
100201 FIGS. 10A-B illustrate gas holdup for the wells of FIGS. 8 and 9.
DETAILED DESCRIPTION
100211 In the following detailed description section, the specific embodiments of the present disclosure are described in connection with preferred embodiments.
However, to the extent that the following description is specific to a particular embodiment or a particular use of the present disclosure, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the disclosure is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

DEFINITIONS
100221 Various terms as used herein are defined below. To the extent a term used in a claim is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent.
100231 The terms "a" and "an," as used herein, mean one or more when applied to any feature in embodiments of the present inventions described in the specification and claims.
The use of "a" and "an" does not limit the meaning to a single feature unless such a limit is specifically stated.
100241 The term "about" is intended to allow some leeway in mathematical exactness to account for tolerances that are acceptable in the trade. Accordingly, any deviations upward or downward from the value modified by the term "about" in the range of 1% to 10%
or less should be considered to be explicitly within the scope of the stated value.
100251 In the claims, as well as in the specification above, all transitional phrases such as "comprising," "including," "carrying," "having," "containing," "involving,"
"holding,"
"composed of," and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases "consisting of' and "consisting essentially of' shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.
100261 The term "dense slurry," as used herein, refers to a mixture of solids and fluids having a solids concentration range of about 20-65 volume percent (vol%). Such a dense slurry may be found naturally in-situ, may be generated by the slurrified heavy oil reservoir extraction (SHORE) process, or may be generated by another process.
100271 The term "exemplary" is used exclusively herein to mean "serving as an example, instance, or illustration." Any embodiment described herein as "exemplary" is not necessarily to be construed as preferred or advantageous over other embodiments.
100281 The term "formation" refers to a body of rock or other subsurface solids that is sufficiently distinctive and continuous that it can be mapped. A "formation"
can be a body of rock of predominantly one type or a combination of types. A formation can contain one or more hydrocarbon-bearing zones. Note that the terms "formation," "reservoir,"
and "interval" may be used interchangeably, but will generally be used to denote progressively

- 5 -smaller subsurface regions, zones or volumes. More specifically, a "formation"
will generally be the largest subsurface region, a "reservoir" will generally be a region within the "formation" and will generally be a hydrocarbon-bearing zone (a formation, reservoir, or interval having oil, gas, heavy oil, and any combination thereof), and an "interval" will generally refer to a sub-region or portion of a "reservoir."
100291 The term "heavy oil" refers to any hydrocarbon or various mixtures of hydrocarbons that occur naturally, including bitumen and tar. In one or more embodiments, a heavy oil has a viscosity of between 1,000 centipoise (cP) and 10,000 cP. In one or more embodiments, a heavy oil has a viscosity of between 10,000 cP and 100,000 cP
or between 100,000 cP and 1,000,000 cP or more than 1,000,000 cP at subsurface conditions of temperature and pressure.
100301 The term "hydrocarbon-bearing zone," as used herein, means a portion of a formation that contains hydrocarbons. One hydrocarbon zone can be separated from another hydrocarbon-bearing zone by zones of lower permeability such as mudstones, shales, or shaley (highly compacted) sands. In one or more embodiments, a hydrocarbon-bearing zone includes heavy oil in addition to sand, clay, or other porous solids.
100311 The term "jet pump," as used herein refers to any apparatus having a nozzle or nozzles configured to flow a fluid (e.g. a power fluid) through the nozzle such that: 1) the fluid is introduced into a producer pipe at a velocity higher than a natural velocity of the dense slurry flowing into the producer pipe without the jet pump; 2) the fluid flow creates a low pressure region in a subsurface formation adjacent to the jet pump that has a lower pressure than the formation's natural pressure; and 3) dilutes the dense slurry in the pipe to a density lower than the natural density of the formation.
100321 The term "overburden" refers to the sediments or earth materials overlying the formation containing one or more hydrocarbon-bearing zones. The term "overburden stress"
refers to the load per unit area or stress overlying an area or point of interest in the subsurface from the weight of the overlying sediments and fluids. In one or more embodiments, the "overburden stress" is the load per unit area or stress overlying the hydrocarbon-bearing zone that is being conditioned and/or produced according to the embodiments described.
100331 The terms "preferred" and "preferably" refer to embodiments of the inventions that afford certain benefits under certain circumstances. However, other embodiments may

- 6 -

7 PCT/US2013/059734 also be preferred, under the same or other circumstances. Furthermore, the recitation of one or more preferred embodiments does not imply that other embodiments are not useful, and is not intended to exclude other embodiments from the scope of the inventions.
100341 The terms "substantial" or "substantially," as used herein, mean a relative amount of a material or characteristic that is sufficient to provide the intended effect. The exact degree of deviation allowable may in some cases depend on the specific context.
100351 The definite article "the" preceding singular or plural nouns or noun phrases denotes a particular specified feature or particular specified features and may have a singular or plural connotation depending upon the context in which it is used.
DESCRIPTION OF EMBODIMENTS
100361 A slurrified heavy oil reservoir extraction process, such as ExxonMobil's SHORE
process, is a developing oil sand in-situ extraction process that relies on fluidization of the reservoir and lifting of the overburden stress to make the oil sand mobile, often referred to as the conditioning phase. After a fluidization or conditioning phase a horizontal pressure difference is created that is sufficient to overcome friction losses within the reservoir. As a result, the whole reservoir slides from an injection well towards a producer well which is put on artificial lift.
100371 The oil sand concentration in the oil sand slurry, which may include sand, clays, bitumen, water and other materials, immediately around the production well is approximately 50% volume solids, but can vary significantly within a large range, such as from 25% to 65%
or larger volume solids. The high density and frictional resistance of the slurry is too high for the bottom hole pressure to allow it to flow to the surface. Therefore, some form of artificial lift is necessary, in one embodiment, a jet pump is used as a form of artificial lift. In another embodiment, an injection line could be used, either in lieu of or instead of the jet pump or in addition to the jet pump. The injection line could use a simple orifice or an expansion valve to achieve a pressure drop in the power fluid resulting in the evaporation or partial evaporation of the power fluid. The jet pump serves as only one embodiment of how liquid can be mixed with the slurry. Another example of dilution method could be liquid introduction through the well wall opening. As a result of any dilution method, a diluted slurry with a sand concentration range of 20-40% volume, or 25-50% volume, enters the production well.

100381 However, even a diluted slurry with a sand concentration range of 20-40% volume is still too heavy for the bottom hole pressure to allow it to flow up the wellbore so a lift method in addition to mere dilution is needed. Most of conventional lift methods will not work due to the high solid concentration. Therefore, gas lift in conjunction with the dilution has been proposed for SHORE production. In general, as gas bubbles move up, their volume will increase due to the expected pressure decrease. The larger bubbles will accelerate and push sluny slugs faster. Turbulence is expected to increase in such accelerated slurry slugs.
Beneficially, this is expected to lead to improved conditioning of the slurry due to increased shear of particles.
100391 As mentioned above in the Background, the use of conventional gas lift (GL) application for SHORE may have certain drawbacks in certain situations. First, due to the high production rate and high slurry weight, the cost of gas compression and injection can be prohibitively high. Second, gas lift has a potential to be detrimental to the surface bitumen extraction, for example, the gas lift could result in foaming in the produced slurry which could be difficult for the surface extraction to separate out the gas. Other types of artificial lift methods, such as the use of pumps, for example, electric submersible, rod or progressive cavity pumps, are not expected to be applicable in a slurrified heavy oil reservoir extraction process due to excessive wear from the slurry or flow rate limitations inherent in those types of pumps.
[0040j The design of a cost effective GL method aiming at enhanced bitumen recovery is an aspect of an embodiment of this invention. An embodiment of the GL method discussed herein can also be specifically tailored to a range of bitumen production methods like SHORE or CHOPS (Cold Heavy Oil Production with Sand) or SAGD (Steam Assisted Gravity Drainage). An embodiment of the present invention includes a proposed GL method to lift large production rates of slurries in vertical or near vertical well to the surface. An embodiment of the present invention uses a lift liquid with controlled boiling pressure and temperature or evaporation pressure and temperature range, instead of compressed gas.
10041j Unlike gas, liquid has very low compressibility and, therefore, it is cheap to pump downhole. Hence, if one replaces gas with a liquid as a lift agent the cost of the lift can be reduced. However, liquid itself is a poor lift agent because it has density comparable to a density of production slurry. In this sense, the "ideal" lift fluid would be the one which is a liquid when being pumped downhole and becomes a gas when it mixes with the production

- 8 -slurry. Evaporation or boiling is a natural process which fits this purpose.
Therefore, an important concept of an embodiment of the present invention is a lift system which utilizes phase transformation from liquid to gas by boiling or evaporation or partial evaporation to economically lift the slurry to the surface.
10042j The existence of a fluid in the liquid or vapor phase is a function of its chemical composition and its pressure and temperature. Pure or single component liquids like water have a single evaporation pressure at a given temperature. Multicomponent fluids have a pressure range over which gradual evaporation of different fluid components occurs. This behavior of evaporation as a function of fluid composition can serve as a means of control of where and how evaporation and corresponding gas lift happens.
100431 In addition, the composition of the lift fluid can also be utilized to promote easier surface recovery of final products, such as bitumen, from the reservoir fluids, such as oil sands. For example, extraction of bitumen from Alberta, Canada, mined oil sands relies on the Clark Hot Water extraction process. This process is both energy and water intensive as it requires large volumes of hot water. Conventional oil sand mining has two drawbacks ¨ only a few percent of oil sands in Alberta are minable and bitumen extraction consumes large volumes of heated fresh water, requiring both water and a fossil fuel for heat. This is contrary to the overall trend towards more stringent legislation limiting fresh water consumption. Development of new technologies like SHORE has a large potential to expand mining on a larger portion of Alberta's oil reserves. The slurrified technology may use gas lift together with novel bitumen extraction techniques like non aqueous extraction (NAE) which relies on mixing of certain solvents and bitumen bearing sand. An embodiment of this invention may use a composition of lift fluid that would contain two groups of chemical component. The first group of chemical components would generally include lighter hydrocarbons, such as methane, ethane, or propane, that would evaporate at an appropriate pressure and temperature to lead to gas lift. A second group of chemical components could include non-evaporating solvent components which remain in liquid phase and aid in bitumen extraction or liberation during the slurry lift, such as pentane, hexane, heptane, naptha, and/or cyclohexane.
[00441 An embodiment of the present invention addresses the problem of water use during sluny lift and the potential detrimental effect of adding significant volumes of water to the slurry when using certain solvent based extraction technologies at the surface for bitumen

- 9 -separation from the sand. Another aspect of an embodiment of the invention is the control of the chemical composition of the lift fluid to benefit or supplement the surface extraction of bitumen from the produced slurry.
100451 Referring now to the Figures, FIG. 1 is process flow chart for methods of producing a dense slurry in accordance with certain aspects of the disclosure.
The process 100 includes injecting 102 a liquid phase fluid into a producer pipe inlet to mix with the dense slurry and form a diluted slurry, evaporating 104 at least a portion of the liquid phase fluid in the producer pipe, and lifting 106 the diluted sluny up the producer pipe utilizing the gas lift of the evaporation of at least a portion of the fluid. The process 100 may also optionally include selecting 108 the fluid to begin evaporating at the pressure and temperature of the producer pipe inlet. The process 100 may also optionally include dissolving 110 at least a portion of the bitumen in the diluted slurry with a liquid phase of the fluid in the producer pipe.
100461 The dense slurry may enter the producer pipe inlet by positioning a jet pump below the producer pipe and injecting a power fluid through the jet pump into the producer pipe. Again, a jet pump is just one possible embodiment of slurry dilution. In another embodiment, an injection line could be used, either in lieu of or instead of the jet pump or in addition to the jet pump. The injection line could use a simple orifice or an expansion valve to achieve a pressure drop in the power fluid resulting in the evaporation or partial evaporation of the power fluid. Another example of dilution method could be liquid introduction through the well wall opening. The diluted slurry is further lifted up the producer pipe utilizing the gas lift of the evaporation of at least a portion of the fluid.
100471 The SHORE process may rely on gas lift and NAE to lift oil sand and extract bitumen. An embodiment of a slurrified heavy oil production slurry lift system 200 is illustrated in Fig. 2. The lift system 200 includes two major components. The first component is a jet pump 202. Power fluid 204 is delivered through a nozzle 206 of the jet pump 202 towards the production well intake 208. High speed fluid jet 210 creates intensive mixing and drives reservoir fluid oil sand 212 into the production well 214.
Therefore, slurry 216 entering the production well 214 will consist of reservoir fluid and oil sand 212 diluted by power fluid 204. The second component is a gas lift 218 in which the gas 220 is injected downstream of the jet pump 202 and reduces the hydrostatic head in the production well 214 to such degree so the well can flow to the surface.

- 10 -100481 Due to a high flow velocity of the slurry as it travels up the production well, approximately one meter per second, an intensive mixing of oil sand, reservoir fluid and power fluid happens in the well. After gas injection, the flow speed increases even further leading to more intense mixing.
10049j Figure 3 illustrates a schematic of a non aqueous extraction process 300 of bitumen that may be applied at the surface to the slurry lifted by SHORE lift process. In a NAE process, a mined oil sand 302 with rather low water content, such as 0.08 < water mass/solid mass <0.12, is mixed with a rather limited amount of organic solvent 304 in a mixing tank 306. Organic solvent 304 can be a paraffinic solvent or a cyclic aliphatic solvent or a mixture thereof. Limiting the amount of organic solvent 304 enables bitumen dissolution without detrimental asphaltene precipitation. Exiting the mixing tank 306, bitumen extract 308 contains fines 310 which agglomerate when water 312 is added to the bitumen extract 308 in the second mixing tank 314. From the second mixing tank 314, agglomerated solids 316 and bitumen extract 318 can be separated in appropriate apparatus like a cyclone 320.
Optionally, a second solvent 322 is added to the bitumen extract 324 leaving the cyclone 320 leading to asphaltene precipitation 326 and additional separation of bitumen from the fines and water. The result is a high quality bitumen extract 328. NAE requires substantially less amount of water than the traditional Clark hot water process. Moreover, organic solvent 304 and second solvent 322 have low boiling temperatures and so a modest amount of energy is needed to separate them from the final bitumen extract 328.
100501 One embodiment of the present invention illustrated in Fig. 4 integrates SHORE
lift, as previously discussed and illustrated in Fig. 2, and a beginning step of NAE, as previously discussed and illustrated in Fig. 3. In this embodiment, the power fluid is a liquid mixture of light and heavier components. Similar to Fig. 2, the power fluid 402 is injected into the production well 404 with a jet pump 408, drawing the reservoir fluid and oil sand 406 into the production well. The light components of the power fluid 402 will evaporate at the pressure and temperature in the production well, providing the needed gas lift 410. The functions of the compressed gas injection and the power fluid injection from the jet pump of Fig. 2 are now combined into a single injection step in Fig. 4. Furthermore, the heavier solvents in the liquid power fluid 402 composed of light and heavier components will extract and/or liberate the bitumen from the oil sand. Thus, the function of mixing the oil sand with an organic solvent in a mixing tank from the example illustrated in Fig. 3 is now accomplished in one step during the slurry lift in the production well of Fig.
4.

- 11 -100511 The power fluid of Fig. 4 may be a special mixture of hydrocarbons that is formed at the surface and liquefied at an appropriate pressure and temperature. The mixture may, in general, include light hydrocarbons and one or more heavier organic solvents.
This liquid mixture is used as a power fluid for the jet pump, i.e., it is injected through the power fluid duct. For typical SHORE production rate, approximately 1000 - 3000 m3/day of slurry per well, the pressure drop at the jet pump nozzle is about 100 psi but it can vary if another dilution method is used apart from jet pump. The SHORE production rate can also be as low as approximately 200 m3/day of slurry. Light hydrocarbons such as methane and/or ethane evaporate at significantly lower pressure than the heavier solvent. Therefore, the composition of the mixture is formulated in such a way that power mixture fluid is liquid upstream of the jet pump nozzle and the resulting pressure drop downstream of the nozzle evaporates a significant part of lighter hydrocarbons. Meanwhile, most of the heavier solvent(s) remains in the liquid phase and serves as both a slurry diluter and a bitumen solvent.
As a result, the evaporated part of the power fluid serves as a gas lift while the heavier solvent portion mixes vigorously with the oil sand during fast lift leading to bitumen liberation and extraction.
100521 It is possible that if the concentration of solvent mass in respect to bitumen mass is too high in the production wellbore, a detrimental asphaltene precipitation may occur.
However, the high velocity in the production wellbore during typical SHORE gas lift leads to a solvent/bitumen mixing time of no more than few minutes. Asphaltene precipitation in general requires a much longer residence time period than a few minutes so the amount of solvent injected at the wellbore may not be restricted by asphaltene precipitation.
100531 Fig. 5 illustrates a modified NAE process 500 integrated with SHORE lift by an embodiment of the present invention. As mentioned above, the function of mixing the oil sand with an organic solvent 304 in a mixing tank 306 from the example of Fig.
3 may be accomplished in one step during the slurry lift in the production well of Fig.
4. In Fig. 5, water 502 as a fines agglomerating agent can be added at the surface after the slurry lift.
Optionally, water 502 as a fines agglomerating agent can be injected as fraction of the power mixture fluid 504. If asphaltene precipitation is not an issue due to short lift residence time, then enough solvent and water can be injected so that solids agglomeration and bitumen extraction may happen during the slurry lift. In this case, the resulting slurry may directly go to separation process, greatly simplify, ing the NAE process and reducing its cost. This simplified version of a NAE process 600 with only the separation process at the surface is illustrated in Fig. 6.

- 12 -100541 As mentioned above, the chemical composition of a power mixture fluid can be tailored in such a way so that evaporation of light hydrocarbons in the power fluid begins downstream of the jet pump nozzle or other relevant dilution method. Different wells may have different downhole pressures and temperatures. Therefore, the composition of the power mixture fluid may vary from well to well so that evaporation of light hydrocarbons in the power fluid begins downstream of the jet pump nozzle, orifice, or expansion valve for different well depths, i.e., different pressures, and different well temperatures. Furthermore, for a given well, it may be necessary to adjust the composition of the power fluid at the surface to control the boiling point and solvency power of the power fluid in response to changes pressure, temperature, oil sand composition, etc. To illustrate this point, the composition of an embodiment of a power fluid will be discussed below that consists of methane and cyclohexane. Methane functions as a lift agent and cyclohexane is a solvent.
Different chemical components can be chosen, the solvent component can be any mixture of hydrocarbons such as paraffinic solvent or cyclic aliphatic hydrocarbon.
Different lift agents may be used as well.
100551 Fig. 7 illustrates a phase diagram 700 of two possible compositions of methane and cyclohexane mixtures. Line 702 is the phase diagram line for a 16% (mole) methane /
84% cyclohexane mixture and line 704 is the phase diagram line for a 6%
methane 94%
cyclohexane mixture. The temperature 706, in Celsius, is on the x-axis and the y-axis is pressure 708 in psia. As is known to a person of ordinary skill in the art, the area within the phase diagram line corresponds to a boiling or evaporation temperature and pressure range for the mixture, the area to the left of the left portion of the line corresponds to the liquid phase for the mixture and the area to the right of the right portion of the line corresponds to the vapor phase for the mixture. The downhole pressure for a 100 meter deep well may be approximately 207 psia, at this pressure, one might choose the 6% methane /
94%
cyclohexane mixture because at a pressure of 207 psia, depending on the temperature, the mixture is likely to be either a liquid, although close to boiling, or nearly a liquid with some vapor.
100561 Fig. 8A illustrates a working cycle on the phase diagram of a gas lift of a 100 m deep well while Fig. 88 depicts a schematic of an embodiment of a corresponding gas lift for the 100 m well. In this embodiment, the power fluid is a mixture of 6% methane and 94%
cyclohexane. Points 801, 802, 803 and 804 on phase diagram Fig. 8A correspond to locations 801, 802, 803 and 804 on the gas lift schematic in Fig. 8B. Point 803 corresponds

- 13 -to the exit of the jet pump nozzle 805, at which point evaporation of a portion of the power fluid should start, i.e., point 803 should be on the phase line separating liquid and liquid-vapor states. Second, production wellhead pressure is fixed ¨ about 50 psi leading to point 804 being at this approximate pressure level.
10057j Starting at the surface, power fluid 808 is injected into power fluid conduit 810 as a liquid-vapor at the surface at a temperature and pressure corresponding to point 801 on the phase diagram of Fig. 8A. At this point 801, the liquid-vapor power fluid 808 mixture has temperature slightly above the reservoir temperature. The liquid-vapor power fluid 808 then flows down the power conduit 810 to the jet pump 812. As the liquid-vapor power fluid 808 flows down the power conduit 810, the pressure increases and the temperature decreases, resulting in any vapor condensing so that the power fluid 808 becomes a liquid and corresponds to the point 802 on the phase diagram. The pressure increase of about 100 psi between points 801 and 802 is due to hydrostatic head of power fluid in conduit assuming that majority of the power fluid height is occupied by liquid phase of power fluid. After ejection from the jet pump 812 the pressure of the power fluid 808 drops to point 803 on the phase diagram. A typical jet nozzle pressure drop is about 100 psi. This leads to evaporation of mainly methane while the temperature of the power fluid remains approximately at reservoir ambient level due to further mixing with reservoir slurry. As the power fluid 808 flows up the well together with the reservoir slurry its pressure decreases leading to further evaporation of mainly methane until it reaches the wellhead pressure, while remaining at reservoir temperature, which pressure and temperature correspond to point 804.
[00581 At the wellhead, in this embodiment, the reservoir slurry and power fluid mixture 820 enter a separator 822 with negligible pressure change. At the separator 822, the diluted bitumen 824, consisting of bitumen and cyclohexane is separated from methane 826. The methane 826 is then mixed with additional cyclohexane 828 and this mixture 830 goes into the pump 832. The pump 832 can be a multiphase pump such as a twin-screw pump or compressor. The pump 832 must then raise the pressure of the mixture 830 from point 804 to point 801. Thus the energy required to run gas lift in this embodiment for a 100 m deep well goes into compression and liquefaction of the power fluid 808 from approximately 50 to 200 psia. If the cost of compression of the mixture of 6% methane and 94%
cyclohexane from 50 to 200 psia is lower than cost of air compression from approximately 50 to 300 psia, where 300 psia is the downhole pressure, then the mixture lift method is more economical than gas lift plus there is the added benefit of initial bitumen dilution and liberation. Note that the

- 14 -pressure of the power fluid does not need to be as high as the bottom hole pressure due to the increase in pressure from the hydrostatic head of the liquid column in the power fluid conduit. For 100 m well this beneficial hydrostatic head is about 100 psi.
100591 In another embodiment, a 300 m well has a downhole pressure of approximately 620 psia. In this embodiment, a mixture of 16% methane and 84% cyclohexane may be more suitable as the power fluid, as illustrated in Fig. 9. It is very similar to the 100 m well except that the power fluid may be a vapor and liquid mixture which is injected into the power conduit at point 901. However, the vapor portion of the power fluid quickly condenses to a liquid as pressure rises from point 901 to point 902 immediately upstream of the jet pump or injection point. In this embodiment thr a 300 m well, the compression cost is higher as the pump and/or compressor must raise the pressure from approximately 50 psia at the wellhead to approximately 650 psia at the surface location of the power fluid conduit.
Again, the cost of such pressurization/compression should be compared to cost of air compression from 50 to 700 psia.
100601 Figs. 10A and 10B illustrate calculated gas holdup along the height of a 100 m (Fig. 10a) and 300 m (Fig. 10b) well. Gas holdup 1002, on the y-axis for both Fig. 10A and 10B, is a volume ratio of the well occupied by gas, which, in the embodiment using a methane/cyclohexane mixture, is primarily evaporated methane. The x-axis is well pressure 1004, in psia. The gas holdup is calculated with a total volume production rate of slurry of 2,000 m3/day while the power fluid liquid injection rate, point 803 on Fig.
8b, was 1,500 m3/day and 500 m3/day for the 100 and 300 m well, respectively. Well locations 801, 802, 803 and 804 on Fig. 8b correspond to the points in Figs. 10A and B.
Calculations have shown that after ejection from the jet nozzle, point 802, methane is evaporated and expanded while moving up the well leading to desired gas holdup values in excess of 0.5. Such holdup profiles reflect typical gas content during normal gas lift operation.
100611 Reservoirs intended for the disclosed methods and systems can be shallow, about 75 m to 150 m, or deep from about 150 m to 460 m, and even as deep as 1,000 m.

Depending on depth and bottom hole pressure, different combinations of power fluid compositions may be utilized. Because the density of the slurry downstream of the jet pump is about 1.5-1.7 times that of water, the gas undergoes significant pressure drop while rising from the reservoir. Consequent gas expansion may lead to a significant increase in gas and slurry rising speed which may incur significant friction losses.

- 15 -[0062] While the present disclosure may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the disclosure is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present disclosure includes all alternatives, modifications, and equivalents.

- 16-

Claims (16)

CLAIMS:

1. A method for producing a dense slurry comprising bitumen from a subsurface formation, comprising:
injecting a liquid phase fluid into a producer pipe inlet to mix with the dense slurry and form a diluted slurry;
evaporating at least a portion of the liquid phase fluid in the producer pipe;
and lifting the diluted slurry up the producer pipe utilizing a gas lift of the evaporation of at least a portion of the fluid;
wherein the fluid is selected to begin evaporating at the pressure and temperatures of the producer pipe inlet; and wherein the fluid is a combination of fluids selected from the group consisting of methane, ethane, propane, butane, pentane, hexane, naptha and cyclohexane.

2. The method of claim 1, further comprising dissolving at least a portion of the bitumen in the diluted slurry with a liquid phase of the fluid in the producer pipe.

3. The method of claim 2, wherein injecting a liquid phase fluid into the producer pipe inlet comprises the use of one of (i) a jet pump and (ii) an orifice or expansion valve.

4. The method of claim 2, wherein the fluid comprises water.

5. The method of claim 4, further comprising agglomerating solids and water in the diluted slurry in the producer pipe.

6. The method of claim 3, further comprising:
separating the evaporated gas phase of the fluid from the diluted slurry;
mixing additional liquid phase of the fluid with the evaporated gas phase to form the fluid; and reinjecting the fluid into the producer pipe inlet.

7. The method of claim 1, further comprising conditioning the subsurface formation to form the dense slurry.

8. The method of claim 3, wherein injecting a liquid phase fluid into the producer pipe inlet comprises a fluid conduit.

9. The method of claim 1, wherein the dense slurry contains from about thirty volume percent to about sixty-five volume percent sand concentration.

10. The method of claim 1, wherein the diluted dense slurry one of (i) is lifted at a rate of between about 200 cubic meters per day (m3/d) to about 3,000 m3/d and (ii) before evaporation of gas lift components, contains from about twenty-five volume percent (25 vol%) to about 50 vol% sand concentration.

11. The method of claim 1, further comprising separating bitumen from the diluted dense slurry.

12. The method of claim 3, wherein conditioning the subsurface reservoir comprises a slurrified heavy oil reservoir extraction process.

13. A system for producing hydrocarbons, comprising:
a well bore containing a producer pipe extending through an overburden below a surface of the earth into an oil sand reservoir, the producer pipe having at least one opening configured to permit the flow of a dense slurry into the producer pipe from the oil sand reservoir;
an injection system configured to inject an organic compound into the at least one opening of the producer pipe to form a diluted slurry, wherein the organic compound is selected so as to vaporize at least a portion of the organic compound in the producer pipe; and a diluted slurry lift system utilizing the gas lift of the evaporation of at least a portion of the organic compound to lift the diluted slurry to the surface of the earth;

wherein the injection system further comprises one of (i) a jet pump configured to inject the organic compound at a rate sufficient to generate a low pressure region around the at least one opening of the producer pipe to draw the dense slurry from the oil sand reservoir into the producer pipe and (ii) the use of an orifice or expansion valve; and wherein the organic compound is a combination of fluids selected from the group consisting of methane, ethane, propane, butane, pentane, hexane, naptha and cyclohexane.

14. The system of claim 13, further comprising dissolving at least a portion of the hydrocarbons in the diluted slurry with a liquid phase of the fluid in the producer pipe.

15. The system of claim 13, wherein the fluid further comprises water.

16. The system of claim 15, further comprising agglomerating solids and water in the diluted slurry in the producer pipe.