WO2011025590A1

WO2011025590A1 - Dense slurry production methods and systems

Info

Publication number: WO2011025590A1
Application number: PCT/US2010/041531
Authority: WO
Inventors: David P. Yale; Andrey A. Troshko; Bennett D. Woods
Original assignee: Exxonmobil Upstream Research Company
Priority date: 2009-08-31
Filing date: 2010-07-09
Publication date: 2011-03-03
Also published as: US20120175127A1; CA2769067A1

Abstract

Methods and systems for producing a dense oil sand slurry from subsurface reservoirs are provided. The methods include reducing pressure at a producer pipe inlet to draw a dense slurry into the producer pipe using a jet pump, generating a diluted dense slurry using the jet pump, and lifting the diluted dense slurry through the producer pipe utilizing a slurry lift apparatus, which may be a fluid lift apparatus. The systems include a producer pipe into an oil sand reservoir, a jet pump configured to generate a low pressure region around the opening of the producer pipe to draw the dense slurry into the producer pipe and dilute the dense slurry to form a diluted dense slurry; and a gas lift apparatus configured to lift the diluted dense slurry through the producer pipe towards the surface of the earth.

Description

DENSE SLURRY PRODUCTION METHODS AND SYSTEMS

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of U.S. Provisional Patent Application 61/238,564 filed 31 August 2009 entitled DENSE SLURRY PRODUCTION METHODS AND SYSTEMS, the entirety of which is incorporated by reference herein.

FIELD OF THE INVENTION

[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. [0005] 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 Fluidized In-situ Reservoir Extraction (FIRE). 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 FIRE (International Patent Application Publication WO2007/050180) processes. When the amounts of sand and water produced are very large, it is important to be able to safely dispose the sand and water back into subsurface.

[0006] 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. Reactions of sand in a slurry in a motive state (having a velocity distribution) may be determined by its rheology expressed by a stress (T ) to strain rate ( γ) relationship. One example of such a relationship is the Herschel-Bulkley model: τ = τ_Y + Ky" . For a dense slurry, an increase in production rate (velocity) by β times could result in a frictional stress increase by a factor of β" , n ~ 1.5 ÷ 2 . As such, a sufficiently powerful artificial lift ("AL") apparatus should be employed to circumvent the frictional pressure drop increase β" associated with the friction increase.

[0007] Another 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.

[0008] Jet pumps have been used in the oil and gas industry for a variety of applications.

For example, U.S. Pat. No. 6,821,060 to McTurk et al. ("McTurk") describes application of a jet pump in an oil sand mining operation. In particular, a mined and crushed oil sand is fed into a jet pump via a hopper to form a "conditioned," aqueous oil sand slurry. In a similar application, U.S. Pat. No. 6,527,960 to Bacon et al. ("Bacon") describes a method of treating mined oil sands using a jet pump scrubber to remove the oily film from the tar sand particulates. Neither McTurk nor Bacon contemplate the use of a jet pump for producing the oil sands from a formation. [0009] A different example of jet pumps in mining operations is disclosed in U.S. Pat. No. 4,527,836 to Uhri ("Uhri"). In Uhri, the jet pump is placed in an oil shale formation where the nozzle of the water jet is directed outwardly to cut chunks of oil shale from the formation. See, e.g. Uhri at FIG. 1 and col. 3, 11. 27-29. Uhri does not disclose use of a jet pump to produce a slurry by moving it into a wellbore. [0010] Jet pumps have also been used in various oil field operations. For instance, U.S. Pat. No. 7,063,161 to Butler et al. ("Butler") describes the use of a jet pump with a motive fluid containing some gas to produce crude oil from a well bore. Butler does not disclose or contemplate producing solids laden slurries. In another application, U.S. Pat. Application No. 2005/0121191 to Lambert et al. ("Lambert") describes the use of a jet pump with increased erosion protection to lift slurry from the wellbore during a cleanout workover in an oil well. The idea is to operate jet with very large pressure drop as motive fluid exits the jet and mixes with slurry to induce cavitation to lower erosion rates in the throat entrance. However, Lambert does not contemplate producing fluids from a formation or producing a dense slurry. [0011] What is needed are methods and systems capable of lifting dense slurries from subsurface formations for production.

[0012] Other relevant material may be found in: U.S. Pat. No. 7,200,539; U.S. Pat. App. No. 2003-0201098; CA Pat. No. 2,582,091; ACKERMAN NL, HUNG TS, Rheological characteristics of solid-liquid mixtures, A. I. Ch. E. Journal, 25 2, 327-332 (1997); JACOBS BEA, Design of Slurry Transport Systems, Taylor and Francis, London and New York, ISBN 1-85166-634-6, 71-101 (2006); Li J, MISSELBROOK JG AND SEAL J, Sand cleanout with coiled tubing: choices of process, tools or fluids, SPE 113267 (2008); HEYWOOD NI AND CHARLES ME, Effects of gas injection on the vertical pipe flow of fine slurry, Proc. Hydrotransport 7 Conf, Paper El, BHRA, Sendai, Japan, (Nov 4-6 1972); ODROWAZ-PIENIAZEK S, Solids- handling pumps - a guide to selection, The Chemical Engineer, (February 1979); MANGESANA N, CHIKUKU RS, MAINZA AN, GOVENDER I VAN DER WESTHUIZEN AP AND NARASHIMA M, The effect of particle sizes and solids concentration on the rheology of silica sand based suspensions, Journal of the Southern African Institute of Mining and Metallurgy, 108, 237-243 (2008); WAKEFIELD AW, The jet-pump scrubber, Quarry Management, (February 1993); WANG X, ZOU H, LI G, NIE C, CHEN J, Integrated well-completion strategies with CHOPS to enhance heavy-oil production: a case study in FuIa oilfield, SPE 97885 (2005); WILLIAMS S, ROZO R, AYA FP, HERNANDEZ JIS, Artificial lift optimization in the Orito field, SPE 116659 (2008); WILSON G, The design aspects of centrifugal pumps for abrasive slurries, Proc. Hydrotransport 2 Conf, Paper H2, BHRA, Cranfield (1972)..

SUMMARY OF THE INVENTION

[0013] In one embodiment of the present disclosure, a method for producing a dense slurry is provided. The method includes reducing a pressure at a producer pipe inlet to draw the dense slurry into a producer pipe from a subsurface formation, wherein the pressure is reduced using a jet pump to direct a power fluid towards the producer pipe inlet at an initial flow rate; generating mixing the power fluid and the dense slurry utilizing the jet pump to form a diluted dense slurry using the jet pump; flowing the diluted dense slurry into the producer pipe at an the initial flow rate; and lifting the diluted dense slurry through the producer pipe utilizing a slurry lift apparatus. The slurry lift apparatus may be a fluid or gas lift apparatus, a progressive cavity pump, an electric submersible pump, or any combination of these. [0014] In a second embodiment of the present disclosure, a system for producing hydrocarbons is provided. The system includes 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 an at least one opening configured to permit the flow of a dense slurry into the producer pipe from the oil sand reservoir; a jet pump incorporated into the well bore configured to inject a power fluid 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 dilute the dense slurry to form a diluted dense slurry; and a slurry lift apparatus configured to lift the diluted dense slurry through the producer pipe towards the surface of the earth. The slurry lift apparatus may be a fluid or gas lift apparatus, a progressive cavity pump, an electric submersible pump, or any combination of these. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] 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: [0016] FIG. 1 is a process flow chart for methods of producing a dense slurry in accordance with certain aspects of the disclosure;

[0017] FIG. 2 is an illustration of one exemplary embodiment of the artificial lift system used in the process of FIG. 1 using a fluid lift apparatus to provide slurry lift;

[0018] FIG. 3 illustrates an alternative exemplary embodiment of the artificial lift system of FIG. 2;

[0019] FIGs. 4A-4C illustrate four additional exemplary embodiments of the artificial lift system of FIG. 2; and

[0020] FIGs. 5A-5B illustrate alternative exemplary embodiments of the artificial lift method of FIG. 1 and system of FIG. 2 utilizing pumps to provide slurry lift. DETAILED DESCRIPTION OF THE INVENTION

[0021] 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

[0022] 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.

[0023] 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.

[0024] 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.

[0025] 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.

[0026] The term "dense slurry," as used herein, refers to a mixture of solids and fluids having a solids concentration range of about 30-65 volume percent (vol%). Such a dense slurry may be found naturally in-situ, may be generated by the FIRE process, or may be generated by another process.

[0027] 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. [0028] 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 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." [0029] 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.

[0030] 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.

[0031] 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.

[0032] 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. [0033] The terms "preferred" and "preferably" refer to embodiments of the inventions that afford certain benefits under certain circumstances. However, other embodiments may 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. [0034] 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.

[0035] 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

[0036] 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 reducing 104 a pressure at a producer pipe opening (e.g. inlet) to draw a dense slurry into the producer pipe, wherein the pressure is reduced using a jet pump directed towards the producer pipe inlet, generating 106 a diluted dense slurry using the jet pump, flowing 108 the diluted dense slurry into the producer pipe at an initial flow rate, and lifting 110 the diluted dense slurry through the producer pipe utilizing a slurry lift apparatus. The process 100 may also optionally include conditioning 102 the subsurface formation to form the dense slurry and separating 112 bitumen from the diluted dense slurry.

[0037] The step of reducing 104 the pressure at the producer pipe inlet may be accomplished by positioning the jet pump below the producer pipe and injecting a power fluid through the jet pump into the producer pipe. This approach creates a low pressure region around the producer pipe inlet, which draws the dense slurry into the producer pipe inlet. This low pressure region is configured to overcome frictional and compression sand resistance and draws the dense slurry into the well. Concurrently, the jetting action generates 106 a diluted dense slurry (e.g. lowers the solids concentration of the dense slurry) by mixing the dense slurry with a power fluid and pushes or flows 108 the diluted dense slurry up the producer pipe towards the surface. However, the jet pump will not generally be sufficient to push or flow the diluted dense slurry all the way to the surface.

[0038] The step 104 may be optional when the radial pressure gradient will be enough to circumvent frictional resistance of the in-situ slurry. In this case, dilution 108 of the slurry is the only necessary step, without the need to create a low pressure region. Accordingly, a lower power jet pump flow rate may be used. As the frictional resistance of the slurry may change during production due to different oil or tar sand quality or different formation impurities (shale, shaley etc.), the power flow rate of the jet pump may be decreased or increased as needed.

[0039] The diluted dense slurry is then lifted 110 by a slurry lift apparatus through the remaining portion of the producer pipe up to the surface. The slurry lift apparatus may be any type of device capable of supplying lift energy to the diluted dense slurry sufficient to lift the slurry to the surface while overcoming erosion problems. In one exemplary embodiment, the slurry lift apparatus is a fluid lift apparatus. Alternatively, the slurry lift apparatus is a progressive cavity pump.

[0040] In one alternative embodiment, the jet pump may be fitted with an additional array of nozzles providing additional fluidization. These additional jets may use its own pump or connected to main power fluid of the jet pump. The purpose of these jets is by action of fluid jetting dilute sand before it is drawn into well by main jet pump. Diluted sand offers less resistance thus reducing power fluid flow rate in the main jet pump. Motive or power fluid may be supplied via a separate pipe using a surface pump. In certain embodiments of the disclosed process, the power fluid may be selected from the group consisting of water, a hydrocarbon solvent, a heated fluid, and any combination thereof.

[0041] Another alternative embodiment includes the use of cavitation. In particular, the temperature of motive or power fluid coming through the array of nozzles may be increased and hot fluid can be utilized to induce cavitation in a mixing chamber for enhanced dense slurry conditioning and erosion reduction. In a jet pump, cavitation occurs when the pumped power fluid stream velocity is increased to a point where the power fluid pressure becomes very low or near absolute zero—lower than the vapor pressure of the fluid itself—where the fluid stream exits the nozzle. Since higher temperature fluid has a higher vapor pressure, it is easier to induce cavitation in higher temperature fluids, but higher temperature is not necessary. As the power fluid exits the nozzle at this high velocity, the ultra low fluid pressure causes the power fluid to create cavitation vapor bubbles, which quickly form and then collapse as the power fluid is recaptured by the throat. This action is extremely violent and causes severe mixing of the power fluid and the dense slurry being drawn in. The severe mixing action forces the sand particles or other solids to be fully immersed in the fluid stream and lessens the sand particles' exposure to the throat surface. Cavitation also helps condition the dense slurry to separate bitumen from the sand particles and mix the dense slurry to form a well-mixed diluted dense slurry. [0042] It should be noted that the disclosed process 100 is considered to be compatible with any and all known bitumen extraction and treatment processes, such as the Clarke hot water extraction (CHWE) and cold water extraction (CWE) processes, paraffmic froth treatment (PFT) and napthenic froth treatment (NFT) processes, and others. Such processes are generally known in the art. It is within the scope of the present disclosure to modify the process 100 to enhance the performance of such extraction and treatment processes by methods configured to result in a "well conditioned" slurry. The term "well conditioned slurry," as used herein means: bitumen separated from the sand and enter the water phase in the form of small "flecks," wherein some bitumen flecks are coalesced and attached to air bubbles entrained by power fluid.

[0043] Several exemplary process modifications configured to optimize extraction and treatment processes include: 1) adjusting the flow rate of the power (motive) fluid to control the composition (e.g. sand concentration) of the diluted dense slurry, 2) adding a chemical hydrocarbon solvent to the power fluid jet pump and/or complimentary nozzles to precondition the dense slurry to facilitate separation 112 of the sand, water, and bitumen, and 3) selecting a type of fluid and a fluid pressure to operate the fluid lift apparatus and promote more efficient extraction and treatment of the diluted dense slurry.

[0044] In one particular embodiment, the step of lifting 110 the diluted dense slurry includes injecting compressed fluid into the producer pipe. In one embodiment of the fluid lift arrangement, the compressed fluid may be introduced just above the jet pump via a standard side pocket valve. Alternatively, the compressed fluid may be mixed with the power fluid in the power fluid feed pipe used to feed the jet pump. This alternative approach may save some cost and effort on installation, but may also reduce the efficiency of the jet pump as additional work would be required to compress/decompress the gas in the mixing chamber. In certain embodiments of the present invention, the compressed fluid may be any one or a combination of natural gas, methane, carbon dioxide, air, nitrogen, tail gas, and products of combustion.

[0045] In an alternative embodiment, the step of lifting 110 the diluted dense slurry includes one or both of a progressive cavity pump (PCP) and an electric submersible pump. In this case, the additional conduit for carrying compressed fluid would be eliminated.

However, the erosion of the stator due to high sand flux would require monitoring, the integrity of the elastomer on the rotor of the PCP, and the accumulation of sand above the pumps may result in drive torque increase, which could decrease the efficiency of the system.

[0046] FIG. 2 illustrates one exemplary embodiment of the artificial lift system used in the process of FIG. 1. As such, FIG. 2 may be best understood with reference to FIG. 1. The system 200 includes a wellbore 202 in a subsurface formation 203 having a producer pipe 204 including a slurry input orifice 205, a mixing chamber 209, a diffuser 215, a jet pump apparatus 206 in the wellbore 202 comprising a power fluid conduit 207 configured to deliver power fluid 208 to a power fluid nozzle 216 and (optionally) additional nozzles 218, and a fluid lift apparatus 210 in the wellbore 202 comprising a compressed fluid conduit 211 configured to deliver compressed fluid 212 into the producer pipe 204 through a side pocket valve 213. The conduits 204, 207, and 211 are held in the wellbore 202 with a triple production packer 214. In a detail view 224, a gas bubble 224a produced by the fluid lift apparatus 210 is shown as it lifts a slurry slug 224b generated and flowed by the jet pump 206. [0047] In the exemplary system 200, the power fluid jet 216 injects fluid into inlet 205 of the mixing chamber 209 creating a lower pressure at 205. The power fluid then mixes with the surrounding fluid (slurry) in the mixing chamber 209 and slows down further downstream as pressure increases in the diffuser 215. The diameter of the mixing chamber 209 must be larger than the jet 216 inlet diameter for the jet pump 206 to work. [0048] It should be understood that the power fluid may be provided using a pump located at the surface. The pump power and speed may be controlled and monitored at the surface using equipment and techniques known in the art. Similarly, the compressed fluid may be provided to the fluid lift apparatus via a pump or other pressurized fluid system located on the surface. Monitor and control may also be provided at the surface. [0049] In particular cases, the lift fluid may be a gas such as, for example, nitrogen, air, flue gas, and combinations of these, but may also include some liquids. In any case, the lift fluid should be configured to be less dense than the dense slurry and the diluted dense slurry and in some cases, expand as it moves up the production pipe 204. The power fluid may be water, a hydrocarbon solvent, a heated fluid, and combinations of these. In particular, the power fluid is preferably configured to create a low pressure volume for drawing in dense slurry, decreasing the solids concentration in the dense slurry, and improving the conditioning of the diluted dense slurry as the diluted dense slurry flows into and up the producer pipe 204.

[0050] Note that the side valve 213 should be appropriately designed to handle increased erosion from slurry stirred by the gas next to the valve entrance to the producer pipe 204. The system 200 may even include redundant or alternative valves 213 (not shown) in the event of failure to avoid a costly work-over. Injected gas is expected to form a bubble and rise up the pipe 204 forming large elongated bubbles 224a intermingled with slurry slugs 224b. Such flow is called "slug flow."

[0051] In general, as bubbles 224a move up, their volume will increase due to the expected pressure decrease. The larger bubbles 224a will accelerate and push slurry slugs 224b faster. Turbulence is expected to increase in such accelerated slurry slugs 224b. Beneficially, this is expected to lead to improved conditioning of the slurry due to increased shear of particles. One side effect of such acceleration will be an increase in friction losses. As such, appropriately large producer pipe 204 diameter should be chosen to keep frictional pressure loss minimal. On the other hand, increased producer pipe 204 diameter will warrant a large gas flow rate so an optimum producer pipe 204 diameter should be determined. In one exemplary embodiment, it is expected that a producer pipe 204 diameter of from about 0.1 to about 0.6 meters or about 0.1 to about 0.4 m is desirable. However, in some embodiments, it is beneficial to make a more precise determination of optimum diameter based on the conditions of the subsurface formation, depth, expected diluted dense slurry flow rate, composition of the diluted dense slurry, and other factors as disclosed in the commonly assigned, concurrently filed application entitled "ARTIFICIAL LIFT MODELING METHODS AND SYSTEMS."

[0052] FIG. 3 illustrates an alternative exemplary embodiment of the artificial lift system of FIG. 2. As such, FIG. 3 may be best understood with reference to FIGs. 1 and 2. FIG. 3 depicts a system 300 having an additional slurry dilution conduit 302 with a valve 304 configured to control and permit flow of power fluid from the power fluid conduit 207 to the producer pipe 204. The dilution conduit 302 replaces the additional nozzles 218 of system

200, but a system may be designed having both features and a possibility of switching operation from one feature to the other feature, depending on the operational circumstances.

The system 300 is a possible lift design for a shallow reservoir, such as a reservoir at a depth of from about 250 feet to about 1,000 feet or less. Such a shallow reservoir may have a relatively small Bottom Hole Pressure, which could result in a more dense slurry flowing into the producer pipe 204. In such a situation, fluid lift may not be feasible, warranting further slurry dilution inside the producer pipe 204 via the dilution conduit 302.

[0053] Additionally or alternatively, the system 300 may be operated by switching valve 304 to redirect fluid flow between the power nozzle 216 and the conduit 302. For example, as introduced above, there may be times during production when the low pressure region is not needed due to decreased frictional resistance. Under such circumstances, the valve 304 may be adjusted to direct dilution fluid flow into conduit 302 to dilute the flow without concern for the pressure in the region of the inlet. In the event that the production rate of oil sand drops due to increased flow resistance, the fluid flow may be redirected towards jet pump 206 by adjusting valve 304.

[0054] FIGs. 4A-4C illustrate three additional exemplary embodiments of the artificial lift system of FIG. 2. As such, FIGs. 4A-4C may be best understood with reference to FIGs. 1 and 2. FIGs. 4A-4C present three possible completion designs for the producer well 202. Note that the designs of FIGs. 2 and 3 include three pipes 204, 207, and 211 running through a triple packer 214 located in the well bore 202. FIG. 4A illustrates a system 400 where the compressed fluid conduit 402 is positioned concentrically around the production pipe 204 with the compressed fluid being supplied through an annulus formed between the compressed fluid conduit 402 and the production pipe 204. Note that the packer 406 is a double packer. [0055] FIG. 4B illustrates a system 420 having a power fluid conduit 422 located concentrically through the production pipe 204 and a single production packer 424 with the wellbore casing reaching below the jet pump 206 and producer pipe and having perforations 447 to permit the passage of slurry while protecting the jet pump 206 from damage or clogging by large rocks that may impinge on the jet pump 206. [0056] FIG. 4C illustrates a system 440 having a power fluid conduit 442 and a compressed fluid conduit 444 in a concentric configuration with respect to each other, but offset from the production pipe 204 and having a double production packer 446.

[0057] FIGs. 5A-5B illustrate alternative exemplary embodiments of the artificial lift method of FIG. 1 and system of FIG. 2 utilizing pumps to provide slurry lift. As such, FIGs. 5A-5B may be best understood with reference to FIGs. 1 and 2. In particular, FIG. 5A shows a system 500 including a wellbore 202 in a reservoir 203 having a jet pump system 207, 208, 216 and a producer pipe 204 with a progressive cavity pump (PCP) 502 incorporated therein. The PCP 502 includes a stator 504, a rotor 506, and a drive string 508.

[0058] In particular, the PCP 502 is what is known as a positive displacement pump (PD pump), which utilizes reciprocating displacement motion to pump fluids or slurries. Although some have reported that the maximum volume pump rate of a PCP is about 1 ,000 m³/day, it may be possible to significantly increase this rate if the slurry is sufficiently diluted and treated such that erosion of the internal parts (e.g. the stator 504, and the rotor 506) is mitigated. [0059] In FIG. 5B, a system 520 is shown having a rotordynamic pump (RP) 522 in place of the positive displacement pump 502. RP 's are radial type machines that use a bladed impeller to push slurry and are generally used to handle higher flow rate, lower head applications. However, RPs have a well adapted version in oil industry called an electric submersible pump (ESP). ESP 's generally have lower solid handling capability than PD pump's and fluid lift apparatuses, but some modifications into ESP design may improve its solid handling capability and, like with the PD pump, dilution and conditioning of the diluted dense slurry may be modified to allow such a pump to operate at sufficient volumetric pumping rates.

[0060] In one exemplary embodiment, assembly of system 200 will likely include three steps: first, installation of production pipe 204 together with connected short fragments of compressed fluid conduit 211 and power fluid conduit 207; second, install the triple packer 214; third, connect the fluid conduit 211 and power fluid conduit 207 with preinstalled pipe fragments. All four designs 200, 400, 420, 440 must account for significant vertical and radial stresses acting on the lowermost part of the well bore 202. Such loads are created by increased overburden load due to overburden relief in the reservoir 203 to make the sand flow as a dense slurry. Use of slip-joints on the conduits 204, 207, and 211 may at least partially alleviate this problem. Additionally, screwing and unscrewing production pipe of such large diameter (e.g. during a workover or installation operation) may create leak problems and large hoop stress. [0061] Each design 200, 400, 420, 440, 500, and 520 has its merits and disadvantages. For example, the system 200 will likely use less steel than system 400 due to its smaller pipe thickness. System 420 may be less complex to install (due to use of a single production packer 424) than the other designs, but results in a reduction of slurry flow area through the production pipe 204 and a consequent erosion increase for both the inside of the production pipe 204 and the outside of the power fluid conduit 422. System 440 will use more steel than that of system 200, but less than system 400 and will be more complicated to install than system 420, but avoid the erosion problem due to slurry flow area. Systems 500 and 520 will eliminate the need for a fluid delivery conduit, but may require some operational limitations and/or have a more limited performance envelope than the other options. However, it is believed that under certain conditions, the presently disclosed embodiments are all capable of improving slurry artificial lift to help produce oil sands from subsurface formations.

[0062] Each completion design 200, 400, 420, 440, 500, and 520 may have an inlet jet pump being lower than the bottom of the wellbore shoe (e.g. Figs. 2, 3) or above the wellbore shoe (e.g. Figs. 4A-C and 5A-B). In particular, designs with the jet pump below the wellbore shoe offer easier access to the surrounding slurry, while above -the-wellbore shoe designs accompanied by wellbore casing slots (e.g. 447) ensures protection against large stones and other debris from entering the jet pump 206. Such debris can be drawn by converging slurry and may damage the completion. Note that the wellbore may extend to the bottom of the reservoir.

EXAMPLES

[0063] In one exemplary embodiment, the dense slurry entering the producer pipe 204 will be diluted from about 60% to below about 40% sand concentration and partially conditioned (e.g. by adding solvent, by turbulence due to the fluid lift system, or some other means). The hydrostatic pressure gradient corresponding to such a slurry is about 1.7 pounds per square inch per meter (psi/m). The jet pump 206 works with the fluid lift apparatus 210 to produce this pressure gradient to lift the diluted dense slurry to the surface for further processing (e.g. extraction and treatment processes).

[0064] Reservoirs intended for the disclosed methods and systems can be shallow (about 250 feet to about 750 ft) or deep (about 500 ft to about 1,500 ft) and even as deep as 3,000 ft. Depending on depth and Bottom Hole Pressure, different combinations of lift methods of slurry in the producer pipe 204 may be utilized. Because density of the slurry downstream of the jet pump 206 is still about 1.5-1.7 times that of water, the gas undergoes significant pressure drop while rising from deep reservoir. Consequent gas expansion may lead to a significant increase in gas and slurry rising speed which may incur significant friction losses. Another consequence of significant gas expansion is an undesirable flow regime transition which may cause significant pressure pulsations in the producer pipe 204. [0065] 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 falling within the true spirit and scope of the appended claims.

Claims

Claims: What is claimed is:

1. A method for producing a dense slurry, comprising:

reducing a pressure at a producer pipe inlet to draw the dense slurry into a producer pipe from a subsurface formation, wherein the pressure is reduced using a jet pump to direct a power fluid towards the producer pipe inlet at an initial flow rate;

mixing the power fluid and the dense slurry utilizing the jet pump to form a diluted dense slurry;

flowing the diluted dense slurry into the producer pipe at the initial flow rate; and lifting the diluted dense slurry through the producer pipe utilizing a slurry lift apparatus.

2. The method of claim 1, wherein the slurry lift apparatus is a fluid lift apparatus utilizing a lift fluid, wherein the lift fluid is less dense than the diluted dense slurry.

3. The method of claim 2, wherein the lift fluid is a gas.

4. The method of claim 1, wherein the slurry lift apparatus is selected from the group consisting of a progressive cavity pump, and electric submersible pump, and any combination thereof.

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

6. The method of claim 1, wherein the jet pump comprises an array of spray nozzles to further dilute the dense slurry or the diluted dense slurry.

7. The method of claim 3, the jet pump comprising a power fluid conduit and the gas lift apparatus further comprising a compressed fluid conduit.

8. The method of claim 7, wherein the compressed fluid conduit is configured in a manner selected from the group consisting of: adjacent to each of the producer pipe and the power fluid conduit, concentric with the producer pipe and adjacent to the power fluid conduit, concentric with the power fluid conduit and adjacent to the producer pipe, and concentric with each of the producer pipe and the power fluid conduit.

9. The method of claim 1, wherein the dense slurry contains from about thirty volume percent (30 vol%) to about 65 vol% sand concentration.

10. The method of claim 1, wherein the diluted dense slurry is lifted at a rate of between about 200 cubic meters per day (m³/d) to about 3,000 m³/d.

11. The method of claim 1, wherein the diluted dense slurry contains from about twenty- five volume percent (25 vol%) to about 50 vol% sand concentration.

12. The method of claim 1, wherein the diluted dense slurry is lifted at least about 250 feet through the producer pipe.

13. The method of claim 1, wherein the producer pipe has an inner diameter of from about 0.1 meters (m) to about 0.4 m.

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

15. The method of claim 5, wherein conditioning the subsurface reservoir comprises a fluidized in-situ reservoir extraction (FIRE) process.

16. The method of claim 1, wherein the power fluid is selected from the group consisting of water, a hydrocarbon solvent, a heated fluid, and any combination thereof.

17. The method of claim 3, wherein the gas is selected from the group consisting of nitrogen, air, flue gas, and any combination thereof.

18. The method of claim 1, wherein the jet pump is operated to induce cavitation in the diluted dense slurry to increase the mixing of the power fluid and the diluted dense slurry.

19. 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;

a jet pump incorporated into the well bore configured to inject a power fluid 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 dilute the dense slurry to form a diluted dense slurry; and a slurry lift apparatus configured to lift the diluted dense slurry through the producer pipe towards the surface of the earth.

20. The system of claim 19, wherein the slurry lift apparatus is a fluid lift apparatus utilizing a lift fluid, wherein the lift fluid is less dense than the diluted dense slurry.

21. The system of claim 20, wherein the lift fluid is a gas.

22. The system of claim 19, wherein the slurry lift apparatus is selected from the group consisting of a progressive cavity pump, and electric submersible pump, and any combination thereof.

23. The system of claim 19, further comprising a fluidized in-situ reservoir extraction (FIRE) system for conditioning the oil sand reservoir.

24. The system of claim 20, the jet pump comprising a power fluid conduit and the gas lift apparatus further comprising a compressed gas conduit.

25. The system of claim 24, wherein the compressed gas conduit is configured in a manner selected from the group consisting of: adjacent to each of the producer pipe and the power fluid conduit, concentric with the producer pipe and adjacent to the power fluid conduit, concentric with the power fluid conduit and adjacent to the producer pipe, and concentric with each of the producer pipe and the power fluid conduit.

26. The system of claim 23, the jet pump further comprising an array of spray nozzles configured to further dilute the dense slurry.

27. The system of claim 23, further comprising an additional slurry dilution conduit configured to permit flow of power fluid from the power fluid conduit to the producer pipe.

28. The system of claim 19, wherein the power fluid is selected from the group consisting of water, a hydrocarbon solvent, a heated fluid, and any combination thereof.

29. The system of claim 19, wherein the dense slurry is lifted at a rate of between about 200 cubic meters per day (m³/d) to about 3 ,000 m³/d.

30. The system of claim 19, wherein the diluted oil sand slurry is lifted at least about 250 feet through the producer pipe.

31. The system of claim 19, wherein the producer pipe has an inner diameter of from about 0.1 meters (m) to about 0.4 m.

32. The system of claim 19, wherein the dense slurry contains from about thirty volume percent (30 vol%) to about 65 vol% sand concentration.

33. The system of claim 19, wherein the diluted dense slurry contains from about twenty- five volume percent (25 vol%) to about 50 vol% sand concentration.

34. The system of claim 19, wherein the jet pump is operated to induce cavitation in the diluted dense slurry to increase the mixing of the power fluid and the diluted dense slurry.

35. The method of claim 1, wherein the flow can be redirected between the jet pump nozzle and a conduit opened into the well.