Patent Grant
9725999
Embodiments of the invention relate to methods and apparatus for recovery of hydrocarbons from geological formations. More particularly, embodiments provided herein relate to recovery of viscous hydrocarbons from geological formations.
There are extensive hydrocarbon reservoirs throughout the world. Many of these reservoirs contain a hydrocarbon, often called “bitumen,” “tar,” “heavy oil,” or “ultra heavy oil,” (collectively referred to herein as “viscous hydrocarbon”) which typically has viscosities in the range from 100 to over 1,000,000 centipoise. The high viscosity of these hydrocarbons makes it difficult and expensive to produce.
Each viscous hydrocarbon reservoir is unique and responds differently to the variety of methods employed to recover the hydrocarbons therein. Generally, heating the viscous hydrocarbon in-situ, to lower the viscosity thereof, has been employed to enhance recovery of these viscous hydrocarbons. Typically, these viscous hydrocarbon reservoirs would be produced with methods such as cyclic steam stimulation (CSS), steam drive (Drive), and steam assisted gravity drainage (SAGD), where steam is injected from the surface into the reservoir to heat the viscous hydrocarbon and reduce its viscosity enough for production.
However, some of these viscous hydrocarbon reservoirs are located under cold tundra or permafrost layers and may be located as deep as 1800 feet or more below the adjacent land surface. Current methods of production face limitations in extracting hydrocarbons from these reservoirs. For example, it is difficult, and impractical, to inject steam generated on the surface through permafrost layers in order to heat the underlying reservoir of viscous hydrocarbons, as the heat of the injected steam is likely to expand or thaw the permafrost. The expansion of the permafrost may cause wellbore stability issues and significant environmental problems, such as seepage or leakage of the recovered hydrocarbons at or below the wellhead.
Additionally, the current methods of producing viscous hydrocarbon reservoirs face other limitations. One such problem is wellbore heat loss of the steam, as the steam travels from the surface to the reservoir. Wellbore heat loss is also prevalent in offshore wells and this problem is exacerbated as the water depth and/or the well's reservoir depth increases. Where steam is generated and injected at the wellhead, the quality of the steam (i.e., the percentage of the steam which is in vapor phase) injected into the reservoir typically decreases with increasing depth as the steam cools on its journey from the wellhead to the reservoir, and thus the steam quality available downhole at the point of injection is much lower than that generated at the surface. This situation lowers the energy efficiency of the hydrocarbon recovery process and associated hydrocarbon production rates. Further, surface generated steam produces gases and by-products that may be harmful to the environment.
The use of downhole steam generators is known to address the shortcomings of injecting steam from the surface. Downhole steam generators provide the ability to produce steam downhole, prior to injection into the reservoir. Downhole steam generators, however, also present numerous challenges, including high temperatures, corrosion issues, and combustion instabilities. These challenges often result in material failures and thermal instabilities and inefficiencies.
Therefore, there is a continuous need for new and improved apparatus and methods for recovering heavy oil using downhole steam generation with improved thermal efficiency and minimal environmental impact.
Embodiments of the invention described herein relate to methods and apparatus for recovery of viscous hydrocarbons from subterranean reservoirs. In one embodiment, a method for recovery of hydrocarbons from a subterranean reservoir is provided. The method includes positioning a packer in an injector well, the packer having a mandrel extending therethrough, positioning a downhole steam generator to couple with the mandrel, flowing fuel, oxidant and water to the downhole steam generator to produce a combustion product, producing hydrocarbons through the one or more production wells, and removing the downhole steam generator from the injector well by disconnecting at least a portion of the downhole steam generator from the packer.
In another embodiment, a system for recovering hydrocarbons comprises a downhole steam generator for coupling with a packer in an injector well, an umbilical device coupled to the downhole steam generator for lifting or lowering the downhole steam generator in the injector well, a first shear point disposed between the downhole steam generator and the packer, and a second shear point disposed between the umbilical device and the downhole steam generator, wherein the first shear point has a shear strength that is different than a shear strength of the second shear point.
In another embodiment, an apparatus for recovering hydrocarbons is provided. The apparatus includes a downhole steam generator, and an umbilical device releasably coupled to the downhole steam generator by an interface module.
So that the manner in which the above-recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements disclosed in one embodiment may be beneficially utilized on other embodiments without specific recitation.
Embodiments of the invention relate to recovery of viscous hydrocarbons from subterranean reservoirs. Viscous hydrocarbons, as described herein, include hydrocarbons having viscosities in the range from about 100 centipoise (cP) to greater than about 1,000,000 cP. Embodiments of the invention as described herein may be utilized in subterranean reservoirs composed of non-porous or porous rock, such as shale, sandstone, limestone, carbonate, and combinations thereof. Embodiments of the invention may be utilized in enhanced oil recovery (EOR) techniques utilizing in-situ gas injection of a combustion product (e.g., hot gases) and/or a vaporization product (e.g., steam), chemical injection and/or in-situ flooding of chemical fluids (e.g., viscosity-reducing fluids such as carbon dioxide (CO2), nitrogen (N2), oxygen (O2), hydrogen (H2), and combinations thereof), microbial and/or particulate injection, and combinations thereof. Embodiments of the invention provide a downhole steam generator for injecting the combustion product, steam and/or other injectants into the reservoirs. The downhole steam generator as described herein is gravity-independent and may perform combustion, vaporization, and/or injection reliably in horizontal wells, vertical wells, or any well orientation therebetween.
Various fluids such as fuel, an oxidant, and water or steam, are provided to the burner 125 to provide an exhaust in the reservoir 115 composed of steam and combustion by-products, which pressurize and heat the reservoir 115. The reservoir 115 is divided into zones 130A-130E and curves 135A-135C overlay each of the zones 130A-130E. Curve 135A represents the gas-hydrocarbon ratio (e.g., gas-to-oil ratio (GOR)) present in the reservoir 115, curve 1358 represents viscosity of the hydrocarbon in the reservoir 115, and curve 135C represents the temperature of the reservoir 115. The EOR delivery system 105 provides an exhaust from the burner 125 to pressurize and heat the reservoir 115 in order to move hydrocarbons in the reservoir 115 toward the producer well 120 as shown by the arrow.
The reservoir management system 100 shown in
The burner 125 may be operable within an operating pressure range of about 300 pounds per square inch (psi) to about 1,500 psi, and up to for example 3,000 psi, or greater. The burner 125 may operate within a single pressure range or multiple pressure ranges, such as about 300 psi to about 3,000 psi, depending on the pressure of the producing reservoir. Operational depths of the EOR delivery system 105 include about 2,000 feet to about 10,000 feet. For example, operational depths of the EOR delivery system 105 include about 2,500 feet to about 8,500 feet at pressures of about 500 pounds per square inch absolute (psia) to about 2,500 psia. For example, steam from the EOR delivery system 105 at temperatures of about 500 degrees Fahrenheit (F) to about 650 degrees F. may be utilized in virgin reservoirs at depths of about 2,500 feet to about 5,500 feet and at a pressure of about 1,100 psia to about 2,500 psia. Steam from the EOR delivery system 105 at temperatures of about 425 degrees F. to about 625 degrees F. may be utilized in partially depleted reservoirs at depths of about 2,500 feet to about 8,500 feet and at a pressure of about 750 psia to about 2,500 psia. Gas mixes to the burner 125 may include enriched air (e.g., about 35% to about 95% O2) as well as some fraction of a viscosity-reducing gas or gases in some embodiments. For example, an oxidant comprising enriched air may be provided to the burner 125 in a stoichiometric ratio such that a great portion of the oxidant is combusted. In another example, an oxidant comprising enriched air with an O2 content greater than the stoichiometric ratio may be provided to the burner 125 to provide surplus O2 in the reservoir 115. The surplus O2 may be mixed with reduced-viscosity hydrocarbons within the reservoir 115 and combusted using the surplus O2. In another example, an oxidant comprising about 95% O2 may be combined with CO2. This mixture may produce surplus O2 that may be combusted with reduced-viscosity hydrocarbons within the reservoir 115. A portion of the surplus CO2 may be separated from the recovered hydrocarbons and recycled.
Water may be supplied to the burner 125 at a flow rate required to generate the desired volume and quality of steam needed to optimize production from the reservoir 115. The flow rates may be as low as about 200 barrels per day (bpd) to about 1,500 bpd, or greater. The burner 125 may be operable to generate steam having a steam quality of about 0 percent to about 80 percent, or up to 100 percent. Water provided to the burner 125 may be purified to less than about one part per million (ppm) of total dissolved solids in order to produce higher quality steam. The burner 125 may be operable to generate steam downhole at a rate of about 750 bpd to about 3,000 bpd, or greater. The burner 125 is also capable of a wide range of flow rate and pressure turndown, such as ratios of about 16:1 to about 24:1. The burner 125 may be operable with a pressure turndown ratio of about 4:1, e.g. about 300 psi to about 1,200 psi, for example. A pressure turndown ratio of about 6:1 (up to about 1,800 psi or more) is possible. The burner 125 may be operable with a flow rate turndown ratio of about 4:1, e.g. about 375 bpd up to about 1,500 bpd or more of steam for example. The exhaust gases injected into the reservoir 115 using the burner 125 may include about 0.5 percent to about 5 percent excess oxygen.
The EOR delivery system 105 may be operable to inject heated viscosity-reducing gases, such as nitrogen (N2) and/or carbon dioxide (CO2), oxygen (O2), and/or hydrogen (H2), into the reservoir 115. N2 and CO2, both being a non-condensable gas (NCG), have relatively low specific heats and heat retention and will not stay hot very long once injected into the reservoir 115. At about 150 degrees C., CO2 has a modest but beneficial effect on the hydrocarbon properties important to production, such as specific volume and oil viscosity. Early in the recovery process, the hot gases will transfer their heat to the reservoir 115, which aids in oil viscosity reduction. As the gases cool, their volume will decrease, reducing likelihood of override or breakthrough. The cooled gases will become more soluble, dissolving into and swelling the oil for decreased viscosity, providing the advantages of a “cold” NCG EOR regime. NCG's reduce the partial pressure of both steam and oil, allowing for increased evaporation of both. This accelerated evaporation of water delays condensation of steam, so it condenses and transfers heat deeper or further into the reservoir 115. This results in improved heat transfer and accelerated oil production using the EOR delivery system 105. The benefits of utilizing the burner 125 downhole may facilitate higher gas solubility, which further decreases viscosity, increases mobility, and accelerates oil production from the reservoir 115. For example, hot exhaust gases (e.g., steam, CO2, and/or non-combusted O2) from the burner 125 heats the oil in the reservoir as well as causing the viscosity of the oil in the reservoir to decrease. The heated gases thin the oil in the reservoir, which makes the oil more soluble to additional viscosity-reducing gases. The increased gas solubility may provide a further reduction in viscosity of the oil in the reservoir. The addition of the heated gases to the steam also results in a higher latent heat of the steam, and deeper (or greater) penetration of the steam into the reservoir 115 due to steam vapor pressure reduction. The combination accelerates oil production in the reservoir 115.
The volume of exhaust gas from the burner 125 may be around 3 thousand cubic feet (of gas) per barrel (Mcf/bbl) of steam or more, which may facilitate accelerated oil production in the reservoir 115. When the hot gas moves ahead of the oil it will quickly cool to reservoir temperature. As it cools, the heat is transferred to the reservoir, and the gas volume decreases. As opposed to a conventional low pressure regime, the gas volume, as it approaches the production well, is considerably smaller, which in turn reduces the likelihood of, and delays, gas breakthrough. For example, N2 and CO2, as well as other gases, may breakthrough ahead of the steam front, but at that time the gases will be at reservoir temperature. The hot steam from the EOR delivery system 105 will follow but will condense as it reaches the cool areas, transferring its heat to the reservoir, with the resultant condensate acting as a further drive mechanism for the oil. In addition, gas volume decreases at higher pressure (V is proportional to 1/P). Since the propensity of gas to override is limited at low gas saturation by low gas relative permeability, fingering is controlled and production of oil is accelerated.
The zone 130A is the volume of the reservoir 115 adjacent the injector well 110. The zone 130A may include a primary combustion region where initial pressurization is provided. As a result of this combustion, the temperature of the viscous hydrocarbon is increased, and its viscosity is decreased, in the zone 130A. After some processing time, the hydrocarbons in zone 130A will be depleted due to the steam front provided by the burner 125. The depletion of hydrocarbons in the zone 130A is due to one or a combination of movement of the hydrocarbons towards the producer well 120 and consumption of the hydrocarbons by combustion. For example, residual oil behind the steam front may be consumed by combustion with excess oxygen provided to the reservoir 115 during the EOR process. Zone 1308 may include an active combustion region where temperature peaks and viscosity decreases. The temperature in the zone 130B may be about 300 degrees Celsius (C) to about 600 degrees C. in one embodiment. In the zone 130B, temperature reaches a peak which reduces the viscosity of the hydrocarbons. Surplus oxygen (O2) may also be injected into the reservoir 115 by the burner 125 which may be utilized for in-situ oxidation of any residual oil that is bypassed by the steam front.
Zone 130C is a steam region where the steam front formed by the zones 130A and 130B may be found. Steam provided in the zone 130C moves towards the producer well 120, which helps reduce oil viscosity ahead of the zone 130C and also pushes hydrocarbons towards the producer well 120. In zone 130D, viscosity rises as the reservoir temperature decreases, but this is countered by the dissolution of cool NCG gases in the oil bank ahead of the steam front. This area reaches the highest GOR encountered in the reservoir 115. Temperatures in zone 130D may be about 100 degrees C. In zone 130E, the producer well 120 is surrounded by oil that has been pushed ahead of the combustion process and is at relatively high viscosity, compared to other higher temperature regions. However the viscosity is still much lower than at original reservoir conditions. In one aspect, the mobility of the hydrocarbons in the reservoir 115 is increased due to various heating regimes, interactions with viscosity-reducing gases, and other energy production and/or chemical reactions provided by the EOR delivery system 105. For example, the hydrocarbons and/or the reservoir 115 may be heated by direct heating from the burner 125 and/or combustion with residual hydrocarbons. In portions of the reservoir management system 100, free energy is released due to a phase change, which provides heat that is absorbed by the hydrocarbons and/or the reservoir 115. Further, viscosity of the hydrocarbons is reduced by interaction with viscosity-reducing gases that are provided to the reservoir by the EOR delivery system 105.
In operation, fuel and an oxidant is provided to the downhole steam generator 220 to generate an exhaust gas. The fuel supplied to the burner head assembly 230 may include natural gas, syngas, hydrogen, gasoline, diesel, kerosene, or other similar fuels. The fuel and oxidant are ignited in the combustion chamber 235. In one mode of operation, the fuel is combusted in the downhole steam generator 220 to produce the exhaust gas without the production of steam. When steam is preferred as an exhaust gas, water, or in some instances saturated steam (i.e., a two-phase mixture of liquid water and steam), is provided to the vaporization chamber 240 where it is heated by the combustion of the fuel and oxidant in the combustion chamber 235 to produce high quality steam therein. The exhaust gas produced by the reaction in the downhole steam generator 220 flows through an upper tailpipe 245A and a lower tailpipe 245B before injection into the reservoir 115. The upper tailpipe 245A and the lower tailpipe 245B are tubular conduits or members that may be a part of the downhole steam generator 220. Injectants, such as O2, and other viscosity-reducing gases, such as H2, N2 and/or CO2, as well as microbial particles, enzymes, catalytic agents, proppants, markers, tracers, soaps, stimulants, flushing agents, nanoparticles, including nanocatalysts, chemical agents or combinations thereof, may be provided to the downhole steam generator 220 and mixed with the exhaust gas, which is provided to the reservoir 115 through the lower tailpipe 245B. Alternatively, a liquid or gas, including but not limited to viscosity-reducing gases, microbial particles, nanoparticles, or combinations thereof, may be injected into the reservoir 115 through the combustion chamber 235 when the downhole steam generator 220 is not producing steam. Alternatively or additionally, injectants, such as O2, and other viscosity-reducing gases, such as H2, N2 and/or CO2, as well as microbial particles, nanoparticles, or combinations thereof, may be provided to the reservoir 115 via the lower tailpipe 245B through a separate conduit (shown in
In some embodiments, the downhole steam generator 220 includes a sealing device, such as a packer 250. The packer 250 may be utilized to bifurcate the inner bore 210 between a portion of the downhole steam generator 220 and the wellbore casing 205 into an upper volume 255A and a lower volume 255B. The packer 250 is utilized as a fluid and pressure seal. The packer 250 may also be utilized to support the weight of the downhole steam generator 220 in the injector well 110. As shown in
In some embodiments, a liquid or a gas may be provided from a fluid source 258 to flow a packer fluid 270A to the upper volume 255A. The packer fluid 270A may be utilized to conduct heat from the downhole steam generator 220. The packer fluid 270A may also facilitate minimizing pressure losses to the upper volume 255A from the reservoir 115. In one embodiment, the packer fluid 270A may be a liquid or a gas provided from a port 272 disposed on the umbilical device 225. The liquid or gas provided in the upper volume 255A may be pressurized to a pressure greater than the pressure in the lower volume 255B. While some portions of the wellbore casing 205 may be heated by combustion in the downhole steam generator 220, the packer fluid 270A conducts heat from the downhole steam generator 220, which may minimize heating of rock and/or permafrost that surrounds the wellbore casing 205. The packer 250 may also be utilized to prevent or fluid losses to the upper volume 255A of the inner bore 210 from the lower volume 255B. The packer 250 may be provided with the packer fluid 270A suitable to withstand temperatures generated by the use of the downhole steam generator 220. In one embodiment, the packer fluid 270A is a thermally conductive liquid with a high boiling point and viscosity. The packer fluid 270A may comprise a gel-type additive for convection control, brine, corrosion inhibitors, bromides, formates, halides, polymers, O2 scavengers, anti-bacterial agents, or combinations thereof, as well as other liquids. Additionally, the packer fluid 270A may be flowed into and out of the upper volume 255A (i.e., circulated).
The fluid source 258 may facilitate heat exchange to remove heat from the packer fluid 270A prior to flowing the fluid into the upper volume 255A. In one embodiment, a dual-phase packer fluid may be used in the upper volume 255A. The dual-phase packer fluid includes the packer fluid 270A as well as a pressurizing fluid 270B disposed above the packer fluid 270A. The pressurizing fluid 270B may be a gas, such as N2, an inert gas or gases, or combinations thereof. The pressurizing fluid 270B may comprise a gas blanket disposed in the upper portion of the wellbore casing 205 for boiling point control (i.e., prevent boiling) of the packer fluid 270A. The pressurized fluid 270B may be provided to the upper volume 255A from the fluid source 258. The pressurizing fluid 270B may be pressurized to a pressure greater than the pressure in the lower volume 255B. A latch mechanism 280 may be provided between the downhole steam generator 220 and the expandable portion 268. The latch mechanism 280 may be a temporary connector between the packer 250 and the upper tailpipe 245A of the downhole steam generator 220. The latch mechanism 280 may be equipped with shear pins to facilitate disconnection of the downhole steam generator 220 when removing the downhole steam generator 220 from the injector well 110.
Over-pressuring the upper volume 255A is utilized to prevent leakage of liquids or gases from the lower volume 255B into the upper volume 255A. The liquid or gas provided in the upper volume 255A may, by thermal conduction, assist in cooling the upper section of the generator apparatus by drawing some thermal energy up away from the downhole steam generator 220 and dispersing it into the extended volume of the well above the downhole steam generator 220. This extended heat transfer may lower the temperature at the interface with the packer fluid to prevent boiling of the packer fluid when exposed to temperatures generated when the downhole steam generator 220 is in use. The gas provided in the upper volume 255A may be air, N2, CO2, helium (He), argon (Ar), other suitable coolant fluids, and combinations thereof. Alternatively or additionally, a heat sink 256 may be placed above the downhole steam generator 220 to dissipate the heat energy at the portion of the wellbore casing 205 proximate the upper end of the downhole steam generator 220. The heat sink 256 may be used to dissipate heat from the downhole steam generator 220 and/or supporting members that may be in thermal communication with the downhole steam generator 220. One or both of the coolant and the heat sink 256 are utilized to maintain a lower temperature on the upper end of the downhole steam generator 220. The heat sink 256 may be a combination of solids, liquids, or gases, which are used to reduce the temperature of any equipment above the downhole steam generator 220. The EOR delivery system 105 may also include a block 252 that is positioned between the umbilical device 225 and the downhole steam generator 220. The block 252 may be a mass of dense material, such as a metal, that facilitates lowering of the downhole steam generator 220 into the wellbore casing 205. The downhole steam generator 220 may also include a sensor package 271. The sensor package 271 may include one or more sensors coupled to the downhole steam generator 220, including other portions of the EOR delivery system 105. The sensor package 271 may be utilized to monitor one or a combination of pressure, flow, viscosity, density, inclination, orientation, acoustics, fluid (gas or liquid) levels, and temperature within the injector well 110 to facilitate control of the downhole steam generator 220 and/or the EOR delivery system 105.
As an alternative completion process for the downhole steam generator 220, one or more strings of tubing may be utilized to lower the downhole steam generator 220 in the injector well 110. Fuel, oxidant and water may be provided to the downhole steam generator 220 through the one or more strings of tubing. Individual signal transmission devices, such as wires or optical fibers may be coupled to the downhole steam generator 220 and lowered into the injector well 110 to facilitate control of the downhole steam generator 220. In one aspect, only two tubing strings may be utilized. One tubing string may be used for the fuel and one tubing string may be used for the oxidant. Water may be provided to the inner bore 210 of the injector well 110 above the downhole steam generator 220. The water may be routed to the combustion chamber 235 for producing steam that is provided to the reservoir 115.
The central conduit 305 may be utilized to flow air, enriched air, oxygen, CO2, N2, or combinations thereof, to the downhole steam generator 220. The central conduit 305 may be utilized to supply an oxidant to the burner head assembly 230 to assist in the combustion and/or vaporization reaction in the downhole steam generator 220. Alternatively or additionally, the central conduit 305 may supply oxidizing gases in excess of the molar amount necessary for the combustion reaction in the downhole steam generator 220. In this manner, oxidizing gases, such as air, enriched air (air having about 35% oxygen), 95 percent pure oxygen, and combinations thereof. A first conduit 310 may be utilized for flowing a fuel gas or liquid to the burner head assembly 230. The fuel supplied to the burner head assembly 230 may include natural gas, syngas, hydrogen, gasoline, diesel, kerosene, or other similar fuels. A second conduit 315 may be utilized for flowing water, or saturated steam, to the vaporization chamber 240 of the downhole steam generator 220. A third conduit 320 and a fourth conduit 325 may be utilized for flowing a viscosity-reducing gas, such as CO2, N2, O2, H2, or combinations thereof, to the downhole steam generator 220 and/or the lower volume 255B of the inner bore 210. A fifth conduit 330 may be utilized for flowing particles to the downhole steam generator 220 and/or to the lower volume 255B of the inner bore 210. The particles may include catalysts, such as nanocatalysts, microbes, or other particles and/or viscosity reducing elements. One or more control conduits 335 may be provided on the body 300 for electrical signals controlling igniters (not shown) and/or valves (not shown) controlling fluid flow within the downhole steam generator 220. The control conduits 335 may be wires, optical fibers, or other signal carrying medium that facilitates signal communications between the surface and the downhole steam generator 220. A sensor 340 may also be provided in or on the body 300. The sensor 340 may be utilized to monitor one or a combination of pressure, flow, viscosity, density, inclination, orientation, acoustics, fluid (gas or liquid) levels, and temperature. For example, the sensor 340 may be utilized to determine temperatures within the wellbore casing 205, pressures within the wellbore casing 205, depth measurements, and combinations thereof. The umbilical device 225 may be a continuous rigid or semi-rigid (i.e., flexible) support member as shown in
The downhole steam generator 220 may be dimensioned to fit within any typical production casing and/or liner. The downhole steam generator 220 may be dimensioned to fit casing diameters of about 5½ inch, about 7 inch, about 7⅝ inch, and about 9⅝ inch sizes, or greater. The downhole steam generator 220 may be about 8 feet in overall length. The diameter of the downhole steam generator 220 may be about 5.75 inches in one embodiment. The downhole steam generator 220 may be compatible with a packer 250 of about 7 inch to about 7⅝ inch, to about 9⅝ inch sizes. The downhole steam generator 220 may be made of carbon steel, or corrosion resistant materials such as stainless steel, nickel, titanium, combinations thereof and alloys thereof, as well as other corrosion resistant alloys (CRA's). The downhole steam generator 220 and the umbilical device 225 may be utilized in casing at about a 20 degree to 45 degree angle of inclination. However, the modular aspect of the umbilical device 225 and the compact size of the downhole steam generator 220 enables use of the EOR delivery system 105 in casing at any angle of inclination.
As one option, carbon steel casing may be utilized for the entire wellbore, with a portion of the casing proximate the depth location of the packer, and downstream therefrom, cemented in high temperature cement. This option may be the least expensive due to the costs of the carbon steel casing relative to CRA casing. This option may be utilized where the completion procedure is estimated to be short (less than about 2-3 years) as prolonged exposure of the carbon steel casing to the corrosive environment below the packer may cause the wellbore to prematurely fail.
As another option, carbon steel casing may be used from the surface to a location slightly upstream from the depth of the packer, and CRA casing may be run from that location to the bottom of the wellbore. The portion of the casing proximate the location of the packer, and downstream therefrom, may be cemented in high temperature cement. This option may require only about two joints (lengths) of CRA casing and the remainder being carbon steel casing. This option may provide longer usable life of the wellbore as the portion of the casing exposed to the corrosive environment below the packer is protected from corrosion. This option may also save costs as the majority of the wellbore consists of carbon steel casing.
Another option includes utilizing carbon steel casing from the surface to a location slightly upstream from the depth of the packer, and using carbon steel casing with a CRA cladding on the inside diameter of the carbon steel casing from that location to the bottom of the wellbore. The portion of the CRA clad carbon steel casing proximate the location of the packer, and downstream therefrom, may be cemented in high temperature cement. This option may provide longer usable life of the wellbore as the portion of the casing exposed to the corrosive environment below the packer is protected from corrosion by the CRA cladding. This option may also save costs as the wellbore consists of entirely of carbon steel casing with the portion proximate and below the packer having a CRA cladding, which is less expensive than CRA casing.
Step 430 includes positioning the downhole steam generator in the casing. Step 430 may include multiple run-ins. A first run-in may consist of positioning the packer 250 in the wellbore. The packer 250 may be lowered into the well on the end of a drillpipe, set, and actuated to bifurcate the inner bore 210 of the wellbore casing 205. While drillpipe is utilized as an example for installation and/or removal of portions of the EOR delivery system 105, other tubular members such as coil tubing or a wire-type strings may also be used. Once set, the drillpipe is removed. This leaves an upper extension of the packer 250 upon which the downhole steam generator 220 is set. A second run-in may consist of positioning the downhole steam generator uphole of the packer 250. During this step, the umbilical device 225 will be attached to the downhole steam generator 220, which assists in supporting and positioning of the downhole steam generator 225. The downhole steam generator 220 and an interface module (UMSCI module 926 (shown in
An additional step may be provided prior to step 430, wherein the combustion chamber 235 is purged. For example, an inert gas, such as nitrogen or argon, may be flowed into the combustion chamber 235 prior to start-up so the system may be started in known conditions, and especially a state wherein the combustion chamber 235 is filled with inert gases. The mixture of fuel, oxidant and water determines the ignition reaction. A safe and controlled start-up mixture is both burner-specific and reactant-specific. Flushing with inert gas provides a known initialization point to which fuel, oxidant and water may be introduced in a controlled and prescribed manner.
Step 440 includes operation of the downhole steam generator to facilitate viscosity reduction of the hydrocarbons in the reservoir. In one mode of operation, the downhole steam generator 220 provides heat and pressure to the reservoir via steam generation, production of hot exhaust gases, and/or fluid injection, with or without a combustion reaction in the downhole steam generator 220. For example, heat may be provided by steam generation in the downhole steam generator 220. In this mode of operation, steam, as well as exhaust gases, is flowed to the reservoir. In another example, heat may be provided by combusting fuel within the downhole steam generator 220 without steam production. This mode produces an exhaust gas that heats the reservoir. The exhaust gas may also be utilized for pressurization of the reservoir. Pressurization may also include flowing injectants, such as H2, N2 and/or CO2, as well as microbial particles, enzymes, catalytic agents, proppants, markers, tracers, soaps, stimulants, flushing agents, nanoparticles, including nanocatalysts, chemical agents or combinations thereof to the reservoir. In one example of operation, the injectants may be provided with or without steam and/or exhaust generation by the downhole steam generator 220.
An optional step 435 may include filling the casing above the packer with a fluid to facilitate thermal insulation and/or maintenance of pressure in the casing annulus above the packer. A blanket gas may be used for additional pressure control.
After a time of operation during step 440, the downhole steam generator and/or the packer may need refurbishment. A target refurbishment time may be about three years of utilizing the EOR delivery system 105. After this period of time, production of hydrocarbons from the reservoir may decline. If production declines below a margin that defeats profitability, then the EOR process is ceased, as shown in step 450, and the reservoir may be shut-in. If the production is above marginal production, then the process proceeds to step 460, which includes refurbishment of the EOR delivery system 105. Refurbishment may include pulling the downhole steam generator out of the wellbore, inspection, and replacement of worn parts of the generator. The packer may also be inspected and refurbished/replaced if needed during this step. Once the downhole steam generator and/or packer is serviced, the process may repeat steps 430 and 440.
In use, the EOR operation 500 may commence after the injector well 110 is drilled and the downhole steam generator 220 is positioned in the wellbore of the injector well 110 according to the installation/completion process 400 described in
The fuel source 535 and/or the steam precursor source 540 may be stand-alone storage tanks that are replenished on-demand during the EOR process. Alternatively, the fuel source 535 and/or the steam precursor source 540 may utilize on-site fluids, such as recycled water and combustible fluids from the oil produced from the reservoir 115. For example, the oil recovered from the producer well 120 may undergo a separation process in a separator unit to remove water and other fluids from the recovered oil. The recovered oil may be provided to a first treatment facility 560A where it is treated and flowed to the wellhead 200 through conduit 555. Excess water may be diverted and stored in the steam precursor source 540 until needed. Likewise, the oil recovered from the producer well 120 may be provided to a second treatment facility 560B. The second treatment facility 560B may be utilized to separate fluids, such as gases or liquids that may be used as fuel (e.g., hydrogen, natural gas, syngas). The second treatment facility 560B may also be equipped to separate the oil into fractions of gasoline or diesel for use as a fuel in the downhole steam generator 220. The recycled fuel fluid(s) may be flowed to the wellhead 200 through conduit 555. Excess fuel fluid(s) may be diverted and stored in the fuel source 535 until needed.
The viscosity-reducing source 545 may deliver injectants, such as viscosity reducing gases (e.g., N2, CO2, O2, H2), particles (e.g., nanoparticles, microbes) as well as other liquids or gases (e.g., corrosion inhibiting fluids) to the downhole steam generator 220 through the wellhead 200 through conduit 565. The viscosity-reducing source 545 may be an import pipeline and/or a stand-alone storage tank(s) that are replenished on-demand during the EOR process. Alternatively, the viscosity-reducing source 545 may be supplemented and/or replenished using recycled material from the oil produced in from the producer well 120. For example, the second treatment facility 560B may be configured to separate gases (e.g., viscosity-reducing gases) and/or particles from the recovered oil. The recovered gases and/or particles may be flowed to the wellhead 200 by conduit 565. Excess gases and/or particles may be diverted and stored in the viscosity-reducing source 545 until needed.
While not shown, the second producer well 507 may be in communication with the second surface facility 510 or have its own production support systems. Any recycled materials utilized by the first treatment facility 505 may be provided by oil recovered by one or both of the producer wells 120 and 507.
The EOR operation 500 utilizing the EOR delivery system 105 as described herein enables a variety of different reservoir regimes. Additionally, the EOR delivery system 105 is highly configurable allowing EOR processes on a wide variety of reservoir types enabling recovery of about 30 percent to about 100 percent more oil than surface steam. One regime includes a high pressure process as described in
In use, the EOR operation 600 may commence after the injector well 110 is drilled and the downhole steam generator 220 is positioned in the wellbore of the injector well 110 according to the installation/completion process 400 described in
The recovered oil is flowed to a primary separator unit 712 from the producer well 120. The primary separator unit 712 processes the oil to separate gases and liquids. The gases are flowed to a dehydration unit 714 and the liquid is flowed to a liquid separator unit 716. The liquid separator unit 716 separates water from the liquid provided from the primary separator unit 712 and the dehydration unit 714 removes moisture from the gases provided from the primary separator unit 712. The gases may then be flowed to a first process unit 718 where bulk N2 may be removed from the gases. Alternatively or additionally, the gases may be flowed to a second gas process unit 720 where CO2 and/or N2 may be removed from the gases. A fuel gas may be produced after treatment in one or more of the dehydration unit 714, the first gas process unit 718, and/or the second gas process unit 720. The fuel gas may include an energy content of about 220 British thermal units (BTU's) to about 300 BTU's, or greater, for example about 260 BTU's. The fuel gas may be directly utilized, marketed, or stored in a storage facility 722 and subsequently marketed. In one embodiment, a portion of the fuel gas is provided to the downhole steam generator 220 to facilitate steam generation. In embodiments where one or both of the first gas process unit 718 and the second gas process unit 720 are utilized, separated gases, such as N2 and/or CO2 may be provided to the EOR delivery system 105. The separated gases may include sour gas (e.g., gas containing significant amounts of hydrogen sulfide (H2S)), an acid gas (e.g., a gas that contains significant amounts of acidic gases such as CO2 and/or H2S). Alternatively or additionally, surplus separated gases, such as CO2, may be stored in a storage facility 726 and subsequently marketed or exported to adjacent oilfields for injection in another EOR process. Referring again to the liquid separator unit 716, recovered oil may be stored in a storage facility 728 and subsequently marketed. Alternatively, if the reservoir 115 is in fluid communication with a pipeline system 724, imported oil may be injected back into the reservoir 115. The injected oil may be utilized as a diluent in the produced fluids from the production wells serving reservoir 115. Water recovered from the oil may be recycled and provided to a water treatment unit 730 where the water is filtered, de-sanded, and processed. Treated water is provided to the downhole steam generator 220 for steam production while unsuitable water and filtered debris is disposed.
During operation of the EOR delivery system 105 as described in
The EOR delivery system 900 includes a wellhead 200 coupled to the injector well 110. The EOR delivery system 900 also includes a downhole steam generator 220 coupled to an umbilical device 225. The downhole steam generator 220 is similar to the embodiments shown in
Wellhead
The wellhead 200 provides the transition from the surface environment to the controlled and sometimes hostile downhole environment. While the wellhead 200 has requirements of different dimensions and pressures, the use of a common (e.g., fit-for-purpose) set of fluid and electrical connections provides a means for optimization of cost and configuration control of mechanical and electrical devices from the surface equipment. In one embodiment, the wellhead 200 comprises an adapter block 905 having multiple manifolds and electrical bulkheads that couple to a wellhead flange 910. The adapter block 905 includes an interface for connections to power and telemetry systems 915A as well as fluid systems 915B (e.g., fuel, oxidant and water). The wellhead flange 910 includes interfaces for the manifolds and electrical bulkheads and may be any diameter that facilitates use on different wellhead diameters. The wellhead flange 910 may include multiple interchangeable flanges of diameters selected so as to be applicable to a range of wellhead diameters and connection configurations. In this manner, the adapter block 905, for a particular wellhead configuration, can be assembled from multiple modular assemblies and built up in a layered sandwich configuration with each layer providing electrical, hydraulic, power, etc. connections to the downhole assembly. The entire assembly may be tailored to fit the particular wellhead diameter and the number and kind of fluid and electrical connections. The wellhead 200 may also include sensor taps 918 for monitoring sensors and borehole fluid placement, circulation and treatment at the wellhead 200. Additionally, an umbilical connector block 920 may be included in the wellhead 200. The umbilical connector block 920 provides the connection points between the umbilical device 225 and the wellhead hydraulic and electrical manifold. The umbilical connector block 920 may be likewise adapted to the particular casing size and configuration. The umbilical connector block 920 may also be used to center or offset the umbilical device 225 within the wellbore casing 205.
In one embodiment, the wellhead 200, which includes the adapter block 905, a wellhead flange 910 for the particular wellhead diameter, and the umbilical connector block 920, comprises a wellhead interface 922 for a particular diameter of casing. This wellhead interface 922 allows use of conventional deployment equipment and methodology to place and retrieve the downhole equipment. In particular, this includes a standard set of holding slips 924, an umbilical distribution reel 925, and extrusion and forming equipment. Additionally, the interface between the umbilical device 225 to the umbilical connector block 920 and thence to the wellhead 200 may be configured so as to support the umbilical device 225 while it is being deployed, manipulated and/or connected or disconnected to the wellhead 200. In most cases, a set of grips or slips are used to hold the upper section of the umbilical device 225. A strengthened outer sheath on the umbilical device 225 provides a robust mechanical surface for gripping by such slips. Thus, the wellhead interface 922 allows use of conventional operational techniques for running-in and retrieval of the downhole equipment, which decreases the need for specialized equipment and minimizes running-in and retrieval time, both of which decrease costs.
Umbilical, Manifold, Sensor, Control and Interconnection (UMSCI) Module
The EOR delivery system 900 includes an umbilical, manifold, sensor, control and interconnection (UMSCI) module 926 (e.g., an interface module) which provides an attachment interface and transition point between the umbilical device 225 and the body of the downhole steam generator 220. The UMSCI module 926 contains the electrical interface and conditioning circuitry for various sensors 928 which may be part of the sensor package 271 described in
As a modular component, the components of the UMSCI module 926 become interchangeable and standardized and thus may be used, as needed, for many different well configurations and geometries. Such re-use includes re-use of components within different diameter housings, different manifold geometry as tailored for the delivery of different mixtures of fuel, oxidants, water, injectants, etc., adaptation to differing umbilical device geometries and conduit configurations, configuring via software or hardware connection for all possible multiple sensor configurations, etc. The modularity of the UMSCI module 926 is also enhanced by the configuration of an umbilical interface block 936A (upper connection interface) and a generator interface block 936B (lower connection interface) that are disposed on opposing ends of the UMSCI module 926. Each of the upper and lower connection interfaces may be designed to a standard form factor that allows re-use of the umbilical interface block 936A and the generator interface block 936B.
The interior volume 962 of the UMSCI module 926 may be utilized for conduits 970A, 970B for flowing fluids therethrough to the downhole steam generator 220 (shown in
For a particular well, the diameter of the wellbore casing 205 and the output requirements of the downhole system will require tailoring the dimensions of the various system components. For example, the dimensions of the water, oxidant and fuel delivery conduits will be dependent upon the downhole steam generator 220 operational conditions, such as depth, casing diameter, steam output, fuel composition, oxidant type, etc. However, other components—such as sensors and associated conditioning electronics—may have the same dimensions regardless of operational condition and therefore one common configuration may be employed over several differing operational conditions and dimensional situations. In one embodiment, such dimension-independent components may be contained in the pressure-controlled chamber 968 in the center of the UMSCI module 926 while dimension-dependent components may be positioned in the surrounding interior volume 962 within the housing 964. For wells with larger casing diameters, the housing 964 may be expanded to accommodate larger feed lines for fuel, oxidant, water, injectants, viscosity-reducing fluids and the like. In this manner, the pressure-controlled chamber 968 may share common dimensional configurations and may used with multiple sizes of housing 964. The adapter module 954 may be sized to readily interconnect with the housing 964 sizes and, when used together with other shared dimensional components and connection interfaces, enable re-use in various well geometries and output performance requirements.
Umbilical Device
The EOR delivery system 900 includes the umbilical device 225 between the wellhead 200 and the UMSCI module 926. The umbilical device 225 comprises an inner bundle of multiple fluid/gas conduits (e.g., pipes or hoses), metallic electrical wires (e.g., twisted, shielded or otherwise bundled), fiber optic cables, and strength members 345 (e.g., wire rope) described in
Because of the complexities of the inner core and the mechanical stresses experienced by the umbilical device 225, the uphole end and the downhole end utilize the wellhead interface 922 and the umbilical interface block 936A, respectively, as an integral termination connector (shown as termination bulkhead 958 in
In one embodiment, a connector assembly 938 for connecting the umbilical device 225 to the UMSCI module 926 may include the umbilical interface block 936A and a spear interface 940. The spear interface 940 may include a tapered or ledged portion for support of the umbilical device 225 or whole system suspended in the well. Shear pins 941 may be provided to facilitate disconnection of the umbilical device 225 from the components below. The connector assembly 938 may also include a fishing grip surface 943 to facilitate retrieval of components remaining in the wellbore casing 205 after disconnection of the umbilical device 225 from the top of the UMSCI module 926. The connector assembly 938 may include support features and components that temporarily fit to the wellhead 200 during deployment, rig-up and retrieval and allow connection/disconnection of the umbilical device 225 to the UMSCI module 926. Like the common, modular wellhead elements, the connector assembly 938 may include a common (e.g., standard) modular configuration permitting the passage of fluid, electrical and optical signals using a standardized configuration of electrical and fluid connectors and fittings. For example, the connector assembly 938 may include electrical connectors and pressure bulkheads, and pressure sealing connections that facilitate communication of fluids and electrical signals to the UMSCI module 926.
In the event that the umbilical device 225 cannot be transported and/or manufactured in the total length required to reach from the surface to the downhole steam generator 220, it may be necessary to include intermediate modular terminations with the same features as described with respect to the wellhead interface 922 and the connector assembly 938, including the ability to support the downhole components in the well during deployment as well as allow for field coupling and decoupling. At each end of the umbilical device 225 will be a standardized connection that allows for passage of the fuel, oxidant, water, injection fluids, electrical and optical power and sensors, etc. For example, elements such as the adapter module 954, the umbilical interface block 936A and/or the termination bulkhead 958 form a strong connection to the internal strength members of the umbilical device 225. The sheath 957 provides an outer surface for supporting the umbilical device 225 while hanging in the well via slips during deployment and retrieval of each section.
The integrated umbilical device 225 as described above is only one of several means for providing the conduits from the wellhead 200 down to the subsystem of the downhole steam generator 220. In another configuration, individual or partial bundles of pipes, conduits, electrical wiring, etc. are combined at the wellhead 200 and then lowered into the well.
Downhole Steam Generator
The downhole steam generator 220 may be customized for a desired operating performance in different well configurations. This customization includes fluid/gas flow, number/placement of monitoring sensors 928, overall outside diameter and length, and mechanical strength. The use of a standardized upper head 942 (e.g., upper portion of the burner head assembly 230) provides a means for interchangeability of different downhole steam generators, depending upon operational needs, without requiring re-engineering of the supporting components. Furthermore, the downhole steam generator 220 may be modular such that the burner head assembly 230, the combustion chamber 235 and the vaporization chamber 240 may be mixed and matched according to operational needs. Thus, various performance parameters can be adjusted simply by exchange/modification/customization of one or more of the components of the downhole steam generator 220. In addition to tailoring to specific operational needs, the repair and maintenance of the system is augmented with the ability to remove and replace standard components. Furthermore, with standardized components, the ability for monitoring to predict reliability and preventative maintenance schedules is greatly enhanced. Additionally, the upper tailpipe 245A mates with an upper portion 944 of the packer 250 described below in further detail. A conduit (shown in
Packer
The configuration of the packer 250 may be chosen primarily based on the inner diameter of the wellbore casing 205. However, this size does not directly dictate the requirements of one or more inner mandrels which are disposed inside the packer body. The inner mandrels may be simple single cylindrical conduits or one or more passages composed of multiple conduits. These conduits may communicate fluids, gas, steam, proppants, tracers, catalysts, hydraulic and electrical control lines, optical signals, electrical signals, etc. between the zones above and below the packer 250. In one embodiment, the upper portion 944 of the packer 250 is constructed so as to enable various interchangeable configurations of the lower section and/or the upper tailpipe 245A of the downhole steam generator 220 with well application specific combinations of conduits through the packer. For example, a family of packers whose application range spans several wellbore casing sizes may share an inner mandrel configuration with a shared dimensional geometry or mechanical configuration. The inner mandrel geometry may be such that there may be an interchangeable or selectable set of mandrels or conduits available for the family of packers. By tailoring the type and number of conduits through this shared-configuration inner mandrel, a family of packers may be used across a span of well applications. Such applications include electrical and optical sensors and control lines, fluid distribution manifolds, fluid injection, etc.
The packer 250 may have a configuration that allows for both setting and retrieval. This is usually done using drillpipe to provide hydraulics, torque, and/or tension or compression to the packer setting and retrieval mechanisms.
In this embodiment, the latch mechanism 280 described in
Referring again to
Generally, the connection of the downhole steam generator 220 (via the upper tailpipe 245A which may be integral to the downhole steam generator 220) to the packer 250 (via the mandrel 951 which may be integral to the packer 250) may be made with the latch mechanism 281 such that the two components are positively latched and held together as one unit. This latch mechanism may then be subsequently manipulated and released to free the downhole steam generator 220 from the packer 250. A shear point, such as the shear pin 950 shown in
Another configuration of the latch mechanism 281 includes the upper tail pipe 245 of the downhole steam generator 220 that is simply set down onto the mandrel 250. In one embodiment, the upper tailpipe 245A and the mandrel 951 may be configured to include diameters permitting one of the upper tailpipe 245A and the mandrel 951 to slide into the other. According to this embodiment, the latch mechanism 281 relies on the combined weight of the downhole steam generator 220, the UMSCI module 926 and the umbilical device 225 to engage contact between the downhole steam generator 220 and the packer 250 (via the upper tailpipe 245A and the mandrel 951), as well as form and retain a seal between the downhole steam generator 220 and the packer 250 (at the upper tailpipe 245A and the mandrel 951). In this configuration, additional weight could be added to the UMSCI module 926 and/or the downhole steam generator 220 to assure maintenance of this seal during the life of the system. In this configuration, a simple upward force on the umbilical device 225 could break the seal and lift the downhole steam generator 220 off of the packer 250. In the event that the seal is difficult to break, a shear point, such as the shear pin 950 shown in
Retrieval Methods
At some time period during use, the EOR delivery system 900 may need to be retrieved from the injector well 110. For example, the EOR delivery system 900 may need to be retrieved for refurbishment, maintenance, or end-of-need if the injector well 110 is to be shut-in. While simply reversing the deployment steps described in
At step 1020, the umbilical device 225 is moved by pulling, twisting (rotating), or other tensional movement, to cause a disconnection between the downhole steam generator 220 and the packer 250. At step 1025, the umbilical device 225 is then pulled out of the well with the lower assembly (e.g., UMSCI module 926 and the downhole steam generator 220) attached. As this assembly comes out of the injector well 110, it may be disconnected at the same subassembly points that were used to assemble during run-in. Drillpipe is then lowered into the injector well 110 and the packer 250 is released and pulled from the well as shown at step 1030. Once the packer 250 is removed, the injector well 110 may be shut-in, as shown at step 1035.
In the event that the downhole steam generator 220 does not simply disconnect from the packer 250 as described at 1020, alternative disconnect points are used. Step 1040, which includes utilizing the latch mechanism 280, may be utilized instead of step 1020.
The latch mechanism 280 is an interface between the packer 250 and the downhole steam generator 220 that provides connection points utilized for assembly when the downhole steam generator 220, the UMSCI module 926, and the umbilical device 225 is lowered into the injector well 110. Although the packer 250 is designed to disconnect from the other components by surface manipulation of the umbilical device 225, it is possible that this disconnect point will stick and fail.
The latch mechanism 280 may be an alternative disconnect point when failure to disconnect occurs. Step 1040 includes disconnecting the downhole steam generator 220 from the packer 250 at a location above the packer 250. Step 1040 may be accomplished by shearing the shear pins 950 between the packer and the downhole steam generator 220. In one embodiment, tension is applied to the umbilical device 225 and the downhole steam generator 220 to break the shear pins 950 of the latch mechanism 280. In one example, tension of about 15,000 pounds applied to the umbilical device 225 breaks this shear point and releases portions of the EOR delivery system 900 above the packer 250. Portions of the downhole steam generator 220 remaining in the wellbore casing 205, such as the lower tailpipe 245B, as well as the packer 250 may be retrieved with either a fit-for-purpose overshot or other fishing equipment attached to the end of a drillpipe, as shown at step 1045.
In another embodiment, the attachment interface 281 shown in
In this embodiment, tension is applied to the umbilical device 225 and the downhole steam generator 220 to break the shear point 999 of the mandrel 951. In one example, tension of about 15,000 pounds applied to the umbilical device 225 breaks this shear point 999 and releases portions of the EOR delivery system 900 above the packer 250. Portions of the downhole steam generator 220 remaining in the wellbore casing 205, such as the mandrel 951, as well as the packer 250 may be retrieved with either a fit-for-purpose overshot or other fishing equipment attached to the end of a drillpipe, as shown at step 1045. A fishing grip surface 943 may be utilized to assist in removal of the portions remaining in the wellbore casing 205.
In the event the latch mechanism 280 does not release as described at step 1040, the umbilical device 225 may be removed from the injector well 110. Simply applying upward force to the umbilical device 225 may cause the umbilical device 225 to break. All shear points are set to break at an applied upward force significantly less than the shear point of the umbilical device 225. Retrieval of a parted umbilical device 225 resting above the downhole assembly may be very difficult and thus there is a need to assure that the umbilical device 225 comes out of the well without breaking.
Another shear point may be provided at the interface between the umbilical device 225 and the UMSCI module 926 as the connector assembly 938. The connector assembly 938 includes shear pins 941 having a shear point is greater than the shear point of the shear pins 950 of the latch mechanism 280. This sequence of shear points provides a secondary shear-release point at the interface between the umbilical device 225 and the UMSCI module 926. This secondary shear point provides a backup means to assure release and retrieval of the typically flexible umbilical device 225 which would be much more difficult to retrieve in the event that it parted (i.e., broke) and a portion of it was left downhole. As an example, the shear point for the shear pins 950 of the latch mechanism 280 may be about 15,000 pounds and the shear point of the shear pins 941 of the connector assembly 938 may be about 30,000 pounds. The setting of this secondary (higher) shear point dictates the minimum shear strength of the umbilical device 225. The parting strength (tensile strength) of the umbilical device 225 must be significantly greater than the total weight of the umbilical device 225 plus this secondary shear point. For example, if an umbilical device 225 weighs 50,000 pounds, the application of more than 50,000 pounds of upward lifting force at the surface is necessary to simply lift the umbilical device 225 only. An additional force is required before any force is applied to lifting the downhole steam generator 220 and the UMSCI module 926. If an additional force of 20,000 pounds is required for shear release at the UMSCI module 926, an upward force of 30,000 pounds is required at the wellhead 200. In this example, the umbilical device 225 must be able to transmit a force of at least 80,000 pounds and thus must have a parting strength well in excess of this combined force requirement.
Thus, at step 1050, where the lower-shear-force point between the packer 250 and the bottom of the downhole steam generator 220 has failed to release the assembly, the umbilical device 225 is simply pulled until the shear pins 941 break, allowing the umbilical device 225 to be pulled from the injector well 110. This leaves the upper head of the UMSCI module 926 exposed. The UMSCI module 926, the downhole steam generator 220, and the packer 250 may then be retrieved with either a fit-for-purpose overshot or other fishing tool attached to the end of a drillpipe, as shown at step 1055. The UMSCI module 926 is constructed so as to withstand upward pulling forces much greater than the umbilical device 225 and strength sufficient to provide significant over-force to shear the pins at the shear points. Ultimately, the bodies of the UMSCI module 926 and the downhole steam generator 220 must be strong enough to transfer enough pulling force so as to remove the packer 250. The connection at the top of the UMSCI module 926 is constructed so as to provide a secure connection to the drillpipe in the worst-case scenario where the UMSCI module 926, the downhole steam generator 220 and the packer 250 have to be pulled out together after their normal release mechanisms have failed. Drillpipe provides the means for the application of significantly greater upward lifting forces as compared to the lifting forces that may be applied to the umbilical device 225.
While the foregoing is directed to embodiments of the invention, other and further embodiments of the invention may be implemented without departing from the scope of the invention, and the scope thereof is determined by the claims that follow.
This application is a continuation-in-part of U.S. patent application Ser. No. 13/560,742, filed Jul. 27, 2012, which application claims benefit of U.S. Provisional Patent Application Ser. No. 61/512,085, filed Jul. 27, 2011. Each of the aforementioned patent applications are hereby incorporated by reference herein.
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| Child | 14252352 | US |
