Producing resources using steam injection

A system for producing fluids from a subterranean zone comprises a tubing string disposed in a well bore, the tubing string adapted to communicate fluids from the subterranean zone to a ground surface. A downhole fluid lift system is operable to lift fluids towards the ground surface. A downhole fluid heater is disposed in the well bore and is operable to vaporize a liquid in the well bore. A seal between the downhole fluid lift system and the downhole fluid heater is operable to isolate a portion of the well bore containing the downhole fluid lift system from a portion of the well bore containing the downhole fluid heater. A method comprises: disposing a tubing string in a well bore; generating vapor in the well bore; and lifting fluids from the subterranean zone to a ground surface through the tubing string.

TECHNICAL FIELD

This invention relates to resource production, and more particularly to resource production using heated fluid injection into a subterranean zone.

BACKGROUND

Fluids in hydrocarbon formations may be accessed via well bores that extend down into the ground toward the targeted formations. In some cases, fluids in the hydrocarbon formations may have a low enough viscosity that crude oil flows from the formation, through production tubing, and toward the production equipment at the ground surface. Some hydrocarbon formations comprise fluids having a higher viscosity, which may not freely flow from the formation and through the production tubing. These high viscosity fluids in the hydrocarbon formations are occasionally referred to as “heavy oil deposits.” In the past, the high viscosity fluids in the hydrocarbon formations remained untapped due to an inability to economically recover them. More recently, as the demand for crude oil has increased, commercial operations have expanded to the recovery of such is 5 heavy oil deposits.

In some circumstances, the application of heated fluids (e.g., steam) and/or solvents to the hydrocarbon formation may reduce the viscosity of the fluids in the formation so as to permit the extraction of crude oil and other liquids from the formation. The design of systems to deliver the steam to the hydrocarbon formations may be affected by a number of factors.

In some cyclical steam injection and producing operations, a dedicated steam injection string is installed in a well bore and used for injecting heated fluid into a target formation during a steam injection cycle to reduce the viscosity of oil in the target formation. Once a steam injection cycle is completed, the injection assembly is removed from the well bore and a production string including an artificial lift assembly is installed on the well bore to produce the well. At some point, the reservoir temperature cools to a point at which increasing viscosity of the oil significantly inhibits reservoir fluid recovery using artificial lift means. Once this happens, the production string is removed from the well bore and the steam injection string is reinstalled to begin next steam injection cycle.

SUMMARY

Systems and methods of producing fluids from a subterranean zone can include downhole fluid heaters (including steam generators) in conjunction with artificial lift systems such as pumps (e.g., electric submersible, progressive cavity, and others), gas lift systems, and other devices. Supplying heated fluid from the downhole fluid heater(s) to a target subterranean zone such as a hydrocarbon-bearing formation or reservoir can reduce the viscosity of oil and/or other fluids in the target formation. To enhance this process of combining artificial lift systems with downhole fluid heaters, a downhole cooling system can be deployed for cooling the artificial lift system and other components of a completion system.

In one aspect, systems for producing fluids from a subterranean zone include: a downhole fluid lift system adapted to be at least partially disposed in the well bore, the downhole fluid lift system operable to lift fluids towards a ground surface; a downhole fluid heater adapted to be disposed in the well bore, the downhole fluid heater operable to vaporize a liquid in the well bore; and a seal between the downhole fluid lift system and the downhole fluid heater, the seal operable to selectively seal with the well bore and isolate a portion of the well bore containing the downhole fluid lift system from a portion of the well bore containing the downhole fluid heater.

In another aspect, systems include: a pump with a pump inlet, the pump inlet disposed in the well bore, the pump operable to lift fluids towards the ground surface; and a downhole fluid heater disposed in the well bore, the downhole fluid heater operable to vaporize a liquid in the well bore.

In one aspect, a method includes: with an artificial lift system in a well bore, introducing heated fluid into a subterranean zone about the well bore; and artificially lifting fluids from the subterranean zone to a ground surface using the artificial lift system.

In one aspect, a method includes artificially lifting fluids from a subterranean zone through a well bore while a downhole heated fluid generator resides in the well bore.

Such systems can include one or more of the following features.

In some embodiments, the downhole fluid lift system includes a gas lift system.

In some embodiments, the downhole fluid lift system includes a pump (e.g., an electric submersible pump). In some cases, the pump is adapted to circulate fluids. In some embodiments, systems also include a surface pump.

In some embodiments, the downhole fluid lift systems are adapted to circulate fluids in the portion of the well bore containing the downhole fluid lift system while isolated from the portion of the well bore containing the downhole fluid heater. In some embodiments, systems can also include a surface pump adapted to circulate fluids in the portion of the well bore containing the downhole fluid lift system while isolated from the portion of the well bore containing the downhole fluid heater.

In some embodiments, the downhole fluid heater includes a steam generator.

In some embodiments, systems also include a tubing string disposed in a well bore, the tubing string adapted to communicate fluids from the subterranean zone to a ground surface.

In some embodiments, systems also include a seal between the pump inlet and the downhole fluid heater such that fluid flow between a portion of the well bore containing the pump inlet and a portion of the well bore containing the downhole fluid heater is limited by the seal.

In some embodiments, methods also include isolating a portion of the well bore containing the artificial lift system from a portion where the heated fluid is being introduced into the subterranean zone.

In some embodiments, methods also include circulating fluid in the portion of the well bore containing the artificial lift system while introducing heated fluid into the subterranean zone. In some instances, circulating fluid comprises circulating fluid using the artificial lift system. In some instances, circulating fluid comprises circulating fluid using a surface pump.

In some embodiments, methods also include cooling a downhole pump present in the well bore while vapor is being generated.

In some embodiments, methods also include heating the fluid in the well bore.

Systems and methods based on downhole fluid heating can improve the efficiencies of heavy oil recovery relative to conventional, surface based, fluid heating by reducing the energy or heat loss during transit of the heated fluid to the target subterranean zones. Some instances, this can reduce the fuel consumption required for heated fluid generation.

In addition, by heating fluid downhole, the injection assembly between the surface and the downhole fluid heating device is no longer used as a conduit for the conveyance of heated fluid into the subterranean zone. Thus, a multipurpose completion assembly can be deployed which provides heated fluid injection into the subterranean zone and a producing conduit to the surface which includes an artificial lift system. Heating the fluids downhole reduces collateral heating of the uphole well bore, thereby reducing heat effects and possible damage on the artificial lift production system and other equipment therein. In addition, multipurpose completion assemblies including cooling mechanisms for downhole artificial lift systems and other devices can further reduce the possibility that heat associated with heating the fluid will damage artificial lift systems or other devices present in the well bore.

Use of multipurpose completion assemblies can also increase operational efficiencies. Such multipurpose completion assemblies can be installed in a well bore and remain in place during both injection and production phases of a cyclic production process. This reduces the number of trips in and out of the well bore that would otherwise be required for systems and methods based on the use of separate injection and production assemblies.

DETAILED DESCRIPTION

Systems and methods of producing fluids from a subterranean zone can include downhole fluid heaters in conjunction with artificial lift systems. One type of downhole fluid heater is a downhole steam generator that generates heated steam or steam and heated liquid. Although “steam” typically refers to vaporized water, a downhole steam generator can operate to heat and/or vaporize other liquids in addition to, or as an alternative to, water. Some examples of artificial lift systems include pumps, such as electric submersible, progressive cavity, and others, gas lift systems, and other devices that operate to move fluids. Supplying heated fluid from the downhole fluid heater(s) to a target formation such as, a hydrocarbon-bearing formation or reservoir can reduce the viscosity of oil and/or other fluids in the target formation. To accomplish this process of combining artificial lift systems with downhole fluid heaters, a downhole cooling system can be deployed for cooling the artificial lift system and other components of a completion system. In some instances, use of a single multipurpose completion assembly allows for cyclical steam injection and production without disturbing or removing the well bore completion assembly. Such multipurpose completion assemblies can include a downhole heated fluid generator, an artificial lift system, and a production assembly cooling system that circulates surface cooled well bore water during the steam injection process.

Referring toFIGS. 1A-1C, a system100for producing fluids from a reservoir or subterranean zone110includes a tubing string112disposed in a well bore114. The tubing string112is adapted to communicate fluids from the subterranean zone to a ground surface116. A downhole fluid lift system118, operable to lift fluids towards the ground surface116, is at least partially disposed in the well bore114and may be integrated into, coupled to or otherwise associated with the tubing string112. A downhole fluid heater120, operable to vaporize a liquid in the well bore114, is also disposed in the well bore114and may be carried by the tubing string112. As used herein, “downhole” devices are devices that are adapted to be located and operate in a well bore. A seal122(e.g., a packer seal) is disposed between the downhole fluid lift system118and the downhole fluid heater120. The seal122may be carried by the tubing string112. The seal122may be selectively actuable to substantially seal the annulus between the well bore114and the tubing string112, thus hydraulically isolating a portion of the well bore114uphole of the seal122from a portion of the well bore114downhole of the seal122. As will be explained in more detail below, the seal122limits the flow of heated fluid (e.g., steam) upwards along the well bore114.

A well head117may be disposed proximal to a ground surface116. The well head117may be coupled to a casing115that extends a substantial portion of the length of the well bore114from about the ground surface116towards the subterranean zone110(e.g., hydrocarbon-containing reservoir). The subterranean zone110can include part of a formation, a formation, or multiple formations. In some instances, the casing115may terminate at or above the subterranean zone110leaving the well bore114un-cased through the subterranean zone110(i.e., open hole). In other instances, the casing115may extend through the subterranean zone and may include apertures formed prior to installation of the casing115or by downhole perforating to allow fluid communication between the interior of the well bore114and the subterranean zone. Some, all or none of the casing115may be affixed to the adjacent ground material with a cement jacket or the like. In some instances, the seal122or an associated device can grip and operate in supporting the downhole fluid heater120. In other instances, an additional locating or pack-off device such as a liner hanger (not shown) can be provided to support the downhole fluid heater120. In each instance, the downhole fluid heater120outputs heated fluid into the subterranean zone110.

In the illustrated embodiment, well bore114is a substantially vertical well bore extending from ground surface116to subterranean zone110. However, the systems and methods described herein can also be used with other well bore configurations (e.g., slanted well bores, horizontal well bores, multilateral well bores and other configurations).

The tubing string112can be an appropriate tubular completion member configured for transporting fluids. The tubing string112can be jointed tubing or coiled tubing or include portions of both. The tubing string112carries the seal122and includes at least two valves125,126bracketing the packer seal (e.g., valve125provided on one side of seal122and valve126provided on the other side of seal). Valves125,126provide and control fluid communication between a well bore annulus128and an interior region130of the tubing string112. When open, valves125,126allow communication of fluid between the annulus128and tubing string interior130, and when closed valves125,126substantially block communication of fluid between the annulus128and tubing string interior130. In this embodiment, the valves125,126are electrically operated valves controlled from the surface116. In other embodiments, valves125,126can include other types of closure mechanisms (e.g., apertures in the tubing string112opened/closed by sliding sleeves and other types of closure mechanisms). Additionally, in other embodiments, the valves125,126can be controlled in a number of other different manners (e.g., as check valves, thermostatically, mechanically via linkage or manipulation of the string112, hydraulically, and/or in another manner).

The downhole fluid lift system118is operable to lift fluids towards the ground surface116. In the illustrated embodiment, the downhole fluid lift system is an electric submersible pump118mounted on the tubing string112. The electric submersible pump118has a pump inlet132which draws fluids from the well bore annulus128uphole of the packer seal120and a pump outlet134which discharges fluids into the interior region130of the tubing string112. Power and control lines associated with electric submersible pump118can be attached to an exterior surface of tubing string112, communicated through the tubing string112, or communicated in another manner. In some embodiments, downhole fluid lift systems are implemented using other mechanisms such as, for example, progressive cavity pumps and gas lift systems as described in more detail below.

The downhole fluid heater120is disposed in the well bore114below the seal122. The downhole fluid heater120may be a device adapted to receive and heat a recovery fluid. In one instance, the recovery fluid includes water and may be heated to generate steam. The recovery fluid can include other different fluids, in addition to or in lieu of water, and the recovery fluid need not be heated to a vapor state (e.g. steam) of 100% quality, or even to produce vapor. The downhole fluid heater120includes inputs to receive the recovery fluid and other fluids (e.g., air, fuel such as natural gas, or both) and may have one of a number of configurations to deliver heated recovery fluids to the subterranean zone110. The downhole fluid heater120may use fluids, such as air and natural gas, in a combustion or catalyzing process to heat the recovery fluid (e.g., heat water into steam) that is applied to the subterranean zone110. In some circumstances, the subterranean zone110may include high viscosity fluids, such as, for example, heavy oil deposits. The downhole fluid heater120may supply steam or another heated recovery fluid to the subterranean zone110, which may penetrate into the subterranean zone110, for example, through fractures and/or other porosity in the subterranean zone110. The application of a heated recovery fluid to the subterranean zone110tends to reduce the viscosity of the fluids in the subterranean zone110and facilitate recovery to the ground surface116.

In this embodiment, the downhole fluid heater is a steam generator120. Gas, water, and air lines136,138,140convey gas, water, and air to the steam generator120. In certain embodiments, the supply lines136,138,140extend through seal122. In the embodiment ofFIG. 1A, a surface based pump142pumps water from a supply such as supply tank144to piping146connected to wellhead148and water line140. Various implementations of supply lines136,138,140are possible. For example, gas, water, and air lines136,138,140can be integral parts of the tubing string112, can be attached to the tubing string, or can be separate lines run through well bore annulus128. One exemplary tube system for use in delivery of fluids to a downhole heated fluid generator device includes concentric tubes defining at least two annular passages that cooperate with the interior bore of a tube to communicate air, fuel and recovery fluid to the downhole heated fluid generator.

In operation, well bore114is drilled into subterranean zone110, and well bore114can be cased as appropriate. After drilling is completed, tubing string112, downhole fluid heater120, downhole fluid lift system118, and seal122can be installed in the well bore114. The seal122is then actuated to extend radially to press against and substantially seal with the casing115. The valves126,125are initially closed.

Referring toFIG. 1A, cooling fluid (e.g., water) can be supplied to uphole well bore annulus128at wellhead148. The downhole fluid lift system118can be activated to circulate the cooling water downward through uphole well bore annulus128and upwards to the interior region130of tubing string112. The combined effect of the isolation of uphole well bore annulus128from downhole well bore annulus129and the circulation of cooling fluid can reduce temperatures in the uphole well bore annulus128. The reduced temperatures reduce the likelihood of heat damage to the downhole fluid lift system118and other devices in the uphole portion of the well bore114(e.g., the deterioration and premature failure of heat sensitive components such as rubber gaskets, electronics, and others). Of note, although additional steps are not required to actively cool the cooling fluid, in some instances, the cooling fluid may be cooled by exposure to atmosphere, using a refrigeration system (not shown), or in another manner.

The downhole fluid heater120can be activated, thus heating recovery fluid (e.g., steam) in the well bore. Because the apertures126in the downhole production sleeve are closed, the heated fluid passes into the target subterranean zone110. The heated fluid can reduce the viscosity of fluids already present in the target subterranean zone110by increasing the temperature of such fluids and/or by acting as a solvent.

Referring toFIG. 1B, after a sufficient reduction in viscosity has been achieved, fluids (e.g., oil) are produced from the subterranean zone110to the ground surface116through the tubing string112. Both the downhole fluid heater120and the downhole fluid lift system118can be turned off and the downhole valve125opened. Flow of cooling water into the uphole annulus128of the well bore114can be stopped. For some period of time after injection is completed, pressures in the subterranean zone110can be high enough to cause a natural flow of fluids from the reservoir to the ground surface116through the tubing string112. During this period of time, the uphole valve126remains closed.

Referring toFIG. 1C, as the pressure in the subterranean zone110is depleted or as the subterranean zone110cools and fluid viscosity in the reservoir increases, production due to reservoir pressure can slow and even stop. As this occurs, the uphole valve126is opened and the downhole fluid lift system118is activated. The downhole fluid lift system118pumps fluids through downhole valve125, out of uphole valve126and from uphole annulus128to the ground surface116through the interior region130of tubing string112. In some instances, tubing string112can include additional flow control mechanisms. For example, tubing string can include check valves and/or other arrangements to direct the travel of fluids transferred into the interior region130of the tubing string112from fluid lift system118uphole in the tubing string11.

As the subterranean zone110further cools and fluid viscosity in the reservoir further increases, production, even using the downhole fluid lift system, can slow. At this point, system100can be reconfigured for injection by closing valves125,126, and by activating the downhole fluid lift system118(to circulate cooling water) and the downhole fluid heater120to repeat the cycle described above. Such systems and methods can increase operational efficiencies because a single completion assembly can be installed in a well bore and remain in place during both injection and production phases of a cyclic production process. This reduces the number of trips in and out of the whole that would otherwise be required for systems and methods based on the use of separate injection and production assemblies.

The concepts described above can be implemented in a variety of systems and/or system configurations. For example, other approaches can be used to cool the downhole fluid lift system. Similarly, other downhole fluid lift systems can be used.

FIG. 2depicts an alternate approach to cooling the downhole fluid lift system and other components in the uphole portion of the well bore114. A system200can be arranged in substantially the same configuration as system100. However, system200can use the surface pump to circulate cooling water through the uphole annulus128of the well bore114during the heated fluid injection phase. This can reduce the overall use of downhole fluid lift system118and, thus, can reduce the likelihood of wear related damage to the downhole fluid lift system. The surface pump can be the pump142used to supply water to the downhole fluid heater120or a separate pump can be used.

FIG. 3depicts yet another alternate approach to cooling the downhole fluid lift system and other components in the uphole portion of the well bore114. Like system200, system300can reduce the overall use of downhole fluid lift system118and, thus, can reduce the likelihood of wear related damage to the downhole fluid lift system. System300is also arranged in substantially the same configuration as system100and system200. However, system300includes an alternate mechanism for cooling the downhole fluid lift system118during the injection phase. The water line140that feeds the downhole fluid heater120is connected to a shroud310disposed around exterior portions of the downhole fluid lift system118. During the injection phase, water flowing to the downhole fluid heater120passes through the shroud310providing both insulation and cooling for the downhole fluid lift system118. Other components in the uphole portion of the well bore114can be similarly cooled using the water line140.

Referring toFIG. 4, systems can also be implemented using alternate downhole fluid lift systems. For example, system400is implemented using a progressive cavity pump418disposed in line with the tubing string112as the downhole fluid lift system. The progressive cavity pump418is driven by a drive shaft420extending downward to the progressive cavity pump through the interior region130of tubing string112. System400is also arranged in substantially the same configuration as the previously described systems100,200,300. However, because the progressive cavity pump418is arranged in line with the tubing string112, the uphole valve can be omitted. In some embodiments, system400includes the shroud310described above as arranged above for cooling the progressive cavity pump418.

Referring toFIG. 5, systems can also be implemented using a gas lift system as the downhole fluid lift system. For example, system500is implemented using a gas lift production assembly rather than pumps as the downhole fluid lift system. System500is also arranged in substantially the same configuration as the previously described system400. However, a gas lift production assembly518which includes at least one gas lift production liner520with gas lift mandrels522. The gas lift mandrels522each include one or more gas lift valves524. Dummies can be placed in the gaslift mandrels522during the injection phase so that the uphole well bore annulus128does not need to be cooled. After the injection phase is completed, the dummies are removed and gas lift valves installed (e.g., by using a wireline system). The reservoir fluid is then lifted to the ground surface116using artificial lift provided by the gas lift system518.