Heavy Oil Recovery and Apparatus

Abstract

A thermal in-situ method and apparatus are provided for recovering hydrocarbons from subterranean hydrocarbon-containing formations such as oil sands, oil shale and other heavy oil systems. Recovery of viscous hydrocarbon by hot fluid injection into subterranean formations is assisted by using a specially designed wellbore with an active hydraulic seal, with a axial communication zone with multiple injection perforations separated from the production perforations by a moveable packer. In addition, a novel downhole thermal sensing apparatus is used to monitor and control oil production. A producing mechanism including pumping equipment lifts the produced oil from the central cavity to the surface.

1 . A method for recovering hydrocarbons from a subterranean formation containing viscous oil or other heavy hydrocarbons, the method comprising the steps of:
 (a) drilling at least one wellbore down to and penetrating the subterranean formation;   (b) providing a wellhead at the entrance or proximal end of the wellbore;   (c) providing at least one set of upper injection perforations and lower production perforations in the wellbores at pre-selected intervals;   (d) installing at least one downhole wellbore packer between upper and lower perforations;   (e) forming a discrete annular zone for increased axial fluid communication near the said wellbore in the said formation so that heated low viscosity oil and hot water produced from condensed displacing fluid can flow downwards to the lower production perforations;   (f) implementing an active hydraulic seal in said annular communication zone;   (g) installing a downhole flow control apparatus;   (h) heating the said formation by injecting a displacing fluid into the formation;   (i) communicating with the downhole flow control apparatus from the surface;   (j) computing the prescribed times for triggering the downhole flow control apparatus;   (k) lifting the produced oil and displaced fluids to the surface;   (l) producing the wellbore fluids at less than a critical rate so that the effects of the displacing fluid coning are substantially eliminated;   (m) scavenging the formation residual hot oil by injecting a displacing scavenger fluid.   
   
   
       2 . The method of  claim 1 , wherein the said formation is heated by injecting steam through wellbore perforations as a displacing fluid. 
   
   
       3 . The method of  claim 2 , wherein the injected steam heats the wellbore and surrounding formation for sufficient time and to a calculated temperature. 
   
   
       4 . The method of  claim 1 , wherein the step of forming said annular zone comprises:
 installing a steel pipe selected from the group consisting of steel casings, steel liners, self-expanding or fixed sand screens   
   
   
       5 . The method of  claim 2 , wherein the said injected steam forms a steam chamber or steam bank. 
   
   
       6 . The method of  claim 1 , wherein the hydraulic seal in the communication zone forms as a no-flow barrier for vertical steam flow. 
   
   
       7 . The method of  claim 1 , further comprising the step of:
 installing a fluid recovery system to lift the produced oil and displaced fluids to the surface, wherein the produced oil and displaced fluids are lifted to the surface by using the said fluid recovery system.   
   
   
       8 . The method of  claim 7 , wherein the said fluid recovery system comprises a plurality of devices including:
 (a) displacement pumps,   (b) gas lift devices,   (c) cavity pumps.   
   
   
       9 . The method of  claim 1 , wherein the wellbore has a downward, lateral and an upward section terminating in a new surface wellhead forming a uniwell. 
   
   
       10 . The method of  claim 1 , wherein the wellbore has a downward section, a lateral section and terminating in a central production cavity. 
   
   
       11 . The method of  claim 1 , wherein the wellbore has a downward section and an enlarged axial central production cavity. 
   
   
       12 . The method of  claim 1 , further comprising the step of cementing a steel casing in the wellbore in the said formation. 
   
   
       13 . The method of  claim 1 , wherein a plurality of lateral and horizontal injection mini-wellbores are implemented in a staggered manner operatively connected to the central wellbore. 
   
   
       14 . The method of  claim 9 , wherein the wellhead at the proximal end of the wellbore is an injection wellhead and the distal end of the wellbore is a production wellhead. 
   
   
       15 . The method of  claim 1 , wherein the perforations in the wellbore are positioned as paired groups or couplets. 
   
   
       16 . The method of  claim 15 , wherein the proximal perforations in the pair group form an injector set of perforations. 
   
   
       17 . The method of  claim 15 , wherein the next or distal set of perforations in the pair group form a producer set of perforations. 
   
   
       18 . The method of  claim 1 , wherein the downhole packer in the wellbore is placed between the injector and producer pair of perforations separating the injection and production zones. 
   
   
       19 . The method of  claim 1 , wherein the downhole packer forces the injection fluid to be to exit the wellbore and be injected into the hydrocarbon bearing formation through the upper injection perforations. 
   
   
       20 . The method of  claim 1 , wherein the downhole packer is retractable and has either a solid or an inflatable element. 
   
   
       21 . The method of  claim 1 , wherein the injected displacing fluid is steam. 
   
   
       22 . The method of  claim 1 , wherein the injected displacing fluid forms a steam bank or chamber in the hydrocarbon reservoir. 
   
   
       23 . The method of  claim 1 , wherein the annular communication zone is concentric to the wellbore. 
   
   
       24 . The method of  claim 1  wherein the diameter of the annular communication zone ranges from at least 8 inches to several feet. 
   
   
       25 . The method of  claim 1 , wherein after each steam displacing zone is depleted of hydrocarbons the downhole packers, and the downhole flow controller apparatus, are unseated and moved axially along the wellbore and re-seated adjacent to new hydrocarbon-rich zones in the formation to implement the said recovery method. 
   
   
       26 . A downhole flow control apparatus comprising:
 (a) a fluid flow sensor;   (b) a flow valve or flow control device for restricting fluid flow;   (c) a flow device controller for controlling the flow control device;   (d) means for communicating;   (e) a wellbore packer;   (f) means for delivering operational power to the apparatus; and   (g) a surface control device.   
   
   
       27 . The apparatus of  claim 26 , wherein the fluid flow sensor is upstream of the flow valve. 
   
   
       28 . The apparatus of  claim 26 , wherein the fluid flow sensor is downstream of the flow valve. 
   
   
       29 . The apparatus of  claim 26 , wherein the fluid flow sensor measures a plurality of material flow characteristics including pressure, temperature, mass rate and quality of the flow stream. 
   
   
       30 . The apparatus of  claim 26 , wherein said fluid flow sensor is selected from the group consisting of electronic, optical, mechanical and electrical sensors. 
   
   
       31 . The apparatus of  claim 26  wherein said fluid flow sensor communicates with a downhole processor, said downhole processor being adapted to process the raw flow data sensed by said steam flow sensor to derive processed data, said processed data being selectively transmitted to the surface. 
   
   
       32 . The apparatus of  claim 26  wherein said fluid flow sensor communicates with a downhole processor, said downhole processor being adapted to process the raw flow data sensed by said steam flow sensor to derive processed data, said processed data being selectively utilized to directly control the flow control device in the steam apparatus. 
   
   
       33 . The apparatus of  claim 26  further comprising a control circuit for controlling the operation of the flow control apparatus. 
   
   
       34 . The apparatus of  claim 33  wherein the control circuit is placed at a remote place from the device. 
   
   
       35 . The apparatus of  claim 33  wherein the control circuit communicates with the flow control device via a conductor. 
   
   
       36 . The apparatus of  claim 33  wherein the control circuit communicates with the flow control device via telemetry. 
   
   
       37 . The apparatus of  claim 33  wherein the control circuit includes a memory system capable of storing instructions for operating the flow control device independently of the surface. 
   
   
       38 . The apparatus of  claim 26 , wherein the fluid flow sensor activates the flow control device. 
   
   
       39 . The apparatus of  claim 26 , wherein the flow control device controls the flow of fluid through the wellbore. 
   
   
       40 . The apparatus of  claim 26 , wherein the fluid flow through the wellbore is greater than zero when the flow device is open. 
   
   
       41 . The apparatus of  claim 26 , wherein the fluid flow through the wellbore is zero when the flow valve is closed. 
   
   
       42 . The apparatus of  claim 26 , wherein the fluid flow sensor detects the flow of hot oil. 
   
   
       43 . The apparatus of  claim 26 , wherein the fluid flow sensor detects the flow of hot water. 
   
   
       44 . The apparatus of  claim 26 , wherein the fluid flow sensor detects the flow of steam. 
   
   
       45 . The apparatus of  claim 26 , wherein the fluid flow sensor detects the combined flow of steam, hot oil and condensed water. 
   
   
       46 . The apparatus of  claim 26 , wherein the fluid flow sensor detects the mass flow rate of the flow stream. 
   
   
       47 . The apparatus of  claim 26 , wherein the fluid flow sensor detects the temperature of the flow stream. 
   
   
       48 . The apparatus of  claim 26 , wherein the fluid flow sensor detects the mass flow rate and temperature of the flow stream simultaneously. 
   
   
       49 . The apparatus of  claim 26 , wherein the fluid flow sensor triggers the flow device controller when the flow sensor detects the flow of steam. 
   
   
       50 . The apparatus of  claim 26 , wherein the flow device controller closes the fluid flow device when the flow sensor detects the flow of steam. 
   
   
       51 . The apparatus of  claim 26 , wherein the flow device controller communicates with the surface control device. 
   
   
       52 . The apparatus of  claim 26 , wherein the flow device controller receives a signal from the surface control device after a prescribed time. 
   
   
       53 . The apparatus of  claim 26 , wherein the signal from the surface to the flow device controller triggers the controller to open the flow control device. 
   
   
       54 . The apparatus of  claim 26 , wherein said flow device controller is selected from the group consisting of electrical, electronic, optical, mechanical, hydraulic, pneumatic and electrical controllers. 
   
   
       55 . The apparatus of  claim 26  wherein the communication with the surface is by a wired connection. 
   
   
       56 . The apparatus of  claim 26  wherein the communication with the surface is a wireless communication. 
   
   
       57 . The apparatus of  claim 26  wherein the communication with the surface is through the steel wellbore using a plurality of electromagnetic transmissions. 
   
   
       58 . The apparatus of  claim 57  wherein the communication with the surface is analyzed using Digital Signal Processing technologies. 
   
   
       59 . The apparatus of  claim 26  wherein the device operates in a “null” sensor mode comprising;
 (a) receiving a control signal at pre-selected timed intervals;   (b) opening the production valve for oil flow;   (c) keeping the production valve open for a fixed time period;   (d) shutting the downhole valve after a timed interval.   
   
   
       60 . The apparatus of  claim 59  wherein the control signal can be sent remotely from the surface or can be generated by an embedded downhole timing mechanism. 
   
   
       61 . The method of  claim 1  wherein the injected displacing scavenger fluid is water. 
   
   
       62 . The method of  claim 1  wherein the injected displacing scavenger fluid is non-condensible gas such as flue gas. 
   
   
       63 . The method of  claim 61 , wherein the injected displacing scavenger water is injected in a plurality of wellbores comprising:
 (a) newly drilled horizontal and vertical injector wellbores;   (b) existing wellbores formerly used for steam injection.   
   
   
       64 . The method of  claim 61 , wherein the injected displacing scavenger non-condensible gas is injected in a plurality of wellbores comprising:
 (a) newly drilled horizontal and vertical injector wellbores;   (b) existing wellbores formerly used for steam injection.   
   
   
       65 . The method of  claim 63 , wherein the injected displacing scavenger water is injected at the bottom of the steam bank in the oil formation. 
   
   
       66 . The method of  claim 64 , wherein the injected displacing scavenger non-condensible gas is injected at the top of the steam bank in the oil formation. 
   
   
       67 . The method of  claim 1 , wherein the injected displacing scavenger fluids are injected simultaneously. 
   
   
       68 . The method of  claim 1 , wherein the injected displacing scavenger fluids are injected separately. 
   
   
       69 . The method of  claim 1 , wherein the critical production rate is less than 5,000 barrels of fluid per day. 
   
   
       70 . The method of  claim 1  wherein the prescribed time for triggering the downhole flow controller is determined by the use of a computer model. 
   
   
       71 . The method of  claim 1 , wherein the step of forming said annular zone comprises implementing an open hole completion without a steel casing.