Search Images Maps Play YouTube News Gmail Drive More »
Sign in
Screen reader users: click this link for accessible mode. Accessible mode has the same essential features but works better with your reader.

Patents

  1. Advanced Patent Search
Publication numberUS20060175061 A1
Publication typeApplication
Application numberUS 11/279,305
Publication dateAug 10, 2006
Filing dateApr 11, 2006
Priority dateAug 30, 2005
Publication number11279305, 279305, US 2006/0175061 A1, US 2006/175061 A1, US 20060175061 A1, US 20060175061A1, US 2006175061 A1, US 2006175061A1, US-A1-20060175061, US-A1-2006175061, US2006/0175061A1, US2006/175061A1, US20060175061 A1, US20060175061A1, US2006175061 A1, US2006175061A1
InventorsHenry Crichlow
Original AssigneeCrichlow Henry B
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method for Recovering Hydrocarbons from Subterranean Formations
US 20060175061 A1
Abstract
Recovery of viscous hydrocarbon from subterranean formations is assisted by using a plurality of novel U-tube type wells, each with dual wellheads, a moveable wellbore packer, a lateral section with a concentric communication zone and with sequential injection production perforations in which heat is injected into the proximal perforations and hot oil and produced fluids are produced from the distal perforations, the whole process being controlled by modulating the production flow where the wellbore fluids are controlled to act as a hydraulic seal to limit bypass of injected fluids. The injection-production displacement process moves axially along the wellbore in a sequential manner as hydrocarbon volumes are depleted by injected fluid displacement of oil and oil and water production.
Images(20)
Previous page
Next page
Claims(56)
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 comprising a vertically drilled downward section, a lateral section and an upward section, in the hydrocarbon bearing formation by penetrating the formation with conventional drilling equipment;
(b) providing a wellhead at the entrance or proximal end of the wellbore and another wellhead at the exit or distal end of the wellbore;
(c) providing a plurality of perforations in the wellbore at pre-selected intervals;
(d) installing a downhole wellbore packer between upper and lower perforations;
(e) forming an annular hot zone of increased fluid conductivity near the said wellbore in the said formation to facilitate vertical flow of heated low viscosity oil and hot water produced from condensed steam, towards lower production perforations;
(f) heating the said formation by injecting a displacing fluid into the formation;
(g) lifting the produced oil and displaced fluids to the surface.
2. The method of claim 1, wherein the said formation is heated by injecting steam through upper 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 at a calculated temperature.
4. The method of claim 1, wherein the said hot annular zone is formed by installing and initiating a downhole heater for a predetermined time greater than 24 hours, and at a predetermined temperature.
5. The method of claim 1, wherein the said formation is heated by transmitting heat energy to the said formation by using a combustion front.
6. The method of claim 1, wherein the said formation is heated by transmitting heat energy to the said formation by using a steam chamber or steam bank.
7. The method of claim 1, wherein the driving pressure of produced oil and displaced fluids is sufficiently high to push the produced oil and displaced fluids to the surface.
8. The method of claim 1, further comprising the steps 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.
9. The method of claim 8, wherein the said fluid recovery system comprises a production pump.
10. The method of claim 1, wherein the step of drilling the upward section of the wellbore comprises the steps of:
drilling a small pilot hole upwards to the exit end of the wellbore with a small drilling assembly and bit; and
enlarging the upward section of the said wellbore.
11. The method of claim 10, wherein the step of enlarging the upward section comprises the steps of:
installing a back-reamer bit, connected to the pull back drill rig at the entrance of the wellbore by a drill pipe; and
pulling the said back-reamer bit to travel from the exit end of the wellbore through the small pilot hole to the entrance, to enlarge the upward section of the said wellbore.
12. The method of claim 10, wherein the step of enlarging the upward section comprises the steps of:
installing a forward-reamer bit, connected to the drill rig at the exit end of the wellbore by a drill pipe; and
rotating the said forward-reamer bit and pushing it forward to travel from the exit end of the wellbore through the small pilot hole to the entrance, to enlarge the upward section of the said wellbore
13. The method of claim 1, further comprising the step of cementing a steel casing in the wellbore in the said formation.
14. The method of claim 1, wherein the wellhead at the proximal end of the wellbore is an injection wellhead.
15. The method of claim 1, wherein the wellhead at the distal end of the wellbore is a production wellhead.
16. The method of claim 1, wherein the perforation zones in the wellbore are positioned as paired groups or couplets.
17. The method of claim 16, wherein the proximal perforations in the pair group form an injector set of perforations.
18. The method of claim 16, wherein the next or distal set of perforations in the pair group forms a producer set of perforations.
19. 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.
20. 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.
21. The method of claim 1, wherein the downhole packer is retractable and be either solid or inflatable.
22. The method of claim 1, wherein the injected fluid is steam.
23. The method of claim 1, wherein the injected fluid forms a steam bank or chamber in the hydrocarbon reservoir.
24. The method of claim 1, wherein the said hot annular zone is formed by installing a reaming device and reaming out a portion of the said formation, thereby enlarging the said wellbore substantially.
25. The method of claim 24, wherein the reamed zone is concentric to the wellbore.
26. The method of claim 24, wherein the reamed zone forms an axial communication zone for fluid flow from the steam bank to the production zone perforations.
27. The method of claim 1, wherein the downhole packer is moved axially along the wellbore to new hydrocarbon rich formations to carry out the said method, after each steam displacing zone is depleted of hydrocarbons.
28. The method of claim 1, further comprising the step of:
installing a downhole backpressure valve in the said wellbore to create a backpressure to prevent the injected steam from bypassing downwards into the production perforations.
29. The method of claim 1, wherein the accumulation of produced hot oil in the lateral section is controlled by controlling the fluid production rate at the distal end of the wellbore, to provide a hydraulic “P-trap” effect, which acts as a backpressure valve preventing the bypass of steam from the upper perforations to the lower perforations.
30. The method of claim 29, wherein the said wellbore is pressured from the surface with natural gas or some inert gas to implement the “P-trap” effect pneumatically in addition to hydraulically.
31. The method of claim 1, wherein the injected fluid is air.
32. The method of claim 1, wherein the injected fluid is a combination of steam and heated water.
33. The method of claim 31, wherein the injected air provides the oxygen needed for combustion front of the in-situ hydrocarbon.
34. The method of claim 1, wherein the angle of the lateral section of the wellbore in the formation ranges between zero (0) degrees to 90 degrees from the horizontal.
35. The method of claim 4, wherein the downhole heater remains in place substantially long enough to heat radially, a preferred annular distance of at least two feet around the wellbore.
36. The method of claim 4, wherein the downhole heater is retractable and moveable.
37. The method of claim 1, wherein the heating of the annular communication zone increases the porosity of the reservoir formation in the annular region.
38. The method of claim 1, wherein the selective heating of the annular communication region increases the permeability of the reservoir formation in the communication zone.
39. The method of claim 1, wherein the selective heating of the annular communication region decreases the water saturation of the reservoir formation in the communication zone.
40. The method of claim 37, wherein the increased reservoir rock formation porosity increases the fluid transmissibility of the rock to oil flow in the annular communication zone.
41. The method of claim 38, wherein the increased reservoir rock formation permeability increases the fluid transmissibility of the rock to oil flow in the annular communication zone.
42. The method of claim 39, wherein the decreased reservoir rock formation water saturation increases the fluid transmissibility of the rock to oil flow in the annular communication zone.
43. The method of claim 1, wherein the lateral wellbore section extends substantially below the hydrocarbon formation.
44. The method of claim 29, wherein the P-trap is used for controlling the flow of produced oil in the wellbore.
45. The method of claim 1, wherein the displacing fluid is injected intermittently.
46. The method of claim 1, wherein the displacing fluid is injected continuously.
47. The method of claim 1, wherein the produced fluids are recovered intermittently.
48. The method of claim 1, wherein the produced fluids are recovered continuously.
49. The method of claim 19, wherein the downhole retractable packer completely separates the injection perforations from the production perforation in the wellbore.
50. The method of claim 1, wherein the heated annular zone extends substantially from below the base of the injection perforations to the top of the production perforations
51. The method of claim 1, wherein maintaining a prescribed oil level in the wellbore controls the vertical steam flow.
52. The method of claim 51, wherein maintaining a prescribed oil level in the wellbore prevents the flow of steam bypassing the cold formation and flowing to the production perforations.
53. The method of claim 1, comprising a plurality of parallel wellbores simultaneously over a large areal extent to maximize oil recovery by minimizing the heat losses attributed to each wellbore.
54. The method of claim 4, wherein the said temperature ranges between 300 deg. F and 600 deg. F.
55. The method of claim 3, wherein steam is injected until the formation is depleted of movable oil.
56. The method of claim 3, wherein the injected steam heats the formation to a temperature above 212 deg. F.
Description
CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority from provisional application 60/712,289 filed Aug. 30, 2005 and Disclosure Document 521,535 by Dr. Henry Crichlow.

INTRODUCTION

This invention relates generally to a new technology application and a new type of oil well for recovery of viscous hydrocarbons from subterranean oil bearing formations. The technology involves the novel use and application of equipment and techniques in which horizontal wells are drilled from the surface down to and across an oil bearing formation and back up to the surface, in a manner similar to that of drilling under a river crossing when laying pipelines across country. This new type of horizontal well is called a Uniwell™ because it has two surface wellheads one at each end of the axis of the horizontal system. Either wellhead can be used for either injection or production as needed by the operator.

The technology is a new application using some elements of an existing technology, which has hitherto been used in horizontal pipeline crossing installations and some technology elements, which have been used in conventional oil well drilling.

FIELD OF THE INVENTION

THIS INVENTION is a unique new approach to drilling horizontal wells for oil recovery. The invention is particularly suited to making heavy oil formations and tar sands producible by a single wellbore drilled using a specialized form of horizontal directional drilling. The invention however is not limited to recovery of heavy oils only; it can be used for many oil recovery processes such as tar sands and oil shale.

With this invention, the operator can drill a new type of well that has all the operational benefits of a horizontal well and in addition this drilling can be implemented either by using modified equipment that is readily available in allied industries such as pipeline laying or by modifying existing oil well drilling rigs. This novel drilling approach effectively lowers costs and increases efficiencies because it can utilize available equipment to drill wells with greater productive capacity. This approach allows wells to be drilled over large lateral distances, up to as much as 5,000 feet in shallow depth oilfields. At greater depths the lateral extension is limited by the rig capability and mechanical limitations of torque and drag in the drilling process. With this innovation, in field practice, which involves in part, the injection and production from the same well, albeit at different ends of the horizontal axis, increased levels of oil recovery are achievable. It is also possible to produce from the same wellhead by using concentric tubular strings and allowing the produced fluid to be removed from the same wellhead.

BACKGROUND OF THE INVENTION

Introduction:

Heavy hydrocarbons in the form of petroleum deposits are distributed worldwide and the heavy oil reserves are measured in the hundreds of billions of recoverable barrels. Because of the relatively high oil viscosity which can exceed 106 Cp, these crude deposits are essentially immobile and cannot be easily recovered by conventional primary and secondary means. The only economically viable means of oil recovery is by the addition of heat to the oil deposit, which significantly decreases the viscosity of the oil by several orders of magnitude and allows the oil to flow from the formation into the producing wellbore. Today, the steam injection can be done in a continuous fashion or intermittently as in the so-called “huff and puff” or cyclic steam process. Oil recovery by steam injection involves a combination of physical processes including, gravity drainage, steam drive and steam drag to move the heated oil from the oil zone into the producing wellbore.

The most significant oil recovery problem with heavy oil, tar sands and similar hydrocarbonaceous material is the extremely high viscosity of the native hydrocarbons. The viscosity ranges from 10,000 cp at the low end of the range to 5,000,000 cp at reservoir conditions. The viscosity of steam at injection conditions is about 0.020 cp. Assuming similar rock permeability to both phases steam and oil, then the viscosity ratio provides a good measure of the flow transmissibility of the formation to each phase. Under the same pressure gradient, gaseous steam can therefore flow from 500,000 to 250,000,000 times easier through the material than the oil at reservoir conditions. Because of this viscosity ratio, it is imperative and critical to any recovery application that the steam be confined or limited to an area of the reservoir by a seal. This seal can be physical, hydraulic or pneumatic and essentially must provide a physical situation which guarantees no-flow of any fluid across an interface. This can be implemented by several means. Without this “barrier” the steam will bypass, overrun, circumvent, detour around the cold viscous formation and move to the producer wellbore. This invention addresses and resolves this major obstructive element in heavy oil recovery.

Horizontal wells have played a prominent part in recovery of oil. These wells can be as much as 4 times as expensive as conventional vertical wells but the increased expense is offset by the increased rates of oil production and faster economic returns. Several patents have described various approaches to using horizontal wellbores. The need for horizontal wells requires a more efficient economical and easily deployable system for developing and drilling these horizontal wells. This novel utilization proposed herein addresses the needs and teaches a method of horizontal well drilling and a production mechanism that is more easily implemented, allows a larger portion of the reservoir to be exposed and allows more oil recovery to occur.

By implementing the new processes which are taught in this application by this invention the oilfield operator can see improved performance, lower costs, better oilfield management, and allow for efficient and orderly development of petroleum resources.

Improvements have been made in enhancing the contact of the steam with the native heavy oil by the introduction of horizontal well technology, which allows greater recovery than with the customary vertical wells. This current invention provides a further extension of the horizontal technology in which a novel drilling methodology is applied to the drilling effort to allow wells of much larger lateral extent, potentially larger diameters and thereby more efficient recovery systems. This invention also describes the use of the single wellbore as the injection and production system simultaneously without the need for additional concentric or multiple complicated tubular systems in the well.

No fully operational cases of horizontal drilling with two wellheads have been reported in the oil and gas drilling industry. To date, horizontal directional drilling with two wellheads, i.e. with an entry and exit wellhead, has been a technology limited almost exclusively to the pipeline construction industry in which the engineers routinely use the horizontal directional drilling techniques to cross rivers by drilling a horizontal well from one side of the river bank, several feet under the river bottom and across to the other bank. Refs.1 and Ref. 2 are horizontal directional drilling publications, which show examples where this technology has been successfully used in river crossings like the Chinese Yangtze River where the crossing was 5,538 feet laterally and 170 feet below the ground level. Some environmental uses have developed recently in which horizontal wells are drilled under immovable structures like buildings to allow liquid contaminants to be siphoned off or produced from subsurface layers.

Prior Art:

Various methods and processes have been disclosed for recovery of oil and gas by using horizontal wells. There have been various approaches utilized with vertical wellbores, to heat the reservoirs by injection of fluids and also to create a combustion front in the reservoir to displace the insitu oil from the injection wellbore to the production wellbore.

Wilson in U.S. Pat. No. 5,165,491 provides a mechanism for putting more weight on the drill bit by utilizing the weighted heavy drill collars in the general vertical portion of the well such that the maximum weight component is available on the bit.

U.S. Pat. No. 5,467,834 provides the method and apparatus for drilling the curved portion of a horizontal well by using a flexible composite drill pipe. U.S. Pat. No. 6,202,761 further elaborates on the process of drilling the initial curved portion of the wellbore by placing a window turning shoe and drilling out a window through the casing.

Keller in U.S. Pat. No. 5,803,666 indicates a process to allow a pilot hole to be back-reamed in making a horizontal crossing with an inverted liner to support the wall of the wellbore.

Landers in WO 99/66168 describes a drilling apparatus for horizontal wells using a horizontal cutting jet blaster device under very high hydraulic pressure. U.S. Pat. No. 5,934,390 by Uthe discusses a similar jet drilling approach.

Rozendaal in patent application US2002/0066598 A1 discloses a reaming device which allows the pilot hole drilled by horizontal drilling machines used in underground utilities for gas, water, electric and phone lines to be reamed to a larger diameter.

U.S. Pat. No. 6,357,537 illustrates the typical use of conventional horizontal directional drilling equipment and the drilling process. This patent and others like it show the use of the drilling technology limited to shallow utility type crossings.

Rankin et al. in patent US2002/0096362 A1 describe a back-reamer device used to enlarge a pilot hole. This device is steer-able and allows the back-reaming process to maintain correct alignment.

Balton in U.S. Pat. No. 5,402,851 teaches a method wherein multiple horizontal wells are drilled to intersect or terminate in close proximity to the vertical well bore. The vertical wellbore is used to actually produce the reservoir fluids. The horizontal wellbore provides the conduits, which direct the fluids to the vertical producing wellbore.

Butler et al in U.S. Pat. No. 4,116,275 use a single horizontal wellbore with multiple tubular strings internal to the largest wellbore for steam recovery of oil. Steam was injected via the annulus and after a soak period the oil is produced from the inner tubing strings.

U.S. Pat. No. 5,626,193 by Nzekwu et al disclose a single horizontal well with multiple tubing elements inside the major wellbore. This horizontal well is used to provide gravity drainage in a steam assisted heavy oil recovery process. This invention allows a central injector tube to inject steam and then the heated produced fluids are produced backwards through the annular region of the same wellbore beginning at the farthest or distal end of the horizontal wellbore. The oil is then lifted by a pump. This invention shows a method where the input and output elements are the same single wellbore at the surface.

U.S. Pat. No. 5,215,149 Lu, uses a single wellbore with concentric injection and production tubular strings in which the injection is performed through the annulus and production occurs in the inner tubular string, which is separated by a packer. This packer limits the movement of the injected fluids laterally along the axis of the wellbores. In this invention the perforations are made only on the top portion of the annular region of the horizontal well. Similarly the production zone beyond the packer is made on the upper surface only of the annular region. These perforated zones are fixed at the time of well completion and remain the same throughout the life of the oil recovery process.

Huang in U.S. Pat. No. 4,700,779 describes a plurality of parallel horizontal wells used in steam recovery in which steam is injected into the odd numbered wells and oil is produced in the even numbered wells. Fluid displacement in the reservoir occurs in a planar fashion.

U.S. Pat. Nos. 6,951,247, 6,929,067, 6,923,257, 6,918,443, 6,932,155, 6,929,067, 6,902,004, 6,880,633, 20050051327, 20040211569 by various inventors and assigned to Shell Oil Company have provided a very exhaustive analysis of the oil shale recovery process using a plurality of downhole heaters in various configurations. These patents utilize a massive heat source to process and pyrolize the oil shale insitu and then to produce the oil shale products by a myriad of wellbore configurations. These patents teach a variety of combustors with different geometric shapes one of which is a horizontal combustor system which has two entry points on the surface of the ground, however the hydrocarbon production mechanism is considerably different from those proposed herein by this subject invention.

Shell U.S. Pat. No. 6,953,087 shows that heating of the hydrocarbon formation increases rock permeability and porosity. This heating also decreases water saturation by vaporizing the interstitial water. The combination of these changes increases the fluid transmissibility of the formation rock in the heated region.

U.S. Pat. No. 6,948,563 illustrates that increases in permeability may result from a reduction of mass of the heated portion due to vaporization of water, removal of hydrocarbrons, and/or creation of fractures. In this manners fluids may more easily flow through the heated portion.

U.S. Pat. No. 3,994,341 teaches a vertical closed loop system inside the wellbore tubulars in which a vertical wellbore is used to generate a vertical circulation of hot fluids which heat the wellbore and nearby formation. Hot fluids and drive fluids are injected into upper perforations which allow the driven oil to be produced from the bottom of the formation after being driven towards the bottom by the drive fluid.

U.S. Pat. No. 6,7255,922 utilizes a plurality of horizontal wells to drain a formation in which a second set of horizontal wells are drilled from and connected to the first group of horizontal wells, These wells from a dendritic pattern arrangement to drain the oil formation,

U.S. Pat. No. 6,729,394 proposes a method of producing from a subterranean formation through a network of separate wellbores located within the formation in which one or more of these wells is a horizontal wellbore, however not intersecting the other well but in fluid contact through the reservoir formation with the other well or wells.

U.S. Pat. No. 6,708,764 provides a description of an undulating well bore. The undulating well bore includes at least one inclining portion drilled through the subterranean zone at an inclination sloping toward an upper boundary of the single layer of subterranean deposits and at least one declining portion drilled through the subterranean zone at a declination sloping toward a lower boundary of the single layer of subterranean deposits. This embodiment looks like a waveform situated in the rock formation.

U.S. Pat. No. 5,167,280 teaches single concentric horizontal wellbores in the hydrocarbon formation into which a diffusible solvent is injected from the distal end to effect production of lowered viscosity oil backwards at the distal end of the concentric wellbore annulus.

U.S. Pat. No. 5,655,605 attempts to use two wellbores sequentially drilled from the surface some distance apart and then to have these wellbores intersect each other to form a continuous wellbore with two surface wellheads. This technology while theoretically possible is operationally difficult to hit such a small underground target, i.e the axial cross-section of a typical 8-inch wellbore using a horizontal penetrating drill bit. It further teaches the use of the horizontal section of these intersecting wellbores to collect oil produced from the formation through which the horizontal section penetrates. Oil production from the native formation is driven by an induced pressure drop in the collection zone by a set of valves or a pumping system which is designed into the internal concentric tubing of this invention. The 5,655,605 patent also describes a heating mechanism to lower the viscosity of the produced oil inside the collection horizontal section by circulating steam or other fluid through an additional central tubing located inside the horizontal section. At no time does the steam or other hot fluid contact the oil formation where viscosity lowering by heat transfer is needed to allow oil production to occur.

U.S. Pat. No. 4,532,986 teaches an extremely complex dual well system including a horizontal wellbore and a connecting vertical wellbore which is drilled to intersect the horizontal well. The vertical well contains a massively complex moveable diverter system with cables and pulleys attached to the two separate wellheads to allow the injection of steam. This system is used to inject steam from the vertical wellhead into the horizontal wellbore cyclically and sequentially while the oil is produced from the wellhead at the surface end of the horizontal well.

U.S. Pat. No. 4,037,658 teaches the use of two vertical shafts or wells connected by a cased horizontal shaft or “hole” with a flange in the vertical well. This type of downhole flange connection is extremely difficult if not impossible to implement in current oilfield practice. Two types of fluids are used in this patent, one inside the horizontal shaft as a heater fluid and one in the formation as a drive fluid. Both fluids are injected either intermittently of simultaneously from the surface wellheads. The laboratory demonstration in this patent shows that the annular steam zone is very conductive to oil production and allows premature steam breakthrough. Based on this demonstrated observation, it is difficult if not impossible, to conceive a situation taught by this patent in which the injected steam as drive fluid will not preferentially flow under the hundreds of pounds injection pressure along the heated annular zone and thus bypassing the cold viscous oil saturated formation. It is noted that the cold viscous formation has an almost zero mobility. This patent essentially teaches a system in which the injected steam shall be cycled through the horizontal tube and the annular zone in the formation under field conditions providing little if any sweep efficiency.

U.S. Pat. No. 3,986,557 claims a method using a horizontal well with two wellheads that can inject steam into a tar sand formation mobilizing the tar in the sands. In this patent, during the injection of the steam it is hoped that the steam will enter the formation and not continue directly down the open wellbore and back to the surface of the opposite wellhead. It is difficult to visualize the steam entering a cold highly viscous formation while a highly open wellbore is available for fluid flow away from the formation. Furthermore, U.S. Pat. No. 3,986,557 teaches that the steam is simultaneously injected through perforations into the cold bitumen formation while hot oil is flowing through the same perforations, in the opposite direction through the rock pore structure, against the invading high pressure steam. This situation is not only physically impossible but it thermodynamically impossible for the hot fluid to flow “against the pressure gradient”.

U.S. Pat. No. 4,445,574 teaches the drilling of a single well with two wellheads. This well is perforated in the horizontal section and a working fluid is injected into the wellbore to produce a mixture of reservoir oil and injected working fluid. Similar to the U.S. Pat. No. 3,986,557 patent it is difficult from a hydraulic point of view to visualize and contemplate the working fluid entering the formation while an open wellbore is available for fluid flow horizontally and vertically out the distal end of this wellbore.

U.S. Pat. No. application 20050045325 describes a recovery mechanism for heavy oil hydrocarbons in which a pair of wells is used. A vertical injector well is horizontally separated from a vertical production well. The hot fluid, steam or air is injected into the bottom portion of the injector and is expected to displace the very viscous immobile oil from the cold reservoir and push this hot oil through the cold oil saturated formation eventually to the producer. The invention expects oil flow to occur by drilling a web or radial channels from the injector to the producer. It is inconceivable that viscous cold oil, or even lower viscosity hot oil will preferably flow along these channels while extremely low viscosity high-pressure steam will flow through the cold formation. Flow in porous media dictates that hot, saturated steam will completely bypass cold viscous oil and the process will be a quick steam recycle process from injector to producer.

Ref. 4, the Society of Petroleum Engineers (SPE), 222 Palisades Creek Dr., Richardson, Tex. 75080, U.S.A, publishes several hundred papers on heavy oil recovery.

SPE paper 37115 describes a single-well technology applied in the oil industry which uses a dual stream well with tubing and annulus: steam is injected into the tubing and fluid is produced from the annulus. The tubing is insulated to reduce heat losses to the annulus. This technology tries to increase the quality of steam discharged to the annulus, while avoiding high temperatures and liquid flashing at the heel of the wellbore.

SPE paper 78131 published an engineering analysis of thermal simulation of wellbore in oil fields in western Canada and Calif., U.S.A.

SPE paper 53687 shows the production results during the first year of a thermal stimulation using dual and parallel horizontal wells using the SAGD technology in Venezuela.

SPE paper 50429 presents an experimental horizontal well where the horizontal well technology was used to replace ten vertical injection wells with a single horizontal well with limited entry. The limited-entry perforations enabled steam to be targeted at the cold regions of the reservoir.

SPE paper 75137 describes a THAI—‘Toe-to-Heel Air Injection’ system involving a short-distance displacement process, that tries to achieve high recovery efficiency by virtue of its stable operation and ability to produce mobilized oil directly into an active section of the horizontal producer well, just ahead of the combustion front. Air is injected via a separate vertical or a separate horizontal wellbore into the formation at the toe end of different horizontal producer well and the combustion front moves along the axis of the producer well.

SPE paper 50941 presents the “Vapex” method which involves injection of vaporized hydrocarbon solvents into heavy oil and bitumen reservoirs; the solvent-diluted oil drains by gravity to a separate and different horizontal production well or another vertical well. S

PE paper 20017 teaches a computer simulation of a displacement process using a concentric wellbore system of three wellbore elements and complex packers in which steam is injected in a vertical wellbore similar to that in the U.S. Pat. No. 3,994,341 patent. Simulated steam injection occurs through one tubing string and circulates in the wellbore from just above the bottom packer to the injection perforations near the top of the tar sand. This perforations near the top of the tar sand. This circulating steam turns the wellbore into a hot pipe which heats an annulus of tar sand and provides communication between the steam injection perforations near the top of the tar sand and the fluid production perforations near the bottom of the tar sand. This process requires 7 years to increase oil production from 20 BOPD to 70 BOPD.

SPE paper 92685 describes U-tube well technology in which two separate wellbores are drilled and then connected to form a single wellbore. The U-tube system was demonstrated as a means of circumventing hostile surface conditions by drilling under these obstacles.

SPE 76727 describes that steam displacement in an underground hydrocarbon reservoir occurs because of three components driving oil production. These are gravity drainage, steam drag and steam drive. Gravity drainage is caused by the oil column height and the difference in density between the hot oil and the steam vapor. Steam drag is caused by the relative motion between the steam and oil and the steam dragging the oil along. Steam drive is the force created by the steam pushing the oil ahead of the steam as it moves through the reservoir.

Ref. 5 shows conclusively that the gravity drainage effect is the most critical factor in oil recovery in heavy oil systems undergoing displacement by steam.

Very few of these prior art systems have been used in the industry with any success because of their technical complexity, operational difficulties, and being physically impossible to implement or being extremely uneconomical systems.

Shortcomings of prior art can be related a combination of effects. These include;

    • the inability of the method to inject the hot fluid into a cold highly viscous oil in the formation;
    • the inability to overcome the viscosity effect, wherein the viscosity of steam is less than 0.020 cp under the reservoir conditions which makes the flow of steam through porous media 5,000,000 times easier than cold high viscosity oil of 100,000 cp. This flow ratio is based directly on the viscosity ratios of 100,000/0.02;
    • the inability of the method or process to prevent bypass of injected fluid directly from the injector source towards the producing sink;
    • the inability of the method or process to provide an effective seal to prevent high pressure injected steam from bypassing cold viscous oil impregnated formation and moving directly from the injector source towards the producing sink;
    • the inability of the method or process to form a viable communication zone from the steam zone or chamber to the producing sink while preventing bypass and early breakthrough of steam;
    • the inability of the process to utilize the significant gravity drainage effects created by the low density of the hot steam compared to condensed water and hot oil;
    • the inability of the method to heat the formation effectively by physical contact between the steam and the rock formation such that the latent heat, which the major source of heat energy compared to the sensible heat, can be transferred to the rock and hydrocarbons efficiently;
    • the requirement of long injection lead times of months to years of hot fluid injection, before there is any production response of the displaced oil;
    • the use of overly complex equipment of questionable operational effectiveness to implement the method in the field.

For example, in U.S. Pat. No. 3,994,341, this embodiment which although on the surface resembles the invention herein differs significantly since the U.S. Pat. No. 3,994,341 patent forms a vertical passage way only by circulating a hot fluid in the wellbore tubulars to heat the nearby formation, the 3,994,341 patent claims the drive fluid promotes the flow of the oil by vertical displacement downwards to the producing perforations at the bottom, the U.S. Pat. No. 3,994,341 patent teaches that the production perforations are set at the bottom of the vertical formation, a distance which can be several hundred feet. In this U.S. Pat. No. 3,994,341 embodiment, since no control mechanism like a back pressure system or pressure control system is taught, it is obvious that the high pressure drive steam, usually at several hundred pounds pressure, will preferentially flow down the vertical passageway immediately on injection and bypass the cold formation with its highly viscous crude and extremely low transmissibility. The same argument of steam bypass applies to U.S. Pat. No. 4,037,658 which teaches a horizontal tube arrangement instead.

Secondly, the large distance between the top of the formation and the bottom of the formation will cause condensation of the drive steam allowing essentially hot water to be produced at the bottom with low quality steam, both fluids being re-circulated back to the surface. In addition the mechanism to heat the near wellbore can only be based on conductive heat transfer through the steel casing. Since there is no formation rock contact with the steam fluid in which latent heat transfer to formation fluids and rock is the major heat transport system, the U.S. Pat. No. 3,994,341 method is incapable of delivering sufficient heat in a reasonable time to heat the formation sufficiently lower the viscosity of the oil, raise the porosity and permeability of the formation as taught in the present patent application.

To date, the majority of producing or injection horizontal well embodiments shown in the petroleum industry have but a single wellhead and are all limited by several physical and operational problems associated with the physical nature of the embodiments. This new embodiment shown herein removes many of the problems associated with the prior art.

In this new embodiment, using 3 drilling phases, a horizontal well is drilled downward to the target formation and across the target producing formation at the required depth and at a predetermined angle and then upward back to the surface. Inside the formation the wellbore is drilled at a slant such that the essential gravity flow component of the recovery process can be optimized. In this phase of the drilling process, a typical drilling plan with a conventional drilling bottom hole assembly is used. At the end of the horizontal or lateral portion, the start of the upward leg of the well is initiated. Since drilling “uphill” is operationally more difficult with heavy drill pipe and working against gravity, a novel solution is needed. This invention also teaches this novel solution.

In this upward portion a smaller bottom hole assembly with a smaller drill bit used. A small pilot hole is drilled on the upward portion to allow for operational ease and to minimize any problems in the drilling process. This smaller hole requires less drilling torque produces less drag and requires less weight on the bit. The portion is drilled in two phases. It also minimizes drilling fluid loss and any damage to the near surface water zones. This is one novel and innovative part of this embodiment since the well involves drilling holes of varying diameters drilled in two or more sequential sections in which the last section is being drilled upwards to the surface of the ground. In one embodiment when the pilot hole is completed, the upward section can be enlarged by back reaming it to a larger size by using a reamer bit that is pulled from the exit side backward toward the horizontal leg of the well. This approach is similar to that used in river crossings in the pipe laying industry. In another embodiment an option is to use a conventional rig and ream the hole in the usual manner by drilling forward. This sequence of operations provides a novel approach to building the upward section of the well bore. In both cases the near surface groundwater must be protected by casing put in place or by using low loss fluids during the drilling process.

All of the prior art relates to horizontal directional drilling used primarily for river crossings, highway crossings involved in pipeline laying, optical fiber laying and environmental remediation. No effort to date has used this technology effectively for oil recovery in a manner and form such as the uniwell™ described herein.

It is seen that the above prior art techniques have several shortcomings and disadvantages that can be avoided by the current invention while improving the recovery process efficiency and lowering the costs.

There is a long felt need in the industry for a means of moving the heated low viscosity crude oil that has been contacted by the steam in the steam zone to a place or location where it can be produced without having to move it through a cold heavily viscous oil impregnated formation. This problem has continued to baffle the contemporary and prior art with possibly the only exception being the SAGD patent which uses two horizontal wells closely juxtaposed in a vertical plane. Even this SAGD approach has inherent difficulties in initiating the hot oil flow between the two wellbores. Trying to push the hot oil through a cold formation is an intractable proposition. The subject invention offers a solution to this need and provides the mechanism by which the solution can be implemented using conventional equipment and procedures.

THIS NEW INVENTION provides an improvement in the method whereby the operator drills a specially designed horizontal well which is drilled from the surface down to the producing formation and continues back up to the surface as shown in the figures herein. This continuous wellbore behaves simultaneously as both an injector and a producer. The techniques proposed herein uses a combination of drilling activities that are known separately and distinctly in the industry, but have not yet been utilized in this integrated manner shown in this new invention.

THIS INVENTION allows the operator to rapidly drill a specialized horizontal well to the producing formation which allows efficient recovery of heavy oil from the subterranean formation. This new drilling technology can be applied to the following systems; heavy oil deposits, tar sands and oil shale systems.

THIS INVENTION allows the orderly development of oil reserves, especially heavy oil reserves by allowing the efficient and cost effective production of these deposits.

SUMMARY OF THE INVENTION

An object of this invention is to provide an improved method for recovery of oils from subterranean formations by exploiting the advantages provided by gravity drainage in the displacement process of heavy oils in porous formations using steam or combustion driven displacement processes. The use of a single modified well bore, with a downward, lateral and upward section, the uniwell™, has several engineering benefits including cost reduction, better fluid displacement and more engineering control of the injection and oil recovery process.

The invention presented herein utilizes two of the three components on steam displacement discussed in the prior art. These are gravity drainage and steam drive. There is very little relative motion between the steam and the oil so there is very little steam drag if any at all in this invention.

A more specific objective is to provide an improved means of drilling a producing wellbore in subterranean formations by using a sequential drilling method to build and drill the upward portion of the well after the lateral portion is drilled.

Another specific objective is to provide a means by which the operational difficulties created by using heavy drill pipe and drilling “uphill” can be overcome. The drilling of the upward portion of the wellbore is implemented by using a pilot hole, a new oilfield concept, in which a small pilot hole is drilled upwards with a very small drilling assembly and bit and then the bore of this section can be enlarged afterwards.

Another specific objective is to provide a means for enlarging the upward section of the wellbore by using a back reaming process with a back reaming bit from the exit end to the horizontal lateral.

Another specific objective is to provide a means for enlarging the upward section of the wellbore by using a forward reaming process from the exit end to the horizontal lateral by using a typical conventional drilling rig with a forward drilling reaming bit.

Another specific objective is to provide for maximum gravity drainage during oil production by drilling the lateral portion at an angle selected to maximize oil production while allowing maximum steam effect on the formation during steam recovery processes.

Another specific objective is to provide a means whereby the lateral portion of the uniwell™ can be extended below the target oil zone to allow maximum contact and drainage within the oil zone of the injected steam and still provide the necessary gradient needed for gravity drainage of heated oil.

Another specific objective is to provide a means where the upward portion of the uniwell™ can begin below the oil zone and be extended upwards to the surface to accommodate the extended lateral wellbore as described above.

Another specific objective is to provide a means whereby the same wellbore perforations along the horizontal section of the wellbore can be used sequentially for either injection or production as required by the operator.

Another specific objective is to use the movable packer between the injection and production perforations, which forces the steam to exit the wellbore and enter the oil zone at a preset location upstream of the production perforations.

Another specific objective is after the initial oil region is depleted, to unseat and move the movable packer between the injection and production perforations a preset distance along the axis of the wellbore and reseat it to allow the steam displacement process to continue throughout the reservoir in a new undepleted oil zone.

Another specific objective is to provide a means to considerably reduce the distance the heated oil has to move from the steam injection point to be produced in the wellbore through the producing formations.

Another specific objective is to provide a concentric communication channel in the formation, which allows the heated oil to move from the upper steam zone to the perforations in the lower production zone.

Another specific objective is to provide a means whereby oil production begins as early as possible during the injection process compared to existing technologies like Steam Assisted Gravity Drainage (SAGD) and conventional Thermal Enhanced Oil Recovery (TEOR).

Another specific objective is to minimize the need to preheat the producing elements of the wellbore and the near wellbore region for a long time to raise the temperature and to lower oil viscosity in order to initiate oil production into the cold producer region.

Another specific objective is to maximize steam zone growth by keeping the steam vertically isolated and higher within the oil formation thus allowing greater steam growth and less potential for steam breakthrough.

Another specific objective is to allow the steam to replace oil and to pressure up the steam bank at the top, which helps to displace low viscosity, heated oil downwards along the interface of steam/cold reservoir oil to the producing perforations where there exists a pressure sink because oil is being removed during production.

Another specific objective is to minimize the effects of a bottom water drive on degrading the steam efficiency since the short distance between steam and oil production perforations allows steam to maintain contact with new oil and not be diffused into the bottom water and dissipate its heat content to the higher heat capacity interstitial water.

Another specific objective is to allow the horizontal wellbore to be drilled close to the bottom of the formation where a water zone exists by making the perforations on the upper side of the lateral wellbore using specialized perforating techniques available in the industry. This allows the injected steam to enter the oil zone preferentially and to stay out of the bottom water zone, while the hot produced oil can be produced from the perforations downstream of the injector point.

Another specific objective is to preclude the need for two wellbores in the same vertical plane, to recover oil as shown in some conventional SAGD technologies, since in thin zones, it is impossible to successfully drill two workable oil wells within the same thin zone using existing drilling equipment.

Another specific objective is to overcome the need for two vertically separated wellbores within close tolerances as proposed in SAGD which is expensive and depends on critical placement of two wells within a vertical axis of 2 meters or less to guarantee hot oil dripping from the top well will not bypass the bottom well.

Another specific objective is to allow the steam to be injected in a horizontal or planar manner into the reservoir. This planar flow from the horizontal axis of the wellbore creates smaller pressure gradients as opposed to pure radial flow in the customary steam injection process.

Another specific objective is to create smaller pressure gradients by the inward horizontal flow along a significant wellbore distance during the production phase and therefore lower the possibility of coning of fluids, in this case steam and formation water. The coning of steam and/or water is an unwanted condition in this type of recovery system since it wastes energy and produces water that replaces oil.

Another specific objective is to drill the wellbore with different diameters in different sections particularly in the lateral portion and the upward leg to minimize costs, increase production and control well bore location.

Another specific objective is to use the accumulated oil in the lateral and upward portion of the wellbore to act as an U-tube device, which behaves similarly to a P-trap in a household drain, allowing the steam to remain on the injector side of the wellbore and maximize growth of the steam zone in the reservoir where it is more effective.

Another specific objective is to use the produced oil, which accumulates in the lateral and upward portion of the wellbore to act as a backpressure system such that the steam bank is prevented from break through by flowing down the wellbore.

Another specific objective is to use the bottom hole pump and by controlling surface production rates thereby allowing the reservoir pressure to be maintained at a level such that no steam is produced because of the back pressure in the production wellbore.

Another specific objective is to use the slim-hole drilling in the upward portion of the wellbore to minimize damage to near surface water zones on the “punch-out” or exit side of the wellbore since drilling occurs through a small rock volume limiting the potential for surface zone damages.

Another specific objective is to use the slim-hole drilling in the upward portion of the wellbore to minimize damage to near surface water zones since the drilling time is very short and fluid loss during the short time is minimized.

Another specific objective is to use a plurality of parallel uniwells™ simultaneously over a large areal extent to maximize reservoir recovery by minimizing the heat losses laterally from a single uniwell™ and to provide a steam drive process that increases production by literally having a steam front move through the reservoir as a vertical plane.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention consists of the wellbore and associated components shown in the figures below:

FIG. 1 Shows an overview of the uniwell™, with the downward, the horizontal lateral and the upward sections of the wellbore.

FIG. 2 Shows the completed downward and lateral portion of the uniwell™ with the initiation of the pilot hole using a smaller bottom-hole drilling assembly.

FIG. 3 Shows the completion of the pilot hole.

FIG. 4 Shows and the initiation of the back reaming process to enlarge the pilot hole.

FIG. 5 Shows and the initiation of the forward reaming process to enlarge the pilot hole.

FIG. 6 Shows the extension of the lateral section of the wellbore below the oil zone and into the under-burden to allow maximum contact of steam in the oil zone. Also shown is upward section.

FIG. 7 Shows a field use of the embodiment in steam recovery of heavy oil.

FIG. 8 Shows a field use of the embodiment in an in-situ combustion recovery of heavy oil or tar sands.

FIG. 9 Shows the flow lines in plan view of a single uniwell™ during a sequence of operational phases in which the movable packer is unseated, moved and re-seated after local oil depletion occurs.

FIG. 10 Shows a plurality of uniwells™ located in parallel in a reservoir system.

FIG. 11 Shows initial heating of the near wellbore zone to allow communication pathway for heated oil. This is done by a removable downhole heater or less effectively by circulating a hot fluid like steam.

FIG. 12 Shows the reamed out open-hole zone which is concentric to the wellbore and used for hot oil communication from the injection zone steam bank to the production perforations.

FIG. 13 Shows a block diagram of the operational aspects of the invention.

FIG. 14 Shows a block diagram continuing the operational aspects of the invention.

FIG. 15 Shows a block diagram continuing the operational aspects of the invention.

FIG. 16 Shows the graph of production during a typical operation of the prior art in which a “huff and puff” steam field operation is implemented.

FIG. 17 Shows the graph of the almost continuous steam injection operations implemented in this invention, with the non-injection periods for wellbore annulus heating and moving of retractable packers.

FIG. 18 Shows the on-off oil production graph in a more detailed version of a part of the production cycle early in the life of the field operations.

FIG. 19 Shows the graph of the growth trend in oil production rates as the steam injection continues followed by the natural decline accompanying oil reserves depletion.

Item No. Description of Elements
 1 Uniwell Wellbore
 2 Underburden Formations
 3 Overburden Formations
 4 Entry wellhead on input side.
 5 Exit wellhead on punch-out side.
 6 Downward section of horizontal well bore
 7 Lateral or horizontal section of wellbore
 8 Completed upward section of horizontal wellbore
 9 Surface of ground
10 Kick off point for start of curved portion of wellbore
11 Drilling Assembly
12 Pilot Hole
13 Upward section of horizontal wellbore after pilot drilling
14 Back reamer Bit
15 Enlarged Wellbore of upward section
16 Drill Pipe
17 Pull back drill rig used in back reaming process
18 Drill rig used in forward reaming process
19 Drill Pipe used in forward reaming process
20 Forward Reaming Bit
21 Overshoot Extension of lateral into underburden
22 Direction of Bit Travel
23 Subterranean Oil Zone
24 Downhole Pump
25 Casing Tubular pipe
26 Liner tubular pipe
27a Perforations for injection
27b Perforations for production
28 Drilling Rig
29 Moveable Oilfield Packer
30 Injected Steam Zone or Steam Bank
31 Hot oil flow direction
32 Parallel wellbores
33 Injected gases for combustion front
34 Burned zone behind combustion front
35 Combustion Front
36 Zone of vaporized oil
37 Light Hydrocarbon Zone
38 Hot Produced Oil
39 Downhole Heater
40 Power Cable to Heater
41 Annular steamed communications zone
42 Reamed out annular zone
43 Hydraulic P-Trap effect
44 Steam injection time.
45 Steam soak time
46 Oil production rate decline curve
47a Oil production cycle period.
47b Oil daily production rate
47c Well Shut-in period, zero production rate
48 Wellbore heating period.
49 Oil flow rate increase trend
50 Oil flow rate decreasing trend.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT:

Referring now to the drawings wherein like reference numerals designate corresponding elements throughout all the figures and referring in particular to FIG. 1. an improved method for extracting hydrocarbons according to an example embodiment of the invention includes a wellbore 1 consisting of three primary sections. As shown in steps 100, 101, 102, in FIG. 13 and in FIG. 1, a downward section 6, a lateral section 7 and an upward section 8 are drilled with conventional oilfield equipment. The downward section 6 has an entry wellhead 4 and is more or less vertically drilled depending on the nature of the recovery operations. Within the scope of this description a horizontal well or horizontal well section means a well or well section, which is substantially at or close to horizontal inclination. The horizontal or lateral section 7 is drilled in the producing oil formation 23, which is a porous medium containing oil, gas and water in the pore spaces. The upward section 8 is a continuation of the lateral section 7 upward along a predetermined curve to the surface 9. A steel casing 25 or steel liner 26 depending on the type of well and the location within the formation can line the wellbore 1. In other embodiments an “open-hole” completion can be used in which there is no steel casing. This can be done in well consolidated rock formations. At the entry end of the well 1 there is an entry wellhead 4 and an exit wellhead 5 is on the distal end.

Perforations 27 b, 27 a are made in the casing to allow oil to be produced or in the case of injection operations to allow injected fluids to enter the oil zone 23. The oil zone 23 is overlain by an overburden 3 and under-burden zone 2. These zones are impermeable and trap the hydrocarbons in the oil zone 23 and from which oil production is possible when the well 1 drilled into the oil zone.

Referring to FIG. 2, a drilling assembly 11 is used to drill through the formations. This assembly is connected to the drill rig 28 at the surface by a drill pipe 16. In some cases the bottom hole assembly consists of a downhole motor and a drill bit. In other cases coiled tubing can be used instead of drill pipe. All the drilling practices are well known in the industry and are not part of this invention. The point where the vertical hole section 6 changes to a horizontal section 7 is called the kickoff point 10. Referring to FIG. 3, a small pilot hole 12 is that portion of wellbore 12, which extends from the lateral section 7 to the surface 9 along a predetermined path 13.

Referring to FIG. 4, the back reaming process shown in step 101 is implemented, using the back-reamer bit 14 which travels through the pilot hole 12. The bit 14 is pulled backwards by pull back drill rig 17 at surface 9 using the drill pipe 16. The enlarged hole 15 develops behind the reamer bit 14. Referring to FIG. 5, a forward reaming process is subsequently implemented by using the forward reamer bit 20 is connected to the drill rig 18 at the exit end 5 by drill pipe 19. The reamer bit 20 moves in a forward direction 22 as it moves down the pilot hole 12 while the rig 18 rotates the reamer bit 20. In FIG. 6, the lateral section 7 can be extended 21 below the oil zone 23 and into the under-burden 2 in order to extend the range of the well and allow more gravity effect on production in the vertical direction. A downhole pump 24 is shown in this embodiment. The pump is used to lift the produced fluids to the surface as needed.

FIG. 7 shows an embodiment of the invention for steam recovery of heavy oil. In a conventional steam recovery process, steam usually generated on the surface using combustion boilers or as a by product of a electric power cogeneration operation, is injected into the injector wellbore to heat the heavy oil, decrease its viscosity and drive it towards a producer well some distance away from the injector. Referring to FIG. 11, as indicated in steps 103 and 104 b of FIG. 13 in this embodiment, a downhole heater 39 is used to conductively preheat a near wellbore annular region 41 to a relatively high temperature of several hundred degrees Fahrenheit between 300 F and 700 F, in a short time. This temperature is sufficient to increase the rock permeability, lower the in-situ hydrocarbon viscosity significantly, raise the rock porosity and increase the oil saturation in the heated zone. After this preheat operation is implemented for a sufficient period of time, the downhole heater is removed. Referring to FIG. 7, in this embodiment, steam 30 is injected into the oil zone 23 through perforations 27 a which are strategically placed in the well casing 25. As indicated in step 105 the steam is prevented from traveling down the wellbore by a movable packer 29, which separates the steam injector section from the oil production section. In an “open hole” completion, this packer 29 can be a retractable inflatable packer in those situations where the well is completed without a casing 25. This blocking packer is retracted and moved along the axis of the lateral 1 as the steam zones are depleted and new oil production occurs as the processes are repeated.

During the recovery process, the steam forms a zone or steam bank 30 in which oil is heated creating a tremendous drop in viscosity allowing the oil to flow easier. A viscosity drop from 10,000 cp at reservoir conditions to 2 cp at steam conditions is possible. The annular region pre-heated in step 104 b by the downhole heater provides a high conductivity communication path 41 and driven by gravity and other hydraulic forces, the hot low-viscosity oil 38 moves to the lower downstream perforations 27 b as shown in step 108 of FIG. 14. As hot oil 38 accumulates in the lateral section 7 and fills the wellbore, it provides a hydraulic “P-trap” effect 43 shown in FIG. 6, which acts as a backpressure valve preventing the bypass of steam from the upper perforations 27 a to the lower perforations 27 b. In one embodiment, the wellbore segment liquid can be pressured from the surface with natural gas or some inert gas to help implement the “P-trap” effect pneumatically in addition to hydraulically. As indicated in step 109 of FIG. 14, by modulating production rates a process called “choking” in the industry, this backpressure can be used to minimize and prevent any steam bypass in step 110. Oil is produced with a pump 24 if the pressure is insufficient to flow to the surface or it can flow to the surface if the driving pressure is sufficiently high. As can be seen from the physical implementation of this new embodiment the heated oil 38 travels only a few feet, a significantly shorter distance in the steam zone 31 to the producing perforations 27 b. This compares to the very large inter-well distances of several hundred feet, through cold highly viscous oil zones with limited transmissibility that the hot oil has to travel in conventional steam floods as shown in Ref. 3. The new embodiment shown herein allows oil recovery to begin almost instantaneously via the highly communicative annular zone developed by the preheat process described above. This is in stark comparison to the long steam injection and steam soak times needed for the conventional steam flood to displace oil to the producer well.

Referring to FIG. 8 which shows an embodiment of the invention in in-situ combustion recovery of heavy oils or tar sands also called a fireflood. In this embodiment, a downhole heater 39 is used to conductively preheat a near wellbore annular region 41. After this preheat the downhole heater is removed. Air 33 is then injected down the downward section 6 of the uniwell™ through perforations 27 a and into the oil zone 23. Following the operations of a typical fireflood a combustion front 35 is initiated in step 107 a. This burning front 35 creates a zone of vapors 36 and a zone of light hydrocarbons 37 ahead of the combustion front. In the conventional fireflood, the intent is to heat the oil to drop the viscosity and move the free flowing oil towards the producer wellbore several hundred feet distance away. In this embodiment as the combustion front moves forward through the reservoir, the heated oil 38 decreases in viscosity and it flows downwards under gravity and other physical forces to the wellbore 1 and through the highly permeable annular communication zone 41 and enters through the perforations 27 b. As can be seen from the physical implementation of the embodiment the heated oil travels a significantly shorter distance from the combustion zone 35 to the producing perforations 27 b and not needing to flow through a cold formation. This compares to the very large inter-well distances through cold highly viscous oil zones with limited transmissibility, that the front has to travel in conventional combustion floods as shown in Ref. 3. The new embodiment shown herein allows oil recovery to begin almost instantaneously compared to the long combustion times needed for the conventional fireflood to displace oil to the producer well. Oil recovery begins in days via the highly communicative annular zone developed by the early preheat process, rather than in months and years under conventional combustion processes and this time shortened time factor increases the economic viability and profitability of the overall process.

Referring to FIG. 9 a plan view of an embodiment is shown in which two cycles of injection and production are superimposed. The first cycle show the stream flow lines 30 from steam injected into the wellbore perforations 27 a and the oil produced from the wellbore perforations 27 b. After a prescribed time interval, the downhole packer 29 is moved down from position ‘a’ to position ‘b’ in the wellbore between the next set of injection and production perforations. A new cycle of operations is initiated as shown in FIG. 15, steps 113, 114, 115 a, 115 b and 116. The downhole heater 39 is re-installed and the new wellbore annular zone is heated to provide a high conductivity zone for hot fluid movement. Next the first production perforation is converted to steam injection and the oil is produced into the wellbore from the next perforation set along the axis of the lateral wellbore. The stream flow lines 31 are shown in the figure. Continued steam injection can still occur in the first set of steam perforations or they can be plugged off if needed to allow the steam front to advance more rapidly.

Referring to FIG. 10 a plurality of parallel wellbores 32 used in an embodiment is shown. This parallel approach allows a planar displacement of oil by the injected steam as injection continues into the reservoir.

Referring to FIG. 11 the initiation of a flow channel 41 is shown. It is made by initially heating the area around the lateral wellbore 7 by using a removable downhole heater 39 which heats the rock to between 300 F and 700 F. This heating lowers the oil viscosity, increases the rock porosity and permeability and lowers the water saturation in the near wellbore region opposite the downhole heater. It is possible but not nearly as effective to form the communication zone by injecting steam for a few days through the first sets of injectors to allow the zone around the wellbore to be heated and to lower the viscosity of oil in place in this near wellbore region.

Referring to FIG. 12 which shows another embodiment of the invention in which a section of the lateral wellbore 7 is reamed out in step 104 a during the drilling process to make a large open-hole annular zone section 42. This annular cylinder 42 around the wellbore forms the communication zone through which the produced fluids 38 move from the steam zone 30 to the production zone. The steam is injected down the wellbore 6, the wellbore packer 29 diverts the steam into the cold formation 23 where a steam chamber 30 develops. The formation oil is heated by the steam and flows down the sides and periphery walls of the steam chamber under gravity towards the bottom of the steam chamber. The produced oil and condensed steam flow down the reamed out zone 42 towards the bottom of the wellbore. In this embodiment the produced fluids accumulate in the lateral wellbore 7 and fill the production string.

A novel aspect of this invention is the use of the heated oil in the wellbore sections to act as a hydraulic pressure control and a flow control device. By modulating the production of the fluid produced the process creates a back pressure and a fluid “P-trap” seal in the lateral section of the wellbore which prevents the injected steam from bypassing the cold formation and forcing the steam to remain in the steam bank zone and then to grow vertically.

Operationally the drilling operation is summarized as follows; the downward portion 6 is drilled in a conventional manner, at the kickoff point 10 the lateral portion 7 is drilled using the typical horizontal drilling operations found in the oilfield today. At the start of the upward portion 8, the drilling assembly is changed to allow the process to continue less expensively with a slim hole assembly 11, which employs a smaller bit to drill the pilot hole to the surface along a planned trajectory 12. On reaching the exit end on the surface the pilot hole 12 is reamed out to a larger size by either a back reamer 14 or by using a forward reamer bit 20. The extension 21 of the lateral below the oil zone 23 is a simple modification of the basic drilling process. In a similar manner the completion processes which include cementing of casings, perforating of casings, or setting of liners in the wellbore, installing of pumps and valves are basic processes in the oil drilling industry and are well known to all versed in the art.

In engineering the steam injection operation, a computer or simulation analysis is routinely used in the industry to calculate the optimal required injection time of steam into the hydrocarbon bearing formation for optimal oil recovery. This analysis incorporates steam flow rate, steam quality, steam pressure, formation rock properties, oil saturation and depth of formation from the surface.

In this invention, during the earliest steam injection time only, the production of hot oil is maintained at zero to allow the oil to accumulate in (a) the bottom of the steam bank, (b) in the vertical communication zone and (c) in the wellbore segment. This accumulated hot oil behaves as a hydraulic seal preventing steam from bypassing the formation and flowing into the wellbore. In alternative embodiments, the backpressure system described herein prevents the production of oil into the wellbore. These no-flow embodiments are essential and by preventing oil flow, they allow a steam bank to grow since the injected steam is forced to enter the formation directly heating the rock and in-situ hydrocarbons.

After the requisite injection time, which is nominally a matter of days, the production of hot oil and condensed water is initiated by permitting the removal of hot fluids from the wellbore via the production system or by lowering the backpressure on the fluid column in the wellbore. After the production of accumulated hot oil is complete as evidenced by the incipient flow of dry steam detectable at the surface, the fluid production is shut down and the accumulation of hot oil and condensed water at the bottom of the steam bank resumes. It should be noted that in this invention, except as noted later, steam injection is a continuous operation and the oil production phase is started and stopped at specific operational conditions during this thermal recovery process.

This invention differs significantly from the prior art in its implementation in the field. The ability of the well to be produced very soon after steam injection begins, allows oil revenue to begin almost immediately. Furthermore the volumetric flow rate of oil remains relatively constant while the steam bank is growing and can even increase as cumulative steam injection occurs. This is due to the larger volume of rock being contacted and heated thus lowering the oil viscosity and also by increasing the vertical extent of the steam bank, the gravity effect on the oil flow column is increased, both results contribute to increased oil flow rates.

A typical response of a steam heated heavy oil reservoir using the prior art of huff and puff operations is shown in FIG. 16. It should be noted that after the steam injection time 44, steam injection is curtailed and after the soak time 45, the well is put on production as shown in curve element 46. There is an initial increase in oil production rate which immediately declines exponentially to the un-stimulated level after a number of days. This process is repeated several times to fully develop the steam operations and deplete the oil reservoir.

On the other hand, the invention described herein, provides for a very different set of operations. FIG. 17 shows the steam injection period 44 followed by the period 48 in one embodiment in which the wellbore heater 39 is installed in the wellbore and is operated for a fixed time, and during which time the packer 29 is also moved along the wellbore. Note that the steam injection rate is essentially constant, however in practice it is usually necessary to increase the injection rate over time to offset the heat losses as the steam bank increases in size.

FIG. 18 shows a more detailed set of operational data where the well production is intermittent. This occurs early in the steam operations since the steam zone or steam bank 30 is still small and growing and the accumulated oil 38 is insufficient to be produced continuously without compromising the hydraulic seal 43 and allowing steam breakthrough in the communication zone 41 and the wellbore 1. This figure shows the oil production rate 47 b and the oil shut-in period 47 c.

As the steam bank 30 grows, there is more reservoir formation 23 volume available for oil production and there is a concurrent increase in the oil production rate as shown by the trend line 49 in FIG. 19. This trend continues to a maximum point after which there is an inevitable decline due to heat losses, oil depletion and other factors as shown by trend line 50.

Given the increased oil flow rates which begin soon after steam injection, coupled with the growth of the steam bank by almost continuous steam injection, as opposed to the intermittent injection of the prior art huff and puff method; and the concurrent oil production increase, this invention provides for an improvement in the technology and prior art in a manner which allows significant rapid development of hydrocarbon reserves from heavy and viscous oil from subterranean formations with existing equipment and field operations applied in a manner that has been heretofore lacking.

Various modifications and alterations of this invention will become apparent to those skilled in the art without departing from the scope and spirit of this invention and it should be understood that this invention in not unduly limited to that set forth herein for illustrative purposes.

In this patent certain U.S. patents, patent applications, and other materials (e.g., articles) have been incorporated by reference. The text of such U.S. patents, U.S. patent applications, and other materials is, however, only incorporated by reference to the extent that no conflict exists between such text and the other statements and drawings set forth herein. In the event of such conflict, then any such conflicting text in such incorporated by reference U.S. patents, U.S. patent applications, and other materials is specifically not incorporated by reference in this patent

Further modifications and alternative embodiments of various aspects of the invention may be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the claims.

References:

1 Robbins Horizontal Drilling, 29100 Hall St, Solon, Ohio 44139. www.robbinstbm.com

2. The Crossing Company Inc.,1807-8th Street, Nisku, Alberta, Canada T9E 7S8, www.thecrossingcompany.com

3. Improved Oil Recovery—Exxon Background Series (1982), NY. NY 10020.

4. The Society of Petroleum Engineers 222 Palisades Creek Dr., Richardson, Tex. 75080, U.S.A. www.spe.org.

5. “A Comparison of Mass Rate and Steam Quality Reductions to Optimize Steamflood Performance”, Topical Report 108, Gregory L. Messner, July 1998, Stanford University, Stanford, Calif.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7814968Aug 26, 2008Oct 19, 2010Dustin BizonGravity drainage apparatus
US7832482 *Oct 10, 2006Nov 16, 2010Halliburton Energy Services, Inc.Producing resources using steam injection
US8079417 *Aug 13, 2008Dec 20, 2011Conocophillips CompanyWireline retrievable dsg/downhole pump system for cyclic steam and continuous steam flooding operations in petroleum reservoirs
US8091636Apr 30, 2008Jan 10, 2012World Energy Systems IncorporatedMethod for increasing the recovery of hydrocarbons
US8307915 *Apr 10, 2008Nov 13, 2012Schlumberger Technology CorporationSystem and method for drilling multilateral wells using magnetic ranging while drilling
US8469092Jul 17, 2008Jun 25, 2013Shell Oil CompanyWater processing system and methods
US8561704 *Jun 28, 2010Oct 22, 2013Halliburton Energy Services, Inc.Flow energy dissipation for downhole injection flow control devices
US8590615Oct 15, 2008Nov 26, 2013Hole In One Producer AsCasing device
US8646526 *Sep 3, 2008Feb 11, 2014Terratek, Inc.Method and system for increasing production of a reservoir using lateral wells
US8678080May 23, 2013Mar 25, 2014Shell Oil CompanyWater processing systems and methods
US8695730Nov 12, 2012Apr 15, 2014Schlumberger Technology CorporationSystem and method for drilling multilateral wells using magnetic ranging while drilling
US8701770 *Jul 3, 2008Apr 22, 2014Halliburton Energy Services, Inc.Heated fluid injection using multilateral wells
US8820420Jan 9, 2012Sep 2, 2014World Energy Systems IncorporatedMethod for increasing the recovery of hydrocarbons
US8851170 *Apr 9, 2010Oct 7, 2014Shell Oil CompanyHeater assisted fluid treatment of a subsurface formation
US20100258309 *Apr 9, 2010Oct 14, 2010Oluropo Rufus AyodeleHeater assisted fluid treatment of a subsurface formation
US20110036576 *Jul 3, 2008Feb 17, 2011Schultz Roger LHeated fluid injection using multilateral wells
US20110315388 *Jun 28, 2010Dec 29, 2011Halliburton Energy Services, Inc.Flow energy dissipation for downhole injection flow control devices
WO2009012378A1 *Jul 17, 2008Jan 22, 2009Shell Oil CoWater processing systems and methods
WO2009134643A2 *Apr 21, 2009Nov 5, 2009World Energy Systems IncorporatedMethod for increasing the recovery of hydrocarbons
Classifications
U.S. Classification166/302, 166/60
International ClassificationE21B43/24
Cooperative ClassificationE21B43/305, E21B43/2406, E21B43/2408
European ClassificationE21B43/30B, E21B43/24S2, E21B43/24S