US20070284107A1

US20070284107A1 - Heavy Oil Recovery and Apparatus

Info

Publication number: US20070284107A1
Application number: US11/421,798
Authority: US
Inventors: Henry B. Crichlow
Original assignee: Individual
Current assignee: Individual
Priority date: 2006-06-02
Filing date: 2006-06-02
Publication date: 2007-12-13
Also published as: CA2549369A1

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.

Description

CROSS REFERENCES

Reference is made to DD 596,606 filed Mar. 16, 2006 by the inventor.

INTRODUCTION

This invention relates generally to a new technology application used in recovery of heavy and viscous hydrocarbons from subterranean oil bearing formations during hot fluid injection. The technology described is the Single Well Acceleration Production process, herein abbreviated as SWAP which allows a single wellbore to perform simultaneously, injection and production operations in heavy oil recovery systems.
This invention is related to prior filings by the same applicant, pertaining to the overall recovery of hydrocarbons from subterranean oil formations. The technology involves the novel use and application of equipment and techniques in which steam or other hot fluids are injected into substantially horizontal wellbores in which injection and production is obtained from the same wellbore.
One of the new types of horizontal well is called a Uniwell™ because it can have at least 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 has been the subject of several prior applications by the same inventor. This particular invention relates to use of a specialized annular fluid communication zone between the steam zone and the production zone and the additional use of a downhole apparatus to selectively monitor flowing fluid characteristics and subsequently control hot oil production in order to facilitate the injection of steam into the steam bank zone. This control mechanism effects oil displacement by maintaining a viable hydraulic seal in the communication zone between the steam displacement zone and the production zone of the wellbore.
This novel completion technique uses injection and production perforations separated by a moveable wellbore packer and this new apparatus is implemented between the injection and production perforations in the wellbore to sense and monitor the flow of steam and control the production of hot oil.

FIELD OF INVENTION

THIS INVENTION is a unique new approach to heavy oil recovery combining horizontal and lateral wells, steam injection and specialized downhole devices to facilitate operations and to significantly accelerate oil production.
The invention is particularly suited to making heavy oil formations, oil shales 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 shales.

BACKGROUND OF THE INVENTION

1. 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 viscosity, up to a million 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 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, steam distillation, gravity drainage, steam drive and steam drag to move the heated oil from the oil zone into the producing wellbore.
Horizontal wells and lateral wells have played a prominent part in recovery of oil. These wells can be as much as 4 times as expensive to drill as conventional vertical wells but the increased expenses are offset by the increases in 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, drilling and utilizing these horizontal wells. The need to accelerate oil production without waiting for steam to traverse several hundred feet of reservoir rock between injection and production wells has created this new technology. In this technology an approach is used wherein oil production occurs almost simultaneously with steam injection initiation.
2. 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.
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 technically difficult to visualize the steam entering a cold formation with extremely highly viscous oil, while a completely open wellbore is readily 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 in the opposite direction against the invading high pressure steam through the same perforations through the rock pore structure. This situation is not only physically impossible but it thermodynamically impossible for the steam fluid to flow out of, and hot oil flow back into the same perforations simultaneously.
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. 4,034,812 describes a cyclic injection process where a single wellbore is drilled into an unconsolidated mineral formation and steam is injected into the formation for a period of time to heat the viscous petroleum near the well. This causes the unconsolidated mineral sand grains to settle to the bottom of the heated zone in a cavity and the oil to move to the top of the zone.
U.S. Pat. No. 4,037,658 teaches the use of two vertical 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 or simultaneously from the surface wellheads.
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. This approach is basically a modified “Huff & Puff” displacement in which the injection “huff” is done through a complex pre-heated horizontal well bore and the well put on production, the “puff” cycle after a soak period of several days. In other patents, U.S. Pat. Nos. 4,085,803, 4,344,485, 5,407,009, 5,607,016, Butler describes further uses of horizontal wells, solvent type and steam displacement mechanisms to produce viscous oils from tar sands using his SAGD technology.
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 in a vertical direction while an open wellbore is available for fluid flow horizontally and vertically out the distal end of this wellbore.
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.
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. 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. 5,215,149 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.
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 a 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.
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 process where the input and output elements are the same single wellbore at the surface.
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 horizontal wellbore segments 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 U.S. Pat. No. 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 actually contact the oil formation where viscosity lowering by sensible and latent heat transfer is needed to allow oil production to occur.
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. At least one declining portion is 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. 6,725,922 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 arrangements 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. 6,948,563 illustrates that increases in permeability may result from a reduction of mass of the heated portion due to vaporization of water, removal of hydrocarbons, and/or creation of fractures. In this manner, fluids may more easily flow through the heated portion.
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.
U.S. Pat. No. 6,953,087 by Shell, 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. 5,896,928 teaches a “dumb” downhole fluid flow control device that is electrically operated from either the surface or downhole. This device is a simple on-off device, which restricts flow, but is unable to determine, process and operate based on the sensible characteristics of the flowing fluid such as the current invention discussed herein.
A further U.S. Pat. No. 5,868,201 illustrates a downhole system that senses pressure and that actuate a valve system for control of the fluid flow remotely. Similar to U.S. Pat. No. 5,896,928 this system is unable to operate based on the sensible characteristics of the flowing fluid as is needed in the case of steam, flow where pressure is a minor parameter in determining flow regimes.
U.S. Pat. No. 6,006,832 discusses a formation sensor system for monitoring a producing formation in-situ by using permanently mounted sensors in the wellbore. These sensors monitor formation properties using gamma ray, neutron and resistivity sensors. These type sensors are passive and measure rock and interstitial fluid properties needed to discriminate rock types and properties. On the other hand, the present invention herein senses flow parameters and properties needed for flow control.
Patent application 20050072578 describes a thermally controlled valve. This thermally controlled valve is a device that is capable of regulating the flow of material into, through, and out of a wellbore in response only to a change in temperature near the valve. All of the subsequent systems related to the valve operation depend on the temperature behavior and its measurement. In steam operations where there is a need to regulate steam flow in porous media such as injection and production in subterranean heavy oil formations, there is an indispensable requirement to determine the total characteristics of the flowing material. A simple temperature record is insufficient to determine whether flow is a gas, a liquid or a solid. To fully describe what fluid is flowing one needs the temperature, pressure and quality in the case of steam. The 20050072578 application does not address this fact and as such is incapable of discriminating between hot oil, hot water and steam in the flow stream and will be inadequate as a controller of steam flow and a reliable steam shut off mechanism as is needed in heavy oil field steam displacement processes.
The Society of Petroleum Engineers Reference 1, SPE 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 an injection period of 7 years to increase oil production from 20 BOPD to 70 BOPD.
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 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 37089 presents an experimental SAGD study in which the lower horizontal well functions as an intermittent steam-injector and a continuous oil-producer, instead of the usual SAGD production-well while steam is also injected continuously through the upper well.
SPE paper 50941 presents the “Vapex” process 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. 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 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 14916 describes the problem of the dual horizontal wells in a formation with a horizontal shale barrier. This barrier slows down the recovery under the SAGD system of dual horizontal wells since the steam bank formation is slowed by the shale. This analysis also confirms that the gaseous steam overrides the cold viscous crude zone as it is injected into the reservoir. SPE paper 78131 published an engineering analysis of thermal simulation of wellbore in oil fields in western Canada and California, U.S.A.
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 physical obstacles.
SPE 54618 and SPE 37115 describe and illustrate a series of heavy oil production mechanisms. They describe a “technically challenging” process whereby in single well gravity drainage process steam is injected into the “toe” or distal end of a horizontal well while oil is produced at the “heel” or proximal end. This system is similar to other approaches in the prior art and has a serious drawback in that neither investigator describes how the backwards flow from the “toe” to the “heel” can occur under reservoir conditions with the extremely viscous in-situ oil. There is no viable mechanism for the hot oil to travel to the producing point at the heel. However, in this subject application, this conceivably insurmountable obstacle is overcome by implementing a communication zone which forms an active channel between the growing steam bank and the downstream production zone.
Reference 2 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, except the SAGD and Huff & Puff processes, 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.
For example, in U.S. Pat. No. 3,994,341, this patent which although on the surface it has several similar aspects of 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 U.S. Pat. No. 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 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 psi, will preferentially flow down the vertical passageway immediately on injection and bypass the cold formation with its highly viscous crude and extremely low transmissibility. 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. There is ineffective heat transfer since there is no direct steam contact with the formation rock in which latent heat transfer to formation fluids and rock can occur, this latent heat being the major heat transport system. The U.S. Pat. No. 3,994,341 process is incapable of delivering sufficient heat in a reasonable time to heat the formation sufficiently to lower the viscosity of the oil, raise the porosity and permeability of the formation as taught in the present patent application.
Additionally many of the downhole devices patented to control fluid flow in the downhole wellbores are designed as “dumb” systems. These so-called dumb systems simply open or close a flow device depending on an event such as a pressure level or a temperature level. None of the devices used in the heavy oil recovery system by steam to date, examine the quality of the flowing fluid in the novel communication zone to discriminate its nature and thus restrict flow based on this knowledge to maintain a hydraulic seal.
In steam operations where there is a need to regulate steam flow in porous media such as injection and production in subterranean heavy oil formations, there is an indispensable requirement to determine the total characteristics of the flowing material. A simple temperature record is insufficient to determine whether flow is a gas, a liquid or a solid. To fully describe what fluid is flowing one needs the temperature, pressure and quality in the case of steam. The prior art applications do not adequately address this fact and as such are incapable of discriminating between hot oil, hot water and steam in the flow stream and will be inadequate as controllers of steam flow and thereby reliable steam shut off mechanisms as are needed in heavy oil field steam recovery operations.
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 a continuous 3-dimensional volumetric zone in 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 by implementing a hydraulic seal at the bottom of the steam bank and in the communication zone.
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 wellbores 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.
In a much-reported SAGD process that has been used extensively in Canada, there are other shortcomings that limit the efficacy of the process and which have been overcome in this subject invention. It is well known that the SAGD production well must be throttled to maintain the production temperature below the saturation steam temperature to allow a column of fluid to exist over 100% of the production well to minimize bypass of steam. In some situations, in this very operation the newly injected steam comes into the formation at the lower end of the steam bank. It then passes vertically through the overlying hot oil and hot water re-heating this mixture repeatedly which must be kept cool to prevent bypassing of steam; this is called the “sub-cool” effect. In essence, this thermodynamically inefficient process is analogous to running an air conditioner and a heater simultaneously to maintain a room at a fixed temperature. Further, even though the SAGD tries to utilize a limited hydraulic seal as is described in this subject invention, the implementation in this subject patent application is more precise, more operationally efficient and does not provide any detrimental effects on the overall steam process. Having to inject the steam through existing hot oil and water uses up part of the latent heat of the steam which is critical to good reservoir heating and effective oil displacement. This heat loss lowers the overall recovery of the process. In the subject process there is no operational loss of latent heat since the hot oil-water leg is at the bottom of the steam bank and the communication zone and steam is injected directly into the native formation above and not through the oil-water accumulation zone with no loss of heat energy.
There are flow control issues that are inherent in the SAGD process that are not present in the SWAP process invented herein. In the SAGD process the operator has to critically control the steam flow rate along the complete length of the SAGD injection wellbore. This wellbore can be several thousand feet in length as it is drilled substantially horizontally, however any deviation from the horizontal of the producing wellbore provides a potential zone where the steam can break through from the higher injector and “short circuit” the recovery process by producing steam in the lower producer. Maintaining precise horizontal separation as well as the same azimuth, between two lateral wellbores over several hundred feet and more than a thousand feet, is not easy and as such the SAGD process puts higher initial capital costs and difficult and stringent long term operational demands on the recovery process. On the other hand the SWAP process presented herein only needs to control the vertical flow in an axial communication zone over a distance of a few feet. This control is easily performed by the hydraulic seal which fills the communication zone and extends upwards into the bottom zone of the steam bank in much the same way as a heavy fluid can rest at the bottom of a kitchen sink over a plugged sink drain while a lighter fluid remains above. Because of the large volumetric extent of the steam bank encompassing several thousand barrels, production of the accumulated fluids at the bottom of the steam bank can occur for a substantial time before the level of the hydraulic seal is lowered by a few feet. For example, lowering a one acre steam bank one foot can deliver about 1,200 barrels of hot oil and water into the wellbore. This slow lowering of fluid levels allows efficient control of the production process and limits the potential of steam break through into the production wellbore.
A further aspect of the SAGD process is pointed out by in SPE 97647 in which the XSAGD process is described. SPE 97647 teaches that since under SAGD it is impossible to move the injector and producer wells farther apart vertically, to minimize steam breakthrough, this constraint necessitates a lowering of oil production rates as the steam bank grows. However in the present SWAP invention taught herein, the communication zone allows the distance between the injector locations (perforations) and producer locations (perforations) to be constantly changed as needed to meet the expanding steam bank zone dimensions and this implementation allows the new invention to maintain a more level rate of high oil production without any steam breakthrough and in many cases to increase steam injection and consequently oil production as the operations develop and the steam bank contacts a larger volume of reservoir rock.
Another aspect of the SAGD process inefficiency is the need to inject steam in both injection and production wells for periods up to 415 days to “pre-heat” the reservoir and create a communication zone between the two wellbores. In this subject invention as soon as a viable steam bank zone develops in a matter of days, hot oil begins to accumulate in the communication zone at the bottom of the steam bank and can be produced. Economically such a long delay can severely impact the economics of a capital project.
Another negative aspect of this SAGD process is the capital needs for drilling and equipping two horizontal wells to implement the SAGD process. Furthermore, the SAGD process requires a vertical separation between these two horizontal wells and this property limits the SAGD process the relatively thick pay sections and cannot be used in thin reservoir sections. A yet further limitation of SAGD is the effects of water zones at the base of the oil formation on the SAGD process since the steam preferentially enters the water zone and bypasses the cold viscous oil zones. This limits the thermal and economic efficiency of the SAGD process. A yet further problem associated with the SAGD process is the presence of horizontal shale barriers in the oil formation. This shale layer between the horizontal wellbores is in effect a vertical barrier and the SAGD process as designed and implemented is unable to operate since the two horizontal wells are unable to communicate.
Additionally, to increase displacement efficiency in thermal recovery operations, there is a need to discriminate the quality of flowing fluid in the communication zone in a manner that allows the operator to open or shut off the production stream and allow the accumulated fluid to behave as an effective hydraulic seal thus propagating the steam displacement in the steam bank. 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.
Shortcomings of prior art can be related a combination of effects. These include:

- (1) the inability of the process to inject the hot fluid into a cold highly viscous oil in a limited conductivity formation with hydrocarbon viscosities in excess of 106 cp, with this viscosity the liquid is essentially immobile at reservoir temperature.;
- (2) the inability of the method to prevent bypass of injected fluid directly from the injector source towards the producing sink;
- (3) the inability of the method to form and maintain a viable communication zone from the steam zone or chamber to the producing sink while simultaneously preventing bypass and early breakthrough of steam;
- (4) the inability of the process to utilize the very effective gravity drainage flow component created by the low density of the hot steam compared to the relatively high density condensed water and hot oil;
- (5) the inability of the process to heat the formation effectively by physical contact between the steam and the rock formation such that latent heat, the major source of steam heat energy, can be transferred to the rock and hydrocarbons efficiently;
- (6) the requirement of long lead times of months to years of hot fluid injection, before there is any measurable production response of the displaced oil in the production wells;
- (7) the inability of the existing technology to maintain and sustain oil production rates when applied to large patterns of several wells;
- (8) the inability of the downhole devices to determine flowing fluid characteristics other than temperature;
- (9) the inability of the technology to discriminate between flowing hot oil, hot water and steam in the flowing material;
- (10) the inability of the devices to operate based on the knowledge gained form these fluid characteristics;
- (11) finally the use of overly complex equipment of questionable operational effectiveness to implement the process in the field.

The above discussed and other problems and deficiencies of the prior art are overcome or improve upon by the heavy oil recovery system of the present invention by integrating a viable steam bank, an axial and concentric communication zone, an active hydraulic seal, a sensible downhole controller and an operative production system.
In contrast to the aforementioned prior art which try to measure fluid temperatures, or pressures in the wellbore the present invention determines the true nature of the fluid flowing, be it steam, hot oil, hot water or a combination of each fluid. This real time measurement is required since to adequately identify the steam flow a measure of steam quality must be made in real time to allow the controller to shut off the oil production inflow from the steam bank

SUMMARY OF THE INVENTION

THIS NEW INVENTION provides an improvement in heavy oil recovery whereby the operator injects a hot displacing fluid into a specially designed well. An additional implementation is the development of an integral downhole apparatus which behaves as a flow sensor, flow controller and a flow valve simultaneously. Operationally this device provides for flow-or-no-flow of produced fluids depending on the type of fluid detected in the produced flow stream. If the flow is hot oil or water the flow device is opened, when steam is detected the valve is closed. In this application the term flow valve and flow device are used interchangeably for a physical element used to control fluid flow.
In this oil recovery method, the operator drills a well which is drilled from the surface down to the producing formation. There are several embodiments of the well ranging from single vertical wellbores, to combined vertical and horizontal wells and to the uniwell system which has two wellheads.
An object of this invention is to provide an improved process for recovery of heavy oils and similar hydrocarbons from subterranean formations. The invention uses a single well bore with an external annular communication zone between the perforations. In this invention, the accumulation of hot oil and condensed water at the bottom of the steam bank and in the vertical communication zone forms a secure controllable hydraulic seal which prevents steam flow bypass away from the steam bank. An isolation packer vertically separates injection and production perforations.
In one embodiment, the external annular communication zone can be implemented by an additional tubular string outside of the injection and production tubular string. The perforations for flow into and out of the wellbores are in the walls of the steel wellbore casings. In this embodiment, the annular region is a void with infinite permeability. In another embodiment, an open-hole communication zone can be implemented. Depending on the rock formation and oil reservoir properties, the communication zone can range from a few inches to several feet in diameter.
The displacing fluid is forced into the upper perforations by a downhole packer and as steam accumulates heats up and displaces native oil this oil and condensed water gravitate to the bottom of the steam bank and collects in the communication annulus waiting to be produced when the downhole controller opens the flow control valve. In this invention, the flow-no-flow operation permits oil and water production but shuts down when steam flow is detected in the flow stream.
An object of this invention is to provide an improved process for recovery of heavy oils and other highly viscous hydrocarbons from subterranean formations by exploiting the advantages provided by gravity drainage in the displacement process of heavy oils in porous formations using steam driven displacement processes. The use of a modified single well bore with coupled pairs of injector-producer perforations in close proximity under positive and viable flow control has several engineering benefits including cost reduction, better fluid displacement and more engineering control and accelerated economic recovery of the injection and oil recovery process.
Another specific objective is to provide a means whereby the same wellbore perforations along the vertical section of the wellbore can be used sequentially for either injection or production as reservoir oil depletion occurs during steam field operations 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 and the accessory downhole flow controller apparatus a preset distance along the axis of the wellbore and reseat them to allow the steam displacement process to continue throughout the reservoir in a new undepleted or virgin oil zone.
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 production perforations in the lower production zone rapidly and under gravity.
Another specific objective is to provide a means to considerably reduce the distance the heated oil has to move through the producing formations from the steam injection point to be produced in the wellbore.
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), where oil production takes place after a considerable length of steam injection ranging from several weeks to several months and even years.
Another specific objective is to utilize and incorporate the lateral steam gravity over-ride characteristics of the steam drive process to enhance the “backwards” flow of hot oil from the leading edge of the steam displacement front to the hot oil accumulation zone and the communication zone in the invention.
Another specific objective is to utilize a set of staggered lateral mini-wellbores drilled into the oil formation to maximize the injection efficiency of the steam so that a steam override effect is implemented such that a lateral physical flow gradient occurs in the oil zone with a thin leading edge and a thicker trailing edge. The hot oil flows along this three-dimensional surface at the steam-oil interface.
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 hot steam and cold reservoir oil via the communication annulus, to the producing perforations where there exists a localized pressure sink because oil is being removed during production.
Another specific objective is to use a downhole steam controller apparatus to control the flow, no-flow of steam under specific operational conditions.
Another specific objective is to use an operatively connected valve apparatus to shut off the flow of produced fluid in the wellbore when the steam sensor indicates that steam break-through has occurred and that steam is flowing down the annular region from the steam bank to the production perforations.
Another specific objective is to monitor operations such that hot oil is produced until continuous steam breakthrough is imminent then close the downhole production valve.
Another specific objective is to control the downhole apparatus from the surface.
Another specific objective is to utilize a scavenging displacing fluid to recuperate part of the residual hot oil in the heated oil formation by injecting this displacing fluid after the steam injection phase is complete.
This novel utilization proposed herein addresses the needs and teaches a method and apparatus that is easily implemented, allows a larger portion of the reservoir to be exposed and allows more heavy oil recovery to occur sooner.
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 well completion methodology is applied to the recovery effort to allow wells of much larger lateral extent, potentially larger diameters and thereby more efficient recovery systems.
By implementing the new method which is 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.
THIS NEW INVENTION provides an improvement in the recovery methods and operations of other applications wherein the process of steam injection was controlled by a downhole apparatus forming a closed seal, which prevents the production of fluids except under certain field conditions and which on sensing the flow of steam shut off the production fluid flow completely.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 a Shows a schematic of the new downhole apparatus implemented in a uniwell™ system. It shows the steam bank, the injection and production perforations, annular communication zone and the accumulated hot fluids in the wellbore.

FIG. 1 b Shows a schematic of a lateral wellbore with the new downhole apparatus implemented in the lateral system. This implementation can connect the lateral to a central production cavity.

FIG. 1 c Shows a vertical well embodiment with a central production cavity below the wellbore. The steam downhole apparatus is implemented in the inner wellbore as shown.

FIG. 2 Shows the steam zone, the communication zone and the accumulated hot fluids in the steam bank. Also shown is the downhole steam controller installed between the injection and production perforations and also shown is the direction of flow of the steam and the hot oil as they move down the communication zone into the wellbore. This figure depicts a closed system in which the downhole apparatus is closed so that no production occurs.

FIG. 3 Shows a schematic of the new downhole steam controller apparatus illustrating the various component locations. The steam sensor, the packer seal, the valve controller, the shut off valve and the flow of steam and hot fluids around and through the apparatus.

FIG. 4 Shows a schematic of the new downhole apparatus implemented in the wellbore. It also shows the fluid level at the bottom of the steam bank and the flow direction for hot fluid entering the device.

FIG. 5 Shows a schematic of the new downhole apparatus illustrating the device in a closed no-flow condition. FIG. 6 Shows a schematic of the new downhole apparatus illustrating the device in an open flow or producing condition.

FIG. 7 a Shows a schematic of system operating with the new downhole apparatus in the closed position with the hot fluids accumulating to form a hydraulic seal at the bottom of the steam zone. Note the elevated level of the steam-hot fluids interface.

FIG. 7 b Shows a schematic of system operating with the new downhole apparatus in the open position with the hot fluids draining, thus lowering the hydraulic seal level at the bottom of the steam zone and allowing the hot oil and water to enter the production cavity. Note the lower level of the steam hot fluids interface.

FIG. 8 Shows a flow chart of the operations during injection and production.

FIG. 9 a, 9 b, 9 c, 9 d Show 4 flow charts illustrating the sequence of the operations of the invention.

FIG. 10 Shows a graphic of the typical temperature viscosity behavior of an oil sands oil.

FIG. 11 Shows a schematic of the development of the steam bank during injection in a system in which a series of horizontal shale barriers occur in the oil formation.

FIG. 12 Shows a schematic of the scavenging phase in which water is injected at the bottom of the formation as the displacing fluid in separate wellbores after steam injection has depleted the oil formation. Also shown is the growth sequence overlay I, II, III, IV, V, VI of the steam zone.

FIG. 13 Shows a schematic of the scavenging phase in which a non-condensing gas is injected at the top of the formation as the displacing fluid in separate wellbores after steam injection has depleted the oil formation. Also shown is the growth sequence overlay I, II, III, IV, V, VI of the steam zone.

FIG. 14 Shows a schematic of the wellbore system with a set of staggered horizontal mini-wellbores implemented to allow steam injection forming a “wedge” shaped profile.

List of Items

	No.	Item

	1	Wellbore
	2	Downhole Steam Control Apparatus
	3a	Steel casing for wellbore
	3b	Steel casing or Liner for annular reamed zone
	4	Steam bank in Oil Formation
	5	Oil bearing formation
	6a	Hot oil flowing
	6b	Non Flowing Hot Oil
	7	Primary Steam Diverter packer
	8	Annular Communication Zone
	9a	Injection perforations
	9b	Perforations in Cased Liner
	10a	Production perforations in inner wellbore
	10b	Production perforation in outer wellbore
	11	Communication element
	12	Injected Steam Flow down wellbore
	13	Top of Formation
	14a	High Level - Hot Fluids - accumulating phase
	14b	Low Level - Hot Fluids - producing phase
	15	Flow Device (Valve) in Downhole apparatus
	16	Slotted Liner for fluid inflow
	17	Steam in Steam Bank and Annular region
	18	Flow sensor
	19	Flow Valve Controller
	20	Hot oil gravitating down steam bank
	21a	Wellbore packer - internal
	21b	Wellbore packer - external
	22	Bottom of Formation
	23	Steam and Hot oil interface
	24	Steam Flow direction
	25	Surface Steam Generation System
	26	WellHead
	27	Production Tubing
	28	Production Pump
	29	Production Cavity
	30	Land surface
	31	Surface control devices
	32	Wellbore for Scavenger water fluids
	33	Surface water injection facilities
	34	Injection lines
	35	Wellbore for Scavenger ono-condensing gases
	36	Surface apparatus for non-condensing gases
	37	Injected Water
	38	Injected non-condensing gas
	39	Shale barriers
	40	Mini-wellbores

DESCRIPTION OF THE PREFERRED EMBODIMENT OF THE INVENTION

Referring now to the drawings, wherein like elements are numbered alike. Referring to FIG. 1 a, specialized wellbore 1 is drilled from the surface down to and into the hydrocarbon bearing formation 5. Many drilling rig configurations can be used, regular vertical type rigs or slant type rigs can be used to implement the drilling phase. In field applications of this invention it is beneficial that the wellbores be oriented along the formation dip angle such that maximum effect of gravity can be obtained in that the dip component adds to the gravity component and increases the gravity segregation of the fluids because of density differences. There are several embodiments of the wellbore system as shown in FIGS. 1 a, 1 b, and 1 c. One of the many embodiments includes a uniwell system with two wellheads shown in FIG. 1 a, and a second is a lateral wellbore which can be extended as shown in FIG. 1 b to intersect a central production cavity, and third a vertical wellbore with a production cavity shown in FIG. 1 c. These three options do not exhaust the available forms and anyone skilled in the art can implement similar or diverse systems for completing a similar wellbore. A significant novel improvement to the wellbore flow system is implementation of an annular fluid communication zone 8 shown in FIGS. 1 a, 1 b and 1 c. This is a zone of increased fluid conductivity which is concentric to the wellbore 1 and forms an effective flow channel from the hot steam zone 4 to the lower producing zone of the wellbore system. This communication zone allows early gravity separation of the steam, hot oil and hot water. This early precipitation of the heavier and denser fluid components of the reservoir frees up formation pore space allowing more steam 17 to be injected into the cold formation 5 and thereby heating the porous medium and increasing the steam zone 4 growth and attendant oil recovery. It is imperative that the steam has a free pore space to enter the formation without which, fluid displacement is impossible at the typical operating fluid flow pressures. In practice, the annular zone is implemented in one embodiment by a steel casing 3 b installed outside the inner wellbore 3 a. In the industry, this is generally done when the well is drilled. A steel liner or a steel screen can also be used to form the annular communication zone in another embodiment.
Operatively implemented in this wellbore and shown in FIG. 2, is a novel element called a steam controller apparatus 2, which monitors and controls the flow of fluid into and through the wellbore 1 below the injection packer system 7. This device is installed downstream of the injection system adjacent to the production perforations 10 as illustrated in FIGS. 2 and 7 a and 7 b.
As shown in FIG. 3 the steam controller apparatus 2 comprises three main segments. An inflow section 16 in which the hot fluids enter the device. An upper steam sensor section 18 which senses the flow of gaseous steam through the device, a controller section 19, which monitors the steam flow and which controls the lower valve section 15 which opens and closes the flow pathway to allow flow or shut off the flow of hot liquids as needed. Both elements have a complement of electronic hardware and software as shown in FIG. 8. It is noted herein, that the device 2 has to detect steam flow which is more complex than just recording or monitoring a fluid flow or a flow temperature. The apparatus 2 is implemented in the wellbore 1 wherein the device is placed between the upper injection perforations 9 a, 9 b and the lower production perforations 10 a, 10 b. The apparatus 2 is anchored in a manner typical to the industry and easily accomplished by those skilled in the industry. In its initial placement in the wellbore, as shown in FIG. 5 and FIG. 7 a, the apparatus is set up in a closed state such that no flow enters the production perforations 10. The no-flow situation allows the accumulation of hot fluids to occur in the communication zone 8 and the bottom of the hot steam bank zone 4.
Referring to FIG. 2, the steam injection fluid 17, which is generated on the surface in a steam generation system 25 is injected into the specialized wellbore 1. The steam fluid 17 is injected down the wellbore and is directed into the cold viscous oil bearing formation 5 by the upper packer 7. The steam 17 enters the formation 5 through the perforations 9 a in the inner casing 3 a, strategically placed external packers 21 b prevent loss of steam down the annulus. This steam then enters through the perforations 9 b of the outer casing 3 b. In the formation 5, it heats up the formation rock, the interstitial water and the native oil, significantly lowering the oil viscosity as shown in FIG. 10 from hundreds of thousands of centipoises to tens of centipoises and forming a steam bank or steam chamber 4. Because of the significant fluid density differences, the hot fluids, oil and water preferentially accumulate at the bottom of this steam chamber 4 under gravity drainage. It should be noted that as the steam injected volumes 17 move into the farther reaches of the reservoir 5, the steam profile appears as an inverted wedge, i.e. flat at the top and triangular on the bottom side, because the steam flows more rapidly at the top of the formation and this override as reported by many researchers, creates a physical flow gradient at the lower surface of the steam bank 4. This steam bank 4 is vertically thinner at the front or leading edge and thicker at the near wellbore 1 region. This phenomenon allows the hot oil to literally flow downhill and backwards through the porous formation towards the bottom of the steam bank 4 where it collects and further into the communication zone 8. It is also noted that this flow phenomenon occurs in 3-dimensions since the steam bank 4 in all respects behaves like an inverted dome with the base being flattened and the walls of the dome being the flow surface for hot oil and water. As shown in FIG. 2, a gas cap, literally a steam cap 17 develops at the top of the production interval and an oil and water leg 14 a (high fluid level), 14 b (low fluid level) develops at the bottom of the zone. This is a stable hydrodynamic situation and the accumulated hot fluids 14 a, 14 b behave as a plug at the bottom of the hot zone and prevents steam from moving down the communication zone 8. The interface 23 is a horizontal plane of density differences between the gas zone and the hot oil and water zone. The accumulated hot fluids create a hydraulic plug 14 a, 14 b, which prevents the steam from bypassing the cold formation and traveling downwards to the production perforations. This plug behaves much like a P-trap in a plumbing system. The invention is designed such that the hot oil 6, condensed water and free steam are forced to flow down the annular conductive zone 8 from the injection zone to the production zone. As shown in FIGS. 4, 7 a, 7 b, these hot fluids flow down the communication zone 8 from the injector zone and steam bank 4 to the production zone and production perforations 10 a, (in inner wellbore), 10 b (in outer wellbore). This hydraulic plug is actively controlled by the levels of oil production of the well and other operational actions under the direction and control of the well operator. Hot fluid enters perforations 10 b in the outer wellbore casing and then flows into the annular cavity 8 whence it enters through perforations 10 a into the innermost wellbore 1 and contacts the input section 16 of the steam controller device 2. This new steam controller device 2 allows hot water and hot oil to flow but a valve 15 shuts off flow when steam is detected in the flow stream. Substantial flow of steam indicates that there is no more oil to be produced from the formation.
In the field, the presence of horizontal shale barriers in the oil zone as shown in FIG. 11 has always been a major obstacle to developers in the prior art. The barriers 39 lower the efficiency of the displacement processes in view of the fact that they provide an almost impenetrable vertical barrier to steam and oil flow. This invention however, addresses and overcomes this major problem by the implementation of the vertical annular communication zone 8 at the near wellbore 1 region. The presence of this vertical communication zone 8 acts as a vertical relief valve for oil flow. In the displacement operations as shown herein earlier, the hot oil 6 a, being displaced, will move counter-current, under gravitational flow, backwards along the shale barrier towards the wellbore because of the 3-dimensional characteristics of the steam bank in which the leading edge is always thinner than the trailing edge. At the near wellbore 1 region the communication zone allows vertical cross flow of the hot oil and hot condensed water towards the bottom of the wellbore and the collection and production systems. The hydraulic seal at the bottom of the steam bank has to be controlled to limit steam bypassing in both layers.
This vertical cross-flow resolves the problem created by the shale barriers. In the field, there may be a plurality of shale barriers shown in FIG. 11, and the same phenomenon will occur simultaneously in all the steam displacement layers because the oil flow occurs along the surface of the steam bank interface with cold reservoir oil and the hot steam, and is not driven by pressure gradients but by the density differences of the two fluid phases.
Referring to FIG. 14 in which a series of lateral or horizontal mini-wellbores 40 are drilled radially from the initial wellbore 1 to increase steam injection efficiency. In this embodiment, the mini-boreholes 40 they are drilled in a staggered pattern such that a wedge-like cross-section of the steam bank is obtained when steam 17 is injected. This cross-section wedge is thicker at the near wellbore region and thinner at the leading or front edge of the steam 17. This type of profile provides a physical flow system in which the hot oil 20 can flow backwards more readily to the bottom of the steam bank 4 and the axial concentric communication zone 8. These mini-wellbores 40 can be predrilled through out the oil formation 5 at specific vertical depths prior to the steam injection process. In this way when the injection system is moved axially down the main wellbore 1 these predrilled mini-wellbores 40 are already in place and available for steam injection and can also aid in hot oil inflow to the communication zone 8.
Referring to FIGS. 5, 6 which show that except under specific conditions, the steam control apparatus 2 prevents the flow of hot fluids 6 a through the production perforations 10 a, 10 b. When the hot fluid flow is allowed, the hot fluid comprising oil and condensed steam enters the wellbore 1 and flows down the well to the collection system and the pumping mechanism 28 of the producing system. As the fluid flows into the steam controller apparatus 2, sensing components in the device shown in FIG. 8, detect the presence of steam. When steam is detected, the apparatus shuts off fluid flow as illustrated in FIG. 5 since there is no more oil to be produced at the current time. However, continuous steam injection still occurs in the wellbore in the upper injection zone perforations 9 a and the accumulation of hot oil at the bottom of the steam zone 4 continues. After a predetermined time as computed by the well operator in which sufficient oil has accumulated, the apparatus reopens the production phase to allow the hot oil 6 a (flowing), 6 b (non-flowing) to be produced. Production of oil and water occurs when the downhole pump 28 is activated and the accumulated oil 14 a, 14 b in the wellbore is produced in the customary manner used in the industry. If the downhole pressure is sufficient, it is possible to flow the oil directly to the surface.
This steam controller apparatus 2 along with the wellbore packers 21 a, 21 b are sequentially moved down the wellbore 1 and reseated in a new axial location as the steam injection process continues until the recoverable oil in the formation 5 is depleted. In one rudimentary embodiment of the invention, a downhole sensor 18 is not utilized but the flow control apparatus 19 is turned on and off to open the flow valve 15 at selected times for specific producing time intervals. This “dumb” approach using a “null” sensor can be used in situations where the sensors are unavailable. A further option of the “dumb” approach is to flow the wells in the producing cycle until steam is visible at the surface 30 then to shut off the downhole valve 15 such that the hydraulic seal created by fluid 14 a, 14 b can start re-forming. These embodiments are wasteful of steam energy and reservoir productivity however, they can still function under the prevailing reservoir conditions and in operating conditions where the low cost of steam generation makes it economically attractive, examples are in some remote foreign environments where environmental concerns on combustion processes for steam generation are not as stringently regulated. An alternative approach to using the “null” sensor uses historical data analysis to correlate statistically, injection and production times such that an intelligent estimate of the required production time before steam breakthrough occurs can be made. In this way, the “dumb” approach can be more effective and lessen injected steam waste.
Power to the downhole apparatus 2 can be implemented by the power cable 11 and information back and forth from the downhole apparatus to the surface can be effected by either a wired or wireless telemetry system. Both systems are typical to the industry and can be done by anyone competent in the field. Optical fibers are a well-developed communications medium used in the telecommunications industry and have been progressively adopted for uses in sensors in the oil and gas industry. One of the greatest benefits of these sensors is the high temperature capability and reliability, which makes them well suited for steam injection and other thermal recovery processes. These fiber optic systems are intrinsically safe since they only transmit light and no electrical flow occurs which completely removes the possibility of a spark to ignite the volatile hydrocarbons in the wellbore.
As shown in FIG. 3 and further illustrated in FIGS. 5, 6, 8, the device 2 comprises the following elements. An inlet section 16 which is generally a slotted liner or a metal sieve to allow the hot fluids to enter the device. The fluid sensor 18 comprises a steam flow sensor for example, a mass flow detector which is minimally capable of determining in realtime the mass of flowing fluid as well as the temperature, pressure and quality of the flow stream. This sensor 18 has its own logic and computer capability to process the data and make it available to other elements of the steam controller 2 and the surface devices 31. In addition operatively connected to the sensor system 18 is a flow device controller system 19. This flow device controller 19 has a full complement of hardware circuitry, software and software logic, memory and storage capabilities to process, store, transmit and implement the instructions needed to control the operations of the flow valve 15 directly or on command from the surface devices 31 as seen in FIG. 8. The flow valve or flow control device 15 is a system typical of the flow devices in industry and are made in a variety of forms. These valve systems 15 are well known in the industry and are actuated in a variety of ways. Implementation of the combination of steam sensor, controller and flow valve as a means of limiting steam flow through an axial communication zone below an operating steam bank provides a new means of accelerating production from a single well. This single well accelerated production or abbreviatively called SWAP™ technology provides for accelerated economics in the enhanced oil recovery industry.
Operationally the preferred embodiment of the invention is practiced as shown by the following: Referring to FIG. 9 a, step 110 illustrates the drilling phase of the field application. In this phase, the operator selects the type of well(s) that should be drilled. These types are shown in FIGS. 1 a, 1 b, 1 c, and FIG. 14 in the case of staggered horizontal or lateral mini-wellbores being implemented. After the wellbores 1 are drilled, in one embodiment, the communication zone 8 is cased and perforations 9 a, 9 b, 10 a, 10 b are made in the tubular goods. As shown in step 111, packers 21 a and 21 b are prepared and seated as needed in the wellbores when the steam control device 2 is installed in the inner wellbore 1. At the same time, the operator computes the steam injection times and rates. After these specific times, the operator can monitor and operations and trigger the downhole steam control device 2 to open up the flow valve 15 as dictated by the flow times. In step 112, steam is generated on the surface in steam generators 25, as shown in FIG. 1 In FIGS. 2 and 7 a, the steam is injected down the wellbore 1, and meets the downhole packer 7 which diverts the steam flow 12 as seen in FIG. 4 thorough the injection perforations 9 a and 9 b of the steel wellbore 3 a and the annular casing 3 b. Flow down and out of the annular zone 8 is prevented by packers 21 b.
In the operational case where no packers 21 b are used some steam can be sacrificed to fill up the annular cavity with no great loss of efficiency. The injected steam 17 begins to heat up the reservoir formation 5, it forms a steam zone or steam bank 4 in which hot oil and hot water accumulate with the steam. The high formation temperature lowers the oil viscosity considerably as shown in FIG. 10 and this oil flow driven by the combined forces of gravity, formation dip angle and pressure in the steam bank 4, gravitates to the bottom of the zone to form a liquid saturated zone 14. This zone forms a fluid-steam contact 23 in the formation similar to an oil/water contact in natural reservoirs which is formed by fluid density differences. In this invention, the steam cap 4 is analogous to a gas cap and the fluid zone 14 is analogous to an oil leg in typical hydrocarbon reservoirs. As indicated in step 112 this layer of hot oil and water 14 a, 14 b forms a hydraulic seal at the bottom of the steam bank. This hydraulic seal 14 is an integral part of the invention and its existence in the steam zone 4 and the communication zone 8 prevents the flow of steam into the wellbore until this seal height is lowered or the fluid is removed by production.
The hot dense fluids, oil and water, enter the annular communication zone through production perforations 10 b in the cased wellbore 3 b. Here they remain until the steam controller device 2 “allows” them to enter the production perforations 10 a and finally the inner wellbore 1. During the injection phase the steam bank grows and its growth and volumetric extent can be easily calculated by many publicly available computer simulation models. The operator as shown in step 113 monitors the injection process and is able to estimate the volume of oil accumulating at the bottom of the zone 4 in the oil leg 14 a, 14 b. At the pre-determined time the downhole steam controller 2 is triggered by the control device 31, the flow control valve 15 is opened and hot fluids begin to enter the inflow section 16 of the device 2 and flow past the steam sensor 18. The steam flow sensor measures the fluid characteristics as shown in steps 102, 103, 104, 105, 106, 107 of FIG. 8. As the flow continues, the level of the fluid interface 23 is lowered, the fluid leg drops from a high volume at 14 a to a lesser volume at 14 b as shown in FIG. 7 b. This fluid lowering occurs in the steam zone 4 and in the communication zone 8. The produced fluids oil and water collect in the inner wellbore, are transported under gravity, and flow pressure to the production zone of the respective well systems used. These can be either into the production cavity 29 of FIG. 1 c or the lateral wellbore of FIG. 1 a, or the central production cavity described for FIG. 1 b. In all cases, the production mechanism 28 is used to lift the oil to the surface if there is insufficient pressure from the injected fluids to lift the fluid to the surface.
As oil production continues through the steam controller device 2, the flow characteristics are monitored constantly by device element 18 and the information is processed locally or remotely at the surface. When the sensor detects the flow of live steam 17 entering the wellbore 1, the valve controller device 19 triggers the valve 15 to close and no more fluid flow 6 a, 6 b is allowed to enter the wellbore 1. This operation creates a shut-off situation and hot fluid 14 a, 14 b begins to re-accumulate in the communication zone 8 and the bottom of the steam zone 4. This re-accumulation creates a new hydraulic seal which prevents the steam from bypassing the cold oil formation and directs it to enter the formation 5 where it remains at the top of the steam zone 4. Steam injection continues at all times during the production phase.
As indicated in step 114, the operator has to make a decision when the oil in the steamed zone 4 is depleted. If an analysis of the cumulative oil volume produced indicates that the reservoir formations 5 are economically depleted, then the heavy oil recovery operations are terminated. If however, there is still economically recoverable oil in the reservoir the injection site for steam injection through the perforations and the steam controller device must be moved axially down the length of the wellbore to a new location to exploit additional oil reserves. This translocation process is shown in step 115. In this step 115, steam injection is temporarily halted, the packers 21 a, 21 b are unseated, the steam controller 2 is unseated and both systems are moved a calculated distance down the wellbore 1 to be reseated opposite a new set of injection 9—production 10 pairs of perforations.
After this re-location, all systems are re-established and steam injection continues.
This process of injection, production, decision analysis and relocation continues until the reservoir is fully depleted as shown in step 116. Steam injection and production are then terminated and the displacement scavenging operations are initiated as shown in step 117 of FIG. 9 d. This process is an “oil salvage” process in which displacing fluids are injected into the hot formation 5 after steam displacement is complete. This is recuperative process well known in the industry in which additional oil can be recovered by flowing these displaced fluids through a hot reservoir with reduced viscosity oil. The scavenging displacement process is helped by the fact that the heated reservoir rock has a higher porosity, higher permeability and the residual oil has a lowered viscosity, all of these factors are complimentary in their effects in promoting additional recovery of in-situ oil. Field tests have shown that as much as 22% of the total oil recovered can be achieved after the scavenging process is initiated. In implementing the scavenging phase, the injected displacing fluids are injected in a plurality wellbores. These wellbores are either:

- (a) newly drilled horizontal and vertical injector wellbores; or
- (b) existing wellbores formerly used for steam injection.

Referring to FIG. 12 treated water 37 from a surface supply source 33 is injected down an injector well 32 and enters the formation at the bottom of the depleted steam bank 4. In one embodiment, these injector wells 32 can be vertical wellbores or in other embodiments, they can be substantially horizontal wellbores. This water 37 displaces the oil towards the wellbore 1 which has all its perforations 9 a, 9 b, 10 a, 10 b open to allow oil flow into the wellbore driven by the water pressure and production of displaced oil and hot water occurs and is pumped to the surface.
Referring to FIG. 13 non-condensing gas or flue gas from a surface supply source 36. The supply source can be the treated exhaust of the steam generation equipment 25. This flue gas 38 is injected down an injector well 33 and enters the formation 5 at the top of the depleted steam bank 4. In one embodiment, these injector wells 33 can be vertical wellbores or in other embodiments, they can be substantially horizontal wellbores. This gas 38 displaces the oil towards the wellbore 1 which has all its perforations 9 a, 9 b, 10 a, 10 b open to allow oil flow into the wellbore driven by the gas pressure and production of displaced oil and gas occurs and the oil is pumped to the surface. The gas can be produced up the casing annulus of the wellbore. Being less dense the injected flue gas remains at the top of the steam bank while the denser water gravitates to the bottom of the steam bank 4.
In one embodiment, both water injection and flue gas injection can occur simultaneously or sequentially. After gas and water breakthrough has occurred, injection is continued to the economic limit of the projects and then terminated as shown in item 118 of FIG. 9 d.

REFERENCES

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8. USDoE Research Contract No. DE-PS26-035NT15477, Stolar Research, Raton, N.Mex.
9. SPE Paper No. 95713-MS,: The Use of Swell Packer's as a Replacement and Alternative to Cementing.
10. SPE Paper No. 78272-MS,: An Oil Selective Inflow Control System.
11. SPE Paper No 78946-MS, Results of Thermal Horizontal Completions with Sand Control in Lake Maracaibo, Venezuela: Case Histories of Horizontal Gravel Packs in Bachaquero-01 Reservoir.
12. SPE Paper No 97928-MS, Innovative Completion Technology Enhances Production Assurance in Alaskan North Slope Viscous Oil Developments.
13. SPE Paper No: 94808-MS, Twenty Years of Vapor Injection in Heavy-Oil Fields.
14. SPE Paper No: 73001-PA, Recommended Practices for Slim-Hole Steam Injectors.
15. SPE Paper No: 20763-PA, Injection Schedules and Production Strategies for Optimizing Steamflood Performance.
16. SPE Paper No: 97776-MS, Thermo-Plastic Properties of OCTG in a SAGD Application.
17. SPE Paper No: 97647-MS, Cross-SAGD (XSAGD)—An Accelerated Bitumen Recovery Alternative.
18. SPE Paper No: 89411-PA, Cruse Steamflood Expansion Case History.
19. SPE Paper No: 19827-PA, Oil Recovery by Gravity Drainage Into Horizontal Wells Compared With Recovery From Vertical Wells.
20. SPE Paper No: 56857-PA, Comparative Effectiveness of CO2 Produced Gas, and Flue Gas for Enhanced Heavy-Oil Recovery.
21. SPE Paper No 97336-MS, Run-and-forget completions for optimal inflow in heavy oil.

Claims

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.