Heavy Oil Recovery and Apparatus

Abstract

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

Description

CROSS REFERENCES[0001]Reference is made to DD 596,606 filed Mar. 16, 2006 by the inventor.INTRODUCTION[0002]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.[0003]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.[0004]One of the new types of horizontal well is called a Uniwell™ because it ca...

AI Technical Summary

Benefits of technology

[0075]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.

[0096]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.

Problems solved by technology

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.

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.

This type of downhole flange connection is extremely difficult if not impossible to implement in current oilfield practice.

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.

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.

A simple temperature record is insufficient to determine whether flow is a gas, a liquid or a solid.

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.

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 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.

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.

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.

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.

A simple temperature record is insufficient to determine whether flow is a gas, a liquid or a solid.

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.

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.

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.

This heat loss lowers the overall recovery of the process.

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.

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.

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.

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.

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