WO2016139498A2 - Method for operating a carbonate reservoir - Google Patents

Abstract

The present disclosure relates to recovery of heavy hydrocarbons, at least in part, by a rapid cyclical steam stimulation process in a thermal or thermal/solvent recovery operation and specifically to a procedure for high-pressure steaming and production without an intermediate soaking period or with a substantially shortened soaking period. The method is applicable for starting up a thermal/solvent recovery operation by establishing rapid initial communication between injector and producer wells and then either continuing into at least the initial production phase of the recovery operation or proceeding directly into a gravity drainage process such as SAGD. A pattern of horizontal wells for implementing the RIAP process involves an upper row and lower row of horizontal wells. The upper row is offset by a selected distance from the lower row. The wells in both upper and lower rows are drilled and completed to function as either injectors or producers.

Description

METHOD FOR OPERATING A CARBONATE RESERVOIR

CROSS REFERENCE TO RELATED APPLICATION

The present application claims the benefits, under 35 U.S.C.§119(e), of U.S. Provisional Application Serial No. 61/722,395 entitled "Method for Starting up a

Carbonate Reservoir" filed November 5, 2012 and Provisional Application Serial No. 61/747,109 entitled "Method for Starting up a Carbonate Reservoir" filed December 28, 2012, both of which are incorporated herein by reference.

FIELD

This disclosure also relates generally to a method for recovery of heavy

hydrocarbons, at least in part, by a rapid cyclical steam stimulation process in a thermal or thermal/solvent recovery operation and specifically to a cycle characterized by a shorter period, higher pressure and higher volume rate of steaming and production often without an intermediate soaking period.

BACKGROUND

There are many hydrocarbon producing regions around the world. These regions may produce hydrocarbons by conventional means or, as production from conventional sources declines, by non-conventional means. For example, conventional means include drilling wells and pumping crude oil or natural gas to the surface. Non-conventional means include recovering bitumen and heavy oil, for example by surface mining and in- situ means involving mobilization of the heavy hydrocarbons. In-situ techniques include injecting steam, solvents, a combination of steam and solvents, electrical heating methods, in-situ combustion, water flooding and chemical flooding.

In the recovery of bitumen and heavy oil, examples of thermal recovery include Steam Assisted Gravity Drain ("SAGD"), Cyclical Steam Stimulation ("CSS") and steam flooding. An example of recovery using solvents is the VAPEX process. Recovery by mining is practiced by large surface mines where the hydrocarbon deposit is near the surface. All three methods are practiced in the recovery of heavy oil and bitumen in the Western Canadian Sedimentary Basin.

In-situ recovery methods now typically use combinations of SAGD, CSS and

VAPEX methods to improve overall reservoir recovery factors and reduce the amounts of water and energy used in these operations. Most of these improvements have been developed in the Alberta oil sands where the reservoir matrix is primarily unconsolidated or weakly cemented quartz sand. As is well known, quartz sand is typically a water-wet matrix and this allows reasonably high recovery of bitumen, heavy oil and solvents used in VAPEX and solvent-enhanced SAGD operations. In addition to the recovery of bitumen and incremental bitumen due to the use of solvent, high solvent recovery factors are important since the cost of solvents is typically a large component of overall recovery costs.

Recently, the Grosmont Carbonates, which also contain enormous reservoirs of bitumen, are being developed. The carbonate reservoir matrix is formed by fractured and karsted dolomitic rocks. Bitumen from the Carbonates is being recovered by variations of the in-situ methods developed in the Alberta oil sands. These include advanced methods such as ES-S AGD, SAP, SAS, S A-S AGD, SC-S AGD, LASER and the like (all of which are further described in the Process Acronyms definitions in the Summary) which involve a combination of various thermal and solvent heavy hydrocarbon mobilization strategies. In the Carbonates, adding solvent to the steam-based thermal processes, such as CSS and SAGD, can still be considered as a preferred option for improving bitumen recovery factors over the steam-based thermal processes. The improved recovery factor of bitumen and the recovery factor of solvents by the end of the reservoir lifetime are becoming important parameters in assessing economic viability.

The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s and Alberta since the 1960s. In the cyclical steam stimulation ("CSS") method, the well is put through cycles of steam injection, soak, and heavy hydrocarbon production. The CSS method has recovery factors of typically 20 to 35% and is commonly terminated when the cost to inject steam is too high for further economical recovery.

There are heavy oil and bitumen reservoirs such as the Grosmont carbonates of Alberta in which it is difficult to maintain pressures typical of the normal CSS process for a prolonged period of time. This may be because of the fluid network of fractures, vugs of various sizes, dolines etcetera that causes the reservoir to communicate over a long range with other portions of the field or provides a highly connected volume network that takes time to fill completely or both.

There therefore remains a need for methods of improving the effectiveness of cyclical steam stimulation and other processes such as SAGD and various SAPs especially in carbonate reservoirs comprising large amounts of potentially valuable bitumen or heavy oil that must be mobilized to be recovered. SUMMARY

These and other needs are addressed by the various embodiments and

configurations of the present disclosure which relate generally to recovery of heavy hydrocarbons, at least in part, by a rapid cyclical steam stimulation process in a thermal or themial/solvent recovery operation and specifically to a cycle characterized by a shorter period, higher pressure and volume rate of steaming and production often without an intermediate soaking period or with a substantially shortened soaking period. The method disclosed herein is applicable for starting up a thermal/sol ent recovery operation by establishing rapid initial communication between injector and producer wells where upper wells are operated as injectors and producers alternating with offset lower wells operated as producers and injectors. This process can be either continued into at least the initial production phase of the recovery operation or converted directly to a gravity drainage process such as SAGD where upper wells are operated only as injectors and lower wells are operated only as producers The cyclical, high-pressure process of the present disclosure may be referred to herein as the Rapid Injection Alternating Production

("RIAP"). After significant communications between wells are established, the RIAP process would be continued for a selected period and then transitioned into a gravity drainage process, such as SAGD or other continuous and relatively lower pressure recovery operation. Examples of other low pressure recovery operations are HAGD, N- Solv, PHARM, SA-SAGD, SC-SAGD, ES-SAGD, SAP, SAS, SAVES and the like which are further described in the Process Acronyms definitions at the end of the Summary.

A normal CSS process cycle comprises a steam injection period, a soak period and a production period. There are heavy oil and bitumen reservoirs in which it is difficult to maintain pressures typical of the normal CSS process for a prolonged period of soak. In the present disclosure, the approach to overcome this inability to maintain reservoir pressure for a prolonged period of soak is to shorten the steam injection period, substantially shorten or even eliminate the soak period and end the production period once the production rate falls off. There will always be a small delay between steaming and production periods for operational changeover. There is usually no significant delay between end of a soak period and initiation of production.

This Rapid Injection Alternating Process is believed to be effective for initially producing significant volume of bitumen (about 5% to about 15% of original oil-in-place) with reasonable steam-to-oil ratio while establishing initial communication between injector and producer wells in a thermal/solvent recovery operation and then continuing into the initial production phase prior to start-up of a more conventional SAGD or SAP recovery process. The RIAP procedure can be applied to in-situ recovery of bitumen or heavy oil in hydrocarbon reservoirs such as the Clearwater Formation in the Cold Lake area or in carbonate reservoirs such as those in the Grosmont Carbonates, both of which are in Alberta Canada.

In a first embodiment, a method is disclosed comprising: (a) providing a plurality of upper and lower wells positioned in a hydrocarbon-containing formation, each well configured to operate, in a first mode, as an injector well and, in a second mode, as a producer well, wherein the upper wells form an upper row and the lower wells form a lower row and wherein the wells in the upper row are offset from the wells in the lower row; (b) assigning a plurality of contiguous wells to a first group for a first selected time period; (c) for the first selected time period, operating a first subset of the wells in the first group in the first mode but not the second mode to inject a hydrocarbon mobilizing fluid into the hydrocarbon-containing formation; (d) for the first selected time period, operating a second subset of the wells of the first group in the second mode but not the first mode to produce a hydrocarbon from the hydrocarbon-containing formation; (e) changing at least one of an injection pressure and an injection volumetric flow rate for the wells in the first subset to provide a user selected operational pressure in the hydrocarbon-containing formation; and (f) repeating steps (c), (d) and (e) until a plurality of the wells within the first group are in full fluid communication with one another, whereby the recovery of a hydrocarbon from an underground hydrocarbon-containing material is initiated. As can be appreciated, the wells in the upper row may be offset midway between the wells in the lower row.

This method is applicable wherein the hydrocarbon mobilizing fluid is at least one of steam, solvent and a steam/solvent mixture, wherein a user selected operational pressure is between about 1.5 MPa and about 4.5 MPa and the user selected operational pressure can be maintained by an automatic controller which may receive inputs comprising data from one or more production wells, injection wells and observation wells.

This method may be comprised of additional steps such as 1) the repeating steps (c), (d) and (e) are continued for a selected period after full fluid communication between all upper wells and lower wells has been established and/or 2) the recovery of

hydrocarbons continues using a gravity drainage process comprising injecting a hydrocarbon mobilizing fluid from the upper wells while producing a hydrocarbon from the lower wells. In a second embodiment, a system is disclosed for initiating recovery of a hydrocarbon from an underground hydrocarbon-containing material comprising: (a) a plurality of upper and lower wells positioned in a hydrocarbon-containing formation, each well configured to operate, in a first mode, as an injector well and, in a second mode, as a producer well, wherein the upper wells form an upper row and the lower wells form a lower row and wherein the wells in the upper row are offset from the wells in the lower row; (b) a first group of wells formed by a plurality of contiguous wells; (c) a hydrocarbon mobilizing fluid injected into the hydrocarbon containing formation from a first subset of the wells in the first group operating in the first mode but not the second mode, wherein an operational pressure is established to a user selected operational pressure; (d) a

hydrocarbon produced from the hydrocarbon-containing formation from a second subset of the wells of the first group operating in the second mode but not the first mode; and (e) an automatic controller configured to alternate between i) producing a hydrocarbon from the second subset of the wells of the first group; and ii) injecting a hydrocarbon production fluid from the first subset of the wells in the first group operating in the first mode but not the second mode; and iii) repeating steps i) and ii) until a plurality of the wells within the first group are in full fluid communication with one another, wherein the recovery of a hydrocarbon from an underground hydrocarbon-containing material is initiated. As can be appreciated, the wells in the upper row may be offset midway between the wells in the lower row.

This system can also include a hydrocarbon mobilizing fluid that is at least one of steam, solvent and a steam/solvent mixture and a user-selected operational pressure between about 1.5 MPa and about 4.5 MPa wherein the user selected operational pressure is maintained by at least one of maintaining an injection pressure and maintaining an injection flow rate.

The system can also include an automatic controller that receives inputs comprising data from one or more production wells, injection wells and observation wells.

After start-up is complete (a plurality of the wells within the first group are in full fluid communication with one another), the system can also be transformed to a configuration wherein a plurality of wells in the upper row can be operated as injection wells and a plurality of the wells in the lower row can be operated as production wells using a gravity drainage process.

In a third embodiment, a method is disclosed that uses a non-transitory computer readable medium having stored thereon computer executable instructions, the computer executable instructions causing a processor of a device to execute a method of initiating recovery of a hydrocarbon from an underground hydrocarbon-containing material, the method comprising: a) instructions to configure a first selected group of upper and lower wells and to select a first subset of the first selected group to operate in a first mode as injection wells and to select a second subset of the first selected group to operate in a second mode as producer wells; b) instructions to operate a subset of the first selected group as injection wells and a second subset of the first selected group as producer wells; c) instructions to establish an operational pressure to a user selected operational pressure; d) instructions to produce a hydrocarbon from the second subset of the first selected group while injecting a hydrocarbon mobilizing fluid from the first subset of the first selected group while maintaining the user selected operational pressure; and e) instructions to repeat the previous two instructions until a plurality of the wells within the selected first group are in full fluid communication with one another, wherein the recovery of a hydrocarbon from an underground hydrocarbon-containing material is initiated.

This method is applicable wherein the hydrocarbon mobilizing fluid is at least one of steam, solvent and a steam/solvent mixture, wherein a user selected operational pressure is between about 1.5 MPa and about 4.5 MPa and wherein the user selected operational pressure is maintained by at least one of maintaining an injection pressure and maintaining an injection flow rate wherein the user selected operational pressure can be maintained by an automatic controller.

The above-described embodiments and configurations are neither complete nor exhaustive. As will be appreciated, other embodiments of the disclosure are possible utilizing, alone or in combination, one or more of the features set forth above or described in detail below. These and other advantages will be apparent from the disclosure of the disclosure(s) contained herein.

The phrases at least one, one or more, and and/or are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions "at least one of A, B and C", "at least one of A, B, or C", "one or more of A, B, and C", "one or more of A, B, or C" and "A, B, and/or C" means A alone, B alone, C alone, A and B together, A and C together, B and C together, or A, B and C together.

The following definitions are used herein:

Acid-producing gases as used herein are gases such as carbon dioxide, sulfur dioxide, nitrogen dioxide and the like when combined with water provided by steam to form carbonic acid, sulfuric acid, nitric acid and the like. Any acid-producing gas may also be referred to as an acid precursor.

The term automatic and variations thereof, as used herein, refers to any process or operation done without material human input when the process or operation is performed. However, a process or operation can be automatic, even though performance of the process or operation uses material or immaterial human input, if the input is received before performance of the process or operation. Human input is deemed to be material if such input influences how the process or operation will be performed. Human input that consents to the performance of the process or operation is not deemed to be "material." The term computer-readable medium as used herein refers to any tangible storage and/or transmission medium that participate in providing instructions to a processor for execution. Such a medium may take many forms, including but not limited to, non- volatile media, volatile media, and transmission media. Non- volatile media includes, for example, NVRAM, or magnetic or optical disks. Volatile media includes dynamic memory, such as main memory. Common forms of computer-readable media include, for example, a floppy disk, a flexible disk, hard disk, magnetic tape, or any other magnetic medium, magneto-optical medium, a CD-ROM, any other optical medium, punch cards, paper tape, any other physical medium with patterns of holes, a RAM, a PROM, and EPROM, a FLASH-EPROM, a solid state medium like a memory card, any other memory chip or cartridge, a carrier wave as described hereinafter, or any other medium from which a computer can read. A digital file attachment to e-mail or other self-contained information archive or set of archives is considered a distribution medium equivalent to a tangible storage medium. When the computer-readable media is configured as a database, it is to be understood that the database may be any type of database, such as relational, hierarchical, object-oriented, and/or the like. Accordingly, the disclosure is considered to include a tangible storage medium or distribution medium and prior art-recognized equivalents and successor media, in which the software implementations of the present disclosure are stored.

CSOR means Cumulative Steam-Oil Ratio.

Dilbit is short for diluted bitumen. Typically, dilbit is about 65% bitumen diluted with about 35% naphtha. The naphtha is added to make a fluid that can be transported by pipeline by reducing the viscosity of the bitumen/naphtha mixture. The dilbit can be transported by pipeline to a refinery. The naphtha diluent can be taken out as a straight run naphtha/gasoline and reused as diluent. Or it can be processed to create products in the refinery. The dilbit has a lot of light hydrocarbons from the diluent and a lot of heavy hydrocarbons from the bitumen. So it is a challenge to process directly in a normal refinery. Dilbit can only be a small part of a normal refinery's total crude slate. In addition to naphtha, condensate can also be used as diluent.

A diluent as used herein is a light hydrocarbon that both dilutes and partially dissolves in heavy hydrocarbons. In a thermal or non-thermal heavy oil or bitumen production method, a solvent liquid or vapor is used to reduce viscosity of the heavy oil. An injected solvent vapor expands and dilutes the heavy oil by contact. The diluted heavy oil is then produced via horizontal or vertical producer wells. Diluent and solvent are often used interchangeably in the production of heavy oil and bitumen.

A doline, sink or sinkhole is a general term for a closed depression in an area of karst topography that is formed either by solution of the surficial limestone or by collapse of underlying caves. It can be cylindrical, conical, bowl- or dish-shaped. The diameter ranges from a few meters to many hundreds of meters. If formed by solution, the corrosive solution of limestone by rainwater is very high in the area of fractures, allowing the water to run into the rock. This normally forms the bowl shaped type of doline. The solution produces large amounts of clay (depending on the pureness of the limestone). This clay is water resistant and sometimes plugs the drainage, so little lakes of rain water can sometimes be found in dolines, a rare thing in waterless karst areas. If formed by collapse, as a cave grows, there may be a point where the roof of a cavern is not stable enough. This results in (several) collapses that shape the roof like a dome. This process runs out, when the shape is able to hold the weight of overlying rocks. If the impact of this collapse reaches the surface, if the overlying layers are too thin. The ceiling collapses and a doline is formed. The doline is often a natural entrance to the cave.

EOR stands for Enhanced Oil Recovery.

A fractal is an object or quantity that displays self-similarity over a range of size scales. A geologic formation which is fractal-like, need not exhibit exactly the same structure at all size scales within the range, but the same type of structures must appear on all scales within the range. A plot of the quantity on a log-log graph versus scale then gives a straight line, whose slope is said to be the fractal dimension. A fractal is a geometric pattern that is repeated at ever smaller scales within the range of size scales to produce irregular shapes and surfaces that cannot be represented by classical geometry. Fractals are used especially in computer modeling of irregular patterns and structures in nature. A gravity drainage process as used herein is a process by which the movement of a mobilized hydrocarbon towards a producer well is caused by predominantly by gravity.

HRSG stands for Heat Recovery Steam Generator. A heat recovery steam generator or HRSG is a heat exchange apparatus that recovers heat from a hot gas stream to produce steam. The hot gas stream can be provided, for example, by the hot exhaust from a gas turbine.

An injector well as used herein is a well drilled from the surface or subsurface workspace that is comprised of a substantially horizontal section from which fluids such as steam, solvents, carbon dioxide and the like can be injected into a hydrocarbon formation. An injector well may sometimes be referred to as an injection well.

A mobilized hydrocarbon is a hydrocarbon that has been made flowable by some means. For example, some heavy oils and bitumen may be mobilized by heating them or mixing them with a solvent to reduce their viscosities and allow them to flow under the prevailing drive pressure. Most liquid hydrocarbons may be mobilized by increasing the drive pressure on them, for example by water or gas floods, so that they can overcome interfacial and/or surface tensions and begin to flow.

A mobilizing agent as used herein is at least one of steam and a solvent.

Natural gas refers to a hydrocarbon gas including low molecular weight hydrocarbons, primarily methane.

An observation well may be a vertical well, an inclined well or a horizontal well installed for the purpose of gathering data on a reservoir formation as it is being operated. An observation well is not used for production but can be used to inject tracer materials or retrieve reservoir matrix and fluid samples. An observation well may also be called a monitor well.

Primary production or recovery is the first stage of hydrocarbon production, in which natural reservoir energy, such as gas-drive, water-drive or gravity drainage, displaces hydrocarbons from the reservoir, into the wellbore and up to surface. Production using an artificial lift system, such as a rod pump, an electrical submersible pump or a gas- lift installation is considered primary recovery. Secondary production or recovery methods frequently involve an artificial-lift system and/or reservoir injection for pressure maintenance. The purpose of secondary recovery is to maintain reservoir pressure and to displace hydrocarbons toward the wellbore. Tertiary production or recovery is the third stage of hydrocarbon production during which sophisticated techniques that alter the original properties of the oil are used. Enhanced Oil Recovery can begin after a secondary recovery process or at any time during the productive life of an oil reservoir. Its purpose is not only to restore formation pressure, but also to improve oil displacement or fluid flow in the reservoir. The three major types of enhanced oil recovery operations are chemical flooding, miscible displacement and thermal recovery.

A producer well as used herein is a well drilled from the surface or subsurface workspace that is comprised of a substantially horizontal section from which fluids such as mobilized bitumen or heavy oil, water, solvents, methane and other formation fluids can be recovered and delivered to a surface facility. A producer well may also be referred to as a production well, a recovery well or a collector well.

SOR means Steam-Oil Ratio

Synbit is a blend of bitumen and synthetic crude. Synthetic crude is a crude oil product produced, for example, by the upgrading and refining of bitumen or heavy oil. Typically, synbit is about 50% bitumen diluted with about 50% synthetic crude.

SMR stands for Steam Methane Reformer.

Upgrading (including partial upgrading) as used herein means removing carbon atoms from a hydrocarbon fuel, replacing the removed carbon atoms with hydrogen atoms to produce an upgraded fuel and then combining the carbon atoms with oxygen atoms to form carbon dioxide.

Vugs are small to medium-sized cavities inside rock that may be formed through a variety of processes. Most commonly cracks and fissures opened by tectonic activity

(folding and faulting) are partially filled by quartz, calcite, and other secondary minerals. Open spaces within ancient collapse breccias are another important source of vugs. Vugs may also result when mineral crystals or fossils inside a rock matrix are later removed through erosion or dissolution processes, leaving behind irregular voids. The inner surfaces of such vugs are often coated with a crystal druse. Fine crystals are often found in vugs where the open space allows the free development of external crystal form. The term vug is not applied to veins and fissures that have become completely filled, but may be applied to any small cavities within such veins. Geodes are a common vug formed rock, although that term is usually reserved for more rounded crystal-lined cavities in sedimentary rocks and ancient lavas.

Well logging is the practice of making a detailed record (a well log) of the geologic formations penetrated by a borehole. The log may be based either on visual inspection of samples brought to the surface (geological logs) or on physical measurements made by instruments lowered into the hole (geophysical logs). Well logging can be done during any phase of a well's history; drilling, completing, producing and abandoning. The oil and gas industry uses wireline logging to obtain a continuous record of a formation's rock properties. These can then be used to infer further properties, such as hydrocarbon saturation and formation pressure, and to make further drilling and production decisions. Wireline logging is performed by lowering a 'logging tool' on the end of a wireline into an oil well (or borehole) and recording petrophysical properties using a variety of sensors. Logging tools developed over the years measure the electrical, acoustic, radioactive, electromagnetic, nuclear magnetic resonance, and other properties of the rocks and their contained fluids. The data itself is recorded either at surface (real-time mode), or in the hole (memory mode) to an electronic data format and then either a printed record or electronic presentation called a "well log" is provided. Well logging operations can either be performed during the drilling process (Logging While Drilling), to provide real-time information about the formations being penetrated by the borehole, or once the well has reached Total Depth and the whole depth of the borehole can be logged. There are many types of wireline logs and they can be categorized either by their function or by the technology that they use. Open hole logs are run before the oil or gas well is lined with pipe or cased. Cased hole logs are run after the well is lined with casing or production pipe.

Wettability is the preference of a solid to contact one liquid or gas, known as the wetting phase, rather than another. The wetting phase will tend to spread on the solid surface and a porous solid will tend to imbibe the wetting phase, in both cases displacing the non-wetting phase. Rocks can be water-wet, oil-wet or intermediate-wet. The intermediate state between water- wet and oil- wet can be caused by a mixed- wet system, in which some surfaces or grains are water- wet and others are oil-wet, or a neutral- wet system, in which the surfaces are not strongly wet by either water or oil. Both water and oil will wet most hydrocarbon reservoirs in preference to gas. Wettability affects relative permeability, electrical properties, nuclear magnetic resonance relaxation times and saturation profiles in the reservoir. The wetting state impacts waterflooding and aquifer encroachment into a reservoir.

If a surface is water-wet then the adhesive attraction of the water for the surface is greater than the cohesive attraction of the water molecules for one another. In an oil-water system, water- wet is also known as hydrophilic or water-loving or oleophobic or oil- hating. If a surface is oil-wet then the adhesive attraction of the oil for the surface is greater than the cohesive attraction of the oil molecules for one another. In an oil-water system, oil-wet is also known as oleophilic or oil-loving or hydrophobic or water-hating. Wettability can be quantified by the contact angle that the liquid makes with the contacting surface where the contact angle is measured through the water. For example, if water is forced to move, it displaces the oil in a water- wet system but advances over the oil in an oil-wet system. Wettability can also be quantified by the "work of cohesion" which is twice the surface tension and the "work of adhesion".

The following in-situ process acronyms are used herein:

CSS means Cyclic Steam Stimulation. In the CSS process, steam is injected into the reservoir at rates of the order of 1000 B/dl for a period of weeks; the well is then allowed to flow back and is later pumped. In suitable applications, the production of oil is rapid and the process is efficient, at least in the early cycles. If the steam pressure is high enough to fracture the reservoir and thus allow injection, it can also be used to produce the very viscous oil of an oil sands or carbonate reservoir. The main drawback of the cyclic steam stimulation process is that it often allows only about 15% of the oil to be recovered before the oil-to-steam ratio becomes prohibitively low.

ESEIEH means Solvent Extraction Incorporating Electromagnetic Heating HAGD is an acronym for Heat Assisted Gravity Drain. In the US oil shales, one recovery method being implemented in pilot projects involves the use of resistance heaters and heating elements to raise the temperature of the oil shales so that oil is produced. These methods are being considered for application to both oil sand and carbonate deposits in Alberta. These methods are designed to heat heavy oil and bitumen deposits to mobilize these hydrocarbons for production. Heating of oil sands by electrodes, often referred to as a form of HAGD. Direct heating of oil sands by electrically-powered heating elements is another form of HAGD.

LASER means Liquid Addition to Steam for Enhancing Recovery

LASER-CSS means Liquid Addition to Steam for Enhancing Recovery of Cyclic Steam Stimulation

N-Solv is a thermal solvent process

PHARM means Passive Heat Assisted Recovery Methods

SAGD means Steam Assisted Gravity Drain. Typically, SAGD wells or well pairs are drilled from the earth's surface down to the bottom of the oil sand deposit and then horizontally along the bottom of the deposit and then used to inject steam and produce mobilized bitumen.

SAGP means Steam Gas Push. SA-SAGD means Solvent Assisted SAGD

SC-SAGD means Solvent-Cyclic SAGD

ES-SAGD means Expanding Solvent-SAGD

SAP means Solvent Assisted Process

SAS means Steam Alternating Solvent

SAVES means Solvent Assisted Vapour Extraction with Steam

SA VEX means Steam and Vapour Extraction process

SGS means Steam Gas Solvent.

In a steamflooding process, steam is forced continuously into specific injection wells and oil is driven to separate production wells. The zones around the injection wells become heated to the saturation temperature of the steam, and these zones expand toward the production wells. Oil and water from the condensation of steam are removed from the producers. With viscous oil there is a considerable tendency for the steam to ovenide the reservoir, and this tends to limit the downward penetration of the heat and hence the recovery. Steamflooding can allow higher steam injection flow rates than steam stimulation; this advantage often offsets the rather lower thermal efficiency. Steam stimulation usually requires less (and sometimes far less) steam than flooding initially but is less efficient as depletion proceeds. Often it is economic to switch to steamflooding after initial operation of a field by steam stimulation. The recovery from steamflooding can approach 50% or even more. Recovery by steamflooding is commonly used in heavy- oil reservoirs containing oil whose high viscosity is a limiting factor for achieving commercial oil-producing rates. It has also been considered, however, as a method for recovering additional light oil. High-temperature steam is continuously injected into a reservoir. As the steam loses heat to the formation, it condenses into hot water, which, coupled with the continuous supply of steam behind it, provides the drive to move the oil to production wells.

VAPEX means Vapour Extraction process and is a process which uses a diluent as the fluid injected into the hydrocarbon formation as a mobilizing fluid

It is to be understood that a reference to solvent herein is intended to include diluent and a reference to diluent herein is intended to include solvent.

It is to be also understood that a reference to oil herein is intended to include low API hydrocarbons such as bitumen (API less than -10°) and heavy crude oils (API from -10° to -20°) as well as higher API hydrocarbons such as medium crude oils (API from -20° to -35°) and light crude oils (API higher than -35°). A reference to bitumen is also taken to mean a reference to low API heavy oils. A reference to heavy hydrocarbons is taken to mean low API hydrocarbons such as bitumen (API less than -10°) and heavy crude oils (API from -10° to -20°).

The preceding is a simplified summary of the disclosure to provide an

understanding of some aspects of the disclosure. This summary is neither an extensive nor exhaustive overview of the disclosure and its various aspects, embodiments, and/or configurations. It is intended neither to identify key or critical elements of the disclosure nor to delineate the scope of the disclosure but to present selected concepts of the disclosure in a simplified form as an introduction to the more detailed description presented below. As will be appreciated, other aspects, embodiments, and/or

configurations of the disclosure are possible utilizing, alone or in combination, one or more of the features set forth above or described in detail below.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure may take form in various components and arrangements of components, and in various steps and arrangements of steps. The drawings are only for purposes of illustrating the preferred embodiments and are not to be construed as limiting the disclosure.

Figure 1 is a schematic of a typical horizontal well pair used in various S AGD, VAPEX and various forms of combined steam and solvent processes.

Figure 2 shows an end view of a partem of horizontal wells for implementing the process of the present disclosure.

Figure 3 shows an end view of a pattern of horizontal wells for implementing the process of the present disclosure illustrating the placement within the producing zone.

Figure 4 is a flow chart showing the main steps in the RIAP process.

Figure 5 illustrates both a normal CSS time history and a possible RIAP time history.

Figure 6 illustrates the sequence of major recovery operations.

Figure 7 is a schematic of a control and feedback system for applying the RIAP process to a hydrocarbon reservoir.

It should be understood that the drawings are not necessarily to scale. In certain instances, details that are not necessary for an understanding of the disclosure or that render other details difficult to perceive may have been omitted. It should be understood, of course, that the disclosure is not necessarily limited to the particular embodiments illustrated herein. DETAILED DESCRIPTION

Figure 1 is a schematic of a typical horizontal well pair used in S AGD and VAPEX for example as well as in other various forms of combined steam and solvent processes. This Figure was taken from US 2011/0120709 published May 26, 2011 entitled "Steam- Gas-Solvent (SGS) Process for Recovery of Heavy Crude Oil and Bitumen". This configuration of injector and producer wells and variants of them are well-known and are prior art. It is possible to use the injector wells to inject either steam, solvent, steam-acid gas vapor or combinations of these fluids into the formation. As used herein, a well pair are two substantially horizontal wells with one located over the other and separated by a space of typically about 1 to about 5 meters. Typically, the upper well in the pair is used for injection of a mobilizing agent and the lower well in the pair is used for recovery of mobilized hydrocarbon.

Rapid Injection Alternating Production ("RIAP")

The RIAP process is defined by the pattern of its horizontal wells - an upper row of wells and lower row of wells wherein the wells in the upper row are offset from the wells in the lower row.

The RIAP process is also defined by the injection/production sequences employed wherein all wells in the upper row are configured as injectors and all wells in the lower row are configured as producers and, after a first selected period, all wells in the lower row are switched to injectors and all wells in the upper row are switched to producers. In a variation of this sequence, a group of wells in the upper row are configured as injectors and a group of wells in the lower row are configured as producers and, after a second selected period, all wells in the lower row are switched to injectors and all wells in the upper row are switched to producers. In this variation, the wells in these groups of upper and lower wells are contiguous. Elsewhere, other groups of wells can be operated in the same way. As can be appreciated, groups of upper and lower wells may be cycled back and forth from injectors to producers while other groups are cycling back and forth from injectors to producers but not in coinciding time periods.

The RIAP process can also be defined by the length of a mobilizing period as well as the shorter period, higher pressure and volume rate of the injected mobilizing agent. Typically the injection periods are weeks to months and injection pressures or injection flow rates are high enough to achieve a local reservoir pressure just below reservoir fracture pressure. The soak periods between injection and production may be as short as a day or two or extend for weeks. The length of production periods are typically about the same as the length of injection periods.

As described above, a pattern of horizontal wells is established comprising an upper row of wells and lower row of wells wherein the wells in the upper row are offset from the wells in the lower row. For example, there may be a hundred or more wells in the pattern. At any time, all the wells may be in operation or only a few of the wells may be in operation while the others are in a prolonged production period or shut down and not in operation. The wells may be divided into groups of contiguous wells and these groups may be operated autonomously or in synchronisation with other groups of wells. A group may consist of about 4 contiguous wells to about 20 contiguous wells with each group comprised of about the same number of upper and lower wells. From time to time, groups of wells may be redefined. For example, wells from a neighboring group on the left may moved into a group on its right or wells from a neighboring group on the right may moved into a group on its left. A group of wells may be operated for a first selected period with its upper row wells configured as injector wells and its lower row of wells configured as producers. Then the configurations of the wells can be switched so that the group of wells may be operated for a second selected period with its lower row wells configured as injector wells and its upper row of wells configured as producers.

Operating the wells in the pattern as members of groups allows for a group or groups of wells to be operated, for example, for a period in injection alternating production mode. Then one or more wells on one end of the group can be shut down while one or more wells on the other end of the group can be added. In this example, a group of wells can over time seem to migrate in the direction in which wells are added to the group. .

The operating procedure of the present disclosure can be applied for establishing initial communication between injector and producer wells in a thermal or a

thermal/solvent recovery operation and then continuing into the initial production phase for a selected period prior to start-up of a more conventional SAGD or SAP recovery process. This process of the present disclosure may be referred to herein as Rapid

Injection Alternating Production ("RIAP"). It should be noted that the RIAP process works only for a large group of wells. For example, the RIAP process can be applied to a large development consisting of about 8 wells or more.

In the RIAP process of the present disclosure, there is an upper row of wells and a lower row of wells. The wells of the upper row are offset from the wells of the lower row. So this configuration is not a configuration of well pairs but a configuration wherein each well in the upper row has two neighboring wells in the lower row and each well in the lower row has two neighboring wells in the upper row, as shown below in Figures 2 and 3.

Figure 2 shows an end view of a pattern of horizontal wells for implementing the RIAP process of the present disclosure. Wells are mstalled and completed in a pattern that involves an upper row and lower row of horizontal wells. The upper row is offset by a selected distance from the lower row. The wells in both upper and lower rows are drilled and completed to function as either injectors or producers.

Figure 2 illustrates an end view of a section of this pattern. A lower row of wells 21 is spaced by a spacing 23 which is typically in the range of about 70 meters to about 130 meters and preferably about 100 meters. An upper row of wells 22 is spaced by a spacing 24 which is also typically in the range of about 70 meters to about 130 meters and also preferably about 100 meters. The wells in the upper row are offset from the wells in the lower row by a spacing 26 which is typically about half the spacing between wells in the upper or lower row. For example, when the wells in each row are spaced about 100 meters apart, the offset between wells in the upper and lower rows is about 50 meters. The vertical distance 25 between the upper and lower rows is in the range of about 5 to about 10 meters. The vertical distance 25 between the upper and lower rows is typically the lower of 1) about one half the reservoir thickness above the lower row and 2) about 10 meters. When all the wells are completed, all the wells may be operated as injector or producer wells.

Figure 3 shows an end view of a pattern of horizontal wells for implementing the process of the present disclosure illustrating the placement within the producing zone. Figure 3 illustrates a reservoir zone with top of the reservoir 38 and bottom of the reservoir 39 with reservoir thickness 30. A lower row of wells 31 is shown offset from an upper row of wells 32 as described in Figure 2. As noted above, the vertical distance 35 between the upper and lower rows is typically the lower of 1) about one half the reservoir thickness above the lower row and 2) about 10 meters. In the Grosmont Carbonates, reservoir thickness 30 is typically in the range of about 12 meters to about 18 meters and sometimes greater than 20 meters. The lower row is typically about 1 meter to about 3 meters above the bottom of the reservoir 39 as shown by spacing 36.

Operating RIAP Wells

The maximum pressure that can be applied to a reservoir such as the Grosmont Carbonates is typically less than one of 1) the fracture pressure of the reservoir (although this is not always well-defined) and 2) the pressure necessary to maintain a substantially constant pressure conditions in a fractal type fluid flow network.

As an example of an operational sequence for start-up phase of the RJAP process, the following steps are typical:

□ inject steam, steam plus solvent or steam alternating with solvent through all wells at a pressure that is less than one of 1) the fracture pressure of the reservoir and 2) the pressure necessary to maintain a substantially constant pressure conditions in a fractal type fluid flow network. There is no production until the reservoir pressure has increased to a desired range, typically just below maximum reservoir pressure.

□ allow the reservoir to soak for a first selected time interval (for example about 7 days or less) while injecting small amounts of steam, steam plus solvent or steam alternating solvent to maintain the desired pressure

□ after a selected period of soaking, produce the lower wells while injecting steam, steam plus solvent or steam alternating with solvent through the upper wells while preferably maintaining pressure control or maintaining injection flow rate control for a second selected time interval

□ then reverse the procedure, injecting steam, steam plus solvent or steam alternating with solvent through the lower wells to rebuild pressure around the lower wells for a third selected time interval which may be approximately the same as the second selected time interval. The pressure around the upper wells should remain approximately constant.

□ again allow the reservoir to soak for the first selected time interval (as before, about 7 days or less) after pressure around the lower wells has been restored to about the pressure around the upper wells

□ after soaking, produce the upper wells while injecting steam, steam plus solvent or steam alternating with solvent through the lower wells while preferably maintaining pressure control or maintaining injection flow rate control

□ repeat the cycle until full communication is established between the upper and lower wells

The reservoir pressure is denoted as p_res and the operational pressure is denoted as Pop. The reservoir pressure is the average pressure of the reservoir as a whole and is generally equal to or less than maximum reservoir pressure. The operational pressure as used herein, is the pressure in the region around the injector/producer wells during the start-up phase of the procedure described herein. In the Grosmont Carbonates, the desired operational pressure, p_op, is typically in the range of about 1.5 MPa to about 4.5 MPa and preferably about 3 MPa.

For a selected period, each individual well is operated in a Cyclical Steam

Stimulation ("CSS") -like mode maintained at operational pressure, p_op,. If the injector well is a lower well then the wells in the upper rows are producers. If the injector well is an upper well then the wells in the lower rows are producers. Each local grouping of upper and lower wells are operated in a steamflood-like mode but with a back and forth or up and down type of flooding. This back and forth strategy is expected to reduce fingering and/or steam breakthrough. Maintaining injection pressure at a substantially constant level ensures minimal leak-off and is believed to result in a more stable reservoir.

After a few cycles of RIAP, when the upper and lower rows of wells are in full communication, the process can be transitioned into a longer term RIAP format and, eventually into a SAGD, SAP or other type of gravity drainage recovery process where the upper wells are used only for injection and the lower wells only for production. In this longer term phase of recovery, gravity drainage rather than pressure becomes the dominant driving force, moving mobilized bitumen to producer wells. Alternately, the process can be directly transitioned into a longer term SAGD, SAP or other type of recovery process where the upper wells are used only for injection and the lower wells only for production.

The RIAP process of alternating injection and production can be implemented as a series of injections and productions such as:

□ injection-production-injection-production-....

□ (nl-injections)-(ml-productions)-(n2-injections)-(m2 -productions)..., where nl, n2, n3,... and ml, m2, m3,... are integers greater or equal to 1, and where nl+n2+n3+... is approximately equal to ml+m2+m3+...

In general, it is preferred to operate the wells so that mobilized hydrocarbons are pushed to the nearest production well. But there can be conditions under which is desired to push mobilized hydrocarbons to other locations in the reservoir. As noted above, the RIAP process is designed to work with a large group of wells wherein the large group may be comprised of smaller local groups of wells. Therefore it is possible to time-phase the cycles of a local group of wells so that the mobilized bitumen is pushed laterally through the reservoir, for example, from a lower temperature region to a higher temperature region or from a region of low permeability to a region of higher permeability or from a region of low porosity to a region of higher porosity or from a region having a weak overlaying thermal barrier to a region having a substantially effective overlaying thermal barrier. The operating procedure described herein can be applied to in-situ recovery of bitumen or heavy oil in hydrocarbon reservoirs such as the Clearwater Formation in the Cold Lake area or in carbonate reservoirs such as those in the Grosmont Carbonates.

Figure 4 is a flow chart showing the main steps in the RJAP process. The reservoir recovery process is begun in step 401. In step 402, the upper and lower wells are installed and completed. As noted previously, the upper and lower wells may be operated as injectors or producers as determined by the operator. In step 403, steam, steam plus solvent or steam alternating solvent is injected through all wells at a pressure that is less than maximum reservoir pressure. If steam pressure is at or above the maximum reservoir pressure, the caprock can be broken and steam can escape vertically. There is no production until the operational pressure has increased to the desired range of about 1.5 MPa to about 4.5 MPa and preferably about 3 MPa which is a pressure range specific to the Grosmont Carbonates.

In step 404, the wells in the lower row are produced while steam, steam plus solvent or steam alternating solvent is injected through the wells in the upper row while maintaining pressure control or maintaining injection flow rate control so that the operational pressure remains at substantially the desired level. In step 405, the process is reversed and the wells in the upper row are produced while steam, steam plus solvent or steam alternating solvent is injected through the wells in the lower row again while maintaining pressure control or maintaining injection flow rate control so that the operational pressure remains at substantially the desired level. In step 406, the

communication between upper and lower wells is tested to determine whether full communication has been established. If full communication has not been established then the process is returned to step 404. The steps 404, 405 and 406 are repeated as indicated by loop 407 until full communication is established as determined in step 406. This ends the start-up phase of the process.

Once communication is established, the recovery moves to step 408 which is the beginning of the main recovery process and is dominated by pressure drive cycling back and forth as described above. Step 408 may be optional (that is, omitted entirely) or be applied for a selected period which may be a few days to a few months. After this selected period, the recovery process moves to step 409 which typically is the longest phase of the main recovery process and is dominated by gravity drainage. This may be any of the in- situ processes such as, for example, SAGD, VAPEX, SAP, SAVE and the like.

Optionally, step 410 may be included. Optional step 410 involves injecting a fluid that treats the reservoir by modifying the wettability of the fractures, vugs and other reservoir matrix surfaces from somewhat oil- wet to somewhat water-wet. This can significantly increase the recovery factor of bitumen and/or solvents from in a solvent or combined thermal-solvent process. Step 411 is the blow-down phase of the recovery operation where residual bitumen and/or solvent is recovered by any of several well-known methods. Step 411 may also include injection of a fluid that treats the reservoir by modifying the wettability of the fractures, vugs and other reservoir matrix surfaces In step 412, the recovery operation is terminated.

The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s. The Cyclic Steam Stimulation ("CSS") or "huff-and-puff ' method has been in use by Imperial Oil at Cold Lake since 1985. In the CSS method, the well is put through cycles of steam injection, soak, and heavy hydrocarbon production. First, steam is injected into a well or wells at a temperature of typically 300 to 340 degrees Celsius for a period of weeks to months; then, the well or wells are allowed to sit and soak for days to weeks to allow heat to soak into the formation; and, later, the hot mobile hydrocarbon is pumped out of the well or wells over a period of weeks or months. Once the production rate falls off, the well or wells are put through another cycle of injection, soak and production. This process is repeated until the cost of injecting steam becomes higher than the return made from producing heavy hydrocarbons. The CSS method has recovery factors of typically 20 to 35% and is commonly terminated when the cost to inject steam is too high for the amount of mobilized oil recovered..

There are heavy oil and bitumen reservoirs in which it is difficult to maintain pressures typical of the normal CSS process for a prolonged period of time (a normal CSS process cycle comprises a steam injection period, a soak period and a production period). The Grosmont carbonates may be such a reservoir because of the network of fractures, vugs of various sizes, dolines etcetera that cause the reservoir to communicate over a long range with other portions of the field or provide a connected volume network that takes time to fill completely or both. As used herein, the volume network of a reservoir means the network of fractures and dolines that may be connected as well as the number of vugs of various sizes which may be connected via the fractures, dolines and crystalline permeability, all of which form a volume network of fluid channels and cavities of varying size distributions.

This volume network may be filled with gases, liquids and solids. The solids existing naturally are heavy immobile hydrocarbons that may be mobilized into fluids with the addition of heat or solvents or both. The volume network therefore comprises the reservoir minus any solid, impermeable rock that cannot be substantially changed with the addition of heat or solvents or both.

One approach to overcome this inability to maintain reservoir pressure for a prolonged period of time is to shorten the steam injection period and increase injection flow rate, then substantially shorten or even eliminate the soak period so that the pressure can be maintained close to the selected level as some fluids will migrate out of the reservoir due to its fractal nature. The production period can be terminated once the production rate falls off. There will always be a small delay between steaming and production periods for operational changeover. There is usually no significant delay between end of a soak period and initiation of production.

Figure 5 illustrates an example of both a normal CSS time history and a Rapid Injection Alternating Production time history . Fig. 5a illustrates a normal CSS time history 500. It begins with a period of steaming 501. After a period of weeks to months, there is a short operational break 502 of about a day to a few days when the changeover from steaming to soaking/producing is accomplished. This is followed by a period of soaking 503 indicated by the dotted line. This period of soaking lasts for days to weeks and is then followed by a period of production 504 for a period of weeks or months. The cycle is repeated until the stimulation process is no longer economically viable.

Fig. 5b illustrates an example of a modified CSS time history 500 called a Rapid

Injection Alternating Production time history. The name Rapid Injection Alternating Production refers to a mode of CSS where the steaming period is more rapid than normal, there is no substantial soak period and the period of production is dependent on the production rate for this altered process. It begins with a period of steaming 511. After a period of days to weeks, there is a short operational break 512 of a day to a few days when the changeover from steaming to producing is accomplished. There is substantially no soak period. This is followed by a period of production 514 for a period of days to weeks that ends once the production rate falls off. As with normal CSS, the cycle is repeated until the stimulation process is no longer economically viable.

Figure 6 illustrates the sequence of major recovery operations along a time axis

600. The start-up phase 601 is followed by a RIAP high pressure recovery phase 602. RIAP high pressure recovery phase 602 is followed by low pressure phase 603 and finally by blow-down phase 604. The total time for the entire recovery operation is typically about 10 to about 20 years. The start-up phase 601 and high pressure recovery phase 602 is typically about 1 to about 5 years and a Rapid Injection Alternating Production process is employed during this period. As noted above, once the start-up phase wherein full communication is established between all wells, high pressure recovery phase 602 can be omitted or applied for a selected period. Thereupon, low-pressure gravity drain phase 603 can be initiated. The blow-down phase 604 typically takes about 5 years. Therefore the low pressure phase 603 is typically about 4 to about 10 years during which a low pressure process such as, for example, SAGD, VAPEX, SAP, SAVE and the like is employed.

As can be appreciated, either or both the high pressure Rapid Injection Alternating Production process and the low pressure process can be earned out while injecting steam, steam-acid gas vapor, solvent or combinations of these fluids into the formation.

As can also be appreciated, the Rapid Injection Alternating Production process can be employed as a start-up process or as a complete recovery process or as an initial recovery process followed, for example, by a period of SAGD or SAP. Both SAGD and SAP are low pressure processes where gravity is the main driving force moving mobilized heavy hydrocarbon toward producer wells and may work well after several cycles of RIAP.

Control of the RIAP Process

In yet another embodiment, the systems and methods of this disclosure can be implemented in conjunction with a special purpose computer, a programmed

microprocessor or microcontroller and peripheral integrated circuit element(s), an ASIC or other integrated circuit, a digital signal processor, a hard- wired electronic or logic circuit such as discrete element circuit, a programmable logic device or gate array such as PLD, PLA, FPGA, PAL, special purpose computer, any comparable means, or the like. In general, any device(s) or means capable of implementing the methodology illustrated herein can be used to implement the various aspects of this disclosure. Exemplary hardware that can be used for the disclosed embodiments, configurations and aspects includes computers, handheld devices, telephones (e.g., cellular, Internet enabled, digital, analog, hybrids, and others), and other hardware known in the art. Some of these devices include processors (e.g., a single or multiple microprocessors), memory, nonvolatile storage, input devices, and output devices. Furthermore, alternative software

implementations including, but not limited to, distributed processing or component/object distributed processing, parallel processing, or virtual machine processing can also be constructed to implement the methods described herein. In yet another embodiment, the disclosed methods may be readily implemented in conjunction with software using object or object-oriented software development environments that provide portable source code that can be used on a variety of computer or workstation platforms. Alternatively, the disclosed system may be implemented partially or fully in hardware using standard logic circuits or VLSI design. Whether software or hardware is used to implement the systems in accordance with this disclosure is dependent on the speed and/or efficiency requirements of the system, the particular function, and the particular software or hardware systems or microprocessor or microcomputer systems being utilized.

In yet another embodiment, the disclosed methods may be partially implemented in software that can be stored on a storage medium, executed on programmed general- purpose computer with the cooperation of a controller and memory, a special purpose computer, a microprocessor, or the like. In these instances, the systems and methods of this disclosure can be implemented as program embedded on personal computer such as an applet, JAVA® or CGI script, as a resource residing on a server or computer workstation, as a routine embedded in a dedicated measurement system, system component, or the like. The system can also be implemented by physically incorporating the system and/or method into a software and/or hardware system.

Figure 7 is a schematic of a control and feedback system for applying the RIAP process to a hydrocarbon reservoir. Manual or computer-automated monitoring of injection diagnostics, reservoir diagnostics and recovered fluid diagnostics provides the feedback for adjusting control of injection pressures, injection volumetric flow rates and selection of injection fluids. Diagnostic feedback also allows the operator to configure the various wells and groups of wells as injectors or producers and alter the timing off the various injection, soak and production periods. This figure illustrates the important functional units of a thermal recovery plant wherein the RIAP process is applied. Steam, solvent, steam-acid gas vapor or combinations of these fluids are generated in facility 703, sent to well pads 702 via path 751 and injected into the reservoir 701 via path 753.

Mobilized bitumen or heavy oil, water, methane and other formation fluids are be recovered from producer wells in reservoir 701 via path 754 at well pads 702 and then delivered via path 752 to surface facility 704 which may be a facility also housing generating facility 703. The flow of material to and from the hydrocarbon reservoir 701 is indicated by solid lines. Figure 7 shows reservoir diagnostics 711 which include diagnostics from observation and other diagnostic wells 711 which communicate with computer 721 via path 761. Figure 7 further shows outgoing injection fluid flow diagnostics 712 which communicate with computer 721 via path 762 and incoming recovered fluid flow diagnostics 713 which communicate with computer 721 via path 763. The flow of diagnostic information and diagnostic control commands to and from the hydrocarbon reservoir 701 is indicated by less densely spaced dashed lines. Computer 721 controls the injection of fluids from generating facility 703 via control path 771 and control elements 733 to well pads 702 and reservoir 701 via control path 772 and control elements 731. Computer 721 also controls the recovery of fluids to surface facility 704 via control path 773 and control elements 734 from well pads 702 and reservoir 701 via control path 774 and control elements 732. The control paths are indicated by densely spaced dashed lines. Computer 721 is comprised of a memory module 722, a processor module 723 and a controller 724. The controller 724 contains control logic electronics used, among other things, to process diagnostic data collected from the aforementioned diagnostics and to provide control inputs for the control elements. In one embodiment, the controller utilizes control algorithms comprising at least one of on/off control,

proportional control, differential control, integral control, state estimation, adaptive control and stochastic signal processing.

The exemplary systems and methods of this disclosure have been described in relation to preferred aspects, embodiments, and configurations. Modifications and alterations will occur to others upon a reading and understanding of the preceding detailed description. It is intended that the disclosure be construed as including all such

modifications and alterations insofar as they come within the scope of the appended claims or the equivalents thereof. To avoid unnecessarily obscuring the present disclosure, the preceding description omits a number of known structures and devices. This omission is not to be construed as a limitation of the scopes of the claims. Specific details are set forth to provide an understanding of the present disclosure. It should however be appreciated that the present disclosure may be practiced in a variety of ways beyond the specific detail set forth herein.

The present disclosure, in various embodiments, includes components, methods, processes, systems and/or apparatus substantially as depicted and described herein, including various embodiments, sub-combinations, and subsets thereof. Those of skill in the art will understand how to make and use the present disclosure after understanding the present disclosure. The present disclosure, in various embodiments, includes providing devices and processes in the absence of items not depicted and/or described herein or in various embodiments hereof, including in the absence of such items as may have been used in previous devices or processes, for example for improving perfomiance, achieving ease and\or reducing cost of implementation.

The foregoing discussion of the disclosure has been presented for purposes of illustration and description. The foregoing is not intended to limit the disclosure to the form or forms disclosed herein. In the foregoing Detailed Description for example, various features of the disclosure are grouped together in one or more embodiments for the purpose of streamlining the disclosure. This method of disclosure is not to be interpreted as reflecting an intention that the claimed disclosure requires more features than are expressly recited in each claim. Rather, as the following claims reflect, inventive aspects lie in less than all features of a single foregoing disclosed embodiment. Thus, the following claims are hereby incorporated into this Detailed Description, with each claim standing on its own as a separate preferred embodiment of the disclosure.

Claims

What is claimed is:

1. A method, comprising:

(a) providing a plurality of upper and lower wells positioned in a hydrocarbon- containing formation, each well configured to operate, in a first mode, as an injector well and, in a second mode, as a producer well, wherein the upper wells form an upper row and the lower wells form a lower row and wherein the wells in the upper row are offset from the wells in the lower row;

(b) assigning a plurality of contiguous wells to a first group for a first selected time period;

(c) for the first selected time period, operating a first subset of the wells in the first group in the first mode but not the second mode to inject a hydrocarbon mobilizing fluid into the hydrocarbon-containing formation;

(d) for the first selected time period, operating a second subset of the wells of the first group in the second mode but not the first mode to produce a hydrocarbon from the hydrocarbon-containing formation;

(e) changing at least one of an injection pressure and an injection volumetric flow rate for the wells in the first subset to provide a user selected operational pressure in the hydrocarbon-containing formation; and

(f) repeating steps (c), (d) and (e) until a plurality of the wells within the first group are in full fluid communication with one another, whereby the recovery of a hydrocarbon from an underground hydrocarbon-containing material is initiated.

2. The method of claim 1 , wherein the wells in the upper row are offset midway between the wells in the lower row.

3. The method of claim 1 , wherein the hydrocarbon mobilizing fluid is at least one of steam, solvent and a steam/solvent mixture.

4. The method of claim 1 , wherein the user selected operational pressure is between about 1.5 MPa and about 4.5 MPa.

5. The method of claim 1, wherein the user selected operational pressure is maintained by an automatic controller.

6. The method of claim 5, wherein the automatic controller receives inputs comprising data from one or more production wells, injection wells and observation wells.

7. The method of claim 1 , further comprising a step (g) wherein the repeating steps (c), (d) and (e) are continued for a selected period after full fluid communication between all upper wells and lower wells has been established.

8. The method of claim 1, further comprising a step (g) wherein the recovery of hydrocarbons continues using a gravity drainage process comprising injecting a hydrocarbon mobilizing fluid from the upper wells while producing a hydrocarbon from the lower wells.

9. A system for initiating recovery of a hydrocarbon from an underground hydrocarbon-containing material comprising:

(a) a plurality of upper and lower wells positioned in a hydrocarbon-containing formation, each well configured to operate, in a first mode, as an injector well and, in a second mode, as a producer well, wherein the upper wells form an upper row and the lower wells form a lower row and wherein the wells in the upper row are offset from the wells in the lower row;

(b) a first group of wells formed by a plurality of contiguous wells;

(c) a hydrocarbon mobilizing fluid injected into the hydrocarbon containing formation from a first subset of the wells in the first group operating in the first mode but not the second mode, wherein an operational pressure is established to a user selected operational pressure;

(d) a hydrocarbon produced from the hydrocarbon-containing formation from a second subset of the wells of the first group operating in the second mode but not the first mode; and

(e) an automatic controller configured to alternate between i) producing a hydrocarbon from the second subset of the wells of the first group; and ii) injecting a hydrocarbon production fluid from the first subset of the wells in the first group operating in the first mode but not the second mode; and iii) repeating steps i) and ii) until a plurality of the wells within the first group are in full fluid communication with one another, wherein the recovery of a hydrocarbon from an underground hydrocarbon-containing material is initiated.

10. The system of claim 9, wherein the hydrocarbon mobilizing fluid is at least one of steam, solvent and a steam/solvent mixture.

11. The system of claim 9 wherein the wells in the upper row are offset midway between the wells in the lower row.

12. The system of claim 9, wherein the user selected operational pressure is between about 1.5 MPa and about 4.5 MPa.

13. The system of claim 9, wherein the user selected operational pressure is maintained by at least one of maintaining an injection pressure and maintaining an inj ection flow rate.

14. The system of claim 9, wherein the automatic controller receives inputs comprising data from one or more production wells, injection wells and observation wells.

15. The system of claim 9 wherein a plurality of wells in the upper row can be operated as injection wells and a plurality of the wells in the lower row can be operated as production wells using a gravity drainage process.

16. A non-transitory computer readable medium having stored thereon computer executable instructions, the computer executable instructions causing a processor of a device to execute a method of initiating recovery of a hydrocarbon from an underground hydrocarbon-containing material, the method comprising:

instructions to configure a first selected group of upper and lower wells and to select a first subset of the first selected group to operate in a first mode as injection wells and to select a second subset of the first selected group to operate in a second mode as producer wells;

instructions to operate a subset of the first selected group as injection wells and a second subset of the first selected group as producer wells;

instructions to establish an operational pressure to a user selected operational pressure;

instructions to produce a hydrocarbon from the second subset of the first selected group while injecting a hydrocarbon mobilizing fluid from the first subset of the first selected group while maintaining the user selected operational pressure; and

instructions to repeat the previous two instructions until a plurality of the wells within the selected first group are in full fluid communication with one another, wherein the recovery of a hydrocarbon from an underground hydrocarbon-containing material is initiated.

17. The medium of claim 16, wherein the hydrocarbon mobilizing fluid is at least one of steam, solvent and a steam/solvent mixture.

18. The medium of claim 16, wherein the user selected operational pressure is between about 1.5 MPa and about 4.5 MPa.

19. The medium of claim 16, wherein the user selected operational pressure is maintained by at least one of maintaining an injection pressure and maintaining an injection flow rate.

20. The medium of claim 16, wherein the user selected operational pressure is maintained by an automatic controller.