WO2014053912A1 - Method for treating carbonate reservoirs - Google Patents

Abstract

A method is disclosed for treating hydrocarbon reservoirs to alter surface wettability of carbonate reservoirs for improved recovery of heavy oil or bitumen. In one embodiment, recovery operations involving solvents and/or steam to mobilize heavy hydrocarbons are addressed, such as oil-wet reservoir matrices of the Grosmont Carbonates. Gases may be added, such as carbon dioxide, sulfur dioxide and/or nitrogen dioxide, to form acidic liquids or vapors when combined with water or steam as injected during in-situ recovery operations. Acid-producing gases adhere to matrix rock surfaces as the gases condense/dissolve; condensed vapors react with carbonate rocks, such as limestone and dolomite, and alter the surfaces from oil-wet towards water- wet. The method's effectiveness may be monitored by analyzing the recovered fluids and/or applying cased-hole diagnostics in observation wells. Compressed flue gases or carbon dioxide gas recovered from other surface plant processes may be added to the injected steam.

Description

METHOD FOR TREATING CARBONATE RESERVOIRS

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. 61/710,363 entitled "Method for Treating Carbonate Reservoirs" filed October 5, 2012 which is incorporated herein by reference and cross- references U.S. Patent Application 12/498,895 entitled "Carbon Removal from an

Integrated Thermal Recovery Process" filed July 7, 2009 which is also incorporated herein by reference.

FIELD

This disclosure relates generally to a method for treating hydrocarbon reservoirs and specifically to a method for altering surface wettability of carbonate reservoirs for improved recovery of heavy oil or bitumen.

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 McMurray 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 McMurray oil sands. These include advanced methods such as ES-SAGD, SAP, SAS, S A- SAGD, SC-SAGD, LASER and the like (all of which are defined in the Summary) which involve a combination of various thermal and solvent heavy hydrocarbon mobilization strategies. As can be appreciated, solvents are now used extensively in bitumen and heavy oil recovery operations. 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 reservoir matrix of the Carbonates is known to be oil wet and this can significantly reduce the recovery factor of bitumen and solvents from fractures, vugs and other matrix surfaces, especially in tight matrices, in thermal, solvent or combined thermal-solvent processes.

Therefore there remains a need for methods of improving the overall recovery factors of bitumen and solvents from thermal, solvent or combined thermal-solvent in-situ processes used in the oil sands and especially in the Carbonates.

SUMMARY

These and other needs are addressed by the various embodiments and

configurations of the present disclosure which are directed to a method for treating hydrocarbon reservoirs and specifically to a method for altering surface wettability of carbonate reservoirs for improved recovery of heavy oil or bitumen. The methods disclosed herein are aimed specifically at oil-wet reservoir matrices such as the Grosmont Carbonates but may be applied to other oil-wet or even water- wet hydrocarbon deposits to improve recovery of residual bitumen and solvents when solvents are used, alone or in combination with steam, to mobilize or assist in mobilizing heavy hydrocarbons.

The method disclosed herein comprises adding gases, such as for example, 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. These acidic liquids or vapors are combined with water or steam when the latter is injected into an in-situ recovery operation to mobilize heavy hydrocarbons.

The acid-producing gas or gases may be injected separately or in combination with injected steam or in combination with injected solvents or in combination with injected steam and solvents. It is noted that solvents are typically injected in the gaseous or vapor state. The acid-producing gas or gases may be injected at any time during the recovery process. While it is preferable to inject one or more acid-producing gases during the terminal phase of recovery operations, the acid-producing gases may be injected continuously during the recovery process or at selected intervals during the recovery process. As can be appreciated, any of the acid-producing gases can be mixed with water or steam above ground and injected separately as acids in liquid or vapor form into the reservoir. An acid-producing gas may also be referred to as an acid precursor.

The concentration of injected acid-producing gas as measured by mass fraction or mass percentage can be 0% to 100%. When no acid-producing gases are being injected, the percentage by injected mass is 0%. When only acid-producing gases are being injected, the percentage by injected mass is 100%.

As can be appreciated, when acid-producing gases are injected, they add to the pressure of other injected gases and therefore become a component of the pressure drive tending to force mobilized hydrocarbons to the periphery of the steam or vapor chamber where they are then dominated by gravity drainage to the collector wells.

The acid-producing gases will typically remain in the gaseous or vapor state at reservoir pressures and temperatures typical of steam and solvent recovery processes. Therefore the acid-producing gases will tend to fill the entire volume of the portion of the reservoir from which at least some hydrocarbon has been recovered. When the acid- producing gases condense or dissolve into liquids, they will tend to adhere to the surfaces of the matrix rock. Acidic fluids are known to react with carbonate rocks such as limestone and dolomite which are typical matrix rocks of the Carbonates and this reaction tends to transform the surfaces from oil-wet towards water- wet. This, in turn, reduces the surface affinities to bitumen and solvents trapped in the pore spaces, vugs and microfractures of the matrix rock where residual bitumen and excess solvents tend to adhere.

Many acid-producing gases are available at in-situ operations, especially carbon dioxide which is generated by steam production facilities and sulfur dioxide which is recovered from, for example, an upgrading process carried out on site. It is believed that acidic vapors or acidic liquids condensed from such vapors will take time to change the surface affinities of oil-wet surfaces. Therefore it is preferred to add acid-producing gases to injected steam whenever steam is used. It is believed that the weak acids formed when the acid-producing gases combine with steam or water will fill the various pore spaces, vugs and micro-fractures of the matrix rock and work over time to change the surface affinity from oil-wet to water-wet. As the reservoir cools, the acidic vapors will condense into acidic liquids and retain their effectiveness.

It is also possible to add acid-producing gases to injected steam during the reservoir blow-down phase and extend the blow-down phase to allow for additional recovery of residual bitumen and solvents.

The procedures involved in applying the above acid-producing gas treatments preferably require ongoing knowledge of the effectiveness of the treatment. The procedures therefore preferably require that changes in the condition of the surface wettability be monitored as the process is applied. This may be carried out by monitoring the recovered fluids (gases, water and hydrocarbons) for changes in pH which would indicate that acidic gases were being consumed and therefore changing surface wettability. When observation wells are installed to allow for in-situ pressure and temperature readings, cased-hole diagnostic systems can be used to determine, for example, changes in formation resistivity and relative amounts of hydrocarbon/water. It is also possible to retrieve matrix rock and fluid samples from time to time from inside a cased observation well. This recovered matrix material allows direct observation of any changes in surface wettability conditions.

The acid-producing gases may be injected along with the steam or steam/solvent gases for mobilizing the bitumen or heavy oil. It is also possible to add compressed flue gases to the injected steam or to add carbon dioxide gas recovered from other surface plant processes when available.

In one embodiment, a method is disclosed, comprising contacting at least one of an acid and acid precursor with a mobilizing agent in a hydrocarbon deposit, whereby a surface wettability of the hydrocarbon deposit before said contacting is altered towards water- wet after said contacting.

In another embodiment, a method is disclosed to alter surface wettability of a hydrocarbon deposit towards water- wet, comprising 1) providing a first stream

comprising a mobilizing agent to mobilize hydrocarbons in a hydrocarbon deposit, 2) providing a second stream comprising an acid and acid precursor, 3) injecting the first and second streams into the hydrocarbon deposit at a respective first rate and a second rate and 4) sensing at least one of fluids recovered from the hydrocarbon deposit and geological properties of the hydrocarbon deposit to adjust or maintain the first and second rates wherein the surface wettability of the hydrocarbon deposit is altered towards water-wet.

In yet another embodiment, a system is disclosed to alter surface wettability of a hydrocarbon deposit towards water- wet, comprising 1) a first input to receive a first stream comprising a mobilizing agent to mobilize hydrocarbons in a hydrocarbon deposit, 2) a second input to receive a second stream comprising an acid and acid precursor, 3) an injector to inject the first and second streams into the hydrocarbon deposit at a respective first rate and a second rate and 4) at least one sensor to sense at least one of fluids recovered from the hydrocarbon deposit and geological properties of the hydrocarbon deposit to adjust or maintain the first and second rates wherein the surface wettability of the hydrocarbon deposit is altered towards water- wet.

In yet another embodiment, 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 altering surface wettability of a hydrocarbon deposit towards water- wet, comprising 1) instructions to provide a first stream comprising a mobilizing agent to mobilize hydrocarbons in a hydrocarbon deposit, 2) instructions to provide a second stream comprising an acid and acid precursor, 3) instructions to inject the first and second streams into the hydrocarbon deposit at a respective first rate and a second rate and 4) instructions to sense at least one of fluids recovered from the hydrocarbon deposit and geological properties of the hydrocarbon deposit to adjust or maintain the first and second rates wherein the surface wettability of the hydrocarbon deposit is altered towards water- wet.

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:

An acid is a chemical substance having the ability to react with bases and certain metals (like calcium) to form salts. There are three common definitions for acids: the Arrhenius definition, the Bronsted-Lowry definition, and the Lewis definition. The Arrhenius definition defines acids as substances which increase the concentration of hydrogen ions (H+), or more accurately, hydronium ions (H30+), when dissolved in water. The Bronsted-Lowry definition is an expansion: an acid is a substance which can act as a proton donor. By this definition, any compound which can easily be deprotonated can be considered an acid. Examples include alcohols and amines which contain O-H or N-H fragments. A Lewis acid is a substance that can accept a pair of electrons to form a covalent bond. Examples of Lewis acids include all metal cations, and electron-deficient molecules such as boron trifluoride and aluminium trichloride.

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.

An acid precursor or acid-producing gas refers to any type of gas or gaseous mixture which forms an acidic compound when mixed with water. The most common types of acid gases are hydrogen sulfide (H₂S), sulfur oxides (SOx) (which can form sulfuric acid when mixed with water), nitric oxides (ΝΟχ) (which can form nitric acid when mixed with water), and carbon monoxide (CO) and/or carbon dioxide (C0₂) (which can form carbonic acid when mixed with water).

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.

A carbon sequestration facility is a facility in which carbon dioxide can be controlled and sequestered in a repository such as for example a mature or depleted oil and gas reservoir, an unmineable coal seam, a deep saline formation, a basalt formation, a shale formation, or an excavated tunnel or cavern.

CSOR means cumulative steam-oil ratio.

The terms determine, calculate and compute and variations thereof, as used herein, are used interchangeably and include any type of methodology, process, mathematical operation or technique.

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 is processed to 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..

EOR stands for Enhanced Oil Recovery.

Finite-difference methods are numerical methods for approximating the solutions to differential equations using finite difference equations to approximate derivatives. An explicit finite difference code involves calculating the appropriate variables (pressure, density, energy, velocity and the like), then calculating a stable time-step, then advancing the calculation time by that time-step. This process is repeated until the time-limit of the calculation is reached. The calculation is regulated by ensuring that mass, momentum and energy are substantially conserved after each time step. These type of calculations are commonly carried out on a high-performance computer.

Imbibition is the process of absorbing a wetting phase into a porous rock. It is possible for the same rock to imbibe both water and oil, with water imbibing at low in-situ water saturation, displacing excess oil from the surface of the rock grains, and oil imbibing at low in-situ oil saturation, displacing excess water. The wettability of the rock is determined by which phase imbibes more.

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. The low molecular weight hydrocarbons commonly include, in addition to methane, ethane, propane, and butane.

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. pH is a measure of the acidity or basicity of an aqueous solution. Solutions with a pH less than 7 are said to be acidic and solutions with a pH greater than 7 are basic or alkaline. Pure water has a pH very close to 7.

Pipeline quality natural gas is specified for example by the American Gas

Association and Canadian Gas Association. Typically, there are limits on sulphur, carbon dioxide, water and other constituents of natural gas obtained from nature to comply with pipeline specifications.

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 is any producer of natural gas, oil, heavy oil, bitumen, peat or coal from a hydrocarbon reservoir.

Reforming means fossil fuel reforming which is a method of producing useful products, such as hydrogen or ethylene from fossil fuels. Fossil fuel reforming is done through a fossil fuel processor or reformer. At present, the most common fossil fuel processor is a steam reformer. This conversion is possible as hydrocarbons contain much hydrogen. The most commonly used fossil fuels for reforming today are methanol and natural gas, yet it is possible to reform other fuels such as propane, gasoline, autogas, diesel fuel, methanol and ethanol. During the conversion, the leftover carbon dioxide is typically released into the atmosphere. On an industrial scale, reforming is the dominant method for producing hydrogen. The produced carbon monoxide can combine with more steam to produce further hydrogen via the water gas shift reaction.

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.

Syngas (from synthesis gas) is the name given to a gas mixture that contains varying amounts of carbon monoxide and hydrogen. Examples of production methods include steam reforming of natural gas or liquid hydrocarbons to produce hydrogen, the gasification of coal and in some types of waste-to-energy gasification facilities. The name comes from their use as intermediates in creating synthetic natural gas and for producing ammonia or methanol. Syngas is also used as an intermediate in producing synthetic petroleum for use as a fuel or lubricant via Fischer-Tropsch synthesis and previously the Mobil methanol to gasoline process. Syngas consists primarily of hydrogen, carbon monoxide, and very often some carbon dioxide, and has less than half the energy density of natural gas. Syngas is combustible and often used as a fuel source or as an intermediate for the production of other chemicals.

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.

The water-gas shift reaction is a chemical reaction in which carbon monoxide reacts with water to form carbon dioxide and hydrogen. The water-gas shift reaction is often used in conjunction with steam reforming of methane or other hydrocarbons. The water-gas shift reaction is slightly exothermic. The process is often used in two stages, stage one a high temperature shift at 350°C and stage two, a low temperature shift at 190 to 210°C.

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/d 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 the oil sands at an economic rate. The main drawback of the cyclic steam stimulation process is that it often allows only about 15% to 25% of the oil to be recovered before the oil-to-steam ratio becomes prohibitively low.

ESEIEH means Enhanced Solvent Extraction Incorporating Electromagnetic Heating

HAGD is an acronym for Heat Assisted Gravity Drainaige. 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 means thermal solvent process

PHARM means Passive Heat Assisted Recovery Methods

SAGD means Steam Assisted Gravity Drainaige. 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 collect 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

SA VES means Solvent Assisted Vapour Extraction with Steam

SAVEX 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 override the reservoir, and this tends to limit the downward penetration of the heat and hence the recovery. Steamflooding can allow higher steam injection 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 heavy hydrocarbons herein is intended to include low API hydrocarbons such as bitumen (API less than -10°) and heavy crude oils (API from -10° to -20°). A reference to oil is understood to include heavy hydrocarbons 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 heavy hydrocarbons.

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 SAGD, VAPEX and various forms of combined steam and solvent processes.

Figure 2 illustrates the types of cased-hole logging technologies available for monitoring reservoir parameters associated with surface wettability.

Figure 3 is a schematic showing the principal elements of a prior-art bitumen recovery operation using natural gas for power. Figure 4 is schematic of a prior-art thermal recovery power plant using natural gas for power and for capturing C02. (Taken from US Patent Application No. 12/498,895 entitled "Carbon Removal from an Integrated Thermal Recovery Process").

Figure 5 is schematic of a bitumen recovery surface plant wherein flue gases and C02 are available for injection into the reservoir.

Figure 6 is an example of a time-line for a cyclical steaming process wherein an acid or acid precursor is injected from time to time during one or more injection intervals.

Figure 7 is a schematic of a control and feedback system for applying an acid treatment 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

Acid Treatment for Altering Surface Wettability

Figure 1 is a schematic of a typical horizontal well pair used in SAGD, VAPEX and 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 wells 30 and recovery wells 35 and variants of them is well-known and is prior art. It is possible to use the injector wells to inject either steam or a steam/solvent mix into the formation. Further, a steam/acid vapor or steam/solvent and acid vapor mix may also be injected into the formation. It is also possible to use separate injector wells to inject acid-producing gas or other forms of acids into the formation.

There are advantages of using a steam and solvent process such as SAVEX over SAGD alone in the McMurray oil sands. The use of a combined thermal-solvent procedure typically results in a more rapid initial recovery rate and an overall increase in total recovery. It is believed that, when used in the Carbonates, the advantages of combined thermal-solvent procedures will diminish because of the oil-wet reservoir matrix. It is therefore believed that the addition of an acid-producing gas treatment schedule will alter the oil-wet surface towards water-wet or at least to intermediate-wet and will therefore restore the advantage of combined thermal-solvent procedures or even improve them especially during the latter stages of the reservoir recovery life cycle. 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. Overall recovery factor of both bitumen and solvent can be improved by altering oil-wet surfaces towards water-wet with the addition of an acid-producing gas treatment especially during the latter stages of the reservoir recovery life cycle.

Any acid-producing gas treatment, especially over a prolonged period, such as when included with all steam injection cycles, should also act to maintain pressure drive as the steam condenses in the vicinity of the steam chamber front. In addition, some acid-gas vapor can condense at the steam chamber front and this will add heat to the steam front.

C0₂ dissolves in water forming carbonic acid, which is a weak acid, because C0₂ molecule ionization in water is incomplete.

Oxidation of S02, usually in the presence of a catalyst such as N02, forms H2S04. The sequential oxidation of sulfur dioxide followed by its hydration is used in the production of sulfuric acid.

2 S0₂ + 2 H₂0 + 0₂→ 2 H₂SO₄

Nitrogen dioxide is the chemical compound with the formula NO₂. It is one of several nitrogen oxides. NO₂ is an intermediate in the synthesis of nitric acid.

Other acids or acid precursors can also be injected to alter surface wettability. These include, for example, volatile organic acids, such as acetic acid.

Monitoring and Controlling the Acid Treatment

Analysis of Recovered Fluids

In a typical thermal/solvent bitumen recovery operation, the mixture brought up by the recovery wells (e.g. the lower well in Figure 1) includes water, mobilized bitumen, solvent and various gases such as methane and carbon dioxide. If acid-producing gases are also injected into the formation along with steam and solvent (e.g. the upper well in Figure 1), then some of these gases may be included in the recovered gases.

Typically, the recovered gases are removed from the recovered mixture before and/or during water/hydrocarbon separation and these gases can be analyzed by known means. If there is a deficit between recovered S0₂, for example, with the amount injected, then it is known that some SO₂ may have been converted on the exposed surfaces of the reservoir. Water is usually separated out next, as described in Figure 3. This recovered water can be analyzed using known methods to determine its pH which can be compared to the pH of the injected steam or a sample of condensed steam. If the pH of the recovered water is higher (more alkaline) than the injected water in the form of steam, then this is another indicator that the injected acid-producing gases have altered the surface wettability from primarily oil-wet to water- wet or at least to intermediate-wet.

If the ratio of recovered bitumen to recovered water increases after a reasonable time delay from injection of acid-producing gases, this increase may be attributable to a change in reservoir surface wettability and a subsequent improved recovery of bitumen and solvent from the reservoir surfaces.

Observation Wells

It is common practice to install a number of cased observation wells in a thermal bitumen recovery operation so as to monitor reservoir temperatures and pressures as the steam chamber develops. It is possible therefore to include well-logging diagnostics in these observation wells. These diagnostics may be installed in fixed locations (as opposed to moving them such as in a wireline operation) or the diagnostics can be operated as a cased-hole wireline (that is, moved back and forth along the well by a wireline). One or more of these diagnostics may be used to determine changes over time of reservoir parameters that relate to changing amounts of water, hydrocarbon and gas.

An observation well may be a vertical well, an inclined well or a horizontal well. The casing of a cased-hole may be made of any number of materials such as, for example, steel, thermal plastic or ceramic. For example, a short section of casing may be made from a suitable thermal plastic, fiberglass or ceramic from which dielectric diagnostics may be operated.

Figure 2 illustrates the types of cased-hole logging technologies available for monitoring reservoir parameters associated with surface wettability. These include known cased-hole well logging diagnostics that can measure formation resistivity, dielectric response, formation fluid flow velocity, porosity and relative amounts of salt water, fresh water, hydrocarbons and reservoir gases and the like. It is also common to run cased-hole temperature and noise logs to detect the flow of fluids and differentiate between liquid and gaseous flows. Radioactive tracers can be injected from a cased-hole and detected from within the casing, a technique that can also determine local reservoir fluid flow

characteristics. Reservoir matrix materials and fluid flow samples can also be retrieved with currently available cased-hole tools. This observation well information, alone or in combination with analysis of recovered fluids, can be used to determine if the acid-producing gas treatment is having the desired effect of changing surface wettability from oil-wet towards water-wet. This information can then be used to alter the injection schedule, injection composition and injection amounts of acid-producing gases to optimize the process of effect of changing surface wettability from oil-wet towards water- wet.

Matching Computations and Observed Data

Detailed reservoir response can be calculated using computer codes such as ID, 2D and 3D explicit finite difference codes. These codes are capable of calculating transient response of large volumes of reservoir utilizing hundreds of thousands or millions of computational "zones". These codes will calculate time histories and spatial contour maps and the like for any selected parameter such as, for example, temperature, pressure, density, stress component, energy, velocity, mass flux, phase change and the like.

Typically, such calculations are organized to match known material and boundary conditions such as, for example, locations of and materials comprising geologic layers in the reservoir, known in-situ pressures (before recovery operations begin), known or estimated features such as porosity distribution, permeability distribution, large fractures and the like.

These calculations can be run multiple times with selected parameters varied until a calculation best matches the available observed data which includes analysis of recovered fluids, observation well diagnostics, surface seismic surveys and the like.

It is therefore possible to use the combination of large finite difference calculations and observed data to infer and further confirm the effects of acid or acid precursor treatments on the surface wettability of various portions of the reservoir as hydrocarbon is recovered.

Utilizing By-Products in the Acid Treatment Process

In a thermal bitumen recovery operation, a surface plant is built to house the steam generation as well as the recovery fluid separation and treatment facilities. These plants typically use natural gas to power the various operations. As can be appreciated other fuels such as oil and coal, for example, may be used for power generation. The following two figures illustrate prior art surface plants whose inputs are recovered

water/hydrocarbon mixtures and fuel, and whose outputs are hydrocarbon products, waste water and emissions from burning fuel. In some cases such as described in Figure 4, captured carbon dioxide may also be an output. Of these outputs, the flue gas emissions from burning fuel are typically released to the atmosphere. If carbon dioxide is captured as a by-product, it may be used for

Enhanced Oil Recovery ("EOR"), sold or sequestered.

Figure 3 is a schematic showing the principal elements of a prior art bitumen recovery operation using natural gas for power. As shown in Figure 3, raw bitumen- water feedstock from a well-pad facility 302 is fed into a bitumen- water separation sequence comprising a Free Water Knock-Out ("FWKO") unit 303. Diluent 306 is added to the raw bitumen-water feedstock to form a pumpable mixture prior to entering the FWKO unit 303. The FWKO unit 303 separates most of the diluent-bitumen mixture ("dilbit"). This dilbit mixture is then sent to an oil treatment unit 304 which separates the remaining water from the dilbit. Additional diluent 307 is added to the dilbit product which is then sent to a product storage tank 305, where it remains ready for transport by rail, truck or pipeline 308 to an upgrader.

The water from the oil treatment unit 304 is sent to a de-oiling unit 310 for final cleaning of remaining oil residue. The oil residue from the de-oiling unit 310 is returned to the feedstock of the FWKO unit 303. Make-up water 316 from a water well source is added to the de-oiled water and then fed to a series of water treatment apparatuses which purify the water in preparation for making steam. The water treatment apparatuses are often comprised of water softener units 311, walnut filter unit 314 and an ion exchange unit 315. The treated water is fed to steam generators 321 which are used to produce primarily hot, dry steam which is sent to a high-pressure steam separator unit 322. In this example, natural gas 323 is used to power the steam generators 321. These steam generators may be large single pass boilers or they may be multi-pass drum steam generators. The combustion products of the fuel burned to power the steam generator 321 is typically released into the atmosphere as flue gases 325.

For example, in a 30,000 barrel per day ("bpd") operation, about 2,700 tons per day of C0₂ is released as part of the emissions 325 into the atmosphere by the drum steam generators 321. This is about 0.09 tons C0₂ released per barrel of bitumen processed.

The high pressure steam separator unit 322 compresses the steam from the steam generators 321 and delivers the hot, high-pressure, high-quality steam to the well-pads 302 for injection into the bitumen reservoir 301 where it is used to continue the bitumen mobilization and recovery process. Condensate from the high pressure steam separator unit 322 is handled by a blowdown apparatus 324 and sent to a water disposal well 326. Figure 4 is schematic of a prior art thermal recovery power plant using natural gas for power and for capturing C02. Figure 4 is taken from US Patent Application No.

12/498,895 entitled "Carbon Removal from an Integrated Thermal Recovery Process". Natural gas fuel 421 is brought into the facility and a substantial fraction of the natural gas is diverted by a gas separator and reformed and water-gas shifted in a carbon extraction plant to eliminate carbon in the form of captured carbon dioxide. The carbon extraction plant delivers clean C0₂, molecular hydrogen and electrical power. The molecular hydrogen is then mixed by a gas combiner with portion of natural gas not sent to the carbon extraction plant to form a mixed gas fuel which is then used to power steam generators and other apparatuses in the main plant. In a typical application, about 20% to about 60% of the methane by volume of the natural gas is converted into molecular hydrogen. Relative to conventional processes in which natural gas is combusted, this use of mixed fuel commonly reduces fossil carbon emissions by at least about 20%> and as high as about 60%>.

In the example of Figure 4, 40,000 bpd of bitumen are processed using

approximately 42 million standard cubic feet per day of natural gas as fuel 421. About 2,880 tons per day of C0₂ is released into the atmosphere by the drum steam generators 412 which is about 0.072 tons C0₂ released per barrel of bitumen processed. The bitumen product is a 19° to 20° API dilbit which is the same as that of the prior art plant described in Figure 3.

The raw bitumen- water feedstock from well pads 401 is fed into a bitumen-water separation sequence comprising a Free Water Knock-Out ("FWKO") unit 403. Diluent

402 is added to the raw bitumen-water feedstock to form a pumpable mixture prior to entering the FWKO unit 403. The de-oiled bitumen-diluent mixture from the FWKO unit

403 is fed to an oil treating unit 404 where at least most of the residual water is removed and added to the input of the water de-oiling unit 408. The treated hydrocarbon mixture, typically, dilbit is sent to a product storage tank 405. Additional diluent 406 is added to the dilbit product so that it can be transported by rail, truck or pipeline 407 to an upgrader.

The FWKO unit 403 separates most of the water which is then sent to a de -oiling unit 408 for final cleaning of remaining oil residue. The oil residue from the de -oiling unit 408 is returned to the feedstock of the FWKO unit 403. Make-up water from a water well source 409, for example, is added to the de-oiled water and then fed to a tube evaporator 410 which distills the water in preparation for making steam. Some water is condensed in the tube evaporator 410 and is processed by a blowdown treatment apparatus 415 and then returned to the ground via a water disposal well 416. It is understood that reference to a tube evaporator may mean a rising tube evaporator or a falling tube evaporator since both accomplish the same function in process illustrated.

The distilled water from the tube evaporator 410 is fed to the steam drum generators 412 which are used to produce primarily hot dry steam which is sent to a high pressure steam separator unit 413. A mixture of molecular hydrogen and methane (called a mixed gas) are used to power the steam drum generators 412. The primary function of the steam drum generators 412 is to produce high quality steam which is transferred to a high pressure steam separator unit 424.

The high pressure steam separator unit 413 compresses the steam from the steam drum generators 412 and delivers the hot, high-pressure, high-quality steam to the underground facility 400 for subsequent use in maintaining temperature and pressure conditions in steam chamber. Water condensate from the high pressure steam separator unit 413 is returned to the tube evaporator 410.

The steam is added to the high pressure steam separator 413; the 24 MW of power is used to operate the various units in the carbon extraction plant 414 and the main plant; the C0₂ 423 is sold, used for EOR or sequestered; and the recovered hydrogen 426 is mixed with the 26 million standard cubic feet per day of natural gas 421 to produce a high energy gas mix that is used in the burners of the steam drum generators 412. Thus, the carbon extraction plant 414 removes a substantial portion of fossil carbon while using slightly less energy to process a barrel of bitumen and produce steam than the prior art plant of Figure 3.

Figure 5 is schematic of a bitumen recovery surface plant wherein flue gases and C02 (when produced as a by-product) are available for compression and injection into the reservoir. Bitumen- water feedstock is recovered from hydrocarbon reservoir 501 at well- pads 502. Diluent is added to the bitumen- water and sent to free water knockout apparatus 503 where the bitumen and diluent are separated from the water.

The bitumen and diluent are sent to a treatment apparatus 504 and then the final plant product is stored in facility 505. From storage the treated bitumen and diluent are shipped out as product 592.

The water from free water knockout apparatus 503 is treated in water treatment apparatus 511 before being sent to steam generation facility 525. The output of the steam generation facility 525 is high quality steam which is sent via path 551 and compressed to injection pressure in compressor 541 before being sent to well-pads 502 for injection into reservoir 501.

Fuel, such as natural gas, for example, is input 591 where it is used to power C0₂ capture plant 53 land steam generator facility 525. The flue gas emissions from burning fuel are output from C0₂ capture plant 53 land combined with the flue gas emissions from burning fuel in steam generation facility 525. These flue gas emissions are then sent via path 552 and compressed to injection pressure in compressor 542 before being sent to well pads 502 for injection into reservoir 501. As can be appreciated these flue gases can be vented from time to time to the atmosphere or stored for later compression and injection into the reservoir.

Carbon dioxide captured in C0₂ capture plant 531 is also compressed to injection pressure in compressor 543 before being sent via path 553 to well-pads 502 for injection into reservoir 501. As can be appreciated this C0₂ can be vented from time to time to the atmosphere before compression or stored for injection into the reservoir or stored for sale as a product for other hydrocarbon recovery operations.

It is also possible to acquire other acid-producing gases such as C0₂, S0₂, NOxs and the like, store them in tanks 581 and, when needed, compress them by compressor 582 before being sent to well pads 502 for injection into reservoir 501.

As can be appreciated, the flue gases, C0₂ from the carbon capture plant and/or the acquired acid-producing gases can be injected separately with the steam or steam/solvent mix on a schedule and in an amount as determined by the acid treatment process requirements.

As described previously, the recovered water can be analyzed after the free water knockout process and compared to the water used to make steam in order to determine if the recovered water is consistent with acid-producing gas interaction with the reservoir surfaces. As also described previously, this information and any information obtained from the observation wells can be used to modify the acid-producing gas injection schedule and amounts.

Figure 6 is an example of a time-line for a cyclical steaming process wherein an acid or acid precursor is injected from time to time during one or more injection intervals. In a CSS, SAGD or steam flooding process, there is typically an operational cycle comprising an injection interval 601, a changeover interval 604, a soak interval 602, another changeover interval, a hydrocarbon recovery interval 603 and a final changeover interval. The changeover interval is typically short lasting from several hours to about a day or two. During this changeover interval, the operation changes from an injection mode to a soak mode or a hydrocarbon recovery mode, or the operation changes from a hydrocarbon recovery mode to an injection mode. As can be appreciated, each well-pair cycles can be operated separately from other well-pairs or in synchronicity with other well-pairs.

Figure 6 is an example of a number of hydrocarbon process cycles that illustrate a short start-up phase, a CSS phase, a SAGD phase and a blow-down phase. Overlaid on these phases is a schedule of acid or acid-precursor injections for the purpose of altering the reservoir surface wettability from oil- wet towards water- wet. As can be appreciated, an injection of steam can be an injection of steam and solvent.

Cycles 1 and 2 represent start-up cycles wherein steam is injected to the reservoir in order to establish fluid communication between an upper injection well and a lower recovery well. The start-up phase typically comprises a number of relatively short injection, soak and recovery intervals. Cycles 3, 4 and 5 represent post start-up cycles wherein some acid or acid-precursors 610 are injected along with the steam in a series of CSS cycles. Cycles 6 through 10 represent a series of SAGD cycles wherein varying amounts of acid or acid-precursors 610 are injected along with the steam. Typically, the pressures associated with SAGD cycles are lower than the pressures associated with CSS cycles. Cycles 11 through 14 represent the blow-down phase wherein the steam chamber is fully developed and is characterized by a series of high acid or acid-precursor content. The objective of the blow-down phase is to recover as much residual bitumen and as much remaining solvent as possible.

As can be appreciated, the number of cycles, the duration of the cycle components (injection, soak, recovery, acid or acid-precursor addition) can be varied as well as the pressure levels associated with each cycle and the relative amounts of steam, solvent, acid or acid-precursors in the injection part of the cycle.

All the variables discussed above are subject to feedback from observations of recovered fluids, observation well data and, if used, numerical simulations that attempt to match as closely as possible the observed results.

Control of the Acid treatment 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 an acid treatment to a hydrocarbon reservoir. This figure illustrates the important functional units of a thermal recovery plant wherein an acid or acid precursor 705 is injected along with steam from a steam generator 704 to a hydrocarbon reservoir 701. The steam is compressed 706 and sent to reservoir 701 via well-pads 702. The acid or acid precursor is also compressed 707 and sent to reservoir 701 via well-pads 702. The steam and acid or acid precursor are injected at the same or different times and may be combined before injection of injected separately. The flow of material to and from the hydrocarbon reservoir 701 is indicated by solid lines. Recovered fluids are shown flowing from reservoir 701 to treatment facility 703 where the fluids are substantially separated as described in Figures 3, 4 and 5. Figure 7 also shows reservoir diagnostics 712 which include cased-hole diagnostics and the like. Fluid recovery information 711 is typically obtained in treatment facility 703. Reservoir diagnostics 712 and fluid recovery information 711 is communicated to a computer 721 as shown by diagnostic paths 751 and 752. 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 is comprised of a memory module 722, a processor module 723 and a controller 724. The computer 721 controls the steam generation and steam injection processes via control path 762. The computer 721 also controls the acid or acid precursor injection processes via control path 761. The control paths are indicated by densely spaced dashed lines.

The controller 724 contains control logic electronics used, among other things, to process sensor data collected from the aforementioned sensors and to provide control inputs for the elements described such as the input streams. 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 performance, 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:

contacting at least one of an acid and acid precursor with a mobilizing agent in a hydrocarbon deposit, whereby a surface wettability of the hydrocarbon deposit before said contacting is altered towards water-wet after said contacting.

2. The method of Claim 1 wherein the hydrocarbon deposit is comprised of a carbonate reservoir matrix.

3. The method of Claim 1 wherein the at least one of an acid and acid precursor is injected in a hydrocarbon deposit as a gas mixed with a mobilizing agent .

4. The method of Claim 1 wherein the at least one of an acid and acid precursor is injected in a hydrocarbon deposit in a selected amount and at a selected time.

5. The method of Claim 4 wherein the selected amount and the selected time are based on the data obtained from at least one of analyzing one or more fluids recovered from the hydrocarbon reservoir and observing geological properties of the reservoir from an observation well.

6. The method of Claim 1 wherein the at least one of an acid and acid precursor is at least one of a flue gas recovered from the means of generating steam and carbon dioxide recovered from a carbon dioxide capture apparatus.

7. The method of Claim 1 wherein the injection of the mobilizing agent is part of at least one of a Cyclical Steam Stimulation, a Steam Assisted Gravity Drainaige or a steam flooding process.

8. A method to alter surface wettability of a hydrocarbon deposit towards water- wet, comprising:

(a) providing a first stream comprising a mobilizing agent to mobilize hydrocarbons in a hydrocarbon deposit;

(b) providing a second stream comprising an acid and acid precursor;

(c) injecting the first and second streams into the hydrocarbon deposit at a respective first rate and a second rate; and

(d) sensing at least one of fluids recovered from the hydrocarbon deposit and geological properties of the hydrocarbon deposit, to adjust or maintain the first and second rates;

wherein the surface wettability of the hydrocarbon deposit is altered towards water- wet.

9. The method of claim 8 wherein the mobilizing agent is at least one of steam, steam/solvent and solvent.

10. The method of claim 8 wherein the first and second streams are combined into a common stream prior to injection into the hydrocarbon deposit.

11. The method of claim 8 further comprising a controller to adjust or maintain the first and second rates.

12. The method of claim 11 wherein the controller is an automatic controller configured to adjust and maintain the first and second rates in at one of duration, frequency, amplitude and injection profile.

13. The method of claim 8 wherein the hydrocarbon deposit comprises a carbonate reservoir matrix.

14. The method of claim 8 wherein the second stream is injected into the hydrocarbon deposit for at least one of a selectable amplitude, composition, duration and time.

15. The method of claim 8 wherein the first and second streams are separate streams when injected into the hydrocarbon deposit.

16. The method of claim 8 wherein the injection is part of at least one of a Cyclical Steam Stimulation, a Steam Assisted Gravity Drainaige, combined steam/solvent process or a steam flooding process.

17. A system to alter surface wettability of a hydrocarbon deposit towards water- wet, comprising:

(a) a first input to receive a first stream comprising a mobilizing agent to mobilize hydrocarbons in a hydrocarbon deposit;

(b) a second input to receive a second stream comprising an acid and acid precursor;

(c) an injector to inject the first and second streams into the hydrocarbon deposit at a respective first rate and a second rate; and

(d) at least one sensor to sense at least one of fluids recovered from the hydrocarbon deposit and geological properties of the hydrocarbon deposit to adjust or maintain the first and second rates;

wherein the surface wettability of the hydrocarbon deposit is altered towards water- wet.

18. The system of claim 17, wherein the mobilizing agent is at least one of steam, steam/solvent and solvent, further comprising an automatic controller to adjust and maintain the first and second rates, the automatic controller configured to adjust the first and second rates in at one of duration, frequency and injection profile.

19. 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 altering surface wettability of a hydrocarbon deposit towards water- wet, comprising:

instructions to provide a first stream comprising a mobilizing agent to mobilize hydrocarbons in a hydrocarbon deposit;

instructions to provide a second stream comprising an acid and acid precursor;

instructions to inject the first and second streams into the hydrocarbon deposit at a respective first rate and a second rate; and

instructions to sense at least one of fluids recovered from the hydrocarbon deposit and geological properties of the hydrocarbon deposit to adjust or maintain the first and second rates; wherein the surface wettability of the hydrocarbon deposit is altered towards water- wet.