CA3063448C - Method of inhibiting deposition of silicon-based inorganic deposits during in-situ hydrocarbon production - Google Patents
Method of inhibiting deposition of silicon-based inorganic deposits during in-situ hydrocarbon production Download PDFInfo
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Abstract
The present disclosure provides methods of inhibiting deposition of a silicon- based inorganic deposit within a production well that is in fluid communication with a subterranean reservoir. The method comprises providing a deposition inhibitor into an internal volume defined by an intermediate casing of the production well. The deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing. The deposition inhibitor is provided into the internal volume of the intermediate casing before, during, and/or after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 °C and about 285 °C, and a pressure of between about 800 kPag and about 7,000 kPag. Methods for producing hydrocarbons under such conditions are also provided.
Description
METHOD OF INHIBITING DEPOSITION OF SILICON-BASED INORGANIC DEPOSITS
DURING IN-SITU HYDROCARBON PRODUCTION
TECHNICAL FIELD
[0001] The present disclosure generally relates to inhibiting deposition of inorganic deposits during in-situ petroleum production. In particular, the present disclosure relates to inhibiting deposition of silicon-based inorganic deposits on surfaces within the intermediate casing of a production well under high-pressure and/or high-temperature conditions.
BACKGROUND
100021 Thermal recovery processes use heat to mobilize viscous hydrocarbons so that they can be recovered from a subterranean reservoir. Such processes typically rely on steam injection to reduce hydrocarbon viscosity in situ. Steam is a useful means for introducing heat energy into a subterranean reservoir, because steam has a high specific heat capacity. Steam assisted gravity drainage (SAGD) is one example of a thermal in-situ hydrocarbon recovery process that uses steam as the primary means for transferring heat energy to the reservoir. In a typical SAGD well configuration, a hydrocarbon-containing reservoir is penetrated by an injection well and a production well. The production well is horizontally aligned with, and vertically displaced from, the injection well.
In a typical SAGD process, steam is injected into the hydrocarbon-containing reservoir where the steam condenses and transfers latent heat energy to the reservoir. The heat transfer mobilizes hydrocarbons within the reservoir by reducing their viscosity. Over time, condensed steam and mobilized hydrocarbons drain to the production well through which they are produced to the surface.
[0003] A typical production well for a SAGD process comprises a liner, an intermediate casing, an electric submersible pump (ESP), and production tubing. The liner is configured to allow passage of production fluids (i.e. condensed steam, mobilized hydrocarbons, and/or other fluids derived from the reservoir) into the production well.
The intermediate casing engages with the liner and runs to the surface. The intermediate casing is configured to provide structural support to the production well and to house the ESP, the production tubing, and other primary completion components. The ESP is configured to pump production fluids from the area proximate to the liner to the surface via the production tubing. Because production fluids are free to flow within the liner and the intermediate casing, fluid levels in the intermediate casing rise and fall as operational protocols and reservoir behavior vary. As a result, surfaces and fluids within the intermediate casing are subjected to a wide range of temperature/pressure conditions which may promote the deposition of problematic inorganic materials during production.
[0004] Scale is a mineral salt deposit that occurs on well completion components, and it causes a variety of problems during hydrocarbon recovery processes. A
range of chemical treatment options have been proposed for scale removal/inhibition.
With respect to scale removal, chemical treatment protocols are generally selected based on the composition of the scale. For example, carbonate scales (such as calcium carbonate) are typically treated with aqueous hydrochloric acid, and sulfate scales (such as calcium sulfate) are typically treated with chelating agents such as ethylenediamine teraacetic acid (EDTA). With respect to scale inhibition, chemical treatments typically involve "squeezing" a chemical inhibitor, such as a chelating agent or a polymer, into the reservoir for subsequent commingling with produced fluids in an attempt to mitigate against further scale precipitation.
[0005] Unlike common scales which comprise primarily mono-valent alkali metals (e.g. Na, Li, K+) and/or di-valent alkaline earth metals (e.g. Ca2+, Sr2+, Ba2+), deposits formed during SAGD processes tend to be primarily comprised of silicon.
Silicon is a metalloid element, and it tends to form stable compounds/complexes in a tetra-valent state. Silicon-based inorganic deposits typically comprise silica (i.e.
silicon dioxide) and/or silicates (i.e. salts derived from silica or silicic acids), and they tend not dissolve in hydrochloric acid or form stable chelate complexes. Accordingly, typical scale-treatment protocols are of limited use for thermal recovery processes like SAGD. The impact of the limited utility of typical treatment protocols and the recalcitrant nature of silicon-based inorganic deposits is amplified by the dynamic high-temperature and high-pressure conditions associated with SAGD. Because, operating conditions and reservoir character
DURING IN-SITU HYDROCARBON PRODUCTION
TECHNICAL FIELD
[0001] The present disclosure generally relates to inhibiting deposition of inorganic deposits during in-situ petroleum production. In particular, the present disclosure relates to inhibiting deposition of silicon-based inorganic deposits on surfaces within the intermediate casing of a production well under high-pressure and/or high-temperature conditions.
BACKGROUND
100021 Thermal recovery processes use heat to mobilize viscous hydrocarbons so that they can be recovered from a subterranean reservoir. Such processes typically rely on steam injection to reduce hydrocarbon viscosity in situ. Steam is a useful means for introducing heat energy into a subterranean reservoir, because steam has a high specific heat capacity. Steam assisted gravity drainage (SAGD) is one example of a thermal in-situ hydrocarbon recovery process that uses steam as the primary means for transferring heat energy to the reservoir. In a typical SAGD well configuration, a hydrocarbon-containing reservoir is penetrated by an injection well and a production well. The production well is horizontally aligned with, and vertically displaced from, the injection well.
In a typical SAGD process, steam is injected into the hydrocarbon-containing reservoir where the steam condenses and transfers latent heat energy to the reservoir. The heat transfer mobilizes hydrocarbons within the reservoir by reducing their viscosity. Over time, condensed steam and mobilized hydrocarbons drain to the production well through which they are produced to the surface.
[0003] A typical production well for a SAGD process comprises a liner, an intermediate casing, an electric submersible pump (ESP), and production tubing. The liner is configured to allow passage of production fluids (i.e. condensed steam, mobilized hydrocarbons, and/or other fluids derived from the reservoir) into the production well.
The intermediate casing engages with the liner and runs to the surface. The intermediate casing is configured to provide structural support to the production well and to house the ESP, the production tubing, and other primary completion components. The ESP is configured to pump production fluids from the area proximate to the liner to the surface via the production tubing. Because production fluids are free to flow within the liner and the intermediate casing, fluid levels in the intermediate casing rise and fall as operational protocols and reservoir behavior vary. As a result, surfaces and fluids within the intermediate casing are subjected to a wide range of temperature/pressure conditions which may promote the deposition of problematic inorganic materials during production.
[0004] Scale is a mineral salt deposit that occurs on well completion components, and it causes a variety of problems during hydrocarbon recovery processes. A
range of chemical treatment options have been proposed for scale removal/inhibition.
With respect to scale removal, chemical treatment protocols are generally selected based on the composition of the scale. For example, carbonate scales (such as calcium carbonate) are typically treated with aqueous hydrochloric acid, and sulfate scales (such as calcium sulfate) are typically treated with chelating agents such as ethylenediamine teraacetic acid (EDTA). With respect to scale inhibition, chemical treatments typically involve "squeezing" a chemical inhibitor, such as a chelating agent or a polymer, into the reservoir for subsequent commingling with produced fluids in an attempt to mitigate against further scale precipitation.
[0005] Unlike common scales which comprise primarily mono-valent alkali metals (e.g. Na, Li, K+) and/or di-valent alkaline earth metals (e.g. Ca2+, Sr2+, Ba2+), deposits formed during SAGD processes tend to be primarily comprised of silicon.
Silicon is a metalloid element, and it tends to form stable compounds/complexes in a tetra-valent state. Silicon-based inorganic deposits typically comprise silica (i.e.
silicon dioxide) and/or silicates (i.e. salts derived from silica or silicic acids), and they tend not dissolve in hydrochloric acid or form stable chelate complexes. Accordingly, typical scale-treatment protocols are of limited use for thermal recovery processes like SAGD. The impact of the limited utility of typical treatment protocols and the recalcitrant nature of silicon-based inorganic deposits is amplified by the dynamic high-temperature and high-pressure conditions associated with SAGD. Because, operating conditions and reservoir character
2 vary widely during recovery, SAGD production wells are routinely exposed to wide temperature/pressure swings and varying compositions and quantities of production fluids. Temperature and pressure variations can shift solubility equilibria towards precipitation, increase flocculation rates, and reduce emulsion stability, all of which may contribute to accelerated deposition of silicon-based inorganic deposits.
Deposition of silicon-based inorganic deposits on surfaces within the intermediate casing is undesirable, because it can lead to sub-optimal production efficiency, increased maintenance requirements, and/or premature failure for casing and primary completion components. Accordingly, there is a need for methods of inhibiting deposition of silicon-based inorganic deposits on surfaces within the intermediate casing of SAGD
production wells.
SUMMARY
[0006] In the context of the present disclosure, it has been determined that deposition of silicon-based inorganic deposits on surfaces within the intermediate casing can be inhibited by providing a deposition inhibitor to the interior volume of the intermediate casing by way of a capillary tube. In the context of the present disclosure, a capillary tube is a conduit that has a first opening at the surface and a second opening in fluid communication with the interior volume of the intermediate casing. In SAGD
production operations, capillary tubes are typically used to evaluate in-situ pressure conditions at the heel of the production tube by counter-pressurizing the capillary tube from the surface. In the context of the present disclosure, the deposition inhibitor is pushed (under pressure from the surface) through the capillary tube into the interior volume of the intermediate casing, such that the deposition inhibitor is introduced in proximity to the surfaces that may be at risk of being compromised by silicon-based inorganic deposits. Specific parameters with respect to the composition, density, pressure, timing, and concentration of the injection of the deposition inhibitor into the interior volume of the intermediate casing are provided in the present disclosure.
Protocols for monitoring the impact of the presence of the deposition inhibitor within the interior volume of the intermediate casing are provided in the present disclosure (e.g.
flow-back testing) as are strategies for modifying related methods based on the results
Deposition of silicon-based inorganic deposits on surfaces within the intermediate casing is undesirable, because it can lead to sub-optimal production efficiency, increased maintenance requirements, and/or premature failure for casing and primary completion components. Accordingly, there is a need for methods of inhibiting deposition of silicon-based inorganic deposits on surfaces within the intermediate casing of SAGD
production wells.
SUMMARY
[0006] In the context of the present disclosure, it has been determined that deposition of silicon-based inorganic deposits on surfaces within the intermediate casing can be inhibited by providing a deposition inhibitor to the interior volume of the intermediate casing by way of a capillary tube. In the context of the present disclosure, a capillary tube is a conduit that has a first opening at the surface and a second opening in fluid communication with the interior volume of the intermediate casing. In SAGD
production operations, capillary tubes are typically used to evaluate in-situ pressure conditions at the heel of the production tube by counter-pressurizing the capillary tube from the surface. In the context of the present disclosure, the deposition inhibitor is pushed (under pressure from the surface) through the capillary tube into the interior volume of the intermediate casing, such that the deposition inhibitor is introduced in proximity to the surfaces that may be at risk of being compromised by silicon-based inorganic deposits. Specific parameters with respect to the composition, density, pressure, timing, and concentration of the injection of the deposition inhibitor into the interior volume of the intermediate casing are provided in the present disclosure.
Protocols for monitoring the impact of the presence of the deposition inhibitor within the interior volume of the intermediate casing are provided in the present disclosure (e.g.
flow-back testing) as are strategies for modifying related methods based on the results
3 obtained from such monitoring. The monitoring methods involve analyzing produced fluids for quantities of silicon-based inorganic compounds and/or quantities of the deposition inhibitor (each in various forms). The monitoring methods allow for feedback-based updating of the protocol for providing the deposition inhibitor to the interior volume of the intermediate casing. Methods for producing hydrocarbons while inhibiting deposition of silicon-based inorganic deposits on surfaces within the interior volume of the intermediate casing are also provided.
100071 In select embodiments, the present disclosure relates to a method of inhibiting deposition of a silicon-based inorganic deposit within a production well that is in fluid communication with a subterranean reservoir. The method comprises providing a deposition inhibitor into an internal volume defined by an intermediate casing of the production well. The deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing. The deposition inhibitor is provided into the internal volume of the intermediate casing before, during, and/or after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 C and about 285 C, and a pressure of between about 800 kPag and about 7,000 kPag.
100081 In select embodiments, the present disclosure relates to a method of producing hydrocarbons from a subterranean reservoir that is in fluid communication with an injection well and a production well. The method comprises injecting steam, solvent, or a combination thereof into the subterranean reservoir by way of the injection well. The method further comprises providing a deposition inhibitor to an internal volume of an intermediate casing within the production well. The deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing. The providing of the deposition inhibitor to the internal volume of the intermediate casing occurs before, during, and/or after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 C
and about 285 C, and a pressure of between about 800 kPag and about 7,000 kPag. The
100071 In select embodiments, the present disclosure relates to a method of inhibiting deposition of a silicon-based inorganic deposit within a production well that is in fluid communication with a subterranean reservoir. The method comprises providing a deposition inhibitor into an internal volume defined by an intermediate casing of the production well. The deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing. The deposition inhibitor is provided into the internal volume of the intermediate casing before, during, and/or after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 C and about 285 C, and a pressure of between about 800 kPag and about 7,000 kPag.
100081 In select embodiments, the present disclosure relates to a method of producing hydrocarbons from a subterranean reservoir that is in fluid communication with an injection well and a production well. The method comprises injecting steam, solvent, or a combination thereof into the subterranean reservoir by way of the injection well. The method further comprises providing a deposition inhibitor to an internal volume of an intermediate casing within the production well. The deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing. The providing of the deposition inhibitor to the internal volume of the intermediate casing occurs before, during, and/or after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 C
and about 285 C, and a pressure of between about 800 kPag and about 7,000 kPag. The
4 method further comprises producing at least a portion of the fluid by way of the production well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] These and other features of the present disclosure will become more apparent in the following detailed description in which reference is made to the appended drawings. The appended drawings illustrate one or more embodiments of the present disclosure by way of example only and are not to be construed as limiting the scope of the present disclosure.
[0010] FIG. 1 provides a schematic illustration of a SAGD
production well that is configured for use in accordance with one or more methods of the present disclosure.
[0011] FIG. 2 provides a plot of the saturation concentration of silica in an aqueous steam condensate fluid as a function of temperature.
[0012] FIG. 3 provides a plot of the saturation concentration of silica in an aqueous steam condensate fluid as a function of pH.
[0013] FIG. 4 provides a plot of pH as a function of time for a produced fluid from a SAGD facility located in Foster Creek, Alberta.
[0014] FIG. S provides IR spectra of a deposition inhibitor taken before (A) and after (B) the deposition inhibitor was heated to a temperature of 235 C for 22 hours.
[0015] FIG. 6 provides results from a differential scanning calorimetry experiment. The results were used to determine the decomposition temperature of a deposition inhibitor.
[0016] FIG. 7A provides a photograph of a silicon-based deposit obtained from within the interior volume of the intermediate casing, and FIG. 7B provides a high-resolution microscopic image of the same.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] These and other features of the present disclosure will become more apparent in the following detailed description in which reference is made to the appended drawings. The appended drawings illustrate one or more embodiments of the present disclosure by way of example only and are not to be construed as limiting the scope of the present disclosure.
[0010] FIG. 1 provides a schematic illustration of a SAGD
production well that is configured for use in accordance with one or more methods of the present disclosure.
[0011] FIG. 2 provides a plot of the saturation concentration of silica in an aqueous steam condensate fluid as a function of temperature.
[0012] FIG. 3 provides a plot of the saturation concentration of silica in an aqueous steam condensate fluid as a function of pH.
[0013] FIG. 4 provides a plot of pH as a function of time for a produced fluid from a SAGD facility located in Foster Creek, Alberta.
[0014] FIG. S provides IR spectra of a deposition inhibitor taken before (A) and after (B) the deposition inhibitor was heated to a temperature of 235 C for 22 hours.
[0015] FIG. 6 provides results from a differential scanning calorimetry experiment. The results were used to determine the decomposition temperature of a deposition inhibitor.
[0016] FIG. 7A provides a photograph of a silicon-based deposit obtained from within the interior volume of the intermediate casing, and FIG. 7B provides a high-resolution microscopic image of the same.
5 [0017] FIG. 8 provides forecasted results for emulsion rates (A and B) and concentration of a deposition inhibitor (C) as a function of time for a well-pad wide experiment relating to methods that are in accordance with the present disclosure.
DETAILED DESCRIPTION
[0018] Embodiments of the present disclosure will now be described with reference to FIG. 1 to FIG. 8.
[0019] The present disclosure sets out an important finding regarding the chemical composition of silicon-based inorganic deposits within the interior volume of the intermediate casing of a SAGD production well. Briefly stated, experimental evidence suggests that under at least some SAGD recovery conditions a large portion (e.g. greater than about 85 %) of surface deposits may be crystalline in form and comprised of silicon-containing compounds. Without being bound to any particular theory, the present disclosure asserts that because: (i) the solubility (and by proxy the deposition characteristics) of crystalline and amorphous forms of silicon-containing compounds are often substantially different, and (ii) the majority of the silicon-based inorganic deposits formed under SAGD recovery conditions are crystalline in form, methods for inhibiting deposition of silicon-containing deposits under SAGD recovery conditions are best targeted towards crystalline forms of silicon-containing compounds. Again without being bound to any particular theory, the present disclosure asserts that crystalline forms of silicon-containing compounds may be inhibited from depositing by reducing the extent crystal nucleation and/or crystal growth in situ such that silicon-containing precipitates stay suspended and/or dispersed so as to be produced to the surface instead of deposited within the interior volume of the intermediate casing. To this end, the methods of the present disclosure utilize a deposition inhibitor that is provided to the interior volume of the intermediate casing by way of a capillary tube. The deposition inhibitor is selected based on its capacity to supress deposition of silica-based inorganic deposits and based on its ability to resist degradation under the temperature, pressure, and/or pH conditions associated with SAGD production. The capillary tube provides a means to introduce the deposition inhibitor in proximity to the surfaces that are most at risk receiving silicon-
DETAILED DESCRIPTION
[0018] Embodiments of the present disclosure will now be described with reference to FIG. 1 to FIG. 8.
[0019] The present disclosure sets out an important finding regarding the chemical composition of silicon-based inorganic deposits within the interior volume of the intermediate casing of a SAGD production well. Briefly stated, experimental evidence suggests that under at least some SAGD recovery conditions a large portion (e.g. greater than about 85 %) of surface deposits may be crystalline in form and comprised of silicon-containing compounds. Without being bound to any particular theory, the present disclosure asserts that because: (i) the solubility (and by proxy the deposition characteristics) of crystalline and amorphous forms of silicon-containing compounds are often substantially different, and (ii) the majority of the silicon-based inorganic deposits formed under SAGD recovery conditions are crystalline in form, methods for inhibiting deposition of silicon-containing deposits under SAGD recovery conditions are best targeted towards crystalline forms of silicon-containing compounds. Again without being bound to any particular theory, the present disclosure asserts that crystalline forms of silicon-containing compounds may be inhibited from depositing by reducing the extent crystal nucleation and/or crystal growth in situ such that silicon-containing precipitates stay suspended and/or dispersed so as to be produced to the surface instead of deposited within the interior volume of the intermediate casing. To this end, the methods of the present disclosure utilize a deposition inhibitor that is provided to the interior volume of the intermediate casing by way of a capillary tube. The deposition inhibitor is selected based on its capacity to supress deposition of silica-based inorganic deposits and based on its ability to resist degradation under the temperature, pressure, and/or pH conditions associated with SAGD production. The capillary tube provides a means to introduce the deposition inhibitor in proximity to the surfaces that are most at risk receiving silicon-
6 based inorganic deposits. Moreover, the capillary tube provides a means to provide the deposition inhibitor under targeted, time, concentration, density, rate, and/or pressure protocols. Taken together, the desirable attributes of targeted capillary tube injection protocols and condition specific deposition inhibitors provide for the inhibition of deposition of silicon-containing deposits during thermal recovery of in situ hydrocarbons.
100201 In the context of the present disclosure, various terms are used in accordance with what is understood to be the ordinary meaning of those terms.
For example, "petroleum" is a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid, or solid phase. In the context of the present disclosure, the words "petroleum" and "hydrocarbon(s)" are used to refer to mixtures of widely varying composition. The production of petroleum from a reservoir necessarily involves the production of hydrocarbons, but is not limited to hydrocarbon production and may include, for example, trace quantities of metals (e.g. Fe, Ni, Cu, V).
Similarly, processes that produce hydrocarbons from a well will generally also produce petroleum fluids that are not hydrocarbons. In accordance with this usage, a process for producing petroleum or hydrocarbons is not necessarily a process that produces exclusively petroleum or hydrocarbons, respectively. "Fluids", such as petroleum fluids, include both liquids and gases.
100211 It is common practice to categorize petroleum substances of high viscosity and density into two categories, "heavy oil" and "bitumen". For example, some sources define "heavy oil" as a petroleum that has a mass density of greater than about 900 kg/m3. Bitumen is sometimes described as that portion of petroleum that exists in the semi-solid or solid phase in natural deposits, with a mass density greater than about 1,000 kg/m3 and a viscosity greater than 10,000 centipoise (cP; or 10 Pa.$) measured at original temperature in the deposit and atmospheric pressure, on a gas-free basis.
Although these terms are in common use, references to heavy oil and bitumen represent categories of convenience, and there is a continuum of properties between heavy oil and bitumen. Accordingly, references to heavy oil and/or bitumen herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the two substances. In particular, the term
100201 In the context of the present disclosure, various terms are used in accordance with what is understood to be the ordinary meaning of those terms.
For example, "petroleum" is a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid, or solid phase. In the context of the present disclosure, the words "petroleum" and "hydrocarbon(s)" are used to refer to mixtures of widely varying composition. The production of petroleum from a reservoir necessarily involves the production of hydrocarbons, but is not limited to hydrocarbon production and may include, for example, trace quantities of metals (e.g. Fe, Ni, Cu, V).
Similarly, processes that produce hydrocarbons from a well will generally also produce petroleum fluids that are not hydrocarbons. In accordance with this usage, a process for producing petroleum or hydrocarbons is not necessarily a process that produces exclusively petroleum or hydrocarbons, respectively. "Fluids", such as petroleum fluids, include both liquids and gases.
100211 It is common practice to categorize petroleum substances of high viscosity and density into two categories, "heavy oil" and "bitumen". For example, some sources define "heavy oil" as a petroleum that has a mass density of greater than about 900 kg/m3. Bitumen is sometimes described as that portion of petroleum that exists in the semi-solid or solid phase in natural deposits, with a mass density greater than about 1,000 kg/m3 and a viscosity greater than 10,000 centipoise (cP; or 10 Pa.$) measured at original temperature in the deposit and atmospheric pressure, on a gas-free basis.
Although these terms are in common use, references to heavy oil and bitumen represent categories of convenience, and there is a continuum of properties between heavy oil and bitumen. Accordingly, references to heavy oil and/or bitumen herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the two substances. In particular, the term
7 "heavy oil" includes within its scope all "bitumen" including hydrocarbons that are present in semi-solid or solid form.
[0022] In the context of the present disclosure, a "reservoir" is a subsurface formation containing one or more natural accumulations of moveable petroleum, which are generally confined by relatively impermeable rock. An "oil sand" or "oil sands"
reservoir is generally comprised of strata of sand or sandstone containing petroleum.
"Thermal recovery" or "thermal stimulation" refers to enhanced oil recovery techniques that involve delivering thermal energy to a petroleum resource, for example to a heavy oil reservoir. There are a significant number of thermal recovery techniques other than SAGD, such as cyclic steam stimulation (CSS), in-situ combustion, hot water flooding, steam flooding, and electrical heating. In general, thermal energy is provided to reduce the viscosity of the petroleum to facilitate production. This thermal energy may be provided by a "thermal recovery fluid", which is a fluid that carries thermal energy, for example in the form of steam, solvents, or mixtures thereof (with or without additives such as surfactants).
[0023] Select embodiments of the present disclosure relate to methods of inhibiting deposition of a silicon-based inorganic deposit within a production well that is in fluid communication with a subterranean reservoir. The method comprises providing a deposition inhibitor into an internal volume defined by an intermediate casing of the production well. The deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing. The deposition inhibitor is provided into the internal volume of the intermediate casing before, during, and/or after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 C and about 285 C and .a pressure of between about 800 kPag and about 7,000 kPag.
[0024] In select embodiments, the present disclosure relates to a method of producing hydrocarbons from a subterranean reservoir that is in fluid communication with an injection well and a production well. The method comprises injecting steam,
[0022] In the context of the present disclosure, a "reservoir" is a subsurface formation containing one or more natural accumulations of moveable petroleum, which are generally confined by relatively impermeable rock. An "oil sand" or "oil sands"
reservoir is generally comprised of strata of sand or sandstone containing petroleum.
"Thermal recovery" or "thermal stimulation" refers to enhanced oil recovery techniques that involve delivering thermal energy to a petroleum resource, for example to a heavy oil reservoir. There are a significant number of thermal recovery techniques other than SAGD, such as cyclic steam stimulation (CSS), in-situ combustion, hot water flooding, steam flooding, and electrical heating. In general, thermal energy is provided to reduce the viscosity of the petroleum to facilitate production. This thermal energy may be provided by a "thermal recovery fluid", which is a fluid that carries thermal energy, for example in the form of steam, solvents, or mixtures thereof (with or without additives such as surfactants).
[0023] Select embodiments of the present disclosure relate to methods of inhibiting deposition of a silicon-based inorganic deposit within a production well that is in fluid communication with a subterranean reservoir. The method comprises providing a deposition inhibitor into an internal volume defined by an intermediate casing of the production well. The deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing. The deposition inhibitor is provided into the internal volume of the intermediate casing before, during, and/or after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 C and about 285 C and .a pressure of between about 800 kPag and about 7,000 kPag.
[0024] In select embodiments, the present disclosure relates to a method of producing hydrocarbons from a subterranean reservoir that is in fluid communication with an injection well and a production well. The method comprises injecting steam,
8 solvent, or a combination thereof into the subterranean reservoir by way of the injection well. The method further comprises providing a deposition inhibitor to an internal volume of an intermediate casing within the production well. The deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing. The providing of the deposition inhibitor to the internal volume of the intermediate casing occurs before, during, and/or after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 C
and about 285 C and a pressure of between about 800 kPag and about 7,000 kPag. The method further comprises producing at least a portion of the fluid by way of the production well.
[0025] In select embodiments of the present disclosure, the production well may be configured for a SAGD process, a cyclic steam stimulation process (CSS), a solvent process such as a solvent assisted process (SAP), or a combination thereof.
For example the production well may comprise a surface casing, an intermediate casing, and a liner.
In the context of the present disclosure, an intermediate casing may engage a liner at one end and may house a production tubing, a pump (such as an electric submersible pump (ESP)), and/or other primary completion components. Accordingly, in the context of the present disclosure, the interior volume of an intermediate casing may comprise any interior surfaces of the intermediate casing, any surfaces of the production tubing housed within the intermediate casing, any surfaces of the ESP housed within the intermediate casing, and/or any surfaces of any other primary completion components housed within the intermediate casing. FIG. 1 provides a schematic of one such production well 100. In FIG.1, the production well 100 comprises a surface casing 102, an intermediate casing 104, a production tubing 106, a liner 108, an ESP 110, a capillary tube 112, and an instrumentation coil 114. The surface casing 102 is a J-55 ST&C surface casing (339.7 mm, 81.105 kg/m). The intermediate casing 104 is an L80 QB2 intermediate casing (244.5 mm, 59.527 kg/m). The production tubing 106 is a 1-55 EUE production tubing (88.9 mm, 13.84 kg/m), the liner 108 is a 177.8 m liner. The capillary tube 112 is a 316L SS
capillary tube (12.7 mm, 0.354 kg/m). The instrumentation coil 114 is a 31.75 mm coil.
and about 285 C and a pressure of between about 800 kPag and about 7,000 kPag. The method further comprises producing at least a portion of the fluid by way of the production well.
[0025] In select embodiments of the present disclosure, the production well may be configured for a SAGD process, a cyclic steam stimulation process (CSS), a solvent process such as a solvent assisted process (SAP), or a combination thereof.
For example the production well may comprise a surface casing, an intermediate casing, and a liner.
In the context of the present disclosure, an intermediate casing may engage a liner at one end and may house a production tubing, a pump (such as an electric submersible pump (ESP)), and/or other primary completion components. Accordingly, in the context of the present disclosure, the interior volume of an intermediate casing may comprise any interior surfaces of the intermediate casing, any surfaces of the production tubing housed within the intermediate casing, any surfaces of the ESP housed within the intermediate casing, and/or any surfaces of any other primary completion components housed within the intermediate casing. FIG. 1 provides a schematic of one such production well 100. In FIG.1, the production well 100 comprises a surface casing 102, an intermediate casing 104, a production tubing 106, a liner 108, an ESP 110, a capillary tube 112, and an instrumentation coil 114. The surface casing 102 is a J-55 ST&C surface casing (339.7 mm, 81.105 kg/m). The intermediate casing 104 is an L80 QB2 intermediate casing (244.5 mm, 59.527 kg/m). The production tubing 106 is a 1-55 EUE production tubing (88.9 mm, 13.84 kg/m), the liner 108 is a 177.8 m liner. The capillary tube 112 is a 316L SS
capillary tube (12.7 mm, 0.354 kg/m). The instrumentation coil 114 is a 31.75 mm coil.
9 [0026] In the context of the present disclosure, the fluid within the internal volume of the intermediate casing may comprise a hydrocarbon fluid, an aqueous fluid (e.g. steam condensate), and/or another fluid which may originate from the reservoir. In select embodiments of the present disclosure, the temperature of the fluid within the intermediate casing may be, at one or more times during the production process, between about 100 C and about 230 C (in particular between about 180 C and about 220 C). Likewise, in select embodiments of the present disclosure, the pressure of the fluid within the intermediate casing may be, at one or more times during the production, between about 2,500 kPag and about 5,500 kPag (in particular between about 36,000 kPag and 5,000 kPag). Further, in select embodiments of the present disclosure, the pH
of the fluid within the intermediate casing may be, at one or more times during the production, between about 5.0 and about 10.0 (in particular between about 6.0 and 9.0).
Because, operating conditions and reservoir characteristics vary widely during recovery, SAGD production wells may be exposed to wide temperature variations, pressure variations, and/or pH variations. Some such variations may drive solubility equilibria towards precipitation, increase flocculation rates, and/or reduce emulsion stability. The equilibrium saturation concentration (mg/L) of silica in a steam condensate as a function of temperature is shown in FIG. 2. The trend in FIG. 2 indicates a decrease of greater than about 25 % of the saturation concentration of silica between 180 C and 220 'C. Without being bound to any particular theory, the present disclosure contemplates that reductions in produced-fluid temperature within such a range may be associated with increased rates of deposition of silicon-based deposits. Similar correlations may arise with respect to pressure and/or pH. The equilibrium saturation concentration (mg/L) of silica in a steam condensate as a function of pH is shown in FIG. 3, and the trend indicates a sharp increase in silica solubility between about 9.0 and about 10Ø pH
values within this range may occur within a SAGD reservoir, especially at or near peak temperature and pressure conditions where CO2 solubility (in the form of carboxylate anion) may be elevated. Without being bound to any particular theory, the present disclosure contemplates that silicon-containing compounds may be leached from the reservoir under such conditions and deposition may be induced in part by pH reduction as reservoir fluids cool and drop in pressure within the interior volume of the intermediate casing.
FIG. 4 which provides a plot of pH as a function of time for a produced fluid stream from a SAGD facility located in Foster Creek, Alberta. Large variations in pH over relatively short periods of time are readily apparent in FIG. 4 with pH values ranging from about 5.1 to about 9.2.
[0027] In the context of the present disclosure, a silicon-based inorganic deposit is one that primarily comprises silicon-containing compounds (by mass, volume, or elemental analysis). In the context of the present disclosure, silicon-based inorganic deposits may comprise primarily crystalline silica, amorphous silica, and/or another silicon-containing compound. Examples of silicon-containing compounds that often occur in silicon-based inorganic deposits include, but are not limited to, Quartz/Cristobalite (SiO2 ¨ various crystal-lattice-structure analogs), Anorthite (CaAl2S1208), Microcline (KAISi308), Illite ((K,H30)Al2Si3A1010(OH)2), Albite (NaAlSi308), Magnesium Aluminum Silicate (Mg2A1415018), Faujasite ((Ca, Na).Al2S12.509.6.4H20), and Analcime (Na(Si2A1)06=H20). As will be appreciated by those skilled in the art, the composition of a silicon-based inorganic deposit may be determined by a variety of characterization techniques including, but not limited to, X-ray diffraction (XRD), transmission electron microscopy (TEM), scanning electron microscopy (SEM), energy dispersive X-ray spectroscopy (EDS), and X-ray absorption fine structure (EXAFS).
[0028] In the context of the present disclosure, a deposition inhibitor is any compound or composition that is capable of suppressing deposition of silicon-based inorganic deposits under the temperature, pressure, and/or pH conditions set out herein.
In the context of the present disclosure, deposition inhibitors may: increase the solubility of silicon-containing compounds in solution; inhibit chain propagation of silicon-containing compounds; decrease the size and/or quantity of silicon-containing compounds; and/or disperse silicon-containing compounds in a fluid. As will be appreciated by those skilled in the art, the stability of a deposition inhibitor under a particular set of pressure, temperature, and/or pH conditions may be evaluated by a variety of methods such as infrared (IR) spectroscopy, nuclear magnetic resonance (NMR) spectroscopy, and/or differential scanning calorimetry (DSC). For example, FIG. 5 shows IR spectra of a deposition inhibitor taken before (A) and after (B) the deposition inhibitor was heated to a temperature of 235 C for 22 hours, and FIG. 6 provides results from a DSC experiment on a deposition inhibitor. The DSC results indicate a that first decomposition event occurred at 118 C (244.2 F), and a second decomposition event occurred at 135 C (275 F). On this basis, the deposition inhibitor was discarded as a candidate for the high temperature and high pressure conditions set out herein. Those skilled in the art, having benefited from the teachings of the present disclosure, may select an appropriate deposition inhibitor by evaluating a compound/composition's ability to: (i) resist degradation under a particular set of temperature/pressure/pH
conditions (for example by IR spectroscopy and/or DSC); and (ii) inhibit deposition of silica-based inorganic deposits (for example by analysing the form, severity, and/or composition of the deposit by XRD) under such conditions.
[0029] In select embodiments of the present disclosure, the deposition inhibitor is a composition that comprises an alcohol, a bisulfate salt, and an organo-phosphorous salt. The alcohol may be ethylene glycol, the bisulfate sulfate salt may be sodium bisulfate, and the organo-phosphorous salt may be an organo-phosphate. In particular, the deposition inhibitor may comprise a composition identified by product number 5CW4481 (as provided by Baker Hughes) which comprises between about 30 % and about 40 % ethylene glycol (by weight), between about 0.1 % and about 1 %
sodium bisulfate (by weight), and an undisclosed quantity of an undisclosed organo-phosphorous salt (trade secret).
[0030] In the context of the present disclosure, a capillary tube is an example of a conduit having an opening in fluid communication with the internal volume of an intermediate casing. Capillary tubes are commonly referred to as "bubble tubes". In the context of the present disclosure, the deposition inhibitor may be provided to the internal volume of the intermediate casing by injecting the deposition inhibitor through the capillary tube under a variety of protocols. Such protocols may include a plurality of parameters as exemplified by the following:
[0031] As a first example, the trigger for the initial injection via the capillary tube may vary. The initial injection may be triggered by: a production-event-based trigger (e.g.
at the onset of fluid communication between the injection well and the production well, or at a specific production rate or ratio); an operation-parameter-based trigger (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or composition of a produced fluid); a reservoir-based-trigger (e.g. at a specific reservoir temperature and/or pressure, or once a steam chamber achieves a particular size and/or growth rate); a time-based trigger (such as a specific time period from the onsite of production or the onsite of injection). In select embodiments of the present disclosure, the initial injection via the capillary tube may be triggered by a reservoir pressure of between about 3,600 kPag and about 5,000 kPag. In select embodiments of the present disclosure, the initial injection via the capillary tube may be triggered by a drop in reservoir pressure from between about 3,600 kPag and about 5,000 kPag to between about 1,500 kPag and about 3,600 kPag.
[0032] As a second example, the schedule of sequential injections via the capillary tube may vary. For example, the injection of the deposition inhibitor via the capillary tube may be continuous, or the deposition inhibitor may be injected via the capillary tube on a cyclic basis (e.g. once every two weeks, once every month, or once every six months) or an iterative basis. Determinations regarding scheduling sequential injections via the capillary tube may be made having regard to: production-event-related indicators (e.g.
time to peak production); operation-parameter-related indicators (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or compositions of the produced fluid); and/or reservoir-related indicators (e.g. at a specific reservoir temperature and/or pressure, or at a specific steam chamber size and/or growth rate).
[0033] As a third example, the trigger for ceasing the injection via the capillary tube may vary. For example, the ceasing the injection via the capillary tube may be triggered by: a production-event-based trigger (e.g. at a specific production rate or ratio);
an operation-parameter-based trigger (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or composition of a produced fluid); a reservoir-based-trigger (e.g. at a specific reservoir temperature and/or pressure, or once a steam chamber achieves a particular size or growth rate); and/or a time-based trigger (e.g. such as a specific time period from the onsite of production or the onsite of injection). In select embodiments of the present disclosure, ceasing the injection via the capillary tube may be triggered after a drop in reservoir pressure from between about 3,600 kPag and about 5,000 kPag to between about 1,500 kPag and about 3,600 kPag, and/or once flow-back testing indicates that dissolved silica concentrations are at a relatively steady state (e.g. within +/- 10 % of a median value).
[0034] As a fourth example, the concentration (rate) of the deposition inhibitor injected via the capillary tube may be varied. For example, the deposition inhibitor may be injected at a first concentration (rate) (e.g. between about 40 ppm and about 60 ppm based on emulsion rates) for one or more injections (or for a specific time period), and then the inhibitor may be injected at a second concentration (rate) (e.g.
between about ppm and about 30 ppm based on emulsion rates) for one or more further injection (or for a specific time period). Of course, further injections based on further alternate concentrations (rates) are also possible via the capillary tube.
Determinations regarding 15 modulating the concentration (rate) of the composition injected via the capillary tube may be made having regard to: production-event-related indicators (e.g. time to peak production); operation-parameter-related indicators (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or compositions of the produced fluid); and/or reservoir-related indicators (e.g.
at a specific 20 reservoir temperature and/or pressure, or at a specific steam chamber size and/or growth rate).
[0035] As a fifth example, the composition of the deposition inhibitor injected via the capillary tube may vary. For example, a first composition may be injected for a first time period (e.g. between about 1 month and about 4 months) and then a second composition may be injected for a second period (e.g. between 6 months and 12 months). Of course, further injections based on further alternate compositions are also possible via the capillary tube. Determinations regarding modulating the components of the composition injected via the capillary tube may be made having regard to:
production-event-related indicators (e.g. time to peak production); operation-parameter-related indicators (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or compositions of the produced fluid); and/or reservoir-related indicators (e.g. at a specific reservoir temperature and/or pressure, or at a specific steam chamber growth rate).
[0036] In the context of the present disclosure, flow-back testing may be utilized to inform decisions relating to, for example, protocols based on the foregoing triggers and parameters. Generally speaking, flow-back testing comprises analyzing produced fluids (and any materials entrained therein) to determine the content of particular components such as silicon-containing compounds, deposition inhibitors, and/or decomposition products thereof. In this way, flow-back testing may provide indirect feedback relating to, for example: the extent of deposition of silicon-based inorganic deposits within the interior volume of an intermediate casing; the extent to which a deposition inhibitor is being degraded within the interior volume of an intermediate casing; and/or the effectiveness of the deposition inhibitor. Such information may be utilized to tailor a particular deposition-inhibitor-injection protocol to provide a sufficient quantity of deposition inhibition to achieve a particular result without using an undue quantity of the deposition inhibitor.
[0037] Accordingly, methods of inhibiting deposition of silicon-based inorganic deposits in accordance with the present disclosure may further comprise an additional step of analyzing produced fluids (and/or any materials entrained therein) and adjusting a production parameter in response to the analysis. The production parameter may be, for example, steam-injection temperature, steam-injection pressure, steam quality, ESP
pump rate, the presence/absence of an injection additive, the composition of the deposition inhibitor, the concentration of the deposition inhibitor, the density of the deposition inhibitor, the injection pressure of the deposition inhibitor, the initiation time for injection of the deposition inhibitor, the stop time for injection of the deposition inhibitor, and/or the schedule for injection of the deposition inhibitor.
Likewise flow-back testing may be used to inform decisions regarding trigger points for such parameters/protocols.
[0038] In the context of the present disclosure, flow-back testing may utilize pressurized emulsion sampling procedures and/or non-pressurized emulsion sampling procedures. Pressurized emulsion sampling may be used for high pressure sample points.
The collection of samples from high pressure sampling points at a wellhead may involve the use of specialized equipment to mitigate against safety risks associated with high pressure and/or high temperature operations (e.g. sampling temperatures between about 150 C and about 220 C and/or sampling pressures between about 10,000 kPag and about 25,000 kPag). Applications of known high-temperature and/or high-pressure sampling procedures in the context of the present disclosure are within the purview of those skilled in the art having regard to the teachings of the present disclosure. Likewise, applications of known non-pressurized sampling procedures in the context of the present disclosure are within the purview of those skilled in the art having regard to the teachings of the present disclosure.
[0039] In the context of the present disclosure, a variety of emulsion separation procedures may be utilized during flow back testing. Centrifugation and Dean-Stark extraction are examples of such procedures, and they may allows for oil-water ratio quantification.
[0040] In the context of the present disclosure, following separation, aqueous phase samples may be analyzed for/to determine a variety of metrics during flow-back testing. For example, aqueous phase samples may be analyzed for/to determine:
temperature; pH; oxidation reduction potential (ORP); anion content (e.g.
alkalinity, chloride, sulfate, and/or sulfide); cation content (Nat, K+, Fe2+/3+, and/or Ca2 ); total dissolved solids (TDS); total suspended solids (TSS); total silica; reactive silica; suspended silica; trace metals; and/or trace elements associated with the deposition inhibitor. A
variety of analytical instruments may be used for the foregoing analyses. For example, inductively coupled plasma emission spectroscopy (ICP-ES) and ion chromatography (IC) may be used to identify solution phase components.
[0041] In the context of the present disclosure, solids entrained in the oil phase of flow-back testing samples may be analyzed for/to determine a variety of metrics. For example, solids entrained in the oil phase may be isolated by centrifugation and/or filtration and identified by for example X-ray powder diffraction (XRD), X-ray fluorescence (XRF), and/or scanning electron microscopy (SEM).
[0042] In select embodiments of the present disclosure, methods of inhibiting deposition of silicon-based inorganic deposits may further comprise collecting baseline flow-back data in advance of the providing of the deposition inhibitor to the intermediate-casing channel. Baseline flow-back data may provide context for additional flow-back data obtained during hydrocarbon production in the presence of a deposition inhibitor. For example, total silica, reactive silica, and/or suspended silica may be analyzed both before and after providing a deposition inhibitor to the interior volume of an intermediate casing, and results from such analyses may be utilized to trigger a modification to the composition, concentration, pressure, and/or density of the deposition inhibitor. Likewise, such analyses may be utilized to trigger a change to the schedule for injecting the deposition inhibitor.
Example 1 [0043] At a SAGD production facility in Foster Creek, Alberta, a SAGD production well completed as set out above with respect to FIG. 1 was operated through a typical SAGD start-up phase, ramp-up phase, and production phase. During the production phase, steam injection parameters were modulated to provide a peak reservoir pressure between about 3,600 kPag and 5,000 kPag, and then the injection conditions were throttled to allow the reservoir pressure to settle. After a period of about
of the fluid within the intermediate casing may be, at one or more times during the production, between about 5.0 and about 10.0 (in particular between about 6.0 and 9.0).
Because, operating conditions and reservoir characteristics vary widely during recovery, SAGD production wells may be exposed to wide temperature variations, pressure variations, and/or pH variations. Some such variations may drive solubility equilibria towards precipitation, increase flocculation rates, and/or reduce emulsion stability. The equilibrium saturation concentration (mg/L) of silica in a steam condensate as a function of temperature is shown in FIG. 2. The trend in FIG. 2 indicates a decrease of greater than about 25 % of the saturation concentration of silica between 180 C and 220 'C. Without being bound to any particular theory, the present disclosure contemplates that reductions in produced-fluid temperature within such a range may be associated with increased rates of deposition of silicon-based deposits. Similar correlations may arise with respect to pressure and/or pH. The equilibrium saturation concentration (mg/L) of silica in a steam condensate as a function of pH is shown in FIG. 3, and the trend indicates a sharp increase in silica solubility between about 9.0 and about 10Ø pH
values within this range may occur within a SAGD reservoir, especially at or near peak temperature and pressure conditions where CO2 solubility (in the form of carboxylate anion) may be elevated. Without being bound to any particular theory, the present disclosure contemplates that silicon-containing compounds may be leached from the reservoir under such conditions and deposition may be induced in part by pH reduction as reservoir fluids cool and drop in pressure within the interior volume of the intermediate casing.
FIG. 4 which provides a plot of pH as a function of time for a produced fluid stream from a SAGD facility located in Foster Creek, Alberta. Large variations in pH over relatively short periods of time are readily apparent in FIG. 4 with pH values ranging from about 5.1 to about 9.2.
[0027] In the context of the present disclosure, a silicon-based inorganic deposit is one that primarily comprises silicon-containing compounds (by mass, volume, or elemental analysis). In the context of the present disclosure, silicon-based inorganic deposits may comprise primarily crystalline silica, amorphous silica, and/or another silicon-containing compound. Examples of silicon-containing compounds that often occur in silicon-based inorganic deposits include, but are not limited to, Quartz/Cristobalite (SiO2 ¨ various crystal-lattice-structure analogs), Anorthite (CaAl2S1208), Microcline (KAISi308), Illite ((K,H30)Al2Si3A1010(OH)2), Albite (NaAlSi308), Magnesium Aluminum Silicate (Mg2A1415018), Faujasite ((Ca, Na).Al2S12.509.6.4H20), and Analcime (Na(Si2A1)06=H20). As will be appreciated by those skilled in the art, the composition of a silicon-based inorganic deposit may be determined by a variety of characterization techniques including, but not limited to, X-ray diffraction (XRD), transmission electron microscopy (TEM), scanning electron microscopy (SEM), energy dispersive X-ray spectroscopy (EDS), and X-ray absorption fine structure (EXAFS).
[0028] In the context of the present disclosure, a deposition inhibitor is any compound or composition that is capable of suppressing deposition of silicon-based inorganic deposits under the temperature, pressure, and/or pH conditions set out herein.
In the context of the present disclosure, deposition inhibitors may: increase the solubility of silicon-containing compounds in solution; inhibit chain propagation of silicon-containing compounds; decrease the size and/or quantity of silicon-containing compounds; and/or disperse silicon-containing compounds in a fluid. As will be appreciated by those skilled in the art, the stability of a deposition inhibitor under a particular set of pressure, temperature, and/or pH conditions may be evaluated by a variety of methods such as infrared (IR) spectroscopy, nuclear magnetic resonance (NMR) spectroscopy, and/or differential scanning calorimetry (DSC). For example, FIG. 5 shows IR spectra of a deposition inhibitor taken before (A) and after (B) the deposition inhibitor was heated to a temperature of 235 C for 22 hours, and FIG. 6 provides results from a DSC experiment on a deposition inhibitor. The DSC results indicate a that first decomposition event occurred at 118 C (244.2 F), and a second decomposition event occurred at 135 C (275 F). On this basis, the deposition inhibitor was discarded as a candidate for the high temperature and high pressure conditions set out herein. Those skilled in the art, having benefited from the teachings of the present disclosure, may select an appropriate deposition inhibitor by evaluating a compound/composition's ability to: (i) resist degradation under a particular set of temperature/pressure/pH
conditions (for example by IR spectroscopy and/or DSC); and (ii) inhibit deposition of silica-based inorganic deposits (for example by analysing the form, severity, and/or composition of the deposit by XRD) under such conditions.
[0029] In select embodiments of the present disclosure, the deposition inhibitor is a composition that comprises an alcohol, a bisulfate salt, and an organo-phosphorous salt. The alcohol may be ethylene glycol, the bisulfate sulfate salt may be sodium bisulfate, and the organo-phosphorous salt may be an organo-phosphate. In particular, the deposition inhibitor may comprise a composition identified by product number 5CW4481 (as provided by Baker Hughes) which comprises between about 30 % and about 40 % ethylene glycol (by weight), between about 0.1 % and about 1 %
sodium bisulfate (by weight), and an undisclosed quantity of an undisclosed organo-phosphorous salt (trade secret).
[0030] In the context of the present disclosure, a capillary tube is an example of a conduit having an opening in fluid communication with the internal volume of an intermediate casing. Capillary tubes are commonly referred to as "bubble tubes". In the context of the present disclosure, the deposition inhibitor may be provided to the internal volume of the intermediate casing by injecting the deposition inhibitor through the capillary tube under a variety of protocols. Such protocols may include a plurality of parameters as exemplified by the following:
[0031] As a first example, the trigger for the initial injection via the capillary tube may vary. The initial injection may be triggered by: a production-event-based trigger (e.g.
at the onset of fluid communication between the injection well and the production well, or at a specific production rate or ratio); an operation-parameter-based trigger (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or composition of a produced fluid); a reservoir-based-trigger (e.g. at a specific reservoir temperature and/or pressure, or once a steam chamber achieves a particular size and/or growth rate); a time-based trigger (such as a specific time period from the onsite of production or the onsite of injection). In select embodiments of the present disclosure, the initial injection via the capillary tube may be triggered by a reservoir pressure of between about 3,600 kPag and about 5,000 kPag. In select embodiments of the present disclosure, the initial injection via the capillary tube may be triggered by a drop in reservoir pressure from between about 3,600 kPag and about 5,000 kPag to between about 1,500 kPag and about 3,600 kPag.
[0032] As a second example, the schedule of sequential injections via the capillary tube may vary. For example, the injection of the deposition inhibitor via the capillary tube may be continuous, or the deposition inhibitor may be injected via the capillary tube on a cyclic basis (e.g. once every two weeks, once every month, or once every six months) or an iterative basis. Determinations regarding scheduling sequential injections via the capillary tube may be made having regard to: production-event-related indicators (e.g.
time to peak production); operation-parameter-related indicators (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or compositions of the produced fluid); and/or reservoir-related indicators (e.g. at a specific reservoir temperature and/or pressure, or at a specific steam chamber size and/or growth rate).
[0033] As a third example, the trigger for ceasing the injection via the capillary tube may vary. For example, the ceasing the injection via the capillary tube may be triggered by: a production-event-based trigger (e.g. at a specific production rate or ratio);
an operation-parameter-based trigger (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or composition of a produced fluid); a reservoir-based-trigger (e.g. at a specific reservoir temperature and/or pressure, or once a steam chamber achieves a particular size or growth rate); and/or a time-based trigger (e.g. such as a specific time period from the onsite of production or the onsite of injection). In select embodiments of the present disclosure, ceasing the injection via the capillary tube may be triggered after a drop in reservoir pressure from between about 3,600 kPag and about 5,000 kPag to between about 1,500 kPag and about 3,600 kPag, and/or once flow-back testing indicates that dissolved silica concentrations are at a relatively steady state (e.g. within +/- 10 % of a median value).
[0034] As a fourth example, the concentration (rate) of the deposition inhibitor injected via the capillary tube may be varied. For example, the deposition inhibitor may be injected at a first concentration (rate) (e.g. between about 40 ppm and about 60 ppm based on emulsion rates) for one or more injections (or for a specific time period), and then the inhibitor may be injected at a second concentration (rate) (e.g.
between about ppm and about 30 ppm based on emulsion rates) for one or more further injection (or for a specific time period). Of course, further injections based on further alternate concentrations (rates) are also possible via the capillary tube.
Determinations regarding 15 modulating the concentration (rate) of the composition injected via the capillary tube may be made having regard to: production-event-related indicators (e.g. time to peak production); operation-parameter-related indicators (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or compositions of the produced fluid); and/or reservoir-related indicators (e.g.
at a specific 20 reservoir temperature and/or pressure, or at a specific steam chamber size and/or growth rate).
[0035] As a fifth example, the composition of the deposition inhibitor injected via the capillary tube may vary. For example, a first composition may be injected for a first time period (e.g. between about 1 month and about 4 months) and then a second composition may be injected for a second period (e.g. between 6 months and 12 months). Of course, further injections based on further alternate compositions are also possible via the capillary tube. Determinations regarding modulating the components of the composition injected via the capillary tube may be made having regard to:
production-event-related indicators (e.g. time to peak production); operation-parameter-related indicators (e.g. at a specific steam injection pressure and/or temperature, or at a specific temperature, pressure, and/or compositions of the produced fluid); and/or reservoir-related indicators (e.g. at a specific reservoir temperature and/or pressure, or at a specific steam chamber growth rate).
[0036] In the context of the present disclosure, flow-back testing may be utilized to inform decisions relating to, for example, protocols based on the foregoing triggers and parameters. Generally speaking, flow-back testing comprises analyzing produced fluids (and any materials entrained therein) to determine the content of particular components such as silicon-containing compounds, deposition inhibitors, and/or decomposition products thereof. In this way, flow-back testing may provide indirect feedback relating to, for example: the extent of deposition of silicon-based inorganic deposits within the interior volume of an intermediate casing; the extent to which a deposition inhibitor is being degraded within the interior volume of an intermediate casing; and/or the effectiveness of the deposition inhibitor. Such information may be utilized to tailor a particular deposition-inhibitor-injection protocol to provide a sufficient quantity of deposition inhibition to achieve a particular result without using an undue quantity of the deposition inhibitor.
[0037] Accordingly, methods of inhibiting deposition of silicon-based inorganic deposits in accordance with the present disclosure may further comprise an additional step of analyzing produced fluids (and/or any materials entrained therein) and adjusting a production parameter in response to the analysis. The production parameter may be, for example, steam-injection temperature, steam-injection pressure, steam quality, ESP
pump rate, the presence/absence of an injection additive, the composition of the deposition inhibitor, the concentration of the deposition inhibitor, the density of the deposition inhibitor, the injection pressure of the deposition inhibitor, the initiation time for injection of the deposition inhibitor, the stop time for injection of the deposition inhibitor, and/or the schedule for injection of the deposition inhibitor.
Likewise flow-back testing may be used to inform decisions regarding trigger points for such parameters/protocols.
[0038] In the context of the present disclosure, flow-back testing may utilize pressurized emulsion sampling procedures and/or non-pressurized emulsion sampling procedures. Pressurized emulsion sampling may be used for high pressure sample points.
The collection of samples from high pressure sampling points at a wellhead may involve the use of specialized equipment to mitigate against safety risks associated with high pressure and/or high temperature operations (e.g. sampling temperatures between about 150 C and about 220 C and/or sampling pressures between about 10,000 kPag and about 25,000 kPag). Applications of known high-temperature and/or high-pressure sampling procedures in the context of the present disclosure are within the purview of those skilled in the art having regard to the teachings of the present disclosure. Likewise, applications of known non-pressurized sampling procedures in the context of the present disclosure are within the purview of those skilled in the art having regard to the teachings of the present disclosure.
[0039] In the context of the present disclosure, a variety of emulsion separation procedures may be utilized during flow back testing. Centrifugation and Dean-Stark extraction are examples of such procedures, and they may allows for oil-water ratio quantification.
[0040] In the context of the present disclosure, following separation, aqueous phase samples may be analyzed for/to determine a variety of metrics during flow-back testing. For example, aqueous phase samples may be analyzed for/to determine:
temperature; pH; oxidation reduction potential (ORP); anion content (e.g.
alkalinity, chloride, sulfate, and/or sulfide); cation content (Nat, K+, Fe2+/3+, and/or Ca2 ); total dissolved solids (TDS); total suspended solids (TSS); total silica; reactive silica; suspended silica; trace metals; and/or trace elements associated with the deposition inhibitor. A
variety of analytical instruments may be used for the foregoing analyses. For example, inductively coupled plasma emission spectroscopy (ICP-ES) and ion chromatography (IC) may be used to identify solution phase components.
[0041] In the context of the present disclosure, solids entrained in the oil phase of flow-back testing samples may be analyzed for/to determine a variety of metrics. For example, solids entrained in the oil phase may be isolated by centrifugation and/or filtration and identified by for example X-ray powder diffraction (XRD), X-ray fluorescence (XRF), and/or scanning electron microscopy (SEM).
[0042] In select embodiments of the present disclosure, methods of inhibiting deposition of silicon-based inorganic deposits may further comprise collecting baseline flow-back data in advance of the providing of the deposition inhibitor to the intermediate-casing channel. Baseline flow-back data may provide context for additional flow-back data obtained during hydrocarbon production in the presence of a deposition inhibitor. For example, total silica, reactive silica, and/or suspended silica may be analyzed both before and after providing a deposition inhibitor to the interior volume of an intermediate casing, and results from such analyses may be utilized to trigger a modification to the composition, concentration, pressure, and/or density of the deposition inhibitor. Likewise, such analyses may be utilized to trigger a change to the schedule for injecting the deposition inhibitor.
Example 1 [0043] At a SAGD production facility in Foster Creek, Alberta, a SAGD production well completed as set out above with respect to FIG. 1 was operated through a typical SAGD start-up phase, ramp-up phase, and production phase. During the production phase, steam injection parameters were modulated to provide a peak reservoir pressure between about 3,600 kPag and 5,000 kPag, and then the injection conditions were throttled to allow the reservoir pressure to settle. After a period of about
10 months production tubing was retrieved from within the interior volume of the intermediate casing and analyzed. FIG. 7A provides a photograph of a silicon-based deposit that was mechanically removed from the production tubing, and FIG. 7B provides a high-resolution microscopic image of the same. A high degree of crystallinity is apparent in the microscopic image. A plurality of samples were obtained from various surfaces with the interior volume of the intermediate casing. The samples were mechanically isolated and prepared for XRD analysis. Results from a typical XRD analysis are provided in Table 1.
The results of Table 1 indicate that a high percentage (greater than 85%) of the analysed deposit is in a crystalline form.
Table 1: Results from XRD analysis of casing deposit from surface exposed to SAGD
production conditions within the interior volume of the intermediate casing.
Formula Name Percentage S102 Quartz 85.2%
SiO2 Cristoba lite 4.6%
CaAl2S1208 Anorthite 4.3%
KAIS1308 Microcline 1.3%
(K,H30)Al2Si3A1010(OH)2 Illite 0.4%
SiO2 Silicon Oxide 0.3%
NaAlSi308 Albite 0.1%
Magnesium Aluminum Mg2A14Si5018 1.2%
Silicate CaSO4 Anhydrite 1.0%
Ca(Fe,Mg)(CO3)2 Ankerite 0.4%
HFe(SO4)2.4H20 Rhomboclase 0.3%
(Ca,Na).Al2Si2509.6.4H20 Fa ujasite 0.3%
Na2(5406)(H20)2 Sodium Sulfite Hydrate 0.3%
Na(Si2A1)06.1-120 Analcime 0.3%
Example 2:
[0044] A well-pad wide experiment is underway at a SAGD production facility in Foster Creek, Alberta. Generally speaking, the reservoir strategy for the experiment is to operate at high pressure until peak oil production rate is achieved. Once peak production is achieved, steam will be redirected to other areas to provide a decline in reservoir pressure. Then, surfaces from within the interior volume of the intermediate casing will be retrieved and evaluated to determine the extent of deposition (both qualitatively and quantitatively) using the protocols set out in the present disclosure. The production wells are generally completed as set out above with respect to FIG. 1. Half of the wells on the pad are being operated in the absence of a deposition inhibitor. For the other half of the wells, capillary tubes are being used to provide a deposition inhibitor to the interior volume of the intermediate casing. The deposition inhibitor is 5CW4481 as provided by Baker Hughes . The concentration of the deposition inhibitor is 40 ppm with respect to emulsion rates, and the deposition is being provided as a constant trickle until definitive results are obtained or the trial ends.
[0045] The wells of the pad are configured for flow-back testing.
During production, samples of the liquid phase (aqueous and oil phases) of the production fluid are being taken at regular volume intervals. For each sample, pH, temperature, and oxidation/reduction potential are being analyzed on site. Following on-site analysis, the samples are being analyzed by ICP-ES and IC to determine the concentrations of key components. In particular one or more of the following may be analysed: anion content;
cation content; TDS; TSS; total silica; reactive silica; suspended silica;
trace metals; and/or trace elements associated with the deposition inhibitor.
[0046] Forecasts for emulsion production rates and deposition inhibitor concentration (rate) for the well-pad wide experiment are set out FIG. 8. In FIG. 8, total emulsion rates for the field (A) and emulsion rates only for the test pad (B) are shown as a function of time, and the concentration of the deposition inhibitor (with respect to emulsion rates) as a function of time is overlaid as plot C. As indicated in plot C, the concentration (rate) of deposition inhibitor is forecasted to peak at about 6.2 ppm based on total emulsion rate and then drop off quickly after injection is ceased.
In the context of the present disclosure, all terms referred to in singular form are meant to encompass plural forms of the same. Likewise, all terms referred to in plural form are meant to encompass singular forms of the same. Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure pertains.
As used herein, the term "about" refers to an approximately +/-10 % variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.
It should be understood that the compositions and methods are described in terms of "comprising," "containing," or "including" various components or steps, the compositions and methods can also "consist essentially of" or "consist of" the various components and steps. Moreover, the indefinite articles "a" or "an", as used in the description and the claims, are defined herein to mean "one or more than one"
of the element that it introduces.
For the sake of brevity, only certain ranges are explicitly disclosed herein.
However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited.
Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, "from about a to about b," or, equivalently, "from approximately a to b," or, equivalently, "from approximately a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.
Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, the disclosure covers all combinations of all those embodiments. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the present disclosure. Moreover, many obvious variations of the embodiments set out herein will suggest themselves to those skilled in the art in light of the present disclosure. Such obvious variations are within the full intended scope of the appended claims.
The results of Table 1 indicate that a high percentage (greater than 85%) of the analysed deposit is in a crystalline form.
Table 1: Results from XRD analysis of casing deposit from surface exposed to SAGD
production conditions within the interior volume of the intermediate casing.
Formula Name Percentage S102 Quartz 85.2%
SiO2 Cristoba lite 4.6%
CaAl2S1208 Anorthite 4.3%
KAIS1308 Microcline 1.3%
(K,H30)Al2Si3A1010(OH)2 Illite 0.4%
SiO2 Silicon Oxide 0.3%
NaAlSi308 Albite 0.1%
Magnesium Aluminum Mg2A14Si5018 1.2%
Silicate CaSO4 Anhydrite 1.0%
Ca(Fe,Mg)(CO3)2 Ankerite 0.4%
HFe(SO4)2.4H20 Rhomboclase 0.3%
(Ca,Na).Al2Si2509.6.4H20 Fa ujasite 0.3%
Na2(5406)(H20)2 Sodium Sulfite Hydrate 0.3%
Na(Si2A1)06.1-120 Analcime 0.3%
Example 2:
[0044] A well-pad wide experiment is underway at a SAGD production facility in Foster Creek, Alberta. Generally speaking, the reservoir strategy for the experiment is to operate at high pressure until peak oil production rate is achieved. Once peak production is achieved, steam will be redirected to other areas to provide a decline in reservoir pressure. Then, surfaces from within the interior volume of the intermediate casing will be retrieved and evaluated to determine the extent of deposition (both qualitatively and quantitatively) using the protocols set out in the present disclosure. The production wells are generally completed as set out above with respect to FIG. 1. Half of the wells on the pad are being operated in the absence of a deposition inhibitor. For the other half of the wells, capillary tubes are being used to provide a deposition inhibitor to the interior volume of the intermediate casing. The deposition inhibitor is 5CW4481 as provided by Baker Hughes . The concentration of the deposition inhibitor is 40 ppm with respect to emulsion rates, and the deposition is being provided as a constant trickle until definitive results are obtained or the trial ends.
[0045] The wells of the pad are configured for flow-back testing.
During production, samples of the liquid phase (aqueous and oil phases) of the production fluid are being taken at regular volume intervals. For each sample, pH, temperature, and oxidation/reduction potential are being analyzed on site. Following on-site analysis, the samples are being analyzed by ICP-ES and IC to determine the concentrations of key components. In particular one or more of the following may be analysed: anion content;
cation content; TDS; TSS; total silica; reactive silica; suspended silica;
trace metals; and/or trace elements associated with the deposition inhibitor.
[0046] Forecasts for emulsion production rates and deposition inhibitor concentration (rate) for the well-pad wide experiment are set out FIG. 8. In FIG. 8, total emulsion rates for the field (A) and emulsion rates only for the test pad (B) are shown as a function of time, and the concentration of the deposition inhibitor (with respect to emulsion rates) as a function of time is overlaid as plot C. As indicated in plot C, the concentration (rate) of deposition inhibitor is forecasted to peak at about 6.2 ppm based on total emulsion rate and then drop off quickly after injection is ceased.
In the context of the present disclosure, all terms referred to in singular form are meant to encompass plural forms of the same. Likewise, all terms referred to in plural form are meant to encompass singular forms of the same. Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure pertains.
As used herein, the term "about" refers to an approximately +/-10 % variation from a given value. It is to be understood that such a variation is always included in any given value provided herein, whether or not it is specifically referred to.
It should be understood that the compositions and methods are described in terms of "comprising," "containing," or "including" various components or steps, the compositions and methods can also "consist essentially of" or "consist of" the various components and steps. Moreover, the indefinite articles "a" or "an", as used in the description and the claims, are defined herein to mean "one or more than one"
of the element that it introduces.
For the sake of brevity, only certain ranges are explicitly disclosed herein.
However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited.
Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, "from about a to about b," or, equivalently, "from approximately a to b," or, equivalently, "from approximately a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.
Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, the disclosure covers all combinations of all those embodiments. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the present disclosure. Moreover, many obvious variations of the embodiments set out herein will suggest themselves to those skilled in the art in light of the present disclosure. Such obvious variations are within the full intended scope of the appended claims.
Claims (68)
1. A method of inhibiting deposition of a silicon-based inorganic deposit within a production well that is in fluid communication with a subterranean reservoir, the method comprising:
providing a deposition inhibitor into an internal volume defined by an intermediate casing of the production well, wherein the deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing, and wherein the deposition inhibitor is provided into the internal volume of the intermediate casing at least one of before, during, and after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 *C
and about 285 C, and a pressure of between about 800 kPag and about 7,000 kPag; and wherein the deposition inhibitor is a composition comprising between about 20 % and about 50 % of an organo-phosphorous salt on a weight basis.
providing a deposition inhibitor into an internal volume defined by an intermediate casing of the production well, wherein the deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing, and wherein the deposition inhibitor is provided into the internal volume of the intermediate casing at least one of before, during, and after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 *C
and about 285 C, and a pressure of between about 800 kPag and about 7,000 kPag; and wherein the deposition inhibitor is a composition comprising between about 20 % and about 50 % of an organo-phosphorous salt on a weight basis.
2. The method of claim 1, wherein at least 50 % of the silicon-based inorganic deposit comprises silica, silicate, or a combination thereof as determined on a mass basis after drying.
3. The method of claim 1, wherein at least 70 % of the silicon-based inorganic deposit comprises silica, silicate, or a combination thereof as determined on a mass basis after drying.
4. The method of claim 1, wherein at least 80 % of the silicon-based inorganic deposit comprises silica, silicate, or a combination thereof as determined on a mass basis after drying.
5. The method of claim 1, wherein at least 50 % of the silicon-based inorganic deposit comprises crystalline silica as determined by X-ray diffraction spectrometry after drying.
6. The method of claim 1, wherein at least 70 % of the silicon-based inorganic deposit comprises crystalline silica as determined by X-ray diffraction spectrometry after drying.
7. The method of claim 1, wherein at least 80 % of the silicon-based inorganic deposit comprises crystalline silica as determined by X-ray diffraction spectrometry after drying.
8. The method of any one of claims 1-7, wherein the production well is configured for a steam assisted gravity drainage process, a solvent assisted process, or a combination thereof.
9. The method of any one of claims 1-7, wherein the production well is configured for cyclic steam stimulation or solvent assisted cyclic steam stimulation.
Date recue/Date received 2023-04-20
Date recue/Date received 2023-04-20
10. The method of any one of claims 1-9, wherein the interior volume of the intermediate casing comprises an interior surface of the intermediate casing, a surface of a production tube that is housed within the intermediate casing, a surface of an electronic submersible pump that is housed within the intermediate casing, a surface of a primary completion component housed within the intermediate casing, or a combination thereof.
11. The method of any one of claims 1-10, wherein the subterranean reservoir is an oil sand reservoir.
12. The method of any one of claims 1-11, wherein the deposition inhibitor is introduced during or after a production ramp-up stage.
13. The method of claim 1, wherein the composition comprises between about 20 % and about SO%
of an alcohol on a weight basis.
of an alcohol on a weight basis.
14. The method of claim 13, wherein the alcohol comprises ethylene glycol.
15. The method of any one of claims 1-14, wherein the composition comprises between about 0.01 % and about 5 % of a bisulfite salt on a weight basis.
16. The method of claim 15, wherein the bisulfite salt comprises sodium bisulfite.
17. The method of any one of claims 1-16, wherein the deposition inhibitor comprises a composition identified by product number 5CW4481 as purveyed by Baker Hughes Canada Company comprising between about 30 % and about 40 % ethylene glycol by weight, between about 0.1 % and about 1 %
sodium bisulfate by weight, and an organo-phosphorous salt.
sodium bisulfate by weight, and an organo-phosphorous salt.
18. The method of any one of claims 1-17, wherein the deposition inhibitor is provided at a rate sufficient to provide a concentration of between about 10 ppm and about 60 ppm based on emulsion rates.
19. The method of any one of claims 1-17, wherein the deposition inhibitor is provided at a rate sufficient to provide a concentration of between about 30 ppm and about 50 ppm based on emulsion rates.
20. The method of any one of claims 1-19, wherein the deposition inhibitor is provided to the interior volume of the intermediate casing on a continuous basis.
21. The method of any one of claims 1-19, wherein the deposition inhibitor is provided to the interior volume of the intermediate casing on an iterative basis or a cyclic basis.
Date recue/Date received 2023-04-20
Date recue/Date received 2023-04-20
22. The method of any one of claims 1-21, wherein the deposition inhibitor is provided to the interior volume of the intermediate casing for a period of between about 6 months and about 24 months.
23. The method of any one of claims 1-22, wherein an initiation time for providing of the deposition inhibitor by way of the conduit is triggered by a production-event-based trigger, an operation-para meter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
24. The method of any one of claims 1-23, wherein a stop time for providing of the deposition inhibitor by way of the conduit is triggered by a production-event-based trigger, an operation-parameter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
25. The method of any one of claims 1-24, wherein a schedule for the providing of the deposition inhibitor by way of the conduit is set based on a production-event-based trigger, an operation-para meter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
26. The method of any one of claims 1-25, wherein the composition of the deposition inhibitor is modified based on a production-event-based trigger, an operation-parameter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
27. The method of any one of claims 1-26, wherein the concentration of the deposition inhibitor is modified based on a production-event-based trigger, an operation-parameter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
28. The method of any one of claims 1-27, which further comprises flow-back testing a fluid produced from the production well.
29. The method of claim 28, wherein the composition of the deposition inhibitor, the concentration of the deposition inhibitor, or a combination thereof is modified based on results from the flow-testing.
30. The method of claim 28 or 29, wherein the start time for providing the deposition inhibitor, the stop time for providing the deposition inhibitor, the schedule for providing the deposition inhibitor, or a combination thereof is modified based on results from the flow-testing.
31. The method of any one of claims 1-30, wherein at one or more times during the hydrocarbon production phase, the temperature of fluid in the intermediate casing is between about 180 C and about 220 C.
Date recue/Date received 2023-04-20
Date recue/Date received 2023-04-20
32. The method of any one of claims 1-31, wherein at one or more times during the hydrocarbon production phase, the pressure of fluid in the intermediate casing is between about 800 kPag and about 5,000 kPag.
33. The method of any one of claims 1-32, wherein at one or more times during the hydrocarbon producton phase, the fluid in the intermediate casing has a pH of between about 6.0 and about 9Ø
34. The method of any one of claims 1-33, further comprising collecting baseline flow-back data in advance of the providing of the deposition inhibitor to the intermediate-casing channel.
35. A method for producing hydrocarbons from a subterranean reservoir that is in fluid communication with an injection well and a production well, the method comprising:
injecting steam, solvent, or a combination thereof into the subterranean reservoir by way of the injection well;
providing a deposition inhibitor to an internal volume of an intermediate casing within the production well, wherein the deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing, and wherein the deposition inhibitor is provided to the internal volume of the intermediate casing at least one of before, during, and after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 C and about 285 C, and a pressure of between about 800 kPag and about 7,000 kPag, wherein the deposition inhibitor is a composition comprising between about 20 % and about 50 % of an organo-phosphorous salt on a weight basis; and producing at least a portion of the fluid by way of the production well.
injecting steam, solvent, or a combination thereof into the subterranean reservoir by way of the injection well;
providing a deposition inhibitor to an internal volume of an intermediate casing within the production well, wherein the deposition inhibitor is provided by way of a conduit having an opening in fluid communication with the internal volume of the intermediate casing, and wherein the deposition inhibitor is provided to the internal volume of the intermediate casing at least one of before, during, and after the internal volume of the intermediate casing is occupied by a fluid having, at one or more times during a hydrocarbon production phase, a temperature of between about 80 C and about 285 C, and a pressure of between about 800 kPag and about 7,000 kPag, wherein the deposition inhibitor is a composition comprising between about 20 % and about 50 % of an organo-phosphorous salt on a weight basis; and producing at least a portion of the fluid by way of the production well.
36. The method of claim 35, wherein at least 50 % of the silicon-based inorganic deposit comprises silica, silicate, or a combination thereof as determined on a mass basis after drying.
37. The method of claim 35, wherein at least 70 % of the silicon-based inorganic deposit comprises silica, silicate, or a combination thereof as determined on a mass basis after drying.
38. The method of claim 35, wherein at least 80 % of the silicon-based inorganic deposit comprises silica, silicate, or a combination thereof as determined on a mass basis after drying.
39. The method of claim 35, wherein at least 50 % of the silicon-based inorganic deposit comprises crystalline silica as determined by X-ray diffraction spectrometry after drying.
Date rectie/Date received 2023-04-20
Date rectie/Date received 2023-04-20
40. The method of claim 35, wherein at least 70 % of the silicon-based inorganic deposit comprises crystalline silica as determined by X-ray diffraction spectrometry after drying.
41. The method of claim 35, wherein at least 80 % of the silicon-based inorganic deposit comprises crystalline silica as determined by X-ray diffraction spectrometry after drying.
42. The method of any one of claims 35-41, wherein the production well is configured for a steam assisted gravity drainage process, a solvent assisted process, or a combination thereof.
43. The method of any one of claims 35-41, wherein the production well is configured for cyclic steam stimulation or solvent assisted cyclic steam stimulation.
44. The method of any one of claims 35-43, wherein the interior volume of the intermediate casing comprises an interior surface of the intermediate casing, a surface of a production tube that is housed within the intermediate casing, a surface of an electronic submersible pump that is housed within the intermediate casing, a surface of a primary completion component housed within the intermediate casing, or a combination thereof.
45. The method of any one of claims 35-44, wherein the subterranean reservoir is an oil sand reservoir.
46. The method of any one of claims 35-44, wherein the deposition inhibitor is introduced during or after a production ramp-up stage.
47. The method of claim 35, wherein the composition comprises between about 20 % and about 50 % of an alcohol on a weight basis.
48. The method of claim 47, wherein the alcohol comprises ethylene glycol.
49. The method of any one of claims 35-48, wherein the composition comprises between about 0.01 % and about 5 % of a bisulfite salt on a weight basis.
50. The method of claim 49, wherein the bisulfite salt comprises sodium bisulfite.
51. The method of any one of claims 35-50, wherein the deposition inhibitor comprises a composition identified by product number SCW4481 as purveyed by Baker Hughes Canada Company comprising between about 30 % and about 40 % ethylene glycol by weight, between about 0.1 % and about 1 %
sodium bisulfate by weight, and an organo-phosphorous salt.
Date recue/Date received 2023-04-20
sodium bisulfate by weight, and an organo-phosphorous salt.
Date recue/Date received 2023-04-20
52. The method of any one of claims 35-51, where the deposition inhibitor is provided at a rate sufficient to provide a concentration of between about 10 ppm and about 60 ppm based on emulsion rates.
53. The method of any one of claims 35-51, where the deposition inhibitor is provided at a rate sufficient to provide a concentration of between about 30 ppm and about 50 ppm based on emulsion rates.
54. The method of any one of claims 35-53, where in the deposition inhibitor is provided to the interior volume of the intermediate casing on a continuous basis.
55. The method of any one of claims 35-53, where in the deposition inhibitor is provided to the interior volume of the intermediate casing on an iterative basis or a cyclic basis.
56. The method of any one of claims 35-55, where in the deposition inhibitor is provided to the interior volume of the intermediate casing for a period of between about 6 months and about 24 months.
57. The method of any one of claims 35-56, wherein an initiation time for providing of the deposition inhibitor by way of the conduit is triggered by a production-event-based trigger, an operation-parameter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
58. The method of any one of claims 35-57, wherein a stop time for providing of the deposition inhibitor by way of the conduit is triggered by a production-event-based trigger, an operation-parameter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
59. The method of any one of claims 35-58, wherein a schedule for the providing of the deposition inhibitor by way of the conduit is set based on a production-event-based trigger, an operation-parameter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
60. The method of any one of claims 35-59, wherein the composition of the deposition inhibitor is modified based on a production-event-based trigger, an operation-parameter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
61. The method of any one of claims 35-60, wherein the concentration of the deposition inhibitor is modified based on a production-event-based trigger, an operation-parameter-based trigger, a reservoir-based trigger, a time-based trigger, or a combination thereof.
Date rectie/Date received 2023-04-20
Date rectie/Date received 2023-04-20
62. The method of any one of claims 35-61, which further comprises flow-back testing a fluid produced from the production well.
63. The method of claim 62, wherein the composition of the deposition inhibitor, the concentration of the deposition inhibitor, or a combination thereof is modified based on results from the flow-testing.
64. The method of claim 62 or 63, wherein the start time for providing the deposition inhibitor, the stop time for providing the deposition inhibitor, the schedule for providing the deposition inhibitor, or a combination thereof is modified based on results from the flow-testing.
65. The method of any one of claims 35-64, wherein at one or more times during the hydrocarbon production phase, the temperature of fluid in the intermediate casing is between about 180 C and about 220 C.
66. The method of any one of claims 35-65, wherein at one or more times during the hydrocarbon production phase, the pressure of fluid in the intermediate casing is between about 800 kPag and about 5,000 kPag.
67. The method of any one of claims 35-66, wherein at one or more times during the hydrocarbon production phase, the fluid in the intermediate casing has a pH of between about 6.0 and about 9Ø
68. The method of any one of claims 35-67, further comprising collecting baseline flow-back data in advance of the providing of the deposition inhibitor to the intermediate-casing channel.
Date recue/Date received 2023-04-20
Date recue/Date received 2023-04-20
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| US201862774582P | 2018-12-03 | 2018-12-03 | |
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