WO2019168568A1 - Procédé permettant de former une phase gazeuse dans des réservoirs d'hydrocarbures saturés en eau - Google Patents

Procédé permettant de former une phase gazeuse dans des réservoirs d'hydrocarbures saturés en eau Download PDF

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Publication number
WO2019168568A1
WO2019168568A1 PCT/US2018/055673 US2018055673W WO2019168568A1 WO 2019168568 A1 WO2019168568 A1 WO 2019168568A1 US 2018055673 W US2018055673 W US 2018055673W WO 2019168568 A1 WO2019168568 A1 WO 2019168568A1
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Prior art keywords
hydrocarbon
gas
still
water
commonly
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PCT/US2018/055673
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English (en)
Inventor
Paul E. MENDELL
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Diversion Technologies, LLC
Highlands Natural Resources, Plc
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Priority claimed from US15/908,099 external-priority patent/US20180187534A1/en
Application filed by Diversion Technologies, LLC, Highlands Natural Resources, Plc filed Critical Diversion Technologies, LLC
Publication of WO2019168568A1 publication Critical patent/WO2019168568A1/fr

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
    • E21B43/168—Injecting a gaseous medium

Definitions

  • the following disclosure relates generally to production of hydrocarbons from a subterranean hydrocarbon-containing reservoir, more particularly to production of hydrocarbons from a water saturated subterranean hydrocarbon-containing reservoir.
  • Oil and gas reservoirs generally have some degree of water saturation within the pore network. Many reservoirs of natural gas and oil throughout the world have high water saturation (50 percent or greater). Even reservoirs which produce water-free, or produce only modest volumes of water, may have up to 60% or more, water saturation. High water saturation in a reservoir causes excessive amounts of water to be produced to produce the hydrocarbons. Coproduction and management of this water is costly and burdensome to operations leaving many reservoirs of oil and gas, stranded as uneconomic. Additionally, many hydrocarbon plays that require large volumes of water to be managed (such as the Mississippi Lime play in Kansas and Oklahoma), require expensive deep injection well facilities. Some of these operations are believed to be responsible for recent earthquake activity and the cause of production curtailments mandated by regulators, imposed on the industry.
  • the present invention is a method of recovering oil and gas from reservoirs with a relatively significant oil and/or gas saturation, but under normal producing operations, produce excessive volumes of water.
  • the present disclosure provides a method that can include the steps: providing a provided gas, injecting the provided gas into a hydrocarbon-containing reservoir, ceasing the injection of the provided gas, and gathering from the hydrocarbon-containing reservoir a mixture of the provided gas and some of the gaseous hydrocarbons from the
  • hydrocarbon-containing reservoir hydrocarbon-containing reservoir
  • the present disclosure provides a method that can include the steps: providing a gas; injecting the provided gas into a selected well bore in fluid communication with a hydrocarbon-containing reservoir having a first water-to-gas production ratio, where the hydrocarbon-containing reservoir comprises a gaseous hydrocarbon, where the provided gas is injected at rate of from about 10 mcfd or more to about no more than about 8,000 mcfd, and where at least most of the hydrocarbons produced through (or via) the well bore is a gaseous hydrocarbon; ceasing the injection of the provided gas into the selected well bore; gathering together from the hydrocarbon-containing reservoir by the selected well bore some of the provided gas and some of the gaseous hydrocarbons to form a gathered- gas mixture comprising the provided gas and some of the gaseous hydrocarbons from the hydrocarbon-containing reservoir, and producing through the selected well bore the gathered-gas mixture, where the hydrocarbon-containing reservoir producing the gathered- gas mixture has a second water-to-gas production ratio and where the second water-to-gas
  • the present disclosure provides a method that can include the steps: providing a well having first water to gas production ratio; providing a gas; injecting the provided gas into a well bore, where the well bore traverses and/or is in fluid communication with a hydrocarbon-containing reservoir, where the hydrocarbon-containing reservoir comprises a gaseous hydrocarbon; ceasing the injection of the provided gas; and producing from the well bore a mixture of the provided gas and some of the gaseous hydrocarbons having a second water to gas production ratio, where the first water-to-gas ratio is greater than the second water-to-gas ratio and where hydrocarbons produced from the well bore in the producing step are at least most gaseous hydrocarbon.
  • the present disclosure provides a method that can include the steps: providing a target well having a first water to gas production ratio from about 1 bbl water/lOOO MCF to about 2000 bbl water/lOOO MCF; providing a gas; injecting the provided gas into a well bore, where the well bore traverses and/or is in fluid communication with the
  • hydrocarbon-containing reservoir where the provided gas is injected at a rate of from about 10 mcfd or more to about no more than about 8,000 mcfd; and producing, after the ceasing of the injection of the provided gas, from the target well at a second water to gaseous hydrocarbon ratio, where the second water to gaseous hydrocarbon ratio is from about 98% to about 2% of first water to gas production ratio and where at least most of the hydrocarbons produced from the well bore in the producing step is a gaseous hydrocarbon.
  • the hydrocarbon-containing reservoir commonly has a moveable water saturation value from about 15% to about 90.
  • the hydrocarbon-containing reservoir can comprise a gaseous hydrocarbon having a carbon backbone from about one to about four carbon atoms.
  • a gaseous hydrocarbon having a carbon backbone from about one to about four carbon atoms.
  • at least about 75 mole% of the hydrocarbons produced from the selected well bore can be a gaseous hydrocarbon.
  • the hydrocarbons produced from the well bore (or well), both before and after the injection of the provided gas is at least about 75 mole% gaseous hydrocarbons.
  • the provided gas can be injected at rate of from about 10 mcfd or more to about no more than about 8,000 mcfd. Commonly, the provided gas is typically injected for a period from about five days to about three months.
  • the gathered gas can comprise a mixture of the provided gas and the gaseous hydrocarbons having from about 2 to about 98 volume% of the provided gas and from about 98 to about 2 volume% the gaseous hydrocarbon.
  • the provided gas injected into the hydrocarbon-containing reservoir can be selected from the group consisting essentially of methane, ethane, propane, nitrogen, butane, air, oxygen, argon, carbon dioxide, helium or mixture thereof.
  • the hydrocarbon-containing reservoir can comprise, prior to the injecting of the provided gas, a plurality of discrete hydrocarbon phases.
  • the plurality of discrete hydrocarbon phases can be in the form of one or more pockets and bubbles of
  • the injecting of the provided gas can coalesce the one or more of the plurality of discrete hydrocarbon phases into one or more continuous hydrocarbon phases.
  • the injection of the provided gas can reduce the level of water saturation from about 5 to about 95%.
  • the gathering step can be continued until one or more of the following is true: (i) the production of the mixture of the provided gas and some of the gaseous hydrocarbons from the hydrocarbon-containing reservoir ceases; and (ii) the hydrocarbon-containing reservoir becomes water saturated and produces primarily water.
  • the provided gas can be one of air, nitrogen, methane, or a mixture thereof.
  • the gaseous hydrocarbon gas can comprise methane.
  • a method can include the steps:
  • the well bore can traverse a hydrocarbon-containing reservoir having a moveable water saturation value from about 5% to about 95%.
  • the hydrocarbon-containing reservoir can typically comprise a gaseous hydrocarbon having a carbon backbone of about one to about four carbon atoms.
  • the gathered gas can comprise a mixture of the provided gas and the gaseous hydrocarbons having from about 2 to about 98 volume% the provided gas and from about 98 to about 2 volume% the gaseous hydrocarbon.
  • the hydrocarbon-containing reservoir can have pore volumes having a porosity and permeability.
  • the hydrocarbon-containing reservoir can have, prior to the injecting of the provided gas, a plurality of discrete hydrocarbon phases contained within the pore volumes.
  • the injecting of the provided gas can coalesce the one or more of the plurality of discrete hydrocarbon phases into one or more continuous hydrocarbon phases.
  • the one or more continuous hydrocarbon phases can span three or more pore volumes.
  • the injection of the provided gas can reduce the level of water saturation from about 2 to about 98%.
  • the provided gas injected into the hydrocarbon-containing reservoir can be one of methane, ethane, propane, nitrogen, butane, air, oxygen, argon, carbon dioxide, helium or mixture thereof.
  • the injecting of the gas into the well bore is generally at a pressure below the fracture press of the hydrocarbon-containing reservoir.
  • the producing step can be continued until one or more of the following is true: (i) the production of the mixture of the provided gas and some of the gaseous hydrocarbons from the hydrocarbon-containing reservoir ceases; and (ii) the hydrocarbon- containing reservoir becomes water saturated and produces primarily water.
  • the provided gas is typically injected into the hydrocarbon-containing reservoir at rate of from about 10 mcfd or more to about no more than about 1,000 mcfd.
  • the injecting of the provided gas can be for a period from about five days to about three months.
  • the present disclosure provides a method that can include the steps: providing a provided gas, injecting the provided gas into a well bore, producing, after the ceasing of the injection of the provided gas, from the well bore a mixture of the provided gas and some of the gaseous hydrocarbons from the hydrocarbon-containing reservoir.
  • the well bore typically traverses a hydrocarbon-containing reservoir comprising a gaseous hydrocarbon having a carbon backbone of about one to about two carbon atoms.
  • the provided gas is generally injected at rate of from about 10 mcfd or more to about no more than about 8,000 mcfd.
  • the injecting of the provided gas can be for a period from about five days to about three months.
  • the gathered gas can usually comprise a mixture the provided gas and the gaseous hydrocarbons having from about 2 to about 98 volume% the provided gas and from about 98 to about 2 volume% the gaseous
  • the hydrocarbon-containing reservoir can have a moveable water saturation value from about 5% to about 95%.
  • the provided gas injected into the hydrocarbon- containing reservoir can be one of methane, ethane, propane, nitrogen, butane, air, oxygen, carbon dioxide, helium or mixture thereof.
  • the injecting of the provided gas into the well bore can be at a pressure below the fracture press of the hydrocarbon-containing reservoir.
  • the present disclosure provides a method that includes the steps: providing a provided gas, injecting the provided gas into a hydrocarbon-containing reservoir having a first water to gas production ratio, ceasing the injection of the provided gas, and gathering from the hydrocarbon-containing reservoir a gathered-gas mixture comprising the provided gas and some of the gaseous hydrocarbons from the hydrocarbon-containing reservoir.
  • the hydrocarbon-containing reservoir can comprise a gaseous hydrocarbon.
  • the provided gas can typically be injected at rate of from about 10 mcfd or more to about no more than about 8,000 mcfd.
  • the hydrocarbon-containing reservoir producing the gathered-gas mixture can commonly have a second water to gas production ratio and where the second water-to-gas ratio is no more than the first water-to-gas ratio.
  • the provided gas injected into the hydrocarbon-containing reservoir can be selected from the group consisting essentially of methane, ethane, propane, nitrogen, butane, air, oxygen, argon, carbon dioxide, helium or mixture thereof.
  • the hydrocarbon-containing reservoir can commonly have, prior to the injecting of the provided gas, a plurality of discrete hydrocarbon phases.
  • the plurality of discrete hydrocarbon phases can usually be in the form of one or more pockets and bubbles of hydrocarbons.
  • the injecting of the provided gas can coalesce the one or more of the plurality of discrete hydrocarbon phases into one or more continuous hydrocarbon phases.
  • the gathered gas mixture can comprise the provided gas and the gaseous hydrocarbons having from about 2 to about 98 volume% the provided gas and from about 98 to about 2 volume% the gaseous hydrocarbon.
  • the gaseous hydrocarbon can comprise one of methane, ethane, propane, n-butane, isobutane, ethylene, propylene, 1 -butene, and mixture thereof.
  • the first water to gaseous hydrocarbon is commonly from about 1 bbl water/lOOO MCF to about 2000 bbl water/lOOO MCF.
  • the second water to gaseous hydrocarbon ratio is generally from about 98% to about 2% of first water to gaseous hydrocarbon ratio.
  • the injecting of the provided gas is typically for a period from about five days to about three months.
  • the gaseous hydrocarbon gas can comprise methane.
  • the present disclosure provides a method that can include the steps: providing a well having first water to gas production ratio providing a provided gas, injecting the provided gas into a well bore, ceasing the injection of the provided gas, and producing from the well bore a mixture of the provided gas and some of the gaseous hydrocarbons having a second water to gas production ratio.
  • the well bore typically traverses a hydrocarbon-containing reservoir.
  • the hydrocarbon-containing reservoir can comprise a gaseous hydrocarbon.
  • the first water-to-gas ratio is usually greater than the second water- to-gas ratio.
  • the hydrocarbon-containing reservoir can have pore volumes having a porosity and permeability.
  • the hydrocarbon-containing reservoir can have, prior to the injecting of the provided gas, a plurality of discrete hydrocarbon phases contained within the pore volumes.
  • the injecting of the provided gas can coalesce the one or more of the plurality of discrete hydrocarbon phases into one or more continuous hydrocarbon phases.
  • the one or more continuous hydrocarbon phases can span three or more pore volumes.
  • the gaseous hydrocarbon can comprise one of methane, ethane, propane, n-butane, isobutane, ethylene, propylene, 1 -butene, and mixture thereof.
  • the first water to gaseous hydrocarbon can be from about 1 bbl water/lOOO MCF to about 2000 bbl water/lOOO MCF.
  • the provided gas injected into the hydrocarbon-containing reservoir can be one of methane, ethane, propane, nitrogen, butane, air, oxygen, argon, carbon dioxide, helium or mixture thereof.
  • the injecting of the gas into the well bore can be at a pressure below the fracture press of the hydrocarbon-containing reservoir.
  • the second water to gaseous hydrocarbon ratio can be from about 98% to about 2% of first water to gaseous hydrocarbon ratio.
  • the mixture of the provided gas and some of the gaseous hydrocarbons can have from about 2 to about 98 volume% the provided gas and from about 98 to about 2 volume% the gaseous
  • the injecting of the provided gas can be for a period from about five days to about three months.
  • the present disclosure can provide a method that can include the steps: providing a target well having a first water to gas production ratio from about 1 bbl water/lOOO MCF to about 2000 bbl water/lOOO MCF, providing a provided gas, injecting the provided gas into a well bore, and producing, after the ceasing of the injection of the provided gas, from the target well at a second water to gaseous hydrocarbon ration.
  • the well bore usually traverses the hydrocarbon-containing reservoir.
  • the provided gas is typically injected at a rate of from about 10 mcfd or more to about no more than about 8,000 mcfd.
  • the second water to gaseous hydrocarbon ratio is commonly from about 98% to about 2% of first water to gas production ratio.
  • the provided gas injected into the hydrocarbon-containing reservoir can be one of methane, ethane, propane, nitrogen, butane, air, oxygen, argon, carbon dioxide, helium or mixture thereof.
  • the injecting of the provided gas into the well bore can be at a pressure below the fracture press of the hydrocarbon-containing reservoir.
  • each of the expressions “at least one of A, B and C”, “at least one of A, B, or C”, “one or more of A, B, and C", “one or more of A, B, or C" and "A, B, and/or C” means A alone, B alone, C alone, A and B together, A and C together, B and C together, or A, B and C together.
  • each one of A, B, and C in the above expressions refers to an element, such as X, Y, and Z, or class of elements, such as Xi-Xn, Yi-Ym, and Zi-Z 0
  • the phrase is intended to refer to a single element selected from X, Y, and Z, a combination of elements selected from the same class (e.g., Xi and X2) as well as a combination of elements selected from two or more classes (e.g., Yi and Z 0 ).
  • gaseous hydrocarbon or“gas-phase hydrocarbon” generally refers to an organic compound having a vapor pressure of about 10 mm Hg at a temperature from about -250 to about -80 degrees Celsius.
  • gaseous compounds are organic compounds from about 1 to about 4 carbon atoms.
  • Non limiting examples of such organic compounds are methane, ethane, propane, n-butane, isobutane, ethylene, propylene, and 1 -butene.
  • Natural gas is an example of a gaseous hydrocarbon.
  • “natural gas” is a naturally occurring mixture, or natural mixture, consisting mainly of methane, a compound with one carbon atom and four hydrogen atoms, small amounts of other hydrocarbon gas liquids and nonhydrocarbon gases.
  • the other hydrocarbon gas liquids commonly include varying amounts of hydrocarbons having two or more carbon atoms varying number of hydrogen atoms.
  • the nonhydrocarbon gas generally include small (wt, volume and mole) percentages of carbon
  • Natural gas is formed when layers of decomposing plant and animal matter are exposed to intense heat and pressure under the surface of the Earth over millions of years. The energy that the plants originally obtained from the sun is stored in the form of chemical bonds in the gas.
  • shale refers to a fine-grained sedimentary rock that forms from the compaction of silt and day-size mineral particles that is commonly called “mud.” This composition places shale in a category of sedimentary rocks known as “mudstones.” Shale is distinguished from other mudstones because it is fissile and laminated. “Laminated” means that the rock is made up of many thin layers. “Fissile” means that the rock readily splits into thin pieces along the laminations.
  • the phrase from about 2 to about 4 includes the whole number and/or integer ranges from about 2 to about 3, from about 3 to about 4 and each possible range based on real (e.g., irrational and/or rational) numbers, such as from about 2.1 to about 4.9, from about 2.1 to about 3.4, and so on.
  • Figure 1 depicts a cross-section of a hydrocarbon-containing reservoir with the fluids omitted according to some embodiments of present disclosure
  • Figure 2 depicts a cross-section of a hydrocarbon-containing reservoir containing fluids according to some embodiments of the present disclosure
  • Figure 3 depicts a cross-section of a hydrocarbon-containing reservoir containing fluids according to some embodiments of the present disclosure
  • Figure 4 depicts a process according to some embodiments of the present disclosure.
  • Figure 5 depicts a cross-section of a hydrocarbon-containing reservoir containing fluids according to some embodiments of the present disclosure.
  • Figure 1 depicts a cross-section of a hydrocarbon-containing reservoir 100 with the fluids omitted.
  • the reservoir comprises a plurality of pore volumes 120 defined by reservoir mineral material 110.
  • the hydrocarbon-containing reservoir can compose one or both of petroleum and gas.
  • the hydrocarbon-containing reservoir comprises predominantly natural gas as the hydrocarbon or, stated differently, has natural gas as the primary valuable hydrocarbon to be recovered.
  • the hydrocarbon content of the hydrocarbon-containing reservoir can be more than about mole 50% gas-phase hydrocarbons, more typically at least about 55 mole% gas-phase hydrocarbons, more typically at least about mole 60% gas-phase hydrocarbons, more typically at least about 65 mole% gas-phase hydrocarbons, more typically at least about 70 mole% gas-phase hydrocarbons, more typically at least about mole 75% gas-phase hydrocarbons, more typically at least about 85 mole% gas-phase hydrocarbons, more typically at least about mole 90% gas-phase hydrocarbons, more typically at least about 95 mole% gas-phase hydrocarbons, and even more typically at least about 99 mole% gas-phase hydrocarbons.
  • the hydrocarbon-containing reservoir can commonly have a carbon content of more than about 50 mole% of the carbon comprising methane and ot her hydrocarbon gas liquids, more commonly more than about 55 mole% of the carbon comprising methane and other hydrocarbon gas liquids, even more commonly more than about 60 mole% of the carbon comprising methane and other hydrocarbon gas liquids, yet even more commonly more than about 65 mole% of the carbon comprising methane and other hydrocarbon gas liquids, still yet even more commonly more than about 70 mole% of the carbon comprising methane and other hydrocarbon gas liquids, still yet even more commonly more than about 75 mole% of the carbon comprising methane and other hydrocarbon gas liquids, still yet even more commonly more than about 80 mole% of the carbon comprising methane and other hydrocarbon gas liquids, still yet even more commonly more than about 85 mole% of the carbon comprising methane and other hydrocarbon gas liquids, still yet even more commonly more than about 90 mole% of the carbon comprising methan
  • the hydrocarbon production from a well bore to be treated by the teachings of the present disclosure is predominantly natural gas.
  • the hydrocarbon content of the produced hydrocarbons can be more than about 50 mole% gas-phase hydrocarbons, more typically at least about 55 mole% gas- phase hydrocarbons, more typically at least about mole 60% gas-phase hydrocarbons, more typically at least about 65 mole% gas-phase hydrocarbons, more typically at least about 70 mole% gas-phase hydrocarbons, more typically at least about mole 75% gas- phase hydrocarbons, more typically at least about 85 mole% gas-phase hydrocarbons, more typically at least about mole 90% gas-phase hydrocarbons, more typically at least about 95 mole% gas-phase hydrocarbons, and even more typically at least about 99 mole% gas-phase hydrocarbons.
  • the produced hydrocarbon can commonly have a carbon content of more than about 50 mole% of the carbon comprising methane and other hydrocarbon gas liquids, rnore commonly more than about 55 mole% of the carbon comprising methane and other hydrocarbon gas liquids, even more commonly more than about 60 mole% of the carbon comprising methane and other hydrocarbon gas liquids, yet even more commonly more than about 65 mole% of the carbon comprising methane and other hydrocarbon gas liquids, still yet even more commonly more than about 70 mole% of the carbon comprising methane and other hydrocarbon gas liquids, still yet even more commonly more than about 75 mole% of the carbon comprising methane and other hydrocarbon gas liquids, still yet even more commonly more than about 80 mole% of the carbon comprising methane and other hydrocarbon gas liquids, still yet even more commonly more than about 85 mole% of the carbon
  • Shale gas refers to natural gas that is trapped substantially within a
  • shale formation Conventional gas reservoirs are created when natural gas migrates toward the Earth's surface from an organic-rich source formation into highly permeable reservoir rock, where it is trapped by an overlying layer of impermeable rock. In contrast, shale gas resources form within the organic-rich shale source rock. The low permeability of the shale greatly inhibits the gas from migrating to more permeable reservoir rocks. Without horizontal drilling and hydraulic fracturing, shale gas production would not be economically feasible because the natural gas would not flow front the formation at high enough rates to justify the cost of drilling.
  • a hydrocarbon-containing reservoir is generally considered to be one of water wet or hydrocarbon wet. More generally, a hydrocarbon-containing reservoir is water wet. In a water wet reservoir, water typically coats at least most, if not substantially all the surfaces comprising the pores. More typically, water coats at least about 50%, if not substantially about 100% of the pores surfaces comprising the water wet reservoir. The water is generally held in place by surface tension. As such, water coating the surface of the pores typically does not move while the hydrocarbon is being produced. It can be appreciated, that the production of the hydrocarbon can change the water saturation of the
  • the degree of change of the water saturation generally varies with the method of production of the hydrocarbon.
  • a hydrocarbon-containing reservoir generally comprises pores and one or more of a mean, mode and average pore volume, commonly referred to herein as reservoir pore volume. Moreover, the hydrocarbon-containing reservoir commonly has a porosity and permeability. Each pore generally contains a fluid. More generally, each pore contains one of water, hydrocarbon, or mixture thereof. Saturation of any fluid in a pore space is the ratio of the volume of the fluid to pore space volume. That is, the degree of water saturation of the hydrocarbon-containing reservoir generally expressed as the ratio of water volume to pore volume.
  • a water saturation of 25% corresponds to one- quarter of pore space being filled with water and the remaining 75% of the pore being with another fluid, such as a hydrocarbon liquid, hydrocarbon gas, or with a fluid other than water or hydrocarbon, such as carbon dioxide, nitrogen, or such.
  • the other fluid can be a provided hydrogen, that is a hydrocarbon gas introduced into the hydrocarbon-containing reservoir by injection through the wellhead.
  • Hydrocarbon saturation is commonly expressed as ratio of hydrocarbon volume to pore volume, or more commonly as one minus the water saturation.
  • the degree of water saturation can be calculated from the effective porosity and the resistivity logs.
  • water contained within a pore can be one of moveable water and substantially immoveable water.
  • the substantially immoveable water comprises the water the wetting the surfaces of the pore volume.
  • the wetted water is generally a film of water covering each pore surface.
  • hydrocarbon-containing reservoir is generally not withdrawn during production of the reservoir.
  • Moveable water is the contained with the pore that is not wetting the surfaces of the pore volume. Moreover, the moveable water generally moves from one pore to another during production of the reservoir. As such, the moveable water can be in some instances produced during hydrocarbon production of the reservoir.
  • the hydrocarbon-containing reservoir can have some degree of water saturation within reservoir pore network.
  • the injection gas can comprise natural gas, nitrogen or in some cases air.
  • hydrocarbon-containing reservoir is composed of high volumes of water, the hydrocarbons are generally disconnected and/or discontinuously distributed through the reservoir.
  • the hydrocarbons commonly exist in the reservoir as one or more of hydrocarbon pockets or bubbles.
  • the hydrocarbons are usually stranded in one or more pores and cracks within the reservoir.
  • water generally surrounds the one or more hydrocarbon pockets and bubbles.
  • hydrocarbons and water are produced together.
  • the mechanism of the co- production of the hydrocarbons and water is believed to work due to one or both water production carrying the hydrocarbons along with the water and production of water lowering the reservoir pressure causing hydrocarbons, particularly gaseous hydrocarbons, to expand to have one or more of pocket and/or bubbles coalesce to form a first continuous phase.
  • industry sees increasing gas to water volume to volume ratios under production of high volumes of water. This is due to the expansion behavior of gas compared to gas, hence the increase in the gas volume to water volume ratio over time as reservoir pressures drop.
  • Figure 2 depicts a cross-section of a hydrocarbon-containing reservoir 100 having a continuous hydrocarbon phase 135 and a plurality of discrete hydrocarbon phases 137.
  • the continuous hydrocarbon phase 135 can be one or more of in contact with and span about four or more pore volumes 120.
  • the discrete hydrocarbon phases 137 are generally dispersed in a continuous, moveable water phase 140.
  • the continuous, moveable water phase 140 can be one or more of in contact with and span about four or more pore volumes 120. It can be appreciated that the continuous hydrocarbon phase 135 and the continuous, moveable hydrocarbon phases 137 are one or more in contact with and span different four or more pore volumes 120. Production of such a reservoir typically produces substantially water and substantially little, if any, hydrocarbon.
  • Figure 3 depicts a cross-section of a hydrocarbon-containing reservoir 100 having a substantially depleted hydrocarbon continuous phase 138 and substantially comprising a plurality of discrete hydrocarbon phases 137.
  • the plurality of discrete hydrocarbon phases 137 are typically dispersed in water saturated hydrocarbon reservoir. More typically, production from a water saturated hydrocarbon reservoir containing a plurality of discrete hydrocarbon phases 137 comprises substantially moveable saturated water 140. Even more typically, production from reservoirs with high moveable water saturation values can comprise substantially more water than hydrocarbons.
  • the hydrocarbon-containing reservoir 100 can commonly have a moveable water saturate level of from one of about 2% or more, more commonly of about 5% or more, even more commonly of about 10% or more, yet even more commonly of about 20% or more, still yet even more commonly about 30% or more, still yet even more commonly about 40% or more, still yet even more commonly about 50% or more, still yet even more commonly about 50% or more, or yet even more commonly about 60% or more to generally one of no more than about 10%, more generally of no more than about 20%, even more generally of no more than about 30%, yet even more generally of no more than about 40%, still yet even more generally of no more than about 50%, still yet even more generally of no more than about 60%, still yet even more generally of no more than about 70%, still yet even more generally of no more than about 80%, still yet even more generally of no more than about 90%, still yet even more generally of no more than about 92%, still yet even more generally of no more than about 95%, or yet still even more generally of no more than about 98%.
  • the hydrocarbon-containing reservoir 100 can usually have a hydrocarbon saturate level of from one of about 2% or more, more usually of about 5% or more, even more usually of about 10% or more, yet even more usually of about 20% or more, still yet even more usually about 30% or more, still yet even more usually about 40% or more, still yet even more usually about 50% or more, still yet even more usually about 50% or more, or yet even more usually about 60% or more to commonly one of no more than about 10%, more commonly of no more than about 20%, even more commonly of no more than about 30%, yet even more commonly of no more than about 40%, still yet even more commonly of no more than about 50%, still yet even more commonly of no more than about 60%, still yet even more commonly of no more than about 70%, still yet even more commonly of no more than about 80%, still yet even more commonly of no more than about 90%, still yet even more commonly of no more than about 92%, still yet even more commonly of no more than about 95%, or yet still even more commonly of no more than about 98%.
  • the hydrocarbon-containing reservoirs having a hydrocarbon saturation value of one of between about 2%, more typically about 5%, even more typically about 10%, yet even more typically about 15%, still yet even more typically about 20%, still yet even more typically about 25%, still yet even more typically about 30%, still yet even more typically about 35%, still yet even more typically about 40%, still yet even more typically about 45%, still yet even more typically about 50%, still yet even more typically about 55%, still yet or yet still even more typically about 60% and one of generally about 15%, more generally about 20%, even more generally about 25%, yet even more generally about 30%, still yet even more generally about 35%, still yet even more typically about 40%, still yet even more generally about 45%, still yet even more generally about 50%, still yet even more generally about 55%, still yet even more generally about 60%, still yet even more generally about 65%, still yet even more generally about 70%, still yet even more generally about 75%, still yet even more generally about 80%, still yet even more generally about 85%, still yet even more generally about 90%, still yet even more generally about
  • Figure 4 depicts process 150 for treating a hydrocarbon-containing reservoir having a high moveable water saturation and a plurality of discrete hydrocarbon phases 137.
  • the plurality of discrete hydrocarbon phases 137 comprise short-chain hydrocarbons.
  • the short-chain hydrocarbons can be without limitation straight or branched chain hydrocarbons having from about one to about six carbon atoms, more commonly from about one to about four carbon atoms, even more commonly from about one to about three carbon atoms, yet even more commonly from about one to about two carbon atoms, or still yet even more commonly about one carbon atom.
  • the short-chain hydrocarbons can be gaseous hydrocarbons.
  • Step 151 of process 150 can comprise providing and/or identifying a target well.
  • the target well generally traverses a hydrocarbon-containing reservoir having a high moveable water saturation and a plurality of discrete hydrocarbon phases 137.
  • the target well can have a water to a gaseous hydrocarbon ratio.
  • the target well typically can have a first water to gaseous hydrocarbon ratio.
  • the first water to gaseous hydrocarbon ratio is generally one of its historical water to gaseous hydrocarbon production ratio or its original water to gaseous hydro-carbon ratio when it was originally put into production.
  • the first water to gaseous hydrocarbon ratio of the target well is one of about from about 10 3 to about 10 3 , more commonly from about 10 2 to about 10 3 , even more commonly about 10 3 to about 10 2 , yet even more commonly about 10 2 to about 10 2 , still yet even more commonly about 10 1 to about 10 2 , still yet even more commonly about 10 2 to about 10 1 , or yet still even more commonly about 10 1 to about 10 1 .
  • the first water to gaseous hydrocarbon ratio is generally one of its historical water to gaseous hydrocarbon production ratio or its original water to gaseous hydrocarbon ratio when it was originally put into production.
  • the first water to gaseous hydrocarbon ratio of the target well is from one of about 1 bbl water per 1000 MCF gaseous hydrocarbon, more commonly of about 10 bbl water per 1000 MCF, even more commonly of about 20 bbl of water per 1000 MCF, yet even more commonly of about 50 bbl water per 1000 MCF, still yet even more commonly of about 100 bbl of water per 1000 MCF, still yet even more commonly of about 200 bbl of water per 1000 MCF, still yet even more commonly of about 500 bbl of water per 1000 MCF, or yet still even more commonly of about 1000 bbl of water per 1000 MCF of gaseous hydrocarbon to one of typically about 2000 bbl water per 1000 MCF gaseous hydrocarbon, more typically of about 1750 bbl water per 1000 MCF,
  • the target well can be identified by one or more of its production and well log characteristics. For example, as described above, the target well produces substantially more water than hydrocarbons and has a well log indicating high levels of moveable water compared to hydrocarbon saturate levels as detailed above.
  • the process 150 can include a step of providing a gas.
  • the provided gas can be any gas.
  • the provided gas can be substantially a single chemical composition or a mixture of chemical compositions.
  • the provided gas can be an inorganic composition, an organic composition, a mixture of inorganic compositions, a mixture of organic compositions, or combinate of inorganic and organic compositions.
  • the provided gas can be an inert gas.
  • the provided gas can be nitrogen (N2).
  • the provided gas can be hydrogen (Fh).
  • the provided gas can be methane (CFU).
  • the provided gas can be ethane (CH3-CH3).
  • the provided gas can be propane (C3H8).
  • C3H8 propane
  • the provided gas can be butane (C4H10).
  • the provided gas can be carbon dioxide (CO2).
  • the provided gas can be one or more of nitrogen (N2), hydrogen (Fh), methane (CFF), ethane (CH3-CH3), propane (C3H8), butane (C4H10), carbon dioxide (CO2), and inert gas.
  • the provided gas can be in some embodiments air, oxygen, nitrogen, an inert gas, carbon dioxide, methane, ethane, propane, iso-propane, butane, isobutane, t- butane, pentane, iso-pentane, t-pentane, or a mixture thereof.
  • the provided gas can be provided by a commercial source, a subterranean source, an atmospheric source, or a combination thereof.
  • an injection gas (such as, but not limited to methane or methane and an associated hydrocarbon) can be injected into a hydrocarbon-containing reservoir.
  • the provided gas can be injected into the target well.
  • the target well can traverse a subterranean hydrocarbon-containing reservoir 100.
  • the provided gas can be injected into the subterranean hydrocarbon-containing reservoir 100.
  • the injection step 153 can include the provided gas being in the gas phase during the injection of the gas into the well bore.
  • the injection step 153 can include the provided gas being in the liquid phase when being injected into the well bore.
  • the injection step 153 can include the provided gas being in the form of a foam when being injected into the well bore.
  • the injection step 153 can include the provided gas being in the form of one or more of gas phase, liquid phase, foam, or combination thereof when being injected into the well bore.
  • the foam can be more gas by volume than liquid by volume. Moreover, in some embodiments the foam can have no more than about 50 volume% liquid.
  • the foam can have less gas by volume than liquid by volume.
  • the subterranean hydrocarbon-containing reservoir 100 generally comprises a reservoir having a high moveable water saturation and a plurality of discreet hydrocarbon phases 137 for a period.
  • the provided gas can be injected into the subterranean hydrocarbon-containing reservoir 100 at a rate of from one of about 10 mcfd or more, more typically at a rate of about 20 mcfd or more, even more typically at a rate of about 30 mcfd or more, yet even more typically at a rate of about 40 mcfd or more, still yet even more typically at a rate of about 50 mcfd or more, still yet even more typically at a rate of about 60 mcfd or more, still yet even more typically at a rate of about 70 mcfd or more, still yet even more typically at a rate of about 80 mcfd or more, still yet even more typically at a rate of about 90 mcfd or more, still yet even more typically at a rate of about 100 mcfd or
  • the provided gas is usually injected at a pressure below the reservoir fracture gradient pressure. Injection period will be for about three months, more typically between three months and three years. In some embodiments, the injection period is more than about 5 days but less than about three months. In some embodiments, the injection period is selected from the group of about 5 days, about 10 days, about 15 days, about 30 days, about 45 days, about 60 days, about 75 days, about 90, or any combination thereof. In some embodiments, the provided gas can be injected for a period of about one day.
  • the provided gas can be injected one of for a period of time of more than about one day but less than about one week, even more commonly for a period of time of more than about one week but less than about one month, yet even more commonly for a period of time of more than about one month but less than about three months, still yet even more commonly for a period of time of more than two months but less than about 6 months, still yet even more commonly for a period of time of more than three months but less than about one year, still yet even more commonly for a period of more than about 6 months but less than about 18 months, still yet even more commonly for a period of time more than about 18 months but less than about 24 months, still yet even more commonly for a period of more than aboutl8 months but less than 36 months, still yet even more commonly for a period of time of more than about two years but less than about four years, or yet still even more commonly for a period of more than about three years but less than about 10 years.
  • the injection of the provided gas into the hydrocarbon-containing reservoir can coalesce one or more of the plurality of discrete hydrocarbon phases 137 in the reservoir to form one or more continuous hydrocarbon phases 161, see Figure 5. It can be appreciated that as the injection of the provided gas in step 153 is maintained, the one or more the plurality of discrete hydrocarbon phases 137 can continue to coalesce.
  • the plurality of discrete hydrocarbon phases 137 can be in the form one or more of pockets and bubbles of hydrocarbons. Moreover, these one or more pockets and bubbles of hydrocarbons can continue coalesce to form the continuous hydrocarbon phases 161 of hydrocarbons.
  • the continuous hydrocarbon phases 161 can comprise one or more of hydrocarbon gas and petroleum. While not wanting to be limited by theory, it is believed that once a more continuous hydrocarbon phase 161 is formed within the reservoir, the hydrocarbons along with the provided gas can flow toward the well bore.
  • Injection of the provided gas into the reservoir in step 153, can imbibe the injected gas into the pore volumes 120.
  • the pore volumes comprise a network of pores within the reservoir.
  • the network of pores within the reservoir have a porosity and permeability.
  • porosity generally relates to void spaces in the subterranean hydrocarbon-containing reservoir 100 that can hold fluids.
  • permeability generally relates to a characteristic of the subterranean hydrocarbon- containing reservoir 100 that fluid to through the rock.
  • permeability is generally a measure of the interconnectivity of the void spaces (porosity) and their size.
  • the provided gas (and other hydrocarbons that can be contained within the provided gas) can imbibe the hydrocarbon-containing reservoir. Moreover, the provided gas (and other hydrocarbons) can coalesce with the hydrocarbons contained in the hydrocarbon-containing reservoir to form a one or more continuous hydrocarbon phases 161 within the reservoir.
  • the one or more continuous hydrocarbon phases 161 commonly span two or more pore volumes 120 defined by the reservoir materials 110, more commonly three or more pore volumes 120, or even more commonly four or more pore volumes 120. This is generally in contrast to the each of the plurality of discrete hydrocarbon phases 137 which typically occupy a single pore volume 120. It can be appreciated that one or more continuous hydrocarbon phases 161 comprise the provided gas and the hydrocarbon(s) comprising the plurality of discrete hydrocarbon phases 137.
  • the injection of the provided gas can increase the degree of hydrocarbon saturation of the hydrocarbon-containing reservoir. Moreover, the injection of the provided gas into the reservoir generally decreases the degree of water saturation of hydrocarbon-containing reservoir.
  • the target well can be logged in step 154.
  • the target well is not logged but put into production, step 155, after a targeted volume of the provided gas has been injected.
  • production step 155 comprises reversing flow of the target well. That is, the injection step 153 is ceased and the flow of gas is reversed from injecting to producing.
  • the production step 155 generally includes gathering from the subterranean hydrocarbon- containing reservoir 100 the injected provided gas and the hydrocarbons contained within the hydrocarbon-containing reservoir. Management of the production step 155 generally depends on reservoir rock properties and conditions. It can be appreciated that the flow of the hydrocarbons towards the well bore resumes producing operations of the target well.
  • the well log indicates that the level moveable water saturation has decreased commonly by an amount of one of about 10%, more commonly by about 20%, even more commonly by about 30%, yet even more commonly by about 40%, still yet more commonly by about 50%, still yet more commonly by about 60%, still yet more commonly by about 70%, still yet more commonly by about 80%, still yet more commonly by about 90% or yet still more commonly by about 95% or more, the well can be put into production, step 155.
  • the well log can indicate the level of moveable water saturation has decreased by generally by amount from about one of about 5% or more, more generally of about 10% or more, even more generally of about 15% or more, yet even more generally of about 20% or more, still yet even more generally about 25% or more, still yet even more generally about 30% or more, still yet even more generally about 40% or more, still yet even more generally about 50% or more, or yet even more generally about 60% or more to typically one of no more than about 10%, more typically of no more than about 20%, even more typically of no more than about 30%, yet even more typically of no more than about 40%, still yet even more typically of no more than about 50%, still yet even more typically of no more than about 60%, still yet even more typically of no more than about 70%, still yet even more typically of no more than about 80%, still yet even more typically of no more than about 90%, still yet even more typically of no more than about 92%, still yet even more typically of no more than about 95%, or yet still even more typically of no more than about 98%.
  • hydrocarbons such as, not limited to gaseous hydrocarbons. More generally, it is believed that the decrease in moveable water saturation can increase the production of gaseous hydrocarbons, such as, but not limited to gaseous hydrocarbons commonly comprising from one of from one to four carbon atoms, more commonly from about one to about three carbon atoms, even more commonly from about one to about two carbon atoms, or yet even more commonly substantially comprising hydrocarbons substantially comprising methane.
  • the well long indicates that the level hydrocarbon saturation has increased generally by an amount, compared to its initial hydrocarbon saturation level prior to the injection of the provided gas, of one of about 10%, more generally by about 20%, even more generally by about 30%, yet even more general by about 40%, still yet even more generally by about 50%, still yet even more generally by about 60%, still yet even more generally by about 70%, still yet even more generally by about 80%, still yet even more generally by about 90%, still yet even more generally by about 100%, still yet even more generally by about 110%, still yet even more generally by about 125%, or yet still even more generally by about 130% or more.
  • the well long indicates that the level hydrocarbon saturation has increased typically by an amount, compared to its initial hydrocarbon saturation level prior to the injection of the provided gas, from one of about 5%, more typically 10%, even more typically about 15%, yet even more typically about 20%, still yet even more typically about 25%, still yet even more typically about 30%, still yet even more typically about 35%, still yet even more typically about 40%, still yet even more typically about 45%, still yet even more typically about 50%, still yet even more typically about 55%, still yet even more typically about 55%, still yet even more typically about 65%, still yet even more typically about 65%, still yet even more typically about 70%, still yet even more typically about 75%, still yet even more typically about 80%, still yet even more typically about 85%, still yet even more typically about 90%, still yet even more typically about 100%, still yet even more typically about 125%, still yet even more typically about 150%, still yet even more typically about 175%, or yet still even more typically about 200% to one of generally about 10%, even more generally about 20%, yet even more generally about
  • the well can be put into production, step 155.
  • the target well after the injection of provided gas, generally can have a second water to gaseous hydrocarbon ratio.
  • the second water to gaseous hydrocarbon ratio is generally less than the first water to gaseous hydrocarbon ratio.
  • the second water to gaseous hydrocarbon ratio is typically from about one of no more than about 98% of the first water to gaseous hydrocarbon ratio, more typically no more than about 95%, even more typically no more than about 90%, yet even more typically no more than about 85%, still yet even more typically no more than about 80%, still yet even more typically no more than about 75%, still yet even more typically no more than about 60%, still yet even more typically no more than about 55%, still yet even more typically no more than about 50%, still yet even more typically no more than about 45%, or yet still even more typically no more than about 40% of the first water to gaseous hydrocarbon ratio to one of commonly about 2% or more of the first water to gaseous hydrocarbon ratio, more commonly about 5% or more, even more
  • the increase in hydrocarbon saturation can increase the production of hydrocarbons, such as, not limited to gaseous hydrocarbons. More commonly, it is believed that the increase in hydrocarbon saturation can increase the production of gaseous hydrocarbons, such as, but not limited to gaseous hydrocarbons generally comprising from one of from one to four carbon atoms, more generally from about one to about three carbon atoms, even more generally from about one to about two carbon atoms, or yet even more generally substantially comprising hydrocarbons substantially comprising methane.
  • the injection of the provided gas in step 153 can be continued or the process 150 can be ceased.
  • Hydrocarbon production can be continued until one or more of the following is true: (a) the well ceases to produce any more hydrocarbons; (b) the level of water production becomes unsatisfactory; and (c) the hydrocarbon-containing reservoir becomes water saturated again.
  • process 150 can be ceased, step 156.
  • the provided gas injection step 153 can be reinitiated.
  • the well can be logged again to determine one or more of the moveable water and hydrocarbon saturation levels. If the hydrocarbon saturation level indicates sufficient hydrocarbons are available for recovery, the provided gas injection step can be reinitiated.
  • the injection of the provided gas into the hydrocarbon-containing reservoir to coalesce one or more of the plurality of discrete hydrocarbon phases 137 in the reservoir to form one or more continuous hydrocarbon phases 161 differs from the injection of carbon dioxide or other similar gas to lower the viscosity of entrained hydrocarbons.
  • the injection of the provided gas and coalesce of the one or more of the plurality of discrete hydrocarbon phases 137 is not believed to be due to change in viscosity of the discrete hydrocarbon phases 157. What, if any change, in the viscosity of the injected provided gas, the discreet hydrocarbon phases 157 and the one or more continuous hydrocarbon phases 161 are believe negligible.
  • the present disclosure in various aspects, embodiments, and configurations, includes components, methods, processes, systems and/or apparatus substantially as depicted and described herein, including various aspects, embodiments, configurations, sub-combinations, and subsets thereof. Those of skill in the art will understand how to make and use the various aspects, aspects, embodiments, and configurations, after understanding the present disclosure.
  • the present disclosure in various aspects, embodiments, and configurations, includes providing devices and processes in the absence of items not depicted and/or described herein or in various aspects, embodiments, and configurations hereof, including in the absence of such items as may have been used in previous devices or processes, e.g., for improving performance, achieving ease and/or reducing cost of implementation.

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Abstract

La présente invention concerne un procédé de récupération de pétrole et de gaz à partir d'un réservoir contenant des hydrocarbures ayant généralement un certain degré de saturation en eau à l'intérieur du réseau de pores du réservoir par injection d'un gaz dans le réservoir. Le procédé peut être appliqué à des réservoirs ayant une saturation en eau élevée d'environ 50 pour cent ou plus. Une saturation élevée en eau dans un réservoir peut provoquer la production de quantités excessives d'eau pour produire des hydrocarbures. La co-production et la gestion de cette eau sont coûteuses et lourdes pour les exploitations, laissant de nombreux réservoirs de pétrole et de gaz abandonnés, amenant ainsi à une production non économique. Le procédé décrit ici répond à ce besoin et à d'autres besoins. Le gaz d'injection (avec ou sans autres hydrocarbures) peut coalescer avec les hydrocarbures contenus dans le réservoir contenant des hydrocarbures pour former une phase continue d'hydrocarbures à l'intérieur du réservoir. Une fois que le volume cible du gaz d'injection est injecté, l'écoulement est inversé, ce qui produit les hydrocarbures collectés.
PCT/US2018/055673 2018-02-28 2018-10-12 Procédé permettant de former une phase gazeuse dans des réservoirs d'hydrocarbures saturés en eau WO2019168568A1 (fr)

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US15/908,099 US20180187534A1 (en) 2016-04-27 2018-02-28 Method for forming a gas phase in water saturated hydrocarbon reservoirs

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Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20120175110A1 (en) * 2005-01-13 2012-07-12 Larry Weiers In situ combustion in gas over bitumen formations
WO2013013721A1 (fr) * 2011-07-28 2013-01-31 Statoil Petroleum As Procédés de récupération pour réservoirs de gaz d'hydrocarbures
US20170314378A1 (en) * 2016-04-27 2017-11-02 Highlands Natural Resources, Plc Method for forming a gas phase in water saturated hydrocarbon reservoirs

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20120175110A1 (en) * 2005-01-13 2012-07-12 Larry Weiers In situ combustion in gas over bitumen formations
WO2013013721A1 (fr) * 2011-07-28 2013-01-31 Statoil Petroleum As Procédés de récupération pour réservoirs de gaz d'hydrocarbures
US20170314378A1 (en) * 2016-04-27 2017-11-02 Highlands Natural Resources, Plc Method for forming a gas phase in water saturated hydrocarbon reservoirs

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