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US20060081374A1 - Process for downhole heating - Google Patents

Process for downhole heating Download PDF

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Publication number
US20060081374A1
US20060081374A1 US11/237,074 US23707405A US2006081374A1 US 20060081374 A1 US20060081374 A1 US 20060081374A1 US 23707405 A US23707405 A US 23707405A US 2006081374 A1 US2006081374 A1 US 2006081374A1
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US
United States
Prior art keywords
exothermic
location
chemical
group
hydration
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
Application number
US11/237,074
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English (en)
Inventor
Ronald Bland
David Young
Marvin Pless
John Trenery
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Baker Hughes Holdings LLC
Original Assignee
Baker Hughes Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Baker Hughes Inc filed Critical Baker Hughes Inc
Priority to US11/237,074 priority Critical patent/US20060081374A1/en
Priority to PCT/US2005/034910 priority patent/WO2006039362A2/fr
Assigned to BAKER HUGHES INCORPORATED reassignment BAKER HUGHES INCORPORATED ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: TRENERY, JOHN B., BLAND, RONALD G., PLESS, MARVIN L., YOUNG, DAVID B.
Publication of US20060081374A1 publication Critical patent/US20060081374A1/en
Abandoned legal-status Critical Current

Links

Classifications

    • 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
    • E21B36/00—Heating, cooling or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones
    • E21B36/008—Heating, cooling or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones using chemical heat generating means
    • 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
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection

Definitions

  • the present invention relates to methods and compositions for providing controlled downhole heating, such as in a subterranean reservoir during a hydrocarbon recovery operation.
  • Drilling fluids used in the drilling of subterranean oil and gas wells along with other drilling fluid applications and drilling procedures are known.
  • drilling fluids also known as drilling muds, or simply “muds”.
  • the drilling fluid is expected to carry cuttings up from beneath the bit, transport them up the annulus, and allow their separation at the surface while at the same time the rotary bit is cooled and cleaned.
  • a drilling mud is also intended to reduce friction between the drill string and the sides of the hole while maintaining the stability of uncased sections of the borehole.
  • the drilling fluid is formulated to prevent unwanted influxes of formation fluids from permeable rocks penetrated and also often to form a thin, low permeability filter cake which temporarily seals pores, other openings and formations penetrated by the bit.
  • the drilling fluid may also be used to collect and interpret information available from drill cuttings, cores and electrical logs. It will be appreciated that within the scope of the claimed invention herein, the term “drilling fluid” also encompasses “drill-in fluids” and “completion fluids”.
  • Drilling fluids are typically classified according to their base fluid.
  • water-based muds solid particles are suspended in water or brine. Oil can be emulsified in the water. Nonetheless, the water is the continuous phase.
  • Oil-based muds are the opposite or inverse. Solid particles are suspended in oil, and water or brine is emulsified in the oil and therefore the oil is the continuous phase.
  • Oil-based muds that are water-in-oil emulsions are also called invert emulsions.
  • Brine-based drilling fluids of course are a water-based mud in which the aqueous component is brine.
  • bitumen or “tar” beds are encountered. These beds are commonly found during sub-salt drilling in the Gulf of Mexico, but also at other locations. Indeed, the bitumen occurs so frequently in the Gulf of Mexico formations that it has been likened to a “river” of tar. Drilling through thin bitumen beds is generally no more than a minor nuisance, but thick beds can result in stuck pipe, stuck casing, side-tracks, loss of hole and other problems that can cost the well operators millions of dollars.
  • One of the most precarious operations is running casing after drilling through a bitumen bed due to the movement or “flow” of the bitumen into the borehole before casing can be picked up and run to bottom.
  • Oil sands are a mixture of grit and bitumen.
  • the deposits are generally either minded in massive open pits, or if too deep for surface mining, are injected with steam to coax the viscous bitumen to flow into wells.
  • Gas hydrates are solid inclusion compounds resembling ice. Gas hydrates occur when water molecules form a cage-like structure around smaller “guest molecules”. The most common guest molecules are methane, ethane, propane, isobutene, n-butane, nitrogen, carbon dioxide and hydrogen sulfide, of which methane occurs most abundantly in naturally-occurring hydrates. In nature, one cubic meter of hydrate may contain up to about 164 m 3 of methane. Gas hydrates occur wherever the conditions within the sediments are in a methane-hydrate stability region and where methane and water are available.
  • gas hydrates are stable at low temperatures and/or high pressure. Because of the requirements of pressure and temperature, and because of the requirement of relatively large amounts of organic matter of bacterial methanogenesis, gas hydrates are primarily restricted to two regions: high latitudes and along the continental margins in oceans. In polar regions, the gas hydrates are commonly linked to permafrost occurrence onshore and on the continental shelves. In the oceans, gas hydrates are found in outer continental margins, where the supply of organic material is high enough to generate enough methane, and with water temperatures close to freezing. These solid crystals, upon melting, can release up to 170 scf of natural gas per cubic foot of hydrate.
  • the oceanic gas hydrate reservoir has been estimated to be about 10,000 to 11,000 GtC (Gigatons carbon).
  • GtC Gigatons carbon
  • the permafrost reservoir has been estimated at about 400 GtC, but no estimates have been made of possible Antarctic reservoirs. Given the amount of hydrocarbons bound in gas hydrates, many are exploring the possibility of recovering hydrocarbons from this source.
  • compositions and methods could be devised to provide localized heating to soften the bitumen to help facilitate movement of the casing or liner through the bitumen to the bottom. It would also be desirable if compositions and methods could be devised to provide controlled localized heating to melt in-situ gas hydrates in order to produce the large quantities of natural gas they contain. Further, it would be helpful to facilitate controlled localized heating of oil sands to improve recovery of hydrocarbons from that source.
  • a method for providing localized heating in a subterranean formation that involves placing at a location in the subterranean formation in any order: an exothermic hydration chemical and an amount of water in contact with the exothermic hydration chemical effective to cause an exothermic reaction thereby heating the location and a suitable medium for transporting the heat source to the desired location.
  • a method for providing localized heating in a subterranean formation involves placing at a location in the subterranean formation where bitumen is present in any order: an exothermic hydration chemical and an effective amount of water in contact with the exothermic hydration chemical to cause an exothermic reaction without generating an appreciable amount of gas; and heating the location sufficiently to at least soften the bitumen.
  • a method for providing localized heating in a subterranean formation involves placing at a location in the subterranean formation containing gas hydrates an exothermic hydration chemical, and reacting at least a portion of the water in the gas hydrates with the exothermic hydration chemical to cause an exothermic reaction to release at least a portion of hydrocarbons bound in the hydrates.
  • an appreciable amount of gas may or may not be released and water may or may not be added to the formation.
  • a method has been discovered to generate localized heat remotely downhole using heat of hydration as a heat source. It has been estimated in one non-limiting embodiment, if the bitumen in the “river of tar” beneath the Gulf of Mexico is heated to about 220 to about 230° F. (about 104 to about 110° C.), the material would be 10 times less viscous. Most exothermic oxidation/combustion reactions require temperatures that would compromise mud/spot stability, if not tubular integrity, would tend to be difficult to initiate and would be problematic to formulate as a liquid or mud for downhole use. Initiating the reaction at the surface would tend to expend and dissipate most of the heat before placement in the target or the mud for downhole use.
  • Hydration of acidic electrolytes such as aluminum chloride, AlCl 3
  • acids would be expected to be corrosive and at high temperatures could compromise the integrity of the tubular goods, tools and other equipment in many circumstances.
  • hydration of aluminum chloride would produce a product environment of about pH 0.8, as contrasted with using NaOH, which would generally yield a product environment of about pH 14.
  • Oil field chemistries are generally and preferably alkaline at least in part to avoid or minimize corrosion concerns.
  • the process in one non-limiting embodiment uses a binary design where in one non-limiting embodiment the “fuel” is placed first as a slurry or suspension or fluid combined with an “initiator”, e.g. water that produces heat precisely at the point or location of interest.
  • an “initiator” e.g. water that produces heat precisely at the point or location of interest.
  • the binary components may be placed at the location in any order, in most embodiments it is expected that the “initiator” (e.g. water) would be placed last in sequence.
  • Heat of hydration is defined as the heat evolved (or absorbed) when a hydrate of a compound is formed.
  • the exothermic hydration chemical has a heat of hydration of at least 40 kJ/mol, and alternatively has a heat of hydration of at least 80 kJ/mol.
  • the exothermic hydration chemical should be a material that when combined with the initiator generates sufficient heat to soften, melt or flow the bitumen, but without generating an appreciable amount of gas.
  • Many exothermic reactions give large amounts of heat, but produce relatively large amounts of gas—a thermite reaction, for example. However, such an exothermic reaction downhole could cause a blowout of the well and is extremely undesirable.
  • an appreciable amount of gas is defined as an amount that would interfere with normal hydrocarbon recovery operations and does not include incidental or non-problematic amounts. It should be understood that avoiding the generation of an appreciable amount of gas does not mean that water vapor may not be evolved. It is acceptable in all embodiments herein for water vapor to be evolved or generated in the process of remote heating a location or formation.
  • tar or bitumen such as oil sands or subterranean bitumen layers
  • these environments are generally non-aqueous, that is, they do not contain appreciable amounts of water.
  • the water is delivered as part of the method to be a co-reactant with the exothermic hydration chemical.
  • the exothermic hydration chemical is used to generate heat in a subterranean gas hydrate formation (e.g. in a permafrost region on land or sub-ocean)
  • the generation of appreciable amounts of gas is acceptable—and in fact is desirable since it is expected to be the primary way in which hydrocarbons (e.g. methane) is released.
  • this embodiment uses a unitary design; it is contemplated that in most cases only the exothermic hydration chemical would be delivered or pumped to the gas hydrate formation or region since the hydrates themselves would provide the source of most of the water. Alternatively, additional water may be added as necessary or desired.
  • a goal of recovering hydrocarbons from gas hydrates is to either deliver heat (increase temperature) or reduce pressure, or both.
  • the temperature of the gas hydrates need only be raised 2 or 3° C. for the gas hydrate to decompose and the guest molecules released.
  • Factors to be considered in selecting the binary reactants include, but are not necessarily limited to the expected amount of heat output (for instance measured in kJ/mol), the cost, the acidity of the resulting products, the solubility of the “fuel” or exothermic hydration chemical, HS&E profile (Health, Safety & Environmental) and the like.
  • a suitable “fuel” or exothermic hydration chemical to react with water in a hydration reaction includes, but is not necessarily limited to, a relatively neutral electrolyte, a metal oxide, a metal hydroxide, and an organic compound.
  • relatively neutral electrolytes examples include, but are not necessarily limited to, halogen salts such as calcium chloride, magnesium chloride, lithium chloride, and lithium bromide and mixtures thereof and the like.
  • relatively neutral electrolytes include sulfate salts such as magnesium sulfate, calcium sulfate, and the like.
  • “Relatively neutral” refers to an electrolyte that is not strictly neutral, but which is sufficiently neutral for the purposes of the process described herein.
  • An example of a non-neutral electrolyte that could be considered is aluminum chloride, which could be useful under certain specialized situations.
  • metal oxides examples include, but are not necessarily limited to, calcium oxide, strontium oxide, barium oxide, and mixtures thereof and the like.
  • metal hydroxides include, but are not necessarily limited to, sodium hydroxide (NaOH), potassium hydroxide (KOH), lithium hydroxide (LiOH), cesium hydroxide (CsOH) and mixtures thereof and the like.
  • suitable organic compounds include, but are not necessarily limited to, peroxides, epoxides and monomers whose polymerization would generate heat such as acrylates, methacrylates and mixtures thereof and the like.
  • Slurry placement of the “fuel” or exothermic hydration chemical is anticipated where the “fuel” would settle out in the zone of interest to concentrate the fuel as much as possible in the desired location.
  • a stable slurry may be desirable or preferred in a method of delivery and/or placement at the desired location.
  • stable is meant that the slurry does not separate or settle upon standing for periods of time. In the case of the stable slurry, it would be pumped downhole to a location or against a structure and pack off like a packed bed. The more densely packed the bed, the more heat generated, and the more effective the process.
  • the slurry must consist of an organic base fluid and preferably one that has a low specific heat.
  • the fluid should also a high thermal conductivity in order to transfer the generated heat effectively.
  • fluid mediums include, but are not necessarily limited to, alcohols, glycols, alcohol/glycol blends, specifically designed heat transfer fluids, such as Dowtherm® fluids (available from Dow Chemical Company) and Therminol® fluids (available from Solutia Inc.), esters either natural such as vegetable oils and/or animal oils or synthetic esters such as 2-ethylhexyl esters of fatty acids and hydrocarbon oils either distillates or synthetic.
  • placement could involve encapsulating the fuel or exothermic hydration chemical, such as with a wax; a polymer wax or other polymer or material that melts or disintegrates or dissociates at the location.
  • the encapsulating material or carrier should not prematurely react with the exothermic hydration chemical or fuel.
  • suitable polymeric materials include, but are not necessarily limited to, hydrocarbon waxes such as paraffin waxes and microcrystalline waxes, vegetable or animal waxes, solid relatively weak acids such as tallow or hydrogenated tallow fatty acid, polybutylene, polymethacrylates, polyethylene glycol (PEG), methoxylated PEG, polyethylene oxide (PEO), polyethylene waxes, polypropylene glycol (PPG), and the like.
  • suitable encapsulating material includes ionomeric waxes, including, but not necessarily limited to, PEG (e.g. CARBOWAX available from Union Carbide Corporation, Danbury, Conn.), alkoxy terminated PEG (e.g.
  • PEG methoxylated PEG or mPEG
  • PEO polypropylene oxide
  • PPO polypropylene oxide
  • the encapsulation may be extended to PEG/PPG, PEG/PEO, and mPEG/PEG blends of different molecular weights. Polymerization of these polymer shells is well known in the art.
  • Other extended release forms include, but are not necessarily limited to, pelletization with binder compounds, absorbed or some other method of layering on a small particle or porous substrate, and/or a combination thereof.
  • the fuel or exothermic hydration chemical may be encapsulated to permit slow or timed release thereof.
  • the coating material may slowly dissolve or be removed by any conventional mechanism, or the coating could have very small holes or perforations therein for the exothermic hydration chemicals within to diffuse through slowly.
  • polymer encapsulation coatings such as used in fertilizer technology available from Scotts Company, specifically POLY-S® product coating technology, or polymer encapsulation coating technology from Fritz Industries could possibly be adapted to the methods herein.
  • the sources could also be absorbed onto zeolites, such as Zeolite A, Zeolite 13X, Zeolite DB-2 (available from PQ Corporation, Valley Forge, Pa.) or Zeolites Na-SKS5, Na-SKS6, Na-SKS7, Na-SKS9, Na-SKS10, and Na-SKS13, (available from Hoechst Aktiengesellschaft, now an affiliate of Aventis S.A.), and other porous solid substrates such as MICROSPONGETM (available from Advanced Polymer Systems, Redwood, Calif.) and cationic exchange materials such as bentonite clay or microscopic particles such as carbon nanotubes or buckminster fullerenes. Further, the component sources may be both absorbed into and onto porous substrates and then encapsulated or coated, as described above.
  • zeolites such as Zeolite A, Zeolite 13X, Zeolite DB-2 (available from PQ Corporation, Valley Forge, Pa.) or Zeolites Na-SKS5, Na-SKS
  • encapsulation includes, but is not necessarily limited to, microencapsulation.
  • one non-limiting example of the invention would be drilling out the bitumen inside of a stuck liner, spotting a caustic soda/“oil” or hydrocarbon slurry inside the liner opposite or adjacent to the bitumen zone, allowing the caustic soda beads/powder to settle, and slowly pumping an aqueous fluid to hydrate the caustic soda to generate localized heating.
  • compositions and methods described herein may be used to help recover hydrocarbons from oil sands.

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  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Working-Up Tar And Pitch (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
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US20080228543A1 (en) * 2007-03-16 2008-09-18 Peter Campbell Doe Methods and apparatus to compute reach and frequency values for flighted schedules
WO2009095476A1 (fr) * 2008-02-01 2009-08-06 Eurovia Utilisation d'un mélange exothermique pour la fabrication d'un enrobe bitumineux
US20090223678A1 (en) * 2008-03-05 2009-09-10 Baker Hughes Incorporated Heat Generator For Screen Deployment
US20110114323A1 (en) * 2009-11-18 2011-05-19 Baker Hughes Incorporated Heat Generation Process for Treating Oilfield Deposits
WO2012138402A1 (fr) * 2011-04-07 2012-10-11 Los Alamos National Security, Llc Initiateur de polymérisation encapsulé dans un métal élémentaire ou alliage fusible à faible point de fusion pour un amorçage retardé
WO2013130361A1 (fr) * 2012-02-28 2013-09-06 Baker Hughes Incorporated Génération de chaleur in situ
WO2016126351A1 (fr) * 2015-02-03 2016-08-11 Halliburton Energy Services, Inc. Procédé d'acidification de formations souterraines dans des opérations de puits
US20180320496A1 (en) * 2013-11-22 2018-11-08 Baker Hughes Incorporated Methods of extracting hydrocarbons from a subterranean formation, and methods of treating a hydrocarbon material within a subterranean formation
US20190024488A1 (en) * 2017-07-19 2019-01-24 Conocophillips Company Accelerated Interval Communication Using Openholes
US10370949B2 (en) 2015-09-23 2019-08-06 Conocophillips Company Thermal conditioning of fishbone well configurations
US10927627B2 (en) 2019-05-14 2021-02-23 DynaEnergetics Europe GmbH Single use setting tool for actuating a tool in a wellbore
US11008832B2 (en) * 2016-05-10 2021-05-18 Board Of Regents, The University Of Texas System Methods for increasing wellbore strength
US11204224B2 (en) 2019-05-29 2021-12-21 DynaEnergetics Europe GmbH Reverse burn power charge for a wellbore tool
US11255147B2 (en) 2019-05-14 2022-02-22 DynaEnergetics Europe GmbH Single use setting tool for actuating a tool in a wellbore
US11578549B2 (en) 2019-05-14 2023-02-14 DynaEnergetics Europe GmbH Single use setting tool for actuating a tool in a wellbore
US11753889B1 (en) 2022-07-13 2023-09-12 DynaEnergetics Europe GmbH Gas driven wireline release tool
US11808128B2 (en) * 2017-11-20 2023-11-07 Schlumberger Technology Corporation Systems and methods of initiating energetic reactions for reservoir stimulation
US11808093B2 (en) 2018-07-17 2023-11-07 DynaEnergetics Europe GmbH Oriented perforating system
RU2807310C1 (ru) * 2022-10-28 2023-11-14 Общество с ограниченной ответственностью "Газпром добыча Уренгой" Способ ликвидации ледяных пробок в скважине
US11851996B2 (en) * 2020-12-18 2023-12-26 Jack McIntyre Oil production system and method
US11946728B2 (en) 2019-12-10 2024-04-02 DynaEnergetics Europe GmbH Initiator head with circuit board
US12000267B2 (en) 2021-09-24 2024-06-04 DynaEnergetics Europe GmbH Communication and location system for an autonomous frack system
US12139984B2 (en) 2022-04-15 2024-11-12 Dbk Industries, Llc Fixed-volume setting tool
USRE50204E1 (en) 2013-08-26 2024-11-12 DynaEnergetics Europe GmbH Perforating gun and detonator assembly
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US12312922B2 (en) 2021-01-08 2025-05-27 DynaEnergetics Europe GmbH Perforating gun assembly and components
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US20110132609A1 (en) * 2006-09-18 2011-06-09 Schlumberger Technology Corporation Formation fluid sampling tools and methods utilizing chemical heating
US20080066904A1 (en) * 2006-09-18 2008-03-20 Van Hal Ronald E G Formation Fluid Sampling Tools and Methods Utilizing Chemical Heating
US8283174B2 (en) * 2006-09-18 2012-10-09 Schlumberger Technology Corporation Formation fluid sampling tools and methods utilizing chemical heating
US7886825B2 (en) * 2006-09-18 2011-02-15 Schlumberger Technology Corporation Formation fluid sampling tools and methods utilizing chemical heating
US20080228543A1 (en) * 2007-03-16 2008-09-18 Peter Campbell Doe Methods and apparatus to compute reach and frequency values for flighted schedules
WO2009095476A1 (fr) * 2008-02-01 2009-08-06 Eurovia Utilisation d'un mélange exothermique pour la fabrication d'un enrobe bitumineux
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US20110114323A1 (en) * 2009-11-18 2011-05-19 Baker Hughes Incorporated Heat Generation Process for Treating Oilfield Deposits
US8691731B2 (en) 2009-11-18 2014-04-08 Baker Hughes Incorporated Heat generation process for treating oilfield deposits
WO2012138402A1 (fr) * 2011-04-07 2012-10-11 Los Alamos National Security, Llc Initiateur de polymérisation encapsulé dans un métal élémentaire ou alliage fusible à faible point de fusion pour un amorçage retardé
US9217101B2 (en) 2011-04-07 2015-12-22 Los Alamos National Security, Llc Low-melting elemental metal or fusible alloy encapsulated polymerization initiator for delayed initiation
US9732266B2 (en) 2011-04-07 2017-08-15 Los Alamos National Security, Llc Low-melting elemental metal or fusible alloy encapsulated polymerization initiator for delayed initiation
WO2013130361A1 (fr) * 2012-02-28 2013-09-06 Baker Hughes Incorporated Génération de chaleur in situ
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