WO2005012684A2 - Compositions et procedes pour le traitement de formations souterraines - Google Patents

Compositions et procedes pour le traitement de formations souterraines Download PDF

Info

Publication number
WO2005012684A2
WO2005012684A2 PCT/US2004/024043 US2004024043W WO2005012684A2 WO 2005012684 A2 WO2005012684 A2 WO 2005012684A2 US 2004024043 W US2004024043 W US 2004024043W WO 2005012684 A2 WO2005012684 A2 WO 2005012684A2
Authority
WO
WIPO (PCT)
Prior art keywords
potassium fluoride
treatment solution
peroxysolvate
subterranean formation
potassium
Prior art date
Application number
PCT/US2004/024043
Other languages
English (en)
Other versions
WO2005012684A3 (fr
Inventor
Vladimir Marakov
Original Assignee
Geostim Group Llc
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
Priority claimed from RU2003123083/03A external-priority patent/RU2242603C1/ru
Application filed by Geostim Group Llc filed Critical Geostim Group Llc
Publication of WO2005012684A2 publication Critical patent/WO2005012684A2/fr
Publication of WO2005012684A3 publication Critical patent/WO2005012684A3/fr

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/607—Compositions for stimulating production by acting on the underground formation specially adapted for clay formations
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/72—Eroding chemicals, e.g. acids

Definitions

  • the present invention generally relates to compositions and methods for treating subterranean formations in order to make them more permeable.
  • Such subterranean formations may, for example, be comprised of silicate minerals or carbonate minerals.
  • this invention is especially concerned with matrix acidizing and/or fracture acidizing them in order to increase their permeability.
  • Matrix acidizing is conducted below formation-fracturing pressures.
  • fracture acidizing is conducted at formation-fracturing pressures.
  • any resulting increase in permeability of a formation can lead to increased production of a targeted material contained therein.
  • increased permeability in a hydrocarbon-bearing formation can lead to increased petroleum and/or natural gas production.
  • Such increased permeability can also lead to increased production of non-hydrocarbon materials (e.g., carbon dioxide, sulphur, water, helium, etc.) from subterranean formations containing such materials.
  • non-hydrocarbon materials e.g., carbon dioxide, sulphur, water, helium, etc.
  • Most matrix acidizing operations are aimed at increasing hydrocarbon production by dissolving subterranean formation clogging materials (especially those located near a borehole) and/or by invasion of existing pores and fractures in a subject formation.
  • any of these operations can be accomplished by pumping treatment fluids (e.g., acidic, aqueous solutions and/or gases) into a subject subterranean formation under pressures and flow rates such that the treatment fluid flows to and around any targeted subterranean formation clogging materials and/or into existing pore spaces and/or into existing fractures in the formation that may be clogged by granular materials.
  • treatment fluids e.g., acidic, aqueous solutions and/or gases
  • the acid components of such treatment fluids then chemically react with certain minerals contained in the formation clogging materials, pore spaces and clogged fractures.
  • Such matrix acidizing operations also can create so-called "wormhole" systems in a matrix acidized formation. In effect, such wormhole systems are complex, three dimensional arrays of interconnected passageways.
  • matrix acidizing treatments there are at least four general types of matrix acidizing treatments: (1) wellbore cleanouts, (2) near-wellbore stimulation treatments, (3) intermediate matrix stimulation treatments and (4) extended matrix acidizing treatments.
  • Each calls for use of different treatment techniques according to the distance between a wellbore and a targeted zone in a given subterranean mineral body.
  • the acid treatment solutions used in each of these four treatment techniques tend to penetrate into subterranean formations for only relatively short distances before they are chemically spent. Indeed, this fact is part of the underlying basis for distinguishing between wellbore cleanouts, near-wellbore stimulation treatments, intermediate matrix stimulation treatments and extended matrix acidizing treatments.
  • acids (and their concentrations) for each of these four treatment methods involves, among other things, further consideration of a given subterranean formation's: (1) mineral composition, (2) structure, (3) permeability, (4) porosity, and (5) physical strength.
  • Other factors which then must be considered in the acid identity (concentration) selection process include, but are by no means limited to: (6) reservoir fluid properties, (7) temperatures, (8) pressures, and (9) any limitations on treatment fluid injection rates.
  • identity and amounts of various additives e.g., corrosion inhibitors, surfactants, and iron-control agents, friction reduction agents and so on, will vary with changes in the identity of a treatment acid (and its concentration).
  • fracture acidizing operations are carried out by pumping acidic fluids into subterranean formations at pressures and flow rates high enough to fracture that formation.
  • the acidic components of the high pressure fluids employed generally serve to etch fluid flow channels in newly fractured regions of that formation.
  • the treatment solution volumes needed to carry out most fracturing operations are, however, generally much larger than those required for matrix acidizing operations.
  • a fracture treatment solution may become a far greater factor relative to that of a matrix acidizing operation.
  • cost of materials considerations also imply extensive design and/or lab work to determine, among other things, the mineral nature of the formation being fractured, identification of the most suitable acids, their optimal concentrations and/or the need for other chemical agents and/or particulate materials in the fracture treatment solution selected.
  • some fracture treatments call for the use of particulate materials such as silica flour and 100-mesh sand particulates. That is to say that such particulate materials can be used to advantage in some fracture acidizing operations - but not in others - depending on the treatment acid selected.
  • granular materials e.g., graded rock salt, benzoic acid flakes, wax beads, wax buttons and/or oil-soluble resin materials
  • Other granular materials may have to be employed in other fracture acidizing operation depending on the identify of the acid selected (e.g., HF versus HCL). Selection of any of these particulate materials also implies further consideration of a host of subtle, complex and interrelated factors that very often compete with each other when they are used in the same subterranean treatment solution and/or fracture acidizing technique.
  • HF treatment solutions have been created by first mixing ammonium bifluoride with water and then with HCL in order to slowly convert the ammonium bifluoride to hydrofluoric acid (HF) - after the solution has been pumped into a subterranean formation.
  • ammonium bifluoride is often preferred over the direct use of HF in many subterranean treatment operations.
  • Ammonium bifluoride starting materials also are often preferred over HF starting materials because ammonium bifluoride can be shipped to the field in the form of solid flakes that are readily soluble in water (that may be locally available). That is to say that the fact that ammonium bifluoride can be shipped in solid forms has important freight cost and ease of handling implications.
  • Still other alternative technologies employ organic acids (e.g., formic acid, acetic acid) in place of mineral acids such as HF because reactions of organic acids are generally easier to inhibit (especially at relatively high temperatures).
  • Organic acids are also much more readily biodegradable.
  • Such organic acids may, however, require use of greater acid quantities and/or concentrations as well as use of entirely different corrosion inhibitors, surfactants, precipitation prevention agents, stabilization agents, friction reduction agents and so forth relative to those used in conjunction with mineral acids such as HF and HCL.
  • hydrofluoric acid treatments of silicate formations carbonate formations (e.g., those containing large proportions of limestone and dolomite) are usually treated with hydrochloric acid.
  • hydrochloric acid attack upon carbonate formations There are at least three generally recognized modes of hydrochloric acid attack upon carbonate formations.
  • highly conductive wormholes tend to be created in carbonate formations when hydrochloric acid invasion of such formations is uneven. Indeed, wormholing is the preferred mode of chemical attack upon carbonate formations.
  • Hydrochloric acid treatments are also influenced by such factors as: surface reaction rates, acid diffusion rates and acid injection rates of the hydrochloric acid.
  • HCL/carbonate reaction products are readily soluble in water. Hence, these reaction products are much less likely to precipitate out of solution relative to precipitation of HF/carbonate reaction products.
  • acid-based subterranean treatment solutions usually include one or more agents in addition to their subterranean mineral dissolving acids.
  • such acid-based subterranean treatment solutions may, depending on the particular acid employed, contain different: (1) corrosion inhibitors, (2) surfactants, (3) precipitation prevention agents, (4) clay stabilization agents, (5) diverting agents, (6) friction reducing agents and the like (see for example U.S. Patent 5,366,643 which teaches use of certain corrosion inhibitors in conjunction with HCL-based treatment solutions).
  • corrosion inhibitors such as sodium sulfate, sodium sulfate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium bicarbonate, sodium sulfate, sodium
  • Corrosion Inhibitors Acids chemically react with steels to produce iron salts and hydrogen. Steel metallurgy, acid type (mineral, organic), acid strength and/or temperature are important factors in these reactions. The first widely used corrosion inhibitor was arsenic. Because of increased environmental concerns concerning the toxicity of arsenic, a variety of organic inhibitors have since been developed. Depending on the acid type being employed, many are based upon acetylenic alcohols (e.g., octynol and propargyl alcohol). Iron Precipitation Prevention Agents Steel dissolves to produce ferrous ions which, in the presence of dissolved oxygen, are often transformed into ferric ions.
  • acetylenic alcohols e.g., octynol and propargyl alcohol.
  • Ferric ions will normally precipitate from a treatment solution as its acid is used up and, hence, as the pH of the solution rises.
  • iron precipitation is addressed through use of chelation, sequestration and reduction agents depending on, among other things, the identity of the acid being employed in a given treatment solution.
  • Clay Stabilization Agents Formation clays can react (by ion exchange or partial dissolution) with treatment solutions and thereby cause damage to a formation.
  • various salts such as ammonium chloride and potassium chloride are added to different acid treatment solutions as clay stabilizers.
  • potassium chloride is not normally employed when HF is present in the treatment solution because of the ability of its secondary precipitation product, potassium fluorosilicate, to cause formation plugging.
  • certain cationic materials quaternary amines or polymers with similar reactive groups
  • Surfactants e.g., foaming agents, water-wetting agents, oil- wetting agents, emulsifiers, demulsifiers and antisludge agents all have effects upon surface and/or interfacial tensions of subterranean treatment solutions.
  • water-wetting surfactants serve to lower the surface tension of HF aqueous treatment solutions and thereby increasing their ability to enter small pores.
  • Demulsifiers serve to break up those viscous emulsions that tend to form between petroleum and certain acids, lonogenic and nonionic agents are often used as surface active agents.
  • Diverting Agents The most widely used materials used to divert treatment solutions are those particulates that are insoluble in the treatment solution. Such agents would include, but not be limited to, benzoic acid, naphthalene, gelsonite, wax beads and/or oil-soluble resins. Other systems have employed polymers that crosslink as the pH level of the treatment solution rises.
  • Friction reducing agents are deposited on inside pipe wall surfaces in order to reduce the attractive forces between a given treatment solution and the piping system through which they will be pumped.
  • the inside surfaces of the pipes being employed are "lubricated" so that pumping pressures - and, hence, pumping costs - can be lowered.
  • hydrofluoric acid tends to react relatively more quickly with authigenic clays such as smectite, kaolinite, illite and chlorite, especially at temperatures above about 150 degree F. It also came to be better recognized that, since clays are often a part of those cementitious materials that hold individual sandgrain components of sandstone materials together, dissolution of such clays tends to physically weaken certain matrices, especially sandstone matrices in the vicinity of wellbores. Be all of the above matters as they may, it eventually came to be generally accepted that hydrochloric acid (HCL) does not react very well with most silicate materials, but that hydrofluoric acid (HF) does.
  • HCL hydrochloric acid
  • HF hydrofluoric acid
  • both matrix acidizing operations and fracture acidizing operations are often highly concerned with using additional chemicals and/or field practices that serve to delay certain acid/mineral reactions and/or prevent precipitation of a wide variety of acid reaction products - given the type of mineral encountered. Indeed, precipitation of various acid/mineral reaction products has proved to be an extremely persistent and vexing problem. In part, this follows from the multicomponent nature of the minerals that make up subterranean formations.
  • phosphonate materials also have been used to prevent and/or inhibit certain silicate scales from forming during use of certain hydrochloric/hydrofluoric acid systems as well as during use of certain organic acid/hydrofluoric acid systems such as those that employ formic acid/hydrofluoric acid mixtures (see again U.S. Patent 5,529,125).
  • Another widely used practice to prevent formation of HF based precipitates is to preflush a hydrocarbon-bearing formation with HCL in order to dissolve certain carbonate minerals that may be contained therein.
  • PPF compounds potassium fluoride hydroperoxide
  • KF*2H 2 O 2 potassium fluoride dihydroperoxide
  • KF*3H2 ⁇ 2 potassium fluoride trihydroperoxide
  • potassium fluoride hydroperoxide (KF ⁇ 2 O 2 ) is more chemically reactive than potassium fluoride dihydroperoxide (KF » 2H 2 ⁇ 2 ), but does not penetrate as far before it is chemically spent. This follows, in part, from the fact that reactions of potassium fluoride hydroperoxide (KF » H 2 ⁇ 2 ) with minerals produce less oxygen gas relative to those of potassium fluoride dihydroperoxide (KF » 2H2 ⁇ 2 ).
  • potassium fluoride dihydroperoxide (KF*2H 2 O 2 ) is more chemically reactive than potassium fluoride trihydroperoxide (KF*3H2 ⁇ 2 ), but does not penetrate as far, for analogous, oxygen production related reasons.
  • nH 2 O 2 compounds serves to create more permeable subterranean formations relative to those created by the previously described prior art subterranean treatment acids.
  • increased permeability can lead to enhanced production of a desired product from a given formation.
  • improved production of petroleum, natural gas, carbon dioxide, water, sulfur, helium and the like can be obtained from an appropriate subterranean formation that has been made more permeable by use of subterranean treatment solutions formulated and used according to the teachings of this patent disclosure.
  • solutions of applicant's PPF compounds also can serve just as well as fracture acidizing fluids as matrix acidizing fluids. This attribute also serves to greatly reduce well design and/or well operation work efforts.
  • the reaction times of applicant's XF » nH 2 ⁇ 2 compounds, and especially the peroxysolvate of potassium fluoride compounds are relatively slow (e.g., compared to those of HCL and/or HF compounds) with respect to a very wide variety of formation minerals (e.g., silicates, carbonates, mixtures of silicates and carbonates as well as other entirely different subterranean formation minerals).
  • formation minerals e.g., silicates, carbonates, mixtures of silicates and carbonates as well as other entirely different subterranean formation minerals.
  • “slowness" of reaction time can be a great virtue in treating certain subterranean formations.
  • this slowness is the case in treating all manner of different subterranean minerals (e.g., silicates, carbonates, mixtures thereof and so on).
  • subterranean minerals e.g., silicates, carbonates, mixtures thereof and so on.
  • Applicant's compounds also can be encapsulated to further slow their reaction times.
  • the herein described subterranean treatment solutions also can be employed as viscosity modifying agents when used in conjunction with suitable viscosity modifying agents.
  • the relatively slower reaction time attribute of these compounds also allows them to be used in matrix acidizing operations at relatively lower pumping pressures.
  • shut in times of from about 10 hours to about 50 hours will normally be required in applicant's subterranean treatment operations.
  • Shut in times of from about 24 to about 36 hours are, however, the more likely time requirements for good overall technical results.
  • oxygen gas is one of the products of their reactions with a wide variety of minerals normally encountered in subterranean formations. That is to say that, once formed, this oxygen gas reaction product creates a gas pressure and, hence, a motive force that serves to propel, drive, urge, etc. any unused XF*nH2 ⁇ 2 compound-containing solution "deeper" (i.e., laterally, upward, and/or downward) into a formation body, relative to a solution that is not so propelled by a gas product created by its own chemical reactions with a subterranean mineral.
  • the "reach" or volume of a zone of permeability may be expanded through use of applicant's oxygen releasing - and, hence, at least partially self propelling - treatment solutions.
  • applicant's subterranean treatment solutions will perform at very low PPF concentrations e.g., as low as about 0.5 weight percent of a liquid solution thereof. Such low concentrations imply important cost advantages over prior art treatment solutions having much higher active agent concentration requirements. Be that as it may, applicant's subterranean treatment solutions will perform over a very wide range of XF » nH 2 ⁇ 2 concentrations.
  • the PPF component of such compositions will normally constitute from about 2.5 to about 97.5 weight percent of the solid composition, with the remainder being a chemical stabilizer such as potassium hydrofluoride (KHF 2 ).
  • Solid compositions comprised of about 50 weight percent PPF compound(s) and 50 weight percent of this chemical stabilizer will produce treatment solutions having wide ranging utilities. Normally, any additional components (corrosion inhibiting agents, surfactants, friction reducing agents and the like) used with applicant's PPF formulations will be added to the carrier fluids for these solid compositions in the field.
  • the PPF embodiments of applicant's XF*nH2 ⁇ 2 compounds are also much more compatible with modern environmental concerns (especially when compared to HF and/or HCL systems). That is to say that the PPF compounds of this patent disclosure are not toxic; moreover, they are readily biodegradable. It also might be noted in passing that, in the absence of any pH influencing agents, the pH of applicant's PPF treatment solutions will be about 7.0. This fact has useful implications in its own right. At the very least, it implies that these solutions are far less hazardous relative to those HF, HCL acids heretofore employed as subterranean treatment agents.
  • PPFs are not corrosive to steel (nor to iron, copper or brass). Indeed, they form a protective film over steel that serves to protect it from other corrosive fluids that may be used in the overall operation of a given well. Moreover, and unlike most prior art treatment acids, applicant's PPF compounds do not chemically attack sealing rings and other devices made of polymeric materials (e.g., rubber, plastics and the like) commonly employed in oil field equipment.
  • PPFs can be shipped to the field as solids (e.g., in granular or flake-like forms). In other cases, they can be shipped to the field as highly concentrated liquids. Wellhead workers will, however, normally prefer to have these PPFs shipped in their solid forms in conveniently sized bags, boxes, plastic containers and the like - and then mix them with their carrier fluids, additional agents, etc., in the field. Aside from the ammonium bifluoride compounds previously noted, this ability to be shipped in solid forms is not true of most other subterranean formation treatment agents.
  • hydrofluoric acid and hydrochloric acid are always shipped in liquid forms - at relatively much greater expense - owing to the fact that these acids are only chemically stable as liquids.
  • HF/HCL liquid acids also are highly toxic and otherwise dangerous to ship, store and deploy.
  • applicant's PPF compounds are much more safe and convenient to ship, store, handle and deploy.
  • the solid forms of applicant's PPFs also can be given relatively long shelf lives (e.g., up to about 2 years) when properly stabilized - e.g., by use of a KHF 2 stabilizer.
  • PPFs are also easily mixed in the field because they do not tend to lump when placed in contact with their carrier fluid (e.g., water); nor do they tend to settle (or phase separate) in well site holding tanks. They also can be mixed down hole as well as above ground. Moreover, they are chemically stable over a wide range of operating temperatures (e.g., from about minus 7°C to about 150°C - under appropriate pressure conditions). It might also be noted in passing that, relative to HF/HCL treatment solutions, the compounds of the present patent disclosure are much less inclined to swell certain clays (e.g., bentonite), especially when they are placed in carrier fluids other than water (e.g., petroleum based fluids, alcohols and crude oil).
  • carrier fluids e.g., water
  • carrier fluids e.g., petroleum based fluids, alcohols and crude oil
  • Applicant's PPF solutions are also especially effective in stimulating production of heavier petroleums that have resisted the stimulative action of many prior art treatment solutions.
  • applicant's XF » nH 2 0 2 treatments can be used in place of conventional present day treatments (e.g., HCL and/or HF treatments), or they can be used after such conventional treatments have reached their technical and/or economic limits.
  • applicant's PPF solutions produced greater permeability in petroleum- containing formations from which no further economic production could be obtained through use of commonly employed prior art treatment solutions.
  • a treatment solution formulated according to the teachings of this patent disclosure (containing KF ⁇ 2 O 2 and a KHF 2 stabilization agent) was injected into a well whose petroleum production had fallen to about 0.68 tonnes/day using a commonly employed treatment solution. Thereafter, treatment of this well with one of applicant's PPF treatment solutions raised the well's production to 56.0 tonnes/day. Needless to say, such greater production, especially after prior art methods have failed, has very significant economic implications.
  • Applicant's XF » nH 2 0 2 compounds can be employed with various carrier fluids (e.g., water, petroleum-based fluids such as diesel fuel, kerosene and or distillates, alcohols and crude oil).
  • carrier fluids can further comprise propellant gases such as steam, carbon dioxide, nitrogen, air, various certain hydrocarbon gases, etc.
  • propellant gases such as steam, carbon dioxide, nitrogen, air, various certain hydrocarbon gases, etc.
  • the carrier fluids for applicant's PPF solutions can themselves, in some instances, be gases/vapors (e.g., steam, nitrogen, carbon dioxide and a wide variety of hydrocarbon-based gases).
  • Water is, however, the generally preferred carrier fluid for both technical and economic reasons. Again, water is an especially useful carrier fluid because many XF » nH 2 O 2 /mineral reaction products are soluble in water.
  • the quality of the water that may be successfully employed in applicant's treatment solutions can vary considerably. For example, sweet water, mineralized water, stratal water and the like (as well as mixtures thereof) can be effectively employed.
  • the pH of a water carrier for applicant's subterranean treatment solutions also can vary over extremely wide ranges (e.g., from a pH levels as low as about 0.5 up to as high as about 14.0).
  • acidic materials e.g., hydrochloric acid, acetic acid and sulfuric acid
  • basic materials e.g., potassium hydroxide, sodium hydroxide and calcium hydroxide
  • metal ions e.g., iron ions
  • potassium hydrofluoride (KHF 2 ) can be employed to great advantage in conjunction with many of the XF « nH2 ⁇ 2 compounds of this patent disclosure for reasons other than pH adjustment. It is, for example, especially useful as a PPF stabilization agent, and especially with respect to potassium fluoride hydroperoxide (KF » H 2 ⁇ 2 ). Applicant has, for example, found that potassium hydrofluoride (KHF 2 ) is particularly effective in stabilizing PPFs, e.g., to an extent such that certain solid PPFs (e.g., KF ⁇ 2 O 2 ) can have their shelf lives extended from about two weeks to about two years through use of KHF 2 as a PPF stabilizer.
  • solid PPFs e.g., KF ⁇ 2 O 2
  • This potassium hydrofluoride (KHF 2 ) stabilizer can be added to the PPF compounds during the PPF manufacturing process, or it can be added to a PPF solution in the field.
  • This KHF 2 component of a subterranean treatment solution may also aid in releasing oxygen gas from PPFs as they undergo chemical reactions with subterranean minerals. Again, this oxygen gas release produces a motive force (e.g., a motive force in its own right, i.e., a motive force beyond those supplied by mechanical pumps) for driving any remaining treatment solution farther into a given formation material; and this is true whether the formation is comprised of silica materials, carbonate materials or other minerals.
  • a motive force e.g., a motive force in its own right, i.e., a motive force beyond those supplied by mechanical pumps
  • the KHF 2 also can serve, in part, to retard the rate at which applicant's PPFs react with those formation minerals they encounter. Again, any such chemical reaction "slowdowns" generally serve to enhance a treatment solution's penetration into a subterranean formation.
  • This source of such chemical slowdowns can, for example, be used in conjunction with the fact that applicant's potassium fluoride trihydroperoxide (KF » 3H 2 O 2 ) compositions tend to penetrate farther than the potassium fluoride dihydroperoxide (KF » 2H 2 0 2 ) compositions because KF » 3H 2 O 2 produces more motive force-supplying oxygen gas.
  • KHF 2 also serves to improve the complexing capacity of PPF-based subterranean treatment solutions.
  • This KHF2 stabilization agent also can be used in subterranean treatment solutions in relatively low concentrations.
  • a KHF 2 stabilization agent will normally constitute at least about 0.5% by weight of a resulting PPF/KHF 2 Awater treatment solution. Treatment solutions having from about 0.7 to about 50.0 weight percent of KHF 2 can more generally be employed.
  • a representative subterranean treatment solution containing both a PPF compound and a KHF 2 stabilizer might comprise from about 0.7 to about 20.0 weight percent PPF and from about 0.7 to about 20.0 weight percent
  • KHF 2 a more specific representative subterranean treatment solution might comprise: KF » H 2 0 2 - 0.7 - 20.0 weight percent KHF 2 - 0.7 - 20.0 weight percent water - Remainder
  • the KHF 2 stabilization agents can be used with a variety of carrier fluids such as water, alcohols, ketones, petroleum- based fluids (e.g., diesel fuel, kerosene, distillates and crude oil) and so on.
  • the carrier fluids can even be vapors/gases (e.g., steam, air, nitrogen, carbon dioxide, natural gas and/or other hydrocarbon-based gases) as well as liquids.
  • applicant's XF*nH 2 0 2 treatment solutions are just as effective over comparably wide ranges of operating pressures and operating temperatures (e.g., from about minus 7°C to about 150°C) when they are used in conjunction with KHF 2 , as well as when they are used alone.
  • the fact that applicant's overall PPF/KHF2 compositions are still active at 100°C (and greater - due to superheating allowed by greater pressures) implies that a gas or vapor (such as steam or hydrocarbon vapors) can act as a carrier fluid for such compositions.
  • applicant's subterranean treatment solutions may further comprise a wide variety of other well known agents (e.g., those corrosion inhibitors, iron precipitation prevention agents, clay stabilization agents, surfactants, friction reducing agents and/or diverting agents previously noted in this patent disclosure, or otherwise known to those skilled in these arts).
  • each such additional agent may comprise from about 0.01 to about 5.0 weight percent of an overall treatment solution.
  • Such additional agents, in total, will not, however, normally comprise more than about 40 weight percent of applicant's overall treatment solutions.
  • Figure 1 depicts one of the comparative advantages of a representative PPF-based treatment solution relative to a prior art treatment solution in terms of their relative abilities to dissolve a given mineral system over time.
  • a first curve labeled TK-2
  • TK-2 is depicted by a line having a series of rectangles at certain points on that curve. It represents the chemical/physical dissolution action of a commonly employed treatment solution, known as TK-2, upon the subject mineral.
  • a second curve, labeled PPF is depicted by a line having a series of diamonds at certain points on that curve. It represents the chemical/physical dissolution of the same mineral by the action of a representative PPF-based solution. More specifically, the PPF solution used to create the PPF curve of Figure 1 was comprised of 20 weight percent KF » H 2 ⁇ 2 , and 0.3 weight percent KHF 2 and water.
  • the TK-2 solution was comprised of ammonium chloride, ammonium fluoride, a surface active agent and certain chemicals that encourage production of HCL and HF by hydrolysis of the ammonium chloride and the ammonium fluoride ingredients.
  • This commercially available TK-2 solution was mixed with five parts of sweet water to create a resulting treatment solution.
  • the mineral material used in each test was the same type (and the same physical form) of siliceous material (i.e., quartz tubes).
  • the relative ability of each solution (PPF versus TK-2) to dissolve the quartz material was confirmed by weighing the respective quartz tube materials at various points in time (0.5 hrs., 1 hr., 2.4 hrs., 3.2 hrs., 4.7 hrs. as generally suggested by the data points in Figure 1).
  • the weight differences of the quartz tubes over time measured the relative abilities of the two solutions (PPF versus TK-2) to dissolve the subject quartz material.
  • Figure 1 also shows that the curve labeled TK-2 reaches its peak rate of reaction (i.e., about 0.8 gr/(m 2 *hr)) in about 0.5 hours. Thereafter, its reaction rate falls off relatively quickly. For example, after about one hour's time its reaction rate has fallen to about 0.34 gr/(m 2 *hr). After that, the TK-2 solution's reaction rate decays more slowly. For example, after about 3.75 hours the TK-2 reaction rate has fallen to about 0.2 gr/(m 2» hr).
  • the curve labeled PPF reaches its peak rate of reaction (i.e., about 0.62 gr/(m 2» hr)) in about 0.9 hours. Thereafter, it decays much more slowly relative to the decay of the TK-2 curve.
  • the reaction rate of the PPF solution after about 2.4 hours, is about 0.45 gr/(m 2» hr).
  • the reaction rate of the TK-2 curve is about only 0.25 gr/(m 2 *hr) after the same 2.4 hours. It also should be noted that these two curves (TK-2 and PPF) have a first point of intersection F at about 0.6 hours when they both have a reaction rate of about 0.57 gr/(m 2 *hr).
  • TK-2 curve reaches its peak in about 0.5 hours while the PPF curve takes about 0.9 hours to reach its peak has great practical significance.
  • both the TK-2 solution and the PPF solution under comparable pumping pressures, penetrate a given formation material to an equal distance of one half meter in the first one half hour of the treatment.
  • both the TK-2 solution and the PPF solution (again under comparable pumping pressures) penetrate the formation to an equal distance of one meter in the first full hour of the treatment.
  • the TK-2 solution and the PPF solution thereafter each penetrate the formation an additional one half meter for each additional half hour of treatment time.
  • the TK-2 solution's rate of reaction is about 0.18 gr/(m 2» hr). This is also a second point S where the TK-2 curve and the PPF curve again intersect. Comparing the TK-2 curve with the PPF curve one also notes that at one half hour's time (when the PPF solution has penetrated the formation to a distance of one half meter), the PPF solution's reaction rate has not yet reached its maximum.
  • the PPF curve reaches its maximum (0.62 gr/(m 2» hr)) after about 0.9 hours time and after the PPF solution has penetrated the formation to a distance of about one meter.
  • the TK-2 solution reaches its peak reaction rate when it has penetrated the formation to a distance of only about one half meter.
  • the PPF curve has reacted its peak (0.62 gr/(m 2 *hr)
  • the TK-2 curve has fallen to about 0.34 gr/(m 2» hr) (which is less than half of its one half hour peak value of about 0.8 gr/(m 2 *hr)).
  • the area under the PPF curve and above the TK- 2 curve between their first point of intersection F (0.6 hours and 0.57 gr/(m 2 *hr)) and their second point of intersection S (4.7 hours and 0.18 gr/(m 2 -hr)) represents an area of improved ability of the PPF solution (relative to the TK-2 solution) to act as a mineral formation permeability enhancing agent.
  • Table 1 shows the relative abilities of certain representative subterranean treatment solutions of this patent disclosure to dissolve a representative silica mineral (i.e., quartz in the form of quartz tubes). These solutions employed a representative PPF (KF*H 2 0 2 ) in the varying proportions indicated (e.g., 10.0, 0.96 and 20 weight percent of the overall solution).
  • a potassium hydrofluoride (KHF 2 ) stabilization agent was also employed in the varying proportions indicated (e.g., 10.0, 20.0 and 1.0 weight percent). All of these solutions also contained a surfactant and a corrosion inhibitor in the respective concentrations indicated (i.e., 0.8 weight percent and 0.05 weight percent). These tests were conducted at two representative temperatures (i.e., 20°C and 70°C). Contact times of 0.5, 1.0 and 5 hours were employed with respect to each composition. Table 1 (see line 4) also shows the relative ability of a prior art HCL-based, subterranean treatment solution to dissolve the subject quartz mineral. Since quartz is a silica mineral, the HCL-based, prior art solution (patented in Russia) was generally unable to chemically attack said mineral.
  • KHF 2 potassium hydrofluoride
  • Table 1 also indicates that as the contact time increases, the rate of reaction decreases while the quantity of quartz dissolved generally continues to increase.
  • the higher KF ⁇ 2 O 2 concentrations i.e., 10 and 20 percent
  • Table 2 is similar to Table 1. The main distinctions are that the material being dissolved is a carbonate, the temperature is held constant (at 20°C) and the contact times are measured in minutes, i.e., at 10, 30, 90 and 300 minutes.
  • Table 2 indicates (see line 4) that the relative ability of a prior art (patented in Russia), HCL-based subterranean treatment solution to dissolve the subject carbonate material. Since the subject material is a carbonate, the HCL-based, prior art solution was able to chemically attack it. Thus, Table 2 demonstrates that these KF ⁇ 2 O 2 solutions were able to chemically attack a carbonate material as well as a quartz (silica) material. However, Table 2 also shows that the 10.0 and 0.96 percent KF ⁇ 2 O 2 solutions dissolved more of the subject carbonate material, while the results of the 20 percent KF » H 2 ⁇ 2 solution were comparatively more modest.
  • Table 3 shows a variation of tests that produced the results given in Table 1.
  • Table 1 is concerned with the relative abilities of certain representative subterranean treatment solutions to dissolve quartz, while Table 3 is concerned with the relative abilities of the same representative subterranean treatment solutions to dissolve a representative clay (a silicate material).
  • Table 3 like Table 1 , also shows the relative ability of a prior art (patented in Russia) HCL- based, subterranean treatment solution to dissolve the subject clay material.
  • Table 4 shows the relative abilities of the subterranean treatment compositions of Table 1 to increase the permeability of a clay core sample.
  • This clay core sample was taken from a well in the Koshil Oil Field in western Siberia.
  • This permeability enhancement was established by pumping the various PPF treatment solutions given in Table 4 through respective core samples whose clay content was 10% by weight. The other factors associated with these tests are given at the top of Table 4.
  • the results of these tests are compared to those produced by a prior art (patented in Russia) HCL- based solution.
  • Table 4 shows that each of the three KF*H 2 0 2 compositions served to increase the permeability of the core clay material relative to the prior art HCL-based subterranean treatment solution.

Landscapes

  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Dispersion Chemistry (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Emulsifying, Dispersing, Foam-Producing Or Wetting Agents (AREA)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)

Abstract

Cette invention se rapporte à une solution contenant un composé représenté par la formule générale XF nH202, dans laquelle X représente K+, Na+ ou NH4+ et n est égal à un nombre entier compris entre 1 et 3 (par exemple un peroxysolvate d'un composé de fluorure de potassium, tel que de l'hydroperoxyde de fluorure de potassium (KF H202)). Cette solution est injectée dans une formation souterraine pour augmenter sa perméabilité, notamment par rapport aux flux d'hydrocarbures. Ces composés servent à dissoudre une grande variété de minéraux contenus dans des formations souterraines (par exemple des matières siliceuses et des matières charbonneuses). De l'hydrofluorure de potassium (KHF2) peut être utilisé avec ces composés pour produire des solutions particulièrement efficaces pour le traitement de formations souterraines.
PCT/US2004/024043 2003-07-28 2004-07-27 Compositions et procedes pour le traitement de formations souterraines WO2005012684A2 (fr)

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
RU2003123083/03A RU2242603C1 (ru) 2003-07-28 2003-07-28 Состав для обработки призабойной зоны нефтегазового пласта
RU2003123083 2003-07-28
US10/898,753 2004-07-26
US10/898,753 US7022652B2 (en) 2003-07-28 2004-07-26 Compositions and methods for treating subterranean formations

Publications (2)

Publication Number Publication Date
WO2005012684A2 true WO2005012684A2 (fr) 2005-02-10
WO2005012684A3 WO2005012684A3 (fr) 2005-11-03

Family

ID=34118049

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2004/024043 WO2005012684A2 (fr) 2003-07-28 2004-07-27 Compositions et procedes pour le traitement de formations souterraines

Country Status (1)

Country Link
WO (1) WO2005012684A2 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9097078B2 (en) 2008-11-19 2015-08-04 Maersk Olie Og Gas A/S Down hole equipment removal system

Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3990978A (en) * 1973-12-12 1976-11-09 The Dow Chemical Company Breaking of gelled organic liquids
US4137969A (en) * 1974-02-26 1979-02-06 Marathon Oil Company Process for recovering oil from subterranean formations
RU2032342C1 (ru) * 1992-07-14 1995-04-10 Всесоюзный научно-исследовательский институт ветеринарной санитарии, гигиены и экологии Биоцидное средство
RU2042330C1 (ru) * 1992-12-30 1995-08-27 Всероссийский научно-исследовательский институт ветеринарной санитарии, гигиены и экологии Способ обработки кормов, контаминированных патогенными микроорганизмами и токсигенными грибами

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3990978A (en) * 1973-12-12 1976-11-09 The Dow Chemical Company Breaking of gelled organic liquids
US4137969A (en) * 1974-02-26 1979-02-06 Marathon Oil Company Process for recovering oil from subterranean formations
RU2032342C1 (ru) * 1992-07-14 1995-04-10 Всесоюзный научно-исследовательский институт ветеринарной санитарии, гигиены и экологии Биоцидное средство
RU2042330C1 (ru) * 1992-12-30 1995-08-27 Всероссийский научно-исследовательский институт ветеринарной санитарии, гигиены и экологии Способ обработки кормов, контаминированных патогенными микроорганизмами и токсигенными грибами

Non-Patent Citations (2)

* Cited by examiner, † Cited by third party
Title
DATABASE CAPLUS [Online] TITOVA ET AL: 'KF H202 solubility in organic solvents and water-organic mixtures', XP002990352 Retrieved from STN Database accession no. 2003:639592 & ZHURNAL NEORGANICHESKOI KHIMII vol. 48, no. 5, 2003, pages 849 - 853 *
DATABASE CAPLUS [Online] TITOVA ET AL: 'Postassium fluoride peroxyhydrates', XP002990351 Retrieved from STN Database accession no. 1988:105129 & ZHURNAL NEORGANICHESKOI KHIMII vol. 32, no. 11, 1987, pages 2612 - 2615 *

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9097078B2 (en) 2008-11-19 2015-08-04 Maersk Olie Og Gas A/S Down hole equipment removal system
DK178700B1 (en) * 2008-11-19 2016-11-21 Maersk Olie & Gas Borehole equipment removal system

Also Published As

Publication number Publication date
WO2005012684A3 (fr) 2005-11-03

Similar Documents

Publication Publication Date Title
Portier et al. Review on chemical stimulation techniques in oil industry and applications to geothermal systems
EP1278939B1 (fr) Fluides de traitement de puits contenant des agents de chelation
US8871691B2 (en) Methods of treating flowback water
US4605068A (en) Well treating composition and method
EP0800613B1 (fr) Procede de traitement acide pour formations siliceuses
EP0271564B1 (fr) Composition et procede pour la dissolution lente de materiaux siliceux
US4136739A (en) Method for generating hydrofluoric acid in a subterranean formation
WO2008038033A1 (fr) Procédés et compositions relatives à la régulation des taux de composés acidogènes dans des opérations d'acidification
EA007631B1 (ru) Композиция и способ обработки подземного пласта
US3319714A (en) Well acidizing method
US20080035342A1 (en) Non-acid acidizing methods and compositions
EP1576253A2 (fr) Procede utilisant des chelates particulaires pour la stimulation de la production de petrole dans des formations de carbonate
Borchardt Chemicals used in oil-field operations
US20080035341A1 (en) Non-acid acidizing methods and compositions
US10975293B2 (en) Methods for treating a subterranean formation with a foamed acid system
US7022652B2 (en) Compositions and methods for treating subterranean formations
US20220049154A1 (en) Rapid reversal of wettability of subterranean formations
US11447685B2 (en) Methods of stabilizing carbonate-bearing formations
Cairns et al. From design to practice: Development of new acid platforms to address upstream oil and gas production challenges
Gomaa et al. Retarded HF Acid System to Deeply Stimulate Sandstone Formation and Eliminate the Needs of Pre-Flush and/or Post-Flush Acid Stages: Experimental and Field Cases
US3927718A (en) Secondary recovery method
WO2005012684A2 (fr) Compositions et procedes pour le traitement de formations souterraines
GB2110744A (en) Method and compositions for acidizing subterranean formations
MXPA05000043A (es) Acido de predescarga de auto desviacion para piedra arenisca.
US3720265A (en) Method for stimulating well production

Legal Events

Date Code Title Description
AK Designated states

Kind code of ref document: A2

Designated state(s): AE AG AL AM AT AU AZ BA BB BG BR BW BY BZ CA CH CN CO CR CU CZ DK DM DZ EC EE EG ES FI GB GD GE GH GM HR HU ID IL IN IS JP KE KG KP KZ LC LK LR LS LT LU LV MA MD MG MK MN MW MX MZ NA NI NO NZ OM PG PH PL PT RO SC SD SE SG SK SL SY TJ TM TN TR TT TZ UA UG US UZ VC VN YU ZA ZM ZW

AL Designated countries for regional patents

Kind code of ref document: A2

Designated state(s): GM KE LS MW MZ NA SD SL SZ TZ UG ZM ZW AM AZ BY KG KZ MD RU TJ TM AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HU IE IT LU MC NL PL PT RO SE SI SK TR BF BJ CF CG CI CM GA GN GQ GW ML MR NE SN TD TG

121 Ep: the epo has been informed by wipo that ep was designated in this application
122 Ep: pct application non-entry in european phase