EP0886719A1 - A process and a formulation to inhibit scale in oil field production - Google Patents

A process and a formulation to inhibit scale in oil field production

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Publication number
EP0886719A1
EP0886719A1 EP97950339A EP97950339A EP0886719A1 EP 0886719 A1 EP0886719 A1 EP 0886719A1 EP 97950339 A EP97950339 A EP 97950339A EP 97950339 A EP97950339 A EP 97950339A EP 0886719 A1 EP0886719 A1 EP 0886719A1
Authority
EP
European Patent Office
Prior art keywords
formulation
ether
glycol mono
scale
water
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.)
Ceased
Application number
EP97950339A
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German (de)
English (en)
French (fr)
Inventor
Ian Ralph Collins
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.)
Ineos Oxide Ltd
Original Assignee
BP Chemicals Ltd
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 BP Chemicals Ltd filed Critical BP Chemicals Ltd
Priority to EP10179985A priority Critical patent/EP2287441A3/en
Publication of EP0886719A1 publication Critical patent/EP0886719A1/en
Ceased legal-status Critical Current

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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
    • E21B37/00—Methods or apparatus for cleaning boreholes or wells
    • E21B37/06—Methods or apparatus for cleaning boreholes or wells using chemical means for preventing or limiting, e.g. eliminating, the deposition of paraffins or like substances
    • 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
    • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • C09K8/524—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning organic depositions, e.g. paraffins or asphaltenes
    • 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
    • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • C09K8/528—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates

Definitions

  • This invention relates to oil field chemicals in particular oil field production chemicals and their use.
  • scale inhibitors which are used in production wells to stop scaling in the reservoir rock formation matrix and/or in the production lines downhole and at the surface. Scaling not only causes a restriction in pore size in the reservoir rock formation matrix (also known as 'formation damage') and hence reduction in the rate of oil and/or gas production but also blockage of tubular and pipe equipment during surface processing.
  • the production well is subjected to a so called “shut-in” treatment whereby an aqueous composition comprising a scale inhibitor is injected into the production well, usually under pressure, and "squeezed" into the formation and held there.
  • scale inhibitor is injected several feet radially into the production well where it is retained by adsorption and/or formation of a sparingly soluble precipitate.
  • the inhibitor slowly leaches into the produced water over a period of time and protects the well from scale deposition.
  • the "shut-in" treatment needs to be done regularly e.g. one or more times a year at least if high production rates are to be maintained and constitutes the "down time" when no production takes place.
  • an anionic scale inhibitor and a multivalent cation salt are dissolved in an alkaline aqueous liquid to provide a solution which contains both scale-inhibiting anions and multivalent cations which are mutually soluble as the alkaline pH, but which, at a lower pH and the temperature of the reservoir are precipitated as a scale inhibiting compound having an effective but relatively low water solubility.
  • At least one compound which reacts at a relatively slow rate to reduce the pH of the alkaline solution is also dissolved in the solution. The rate at which the pH of the solution is reduced is adjusted, by arranging the composition and/or concentration of the compounds dissolved in the solution to correlate the rate of pH reduction with the temperature and injectivity properties of the well and reservoir.
  • the present invention is a process for minimising the number of squeezing and shut-in operations needed to inhibit scale and thereby increase the production rate from an oil well using the precipitation squeeze method, said process comprising injecting into an oil-bearing rock formation matrix a water- miscible formulation comprising: (a) a water-miscible surfactant which is in liquid form,
  • (c) a solution of a water-miscible scale-inhibiting compound comprising an anionic component capable of forming a scale inhibiting precipitate in situ in the presence of cations of (b) upon injection into in the rock formation matrix, characterised in that the surfactant (a) is a glycol ether and the minimum ion concentration of the scale inhibiting compound (c) is 5000 ppm based on the weight of the total formulation, said components (a) - (c) being introduced either as a pre-formed single homogeneous composition, or simultaneously in parallel or sequentially in either order into the rock formation matrix.
  • the glycol ether is suitably an alkyl glycol ether in which the alkyl group may be straight or branched chain and suitably has 3-6 carbon atoms, preferably from 3-5 carbon atoms.
  • the glycol ethers that may be used is suitably a mono alkyl ether such as eg n-butyltriglycol ether (also known as triethylene glycol mono-tt-butyl ether). More specifically, these glycol ethers include / «ter alia one or more of
  • Diethylene glycol mono-tert-butyl ether Diethylene glycol mono-n-pentyl ether Diethylene glycol mono-2-methylbutyl ether Diethylene glycol mono-3-methylbutyl ether Diethylene glycol mono-2-pentyl ether Diethylene glycol mono-3-pentyl ether Diethylene glycol mono-tert-pentyl ether
  • Triethylene glycol mono butyl ether ( «-butyltriglycol ether) Tetraethylene glycol mono butyl ether ( 7-butyltetraglycol ether) and Pentaethylene glycol mono butyl ether ( «-butylpentaglycol ether).
  • the water-soluble metal salt (b) comprising multivalent cations is suitably a water-soluble salt of a metal from Group II or Group VI of the Period Table. More specifically, these are suitably salts of one or more metals selected from copper, calcium, magnesium, zinc, aluminium, iron, titanium, zirconium and chromium. Since the salts must be water-soluble, they are preferably the halides, nitrates, formates and acetates of these metals. In choosing the relevant metal, care must, however, be taken to ensure that the conditions in the rock formation matrix are not such as to cause scaling by one of these metals. Calcium chloride, magnesium chloride or mixtures thereof is preferred.
  • the solution of the water soluble salt is suitably an aqueous solution.
  • the water-miscible scale-inhibiting compound (c) comprising an anionic component capable of forming in the presence of cations of (b) a scale inhibiting precipitate in situ upon injection into in the rock formation matrix
  • the precipitate formed in situ is particularly effective in stopping calcium and/or barium scale with threshold amounts rather than stoichiometric amounts.
  • the minimum ion concentration (hereafter "MIC") of the scale inhibiting compound (c) used is at least 5000 ppm based on the total weight of the formulation, and is suitably at least 10000 ppm, preferably at least 12000 ppm by weight.
  • the scale inhibiting compound (c) may be a water-soluble organic molecule having at least 2 carboxylic and/or phosphonic acid and/or sulphonic acid groups e.g. 2-30 such groups.
  • the scale inhibiting compound (c) is an oligomer or a polymer, or may be a monomer having at least one hydroxyl group and/or amino nitrogen atom, especially in a hydroxycarboxylic acid or hydroxy or aminophosphonic, or, sulphonic acid.
  • Examples of compounds (c) are aliphatic phosphonic acids having 2-50 carbons, such as hydroxyethyl diphosphonic acid, and aminoalkyl phosphonic acids, e.g.
  • polyaminomethylene phosphonates with 2- IO N atoms e.g. each bearing at least one methylene phosphonic acid group; examples of the latter are described further in published EP-A-479462, the disclosure of which is herein incorporated by reference.
  • Other scale inhibiting compounds are polycarboxylic acids such as lactic or tartaric acids, and polymeric anionic compounds such as polyvinyl sulphonic acid and poly(meth)acrylic acids, optionally with at least some phosphonyl or phosphinyl groups as in phosphinyl polyacrylates.
  • the scale inhibitors are suitably at least partly in the form of their alkali metal salts e.g. sodium salts.
  • examples of (c) include one or more of: polyphosphino carboxylic acids polyacrylic acids polymaleic acids other polycarboxylic acids or anhydrides such as eg maleic anhydride, itaconic acid, fumaric acid, mesaconic acid & citraconic acid, polyvinyl sulphonates co- and ter-polymers of the above eg polyvinyl sulphonate-polyacrylic acid copolymers polyvinyl sulphonate-polyacrylic acid-polymaleic acid terpolymers polyvinyl sulphonate-polyphosphino carboxylic acid copolymers, phosphonates poly(aminoethylenephosphonic acids) such as eg aminotrimethylene phosphonic acid ethylenediamine tetramethylene phosphonic acid nitriIotri(methylene phosphonic
  • one of the ways of controlling the formation of the precipitate of the scale-inhibiting compound in situ is to control the pH of the solution of the compound from its original value at which value the compound stays in solution to that at which pH value when it generates in situ a precipitate of the scale inhibitor when in contact with the component (b). This may be achieved by various means.
  • the present invention is a formulation comprising in an aqueous medium (d) at least one surfactant comprising -butyltriglycol ether in an amount of 1- 45% w/w of the total formulation
  • the components of the formulation can be introduced simultaneously but separately, or, sequentially, or as a pre-formed single composition care should be taken in choosing the components to ensure that they do not form any significant amounts of a precipitate, especially of the scale inhibitor.
  • the injected glycol ether (a) may, in most instances, 'move' at a lower velocity than the scale inhibitor forming components (b) & (c).
  • a double slug deployment system could be used. For instance, a slug of glycol ether (a) could be injected into the formation first, followed by a slug of scale inhibitor forming components (b) & (c).
  • the two slugs could then be overflushed into the near wellbore in the usual way that scale squeeze treatments are performed.
  • a spacer of sea ater can be placed between the two slugs of the main treatment, and in this case, the overflush could be sized to achieve mixing of the two slugs in the reservoir (assuming that the relative velocities of the glycol ether (a) and the scale inhibitor forming components (b) & (c) are known). It is preferable that each of the components used is homogeneous in itself and is also water-miscible.
  • the surfactant is suitably present in the formulation in an amount ranging from 1-45% by weight, preferably from 5 to 25% by weight, more preferably from 5 to 15% by weight.
  • by-product streams from glycol ether manufacturing processes which contain a high proportion of glycol ethers such as eg «-butyltriglycol ether.
  • One such byproduct stream comprises about 75% w/w of «-butyItriglycol ether, about 2.5% w/w of M-butyldiglycol ether, about 19% of w-butyl tetraglycol ether and about 2% of rt-butyi pentaglycol ether.
  • the relative proportions of components (a)-(c) in the formulation may vary within wide ranges depending upon whether the components are introduced into the rock formation matrix simultaneously, sequentially or as a pre-formed single composition consistent with the need to maintain homogeneity prior to injection thereof into the rock formation matrix. For instance, at relatively higher concentrations of the surfactant or at relatively higher temperatures or extremely low temperatures, it is possible that a pre-formed formulation loses its homogeneity due to reduced solubility of one or more components in the formulation under those conditions.
  • small amounts of a solubilizing agent such as eg a lower aliphatic alcohol, especially methanol or ethanol, can either be added to the inhomogeneous pre-formed formulation or used to partially replace the surfactant in the formulation to restore the homogeneity of the formulation.
  • the homogeneous, pre-formed formulations of the present invention may contain, in addition to the glycol ether, a cosolvent such as eg a lower aliphatic alcohol, especially methanol or ethanol.
  • a cosolvent such as eg a lower aliphatic alcohol, especially methanol or ethanol.
  • the aqueous medium in the formulation may be from fresh, tap, river, sea, produced or formation water, with a total salinity of eg 0-250g/l such as 5-50g/l and may have a pH of 0.5-9. Where sea water is used, the formulation may have a highly acidic pH in the region of 0.1 to 1.5 if a highly acidic scale inhibiting compound (c) is used. In such cases it may be necessary to neutralise the acidity of the formulation by using an alkali metal hydroxide, especially sodium hydroxide, potassium hydroxide or lithium hydroxide in order to ensure homogeneity of the formulation. It has been found for instance that use of lithium hydroxide as a neutralising agent instead of the other alkali metal hydroxides allows tolerance of relatively higher levels of the surfactant in the formulation when it is required to maintain homogeneity of the formulation.
  • an alkali metal hydroxide especially sodium hydroxide, potassium hydroxide or lithium hydroxide
  • the amount of the scale inhibiting compound used is at least 5000 ppm, suitably at least 10000 ppm, and is in the range from 1-25% w/w of the total formulation, suitably from 5-15% w/w, preferably from 6-10% w/w. Within these ranges the amount used would depend upon the nature of the chemical used and its intended purpose, the nature of the rock formation matrix and that it is consistent with the components of the formulation being water miscible and homogeneous.
  • formulations of the present invention it is important with the formulations of the present invention that they remain a clear and stable over a temperature range from ambient to least about 45°C.
  • concentration ranges of the components specified above it is possible to devise formulations which remain stable over a much wider temperature range eg from ambient to the temperature of the production well (eg from 90 to about 150°C, especially around 110°C) into which the formulation is introduced.
  • the components of the formulation when the components of the formulation are injected under pressure into the production well or rock formation matrix either as a pre-formed formulation, simultaneously or sequentially, the scale inhibitors precipitate in situ on the surface(s) of the reservoir rock formation matrix and are retained for relatively long periods.
  • such a formulation may contain, in addition, other components such as (x) other production chemicals or (y) cosolvents which, when necessary, enable the formulation to remain stable at relatively higher temperatures or when the surfactant is used in concentrations in the upper quartile of the range specified.
  • such formulations should be substantially free of water-immiscible components.
  • the pre-formed homogeneous formulations of the present invention when used, may be suitably made by adding the glycol ether surfactant (a) to an aqueous solution of the scale inhibitor forming compounds (b) & (c) followed by gentle mixing. If the material made initially is cloudy, then minor adjustments to the relative proportions of the ingredients or a change in the nature or amount of the cosolvent used or the temperature will be needed. Their viscosity is suitably such that at the reservoir temperature, eg at 100°C, they are easy to pump downhole.
  • the pre-formed formulations of the present invention may be prepared via a concentrate of ingredients (a), (b) and (c), which can be transported as such to the site of use, where it is mixed with the aqueous medium in appropriate proportions to achieve the desired homogeneity and into which the chemical has been dissolved.
  • the components can be injected, suitably under pressure, into an oil bearing zone, eg rock formation matrix, via a producing well e.g. down the core, followed by a separate liquid to force the components of the formulation into the oil bearing zone; the liquid may be used as an overflush and can be sea water or diesel oil.
  • the components of the formulation are then left ("shut-in") in the oil bearing zone while oil production is stopped temporarily.
  • a desirable shut-in period is 5-50hrs e.g. 10-30hrs.
  • the injected components of the formulation percolate through the oil bearing zone under the injection pressure.
  • the injected components of the formulation comes into contact with reservoir fluids and form in situ a precipitate of the scale inhibitor which is deposited on the surface(s) of the reservoir rock formation matrix.
  • This is the so called "precipitation squeeze" effect which precipitate inhibits scale deposition and furthermore is not readily leached out by the production water thereby maintaining continuous oil recovery from such zones.
  • the oil production can be re-started. In the case the oil production rate will be initially high, as will the soluble calcium content of the produced water. Over time, e.g.
  • the rate of production may decrease and the scale inhibitor content of the production water may also decrease signifying possible scaling problems in the rock formation, whereupon the production can be stopped and fresh aliquot of the components of the formulation injected into the well.
  • Similar methods can be used to achieve asphaltene inhibition, wax inhibition or dispersion and hydrogen sulphide scavenging, while for corrosion and gas hydrate inhibition, the formulation is usually injected continuously downhole.
  • a further feature of the formulations of the present invention is that when a precipitate of the scale-inhibitor is used, oil and the glycol ether are recovered at the surface, ie above ground level, after the above procedure of precipitation squeeze and upon subsequent cooling thereof, most of the glycol ether enters in the aqueous phase rather than the oil phase of this composition.
  • the glycol ether does not cause any problems either in subsequent production or refining operations such as eg contributing to any haze formation in fuels due to the presence of solubilized water in the glycol ether.
  • biodegradation of dissolved glycol ether can be relatively rapid in the thermal layer of the sea thereby minimising pollution.
  • the formulations of the present invention can increase the effectiveness of the scale inhibitor by at least two-fold, so that less chemical would be usually needed per year and the down time due to application of the chemical and shut-in would also be correspondingly reduced thereby increasing the production rate.
  • Example 1 The process can be operated equally efficiently by injecting the components of the formulation sequentially into the production well.
  • Example 1 The present invention is illustrated in the following Examples.
  • Example 1 The process can be operated equally efficiently by injecting the components of the formulation sequentially into the production well.
  • Example 1 The present invention is illustrated in the following Examples.
  • a low rate waterflood was performed at this temperature to restore the core plug to residual oil saturation (S or ), ie no more oil could be extracted.
  • the core plug was then cooled to room temperature. 2 pore volumes of a 15% by weight solution of a glycol ether mixture, PCP 96-44 (see below for composition of the glycol ether mixture), in sea water was then injected into the core plug. The temperature of the plug was then raised again to 107°C and the plug left at that temperature for 6 hours. Thereafter, 8 pore volumes of a slug of the scale inhibiting compound (c) admixed with the metal salt (b) dissolved in sea water was injected at temperature and the core left shut-in at temperature for a further 12 hours. After shut-in, the core was post-flushed with sea- water. The results of the coreflood are tabulated below:
  • the scale inhibiting compound (c) used was Dequest® 2060S* (ex Monsanto which is a solution of diethylene triamine pentamethylene . phosphonic acid), dissolved in sea water.
  • the concentration of the scale inhibiting compound (c) was 12628 ppm of active inhibiting compound and 2000 ppm of calcium ion (b) as CaCl 2 .6H 2 O was added to effect precipitation.
  • the calcium addition was followed by adjustment of the pH to 4.0.
  • the active inhibiting compound concentration was 12000 ppm at pH 4.5.
  • the surfactant PCP 96-44 had the following composition:
  • the precipitation squeeze technique of inhibiting scale deposition was tested out in a set of laboratory coreflood experiments.
  • the general procedure was as follows: A core plug (2.54cm (1 inch) x 7.62 cm (3 inches), sampled from the Magnus Main sandstone) to simulate a rock formation of an oil well was mounted in a Hassler-type core holder. This was cleaned with a sequence of mild solvents including alternate injection of toluene and methanol at ambient temperature to remove any hydrocarbons or polar components present in the core sample. The spiked brine was injected into the core at 120 ml/hr and the resulting effluent stream sampled in 2 ml aliquots.
  • the mounted core plug was then saturated with Magnus formation brine at 120 ml/hr for three hours and permeability to brine at room temperature was measured.
  • the Magnus formation brine was spiked with 50 ppm lithium tracer to determine the Clean Pore Volume of the core sample.
  • a plot of the normalised lithium concentration was then used to determine the effective pore volume by determining the volume of brine injected when the lithium concentration was at half the normalised value, and subtracting the known dead volume of the system.
  • Absolute liquid permeability of the core was determined by heating the core to 1 16°C, and then by flooding the core sample at 0, 30, 60, 90 and 120 ml/hr.
  • the plug was then saturated with dead crude oil (ex Magnus Field, North Sea, filtered and de-gassed) by injecting the oil into the sample at 120 ml/hr for a period of 1 hour heated to 1 16°C and left at that temperature for 24 hours.
  • the permeability to oil (at S braid c ) was then measured using the same procedure as above.
  • the crude oil was displaced from the core by flooding with Magnus formation water at reservoir temperature [1 16°C] and at a flow rate of 120 ml/hr. A permeability measurement of S or was then made.
  • the inlet lines were flushed clean and bled up to the core face with the flowback (also known as "post-flush") brine (50:50 Formation wate ⁇ Sea water) prior to increasing the oven temperature to 1 16°C.
  • the fluids within the core sample were then shut-in for 24 hours.
  • the inhibitor solution was spiked with a 50 ppm lithium tracer to allow determination of the effective liquid pore volume at this stage of the test.
  • the core was post-flushed with a 50:50 formation water : sea water mixture (flowback brine) which was injected into the core at 60 ml/hr for approximately 2400 volumes.
  • the permeability to 50:50 brine was then determined using the same procedure as before.
  • the core was flooded with crude oil at 120 ml/hr for 1 hour; the permeability to oil was then determined.
  • the sample was re- cleaned using toluene and methanol, and saturated with Magnus formation water; the final permeability to formation water was then measured.
  • methanol was passed through the sample, prior to dismantling the apparatus, removing the core sample and drying. Scanning Electron Microscope (SEM) analysis was carried out on the post-test sample, and compared with a pre-test sample. The upstream plug face from the actual test sample was used as the post-test specimen.
  • the scale inhibiting compound used was a proprietary formulation Scaletreat® XL MFD (which generated an active polymaleate in situ) as follows: The solutions of the maleate and a low acidity calcium chloride were injected into the rock formation matrix. Thereafter a thermally decomposable compound, urea, was introduced into the rock formation which decomposed under the temperature conditions prevalent in the rock formation matrix thereby generating a basic compound which raised the pH of the solutions and generated a precipitate of the active polymaleate compound in situ.
  • the brines used had the ions listed in the table below present:

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  • Chemical & Material Sciences (AREA)
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  • Organic Chemistry (AREA)
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  • Emulsifying, Dispersing, Foam-Producing Or Wetting Agents (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
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  • Cosmetics (AREA)
  • Colloid Chemistry (AREA)
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EP97950339A 1997-01-13 1997-12-24 A process and a formulation to inhibit scale in oil field production Ceased EP0886719A1 (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
EP10179985A EP2287441A3 (en) 1997-01-13 1997-12-24 Oil and gas field chemicals

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
GBGB9700532.6A GB9700532D0 (en) 1997-01-13 1997-01-13 Oil and gas field chemical
GB9700532 1997-01-13
PCT/GB1997/003553 WO1998030783A1 (en) 1997-01-13 1997-12-24 A process and a formulation to inhibit scale in oil field production

Publications (1)

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EP0886719A1 true EP0886719A1 (en) 1998-12-30

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EP97950339A Ceased EP0886719A1 (en) 1997-01-13 1997-12-24 A process and a formulation to inhibit scale in oil field production
EP10179985A Withdrawn EP2287441A3 (en) 1997-01-13 1997-12-24 Oil and gas field chemicals

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EP10179985A Withdrawn EP2287441A3 (en) 1997-01-13 1997-12-24 Oil and gas field chemicals

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AR (1) AR011403A1 (es)
AU (1) AU718313B2 (es)
CA (1) CA2245886C (es)
CO (1) CO5031323A1 (es)
EA (1) EA000901B1 (es)
GB (1) GB9700532D0 (es)
MY (1) MY120014A (es)
NO (1) NO321722B1 (es)
RO (1) RO117977B1 (es)
SA (1) SA98190109B1 (es)
WO (1) WO1998030783A1 (es)

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GB2423099A (en) * 2005-02-10 2006-08-16 Rhodia Uk Ltd Phosphorus containing species in sludge control
IT1396212B1 (it) * 2009-10-20 2012-11-16 Eni Spa Procedimento per il recupero di olio pesante da un giacimento sotterraneo
CN103224776A (zh) * 2013-03-29 2013-07-31 中国石油天然气股份有限公司 一种油田注水地层保护剂及其制备方法与应用
AR103391A1 (es) 2015-01-13 2017-05-03 Bp Corp North America Inc Métodos y sistemas para producir hidrocarburos desde roca productora de hidrocarburos a través del tratamiento combinado de la roca y la inyección de agua posterior
CN104726082B (zh) * 2015-03-27 2018-05-15 中国石油天然气集团公司 一种应用于三元复合驱的有机碱清垢剂及其制备方法
CN109705831B (zh) * 2019-01-23 2021-04-13 长江大学 一种油田阻垢剂及其制备方法和使用方法
RU2723809C1 (ru) * 2019-02-13 2020-06-17 Публичное акционерное общество "Нефтяная компания "Роснефть" (ПАО "НК "Роснефть") Состав для предотвращения кальциевых солеотложений
CN114805055B (zh) * 2022-04-29 2023-06-23 山东天庆科技发展有限公司 一种新型超支化大分子阻垢剂及其制备方法
CN115386356B (zh) * 2022-09-14 2023-03-17 广汉市福客科技有限公司 一种油气井用解堵剂及制备方法

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EA000901B1 (ru) 2000-06-26
CA2245886A1 (en) 1998-07-16
NO321722B1 (no) 2006-06-26
AR011403A1 (es) 2000-08-16
EP2287441A3 (en) 2011-03-16
GB9700532D0 (en) 1997-03-05
RO117977B1 (ro) 2002-11-29
NO984125D0 (no) 1998-09-07
SA98190109B1 (ar) 2006-08-15
EA199800801A1 (ru) 1999-04-29
AU718313B2 (en) 2000-04-13
CO5031323A1 (es) 2001-04-27
WO1998030783A1 (en) 1998-07-16
AU5333698A (en) 1998-08-03
CA2245886C (en) 2005-03-15
EP2287441A2 (en) 2011-02-23
NO984125L (no) 1998-09-07
MY120014A (en) 2005-08-30

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