WO2014049015A1 - Method for the recovery of natural gas and natural gas condensate from subterranean gas condensate reservoirs - Google Patents
Method for the recovery of natural gas and natural gas condensate from subterranean gas condensate reservoirs Download PDFInfo
- Publication number
- WO2014049015A1 WO2014049015A1 PCT/EP2013/070007 EP2013070007W WO2014049015A1 WO 2014049015 A1 WO2014049015 A1 WO 2014049015A1 EP 2013070007 W EP2013070007 W EP 2013070007W WO 2014049015 A1 WO2014049015 A1 WO 2014049015A1
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- WO
- WIPO (PCT)
- Prior art keywords
- solution
- gas condensate
- natural gas
- urea
- deposit
- Prior art date
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- 239000007789 gas Substances 0.000 title claims abstract description 199
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 title claims abstract description 140
- 238000000034 method Methods 0.000 title claims abstract description 106
- 239000003345 natural gas Substances 0.000 title claims abstract description 65
- 239000003498 natural gas condensate Substances 0.000 title claims abstract description 57
- 238000011084 recovery Methods 0.000 title abstract 2
- XSQUKJJJFZCRTK-UHFFFAOYSA-N Urea Chemical compound NC(N)=O XSQUKJJJFZCRTK-UHFFFAOYSA-N 0.000 claims abstract description 118
- 239000004202 carbamide Substances 0.000 claims abstract description 118
- 238000004519 manufacturing process Methods 0.000 claims abstract description 110
- 239000000203 mixture Substances 0.000 claims abstract description 65
- 238000009833 condensation Methods 0.000 claims abstract description 31
- 230000005494 condensation Effects 0.000 claims abstract description 31
- 239000002904 solvent Substances 0.000 claims abstract description 29
- 239000000243 solution Substances 0.000 claims description 175
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 75
- LFQSCWFLJHTTHZ-UHFFFAOYSA-N Ethanol Chemical compound CCO LFQSCWFLJHTTHZ-UHFFFAOYSA-N 0.000 claims description 38
- QGZKDVFQNNGYKY-UHFFFAOYSA-N Ammonia Chemical compound N QGZKDVFQNNGYKY-UHFFFAOYSA-N 0.000 claims description 36
- 239000003949 liquefied natural gas Substances 0.000 claims description 32
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims description 30
- 230000007062 hydrolysis Effects 0.000 claims description 27
- 238000006460 hydrolysis reaction Methods 0.000 claims description 27
- 229910021529 ammonia Inorganic materials 0.000 claims description 17
- 238000002425 crystallisation Methods 0.000 claims description 17
- 230000008025 crystallization Effects 0.000 claims description 17
- 229910002092 carbon dioxide Inorganic materials 0.000 claims description 15
- 239000001569 carbon dioxide Substances 0.000 claims description 15
- 238000002347 injection Methods 0.000 claims description 11
- 239000007924 injection Substances 0.000 claims description 11
- 239000011148 porous material Substances 0.000 claims description 5
- 229910052799 carbon Inorganic materials 0.000 claims description 3
- 230000016507 interphase Effects 0.000 claims description 3
- 230000001737 promoting effect Effects 0.000 claims description 2
- OKKJLVBELUTLKV-UHFFFAOYSA-N Methanol Chemical compound OC OKKJLVBELUTLKV-UHFFFAOYSA-N 0.000 description 39
- 239000012071 phase Substances 0.000 description 37
- 230000008569 process Effects 0.000 description 26
- 239000007788 liquid Substances 0.000 description 19
- 150000002430 hydrocarbons Chemical class 0.000 description 15
- 230000009467 reduction Effects 0.000 description 15
- 229930195733 hydrocarbon Natural products 0.000 description 13
- 230000015572 biosynthetic process Effects 0.000 description 11
- VLKZOEOYAKHREP-UHFFFAOYSA-N n-Hexane Chemical class CCCCCC VLKZOEOYAKHREP-UHFFFAOYSA-N 0.000 description 8
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical class CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 7
- 238000007796 conventional method Methods 0.000 description 7
- IMNFDUFMRHMDMM-UHFFFAOYSA-N N-Heptane Chemical class CCCCCCC IMNFDUFMRHMDMM-UHFFFAOYSA-N 0.000 description 6
- 235000013849 propane Nutrition 0.000 description 6
- OTMSDBZUPAUEDD-UHFFFAOYSA-N Ethane Chemical compound CC OTMSDBZUPAUEDD-UHFFFAOYSA-N 0.000 description 5
- OFBQJSOFQDEBGM-UHFFFAOYSA-N Pentane Chemical class CCCCC OFBQJSOFQDEBGM-UHFFFAOYSA-N 0.000 description 5
- 230000000903 blocking effect Effects 0.000 description 5
- 230000018109 developmental process Effects 0.000 description 5
- 239000008398 formation water Substances 0.000 description 5
- 238000010438 heat treatment Methods 0.000 description 5
- 230000035699 permeability Effects 0.000 description 5
- 239000000126 substance Substances 0.000 description 5
- CSCPPACGZOOCGX-UHFFFAOYSA-N Acetone Chemical compound CC(C)=O CSCPPACGZOOCGX-UHFFFAOYSA-N 0.000 description 4
- HEDRZPFGACZZDS-UHFFFAOYSA-N Chloroform Chemical compound ClC(Cl)Cl HEDRZPFGACZZDS-UHFFFAOYSA-N 0.000 description 4
- 235000013844 butane Nutrition 0.000 description 4
- 239000013078 crystal Substances 0.000 description 4
- 230000007423 decrease Effects 0.000 description 4
- IJDNQMDRQITEOD-UHFFFAOYSA-N n-butane Chemical class CCCC IJDNQMDRQITEOD-UHFFFAOYSA-N 0.000 description 4
- 238000003860 storage Methods 0.000 description 4
- 230000003797 telogen phase Effects 0.000 description 4
- KFZMGEQAYNKOFK-UHFFFAOYSA-N Isopropanol Chemical compound CC(C)O KFZMGEQAYNKOFK-UHFFFAOYSA-N 0.000 description 3
- 229920003171 Poly (ethylene oxide) Polymers 0.000 description 3
- 150000001298 alcohols Chemical class 0.000 description 3
- 238000010790 dilution Methods 0.000 description 3
- 239000012895 dilution Substances 0.000 description 3
- 238000004090 dissolution Methods 0.000 description 3
- 238000002360 preparation method Methods 0.000 description 3
- BDERNNFJNOPAEC-UHFFFAOYSA-N propan-1-ol Chemical compound CCCO BDERNNFJNOPAEC-UHFFFAOYSA-N 0.000 description 3
- 239000004094 surface-active agent Substances 0.000 description 3
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- AWMVMTVKBNGEAK-UHFFFAOYSA-N Styrene oxide Chemical class C1OC1C1=CC=CC=C1 AWMVMTVKBNGEAK-UHFFFAOYSA-N 0.000 description 2
- 230000009471 action Effects 0.000 description 2
- 239000003945 anionic surfactant Substances 0.000 description 2
- 230000008901 benefit Effects 0.000 description 2
- 230000002051 biphasic effect Effects 0.000 description 2
- 239000007853 buffer solution Substances 0.000 description 2
- 239000003093 cationic surfactant Substances 0.000 description 2
- 238000011109 contamination Methods 0.000 description 2
- 238000006073 displacement reaction Methods 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 238000000605 extraction Methods 0.000 description 2
- 239000002736 nonionic surfactant Substances 0.000 description 2
- 239000003960 organic solvent Substances 0.000 description 2
- 238000010587 phase diagram Methods 0.000 description 2
- 229920000233 poly(alkylene oxides) Polymers 0.000 description 2
- 229920001451 polypropylene glycol Polymers 0.000 description 2
- FFYRIXSGFSWFAQ-UHFFFAOYSA-N 1-dodecylpyridin-1-ium Chemical class CCCCCCCCCCCC[N+]1=CC=CC=C1 FFYRIXSGFSWFAQ-UHFFFAOYSA-N 0.000 description 1
- UENCOZAJOJQVED-UHFFFAOYSA-L 1-hexadecylpyridin-1-ium;sulfate Chemical compound [O-]S([O-])(=O)=O.CCCCCCCCCCCCCCCC[N+]1=CC=CC=C1.CCCCCCCCCCCCCCCC[N+]1=CC=CC=C1 UENCOZAJOJQVED-UHFFFAOYSA-L 0.000 description 1
- JKTORXLUQLQJCM-UHFFFAOYSA-N 4-phosphonobutylphosphonic acid Chemical compound OP(O)(=O)CCCCP(O)(O)=O JKTORXLUQLQJCM-UHFFFAOYSA-N 0.000 description 1
- VHUUQVKOLVNVRT-UHFFFAOYSA-N Ammonium hydroxide Chemical compound [NH4+].[OH-] VHUUQVKOLVNVRT-UHFFFAOYSA-N 0.000 description 1
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical class S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 1
- JUJWROOIHBZHMG-UHFFFAOYSA-N Pyridine Chemical class C1=CC=NC=C1 JUJWROOIHBZHMG-UHFFFAOYSA-N 0.000 description 1
- DBMJMQXJHONAFJ-UHFFFAOYSA-M Sodium laurylsulphate Chemical compound [Na+].CCCCCCCCCCCCOS([O-])(=O)=O DBMJMQXJHONAFJ-UHFFFAOYSA-M 0.000 description 1
- QAOWNCQODCNURD-UHFFFAOYSA-L Sulfate Chemical compound [O-]S([O-])(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-L 0.000 description 1
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 1
- 150000001242 acetic acid derivatives Chemical class 0.000 description 1
- 239000002253 acid Substances 0.000 description 1
- 150000007513 acids Chemical class 0.000 description 1
- 239000000654 additive Substances 0.000 description 1
- 230000002776 aggregation Effects 0.000 description 1
- 238000004220 aggregation Methods 0.000 description 1
- 229910052783 alkali metal Inorganic materials 0.000 description 1
- 150000001340 alkali metals Chemical class 0.000 description 1
- 239000012670 alkaline solution Substances 0.000 description 1
- 125000002877 alkyl aryl group Chemical group 0.000 description 1
- 125000000217 alkyl group Chemical group 0.000 description 1
- 150000008051 alkyl sulfates Chemical class 0.000 description 1
- 125000002947 alkylene group Chemical group 0.000 description 1
- 235000011114 ammonium hydroxide Nutrition 0.000 description 1
- 150000003863 ammonium salts Chemical class 0.000 description 1
- 125000000129 anionic group Chemical group 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 230000033558 biomineral tissue development Effects 0.000 description 1
- 239000012455 biphasic mixture Substances 0.000 description 1
- 229920001400 block copolymer Polymers 0.000 description 1
- 125000004432 carbon atom Chemical group C* 0.000 description 1
- 125000002091 cationic group Chemical group 0.000 description 1
- 230000036461 convulsion Effects 0.000 description 1
- 125000004122 cyclic group Chemical group 0.000 description 1
- 230000008021 deposition Effects 0.000 description 1
- VFNGKCDDZUSWLR-UHFFFAOYSA-N disulfuric acid Chemical class OS(=O)(=O)OS(O)(=O)=O VFNGKCDDZUSWLR-UHFFFAOYSA-N 0.000 description 1
- HBRNMIYLJIXXEE-UHFFFAOYSA-N dodecylazanium;acetate Chemical compound CC(O)=O.CCCCCCCCCCCCN HBRNMIYLJIXXEE-UHFFFAOYSA-N 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 150000002148 esters Chemical class 0.000 description 1
- 150000002191 fatty alcohols Chemical class 0.000 description 1
- 239000008187 granular material Substances 0.000 description 1
- -1 heterocyclic radicals Chemical class 0.000 description 1
- 230000003301 hydrolyzing effect Effects 0.000 description 1
- MTNDZQHUAFNZQY-UHFFFAOYSA-N imidazoline Chemical class C1CN=CN1 MTNDZQHUAFNZQY-UHFFFAOYSA-N 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 239000007791 liquid phase Substances 0.000 description 1
- YNAVUWVOSKDBBP-UHFFFAOYSA-O morpholinium Chemical compound [H+].C1COCCN1 YNAVUWVOSKDBBP-UHFFFAOYSA-O 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 239000003208 petroleum Substances 0.000 description 1
- 150000004714 phosphonium salts Chemical class 0.000 description 1
- 229920000642 polymer Polymers 0.000 description 1
- 150000003864 primary ammonium salts Chemical class 0.000 description 1
- 239000001294 propane Substances 0.000 description 1
- 150000003242 quaternary ammonium salts Chemical class 0.000 description 1
- 229920005604 random copolymer Polymers 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 150000003865 secondary ammonium salts Chemical class 0.000 description 1
- 235000019333 sodium laurylsulphate Nutrition 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
- 230000004936 stimulating effect Effects 0.000 description 1
- 229910052717 sulfur Inorganic materials 0.000 description 1
- 239000011593 sulfur Substances 0.000 description 1
- 150000003866 tertiary ammonium salts Chemical class 0.000 description 1
- 230000001988 toxicity Effects 0.000 description 1
- 231100000419 toxicity Toxicity 0.000 description 1
- GETQZCLCWQTVFV-UHFFFAOYSA-N trimethylamine Chemical compound CN(C)C GETQZCLCWQTVFV-UHFFFAOYSA-N 0.000 description 1
- 238000010792 warming Methods 0.000 description 1
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
- 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
-
- 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
- C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
Definitions
- the present invention relates to a process for the production of natural gas and / or natural gas condensate from underground gas condensate deposits containing a gas mixture with retrograde condensation behavior.
- Gas mixtures with retrograde (retrogressive) condensation behavior coming from the gas phase, undergo a partial condensation in the event of an isothermal reduction in pressure and return to the gas phase on further lowering of the pressure.
- a retrograde condensation behavior occurs in a gas mixture whose temperature is above the critical temperature of the gas mixture.
- Natural gas mixtures containing, for example, besides methane, ethane, propanes and butanes, 2 to 20% by volume of heavy hydrocarbons (C 5 +, such as, for example, pentanes and hexanes) generally have a retrograde condensation behavior.
- the phase behavior of gas mixtures with retrograde condensation behavior is shown by way of example in FIG.
- This liquid gas condensate can block the Bohrlochnahzone, the delivery rate of natural gas and / or natural gas condensate through the production wells decreases sharply or even completely comes to a standstill. This effect is particularly pronounced in the production of natural gas and / or natural gas condensate deposits, which have a low permeability. By blocking the porous rocks in the area of the borehole near zone, the inflow of natural gas and / or natural gas condensate to the production well is severely restricted or even completely stopped. Depending on the geological characteristics of the deposit and on the pressure and temperature conditions in the deposit, the area where the liquid gas condensate blocks the flow of natural gas and / or natural gas condensate to the production well may be 5 to 100 m wide.
- the region in which the blocking is brought about by the liquid gas condensate generally has a quasi-cylindrical shape in the center of which the production bore lies.
- RU 2018639 describes a method for preventively preventing the formation of liquid gas condensate in a gas condensate reservoir.
- the process described there is also known as "cycling-process.”
- the heavy hydrocarbons (C 5 +) are separated from light hydrocarbons (such as methane, ethane, and propanes) by light hydrocarbons Gas “pressed back into the deposit to increase the reservoir pressure.
- the "cyc // ng" process is very time-consuming and cost-intensive and, with this process, the formation of liquid gas condensate in gas condensate deposits can not be reliably prevented.
- SU 605429 describes a process for the development of gas condensate deposits.
- the deposit is flooded with highly mineralized water.
- the high mineralization prevents the solution of gases in the flood water and thus allows the displacement of the natural gas and the natural gas condensate from the area of the borehole near the production well.
- a disadvantage of this method is the massive dilution of the deposit by the injected flood water.
- the injected flood water itself can lead to a blockage of the Bohrlochnahzone. This method does not allow for an effective increase in production rates.
- SU 1596081 and RU 2064572 disclose methods of treating the gas condensate reservoir with seismic waves.
- the seismic waves should thereby lead to an increase in the delivery rate from the gas condensate deposit. This process is not very efficient, especially in low-lying deposits.
- RU 2415257 describes a method of stimulating the rates of delivery of gas condensate deposits by electromagnetic waves. This method is also unsuitable, especially for low-lying deposits.
- RU 2245997 discloses a method in which solvents are injected into the well area at cyclic intervals to dissolve the liquid condensate.
- the solvents used for this purpose are aqueous mixtures of acetone and methanol, chloroform and methanol or acetone and chloroform.
- a disadvantage of this method is that the introduced aqueous mixtures also lead to a dilution of Bohrlochnah Kunststoffs.
- the process is associated with the organic solvents used at an enormous cost.
- the organic solvents used also cause environmental problems due to their toxicity.
- the present invention is therefore based on the object to provide an improved method for the production of natural gas and / or natural gas condensate from underground gas condensate deposits containing a gas mixture having a retrograde condensation behavior.
- the method should not or only to a lesser extent have the disadvantages of the prior art described above.
- the inventive method should be inexpensive and easy to carry out and lead to an effective increase in the delivery rate of natural gas and / or natural gas condensate from gas condensate deposits after the well zone was at least partially blocked by liquid gas condensate.
- the object is achieved by a method for the production of natural gas and / or natural gas condensate from a subterranean gas condensate deposit containing a gas mixture with retrograde condensation behavior, comprising at least the process steps a) Lowering at least one production well into the underground gas condensate deposit and natural gas and / or natural gas condensate from the underground production well through the at least one production well, b) injecting a solution (L) containing a solvent and urea through the at least one production well into the subterranean gas condensate reservoir, c) placing a quiescent phase in which the urea contained in the solution (L) is hydrolyzed, (d) extraction of natural gas and / or natural gas condensate from the underground gas condensate reservoir through the at least one production well.
- the object is further achieved by a method for the production of natural gas and / or natural gas condensate from a subterranean gas condensate deposit containing a gas mixture with retrograde condensation behavior, comprising at least the process steps a) Lowering at least one production well into the underground gas condensate deposit and promotion of Natural gas and / or
- the method according to the invention makes it possible to effectively increase the delivery rate of natural gas and / or natural gas condensate from a gas condensate deposit in which the well area is blocked by liquid natural gas condensate.
- the method according to the invention has the advantage that it manages with cost-effective and toxicologically harmless substances.
- the inventive method prevents dilution of the Bohrlochnahzone the gas condensate deposit.
- At least one production well is drilled into the underground gas condensate deposit.
- the downcasting of the at least one production well into the underground gas condensate deposit takes place by conventional methods known to the person skilled in the art and is described, for example, in EP 0 952 300.
- the production hole can be a vertical, horizontal or a deflected hole.
- the production well is a deflected well that includes a quasi-vertical and a quasi-horizontal section.
- the gas condensate deposit contains a gas mixture with a retrograde condensation behavior. Such gas condensate deposits are also referred to as retrograde gas condensate deposits.
- the gas mixture contained in the underground gas condensate deposit generally contains from 80 to 98% by volume of light hydrocarbons and from 2 to 20% by volume of heavy hydrocarbons.
- light hydrocarbons are understood according to the invention methane, ethane, propanes and butanes.
- Hydrocarbons according to the invention are understood to mean hydrocarbons having 5 or more carbon atoms, for example pentanes, hexanes and heptanes and optionally higher hydrocarbons.
- propanes, butanes, pentanes, hexanes and heptanes are understood in the present case to mean both the unbranched hydrocarbon compounds and also all branched isomers of the abovementioned hydrocarbon compounds.
- the properties of gas mixtures with retrograde condensation behavior are shown purely by way of example in FIG.
- the area denoted by (al) describes the single-phase region in which the gas mixture is present exclusively in liquid form.
- the single-phase region marked with (av) shows the region in which the gas mixture is exclusively gaseous.
- the region marked (l + v) shows the biphasic region in which one part of the gas mixture is in liquid form and another part is in gaseous form.
- (CP) shows the critical point of the gas mixture connecting the bubble point curve (bpc) to the dew point curve (dpc).
- the Bubble Point Curve (bpc) is also referred to as the bubble-po / nf curve, and the dew point curve (dpc) is also called the dew-point curve.
- the bubble point curve (bpc) separates the single-phase liquid region (a1) from the biphasic region (l + v).
- the gas mixture is virtually 100% liquid and contains only infinitesimal amounts of gas.
- the dew point curve (dpc) separates the single-phase gaseous region (av) from the two-phase region (c + v).
- the gas mixture On the dew point curve (dpc), the gas mixture is virtually 100% gaseous and contains only infinitesimal amounts of liquid.
- T On the horizontal axis is the temperature (T), on the vertical axis the pressure (P) is plotted.
- a gas mixture with a retrograde condensation behavior undergoes a partial condensation in the event of an isothermal reduction in pressure and reverts to the gas phase on further lowering of the pressure.
- the retrograde condensation behavior usually occurs at temperatures which are above the critical point (CP) of the gas mixture.
- CP critical point
- the gas mixture with retrograde 5 condensation behavior at point (A) is gaseous and single-phase.
- the gas mixture at point (B) reaches the dew point curve (dpc).
- the gas mixture is virtually 100% gaseous, but an infinitesimal amount of liquid begins to form.
- the reservoir temperature T L of the gas condensate deposits from which natural gas and / or natural gas condensate are conveyed by the process according to the invention is usually in the range from 60 to 200 ° C., preferably in the range from 70 to 150 ° C., particularly preferably in the region of 80 to 140 ° C and in particular in the range of 25 85 ° C to 120 ° C.
- the storage temperature T L of the gas condensate deposits must meet the following conditions:
- T L is higher than the crystallization temperature of the solution
- T L must allow the complete hydrolysis of the urea in a relatively short time, for example within 1 to 20 days.
- the subject matter of the present invention is therefore also a process in which the underground gas condensate deposit has a reservoir temperature (T L ) in the range 35 from 60 to 200 ° C, preferably in the range from 70 to 150 ° C, particularly preferably in the range from 80 to 140 ° C and in particular in the range of 85 to 120 ° C.
- T L reservoir temperature
- the initial reservoir pressure that is, the pressure of prior to carrying out the process of the invention, is usually in the range of 80 to 1500 bar, 40 normally the initial reservoir pressure at gas condensate reservoirs is 300 to 600 bar.
- the permeability of the underground gas condensate deposits is generally in the range of 0.01 to 10 mD (MiliDarcy).
- the porosity of the underground gas condensate deposits is generally in the range of 0.1 to 30%.
- natural gas and / or natural gas condensate do not in this context mean a pure hydrocarbon mixture.
- the natural gas and / or natural gas condensate can of course also contain other substances in addition to methane, ethane, propanes, butanes, hexanes and heptanes and optionally higher hydrocarbons.
- formation water is understood to mean water which is originally present in the deposit, and water which has been introduced into the deposit through secondary and tertiary production process steps, for example so-called floodwater.
- the formation water also includes water which has optionally been introduced into the gas condensate deposit by the process according to the invention.
- a gas mixture with a retrograde condensation behavior has the following composition (data in mol%):
- natural gas is understood as meaning gaseous gas mixtures which are conveyed from the gas condensate deposit.
- Natural gas condensate is understood as meaning liquid mixtures which are conveyed from the gas condensate reservoir.
- the aggregate state of the mixtures extracted from the gas condensate deposit depends on the temperature and the pressure in the deposit or in the production well. According to the method of the invention, it is possible to exclusively feed natural gas through the production well. In addition, it is possible to promote only natural gas condensate through the production well. It is also possible to have one Promote mixture of natural gas and natural gas condensate through the production well.
- the state of aggregation of the further substances optionally present in the natural gas or in the natural gas condensate likewise depends on the pressure and the temperature in the deposit or in the production well.
- the other substances may likewise be present in liquid form or in gaseous form in the mixture conveyed through the production well.
- the reservoir pressure is sufficient to deliver natural gas and / or natural gas condensate from the reservoir through the production well, this is done by conventional production methods.
- the subject matter of the present invention is thus also a method in which, after the sinking, the at least one production well is introduced into the underground gas condensate deposit (process step a) and before the solution (L) is injected into the underground gas condensate reservoir (process step b)). first, natural gas and / or natural gas condensate (by conventional methods) is conveyed through the at least one production well.
- process step b) is also possible to carry out process step b) directly after the production well has been lowered in order to prevent the formation of natural gas condensate.
- the temperature of the gas condensate storage in the implementation of the method according to the invention remains largely constant, that is, that the temperature of the gas condensate deposit by a maximum of +/- 20 ° C, preferably by +/- 10 ° C, and more preferably by +/- 5 ° C when carrying out the method according to the invention compared to the initial storage temperature before carrying out the method according to the invention changes.
- FIG. 2 shows by way of example the pressure curve in the underground gas condensate deposit as a function of the distance to the production well.
- the distance to the production bore is plotted on the horizontal axis in meters.
- the reservoir jerk (P) is plotted on the dashed vertical axis.
- the reservoir pressure (P) reaches a value at which the partial condensation of the retrograde gas mixture begins. This distance is shown by the vertical dotted line in FIG.
- point (B) on the dashed reservoir pressure curve (P) formation of a biphasic mixture containing natural gas and natural gas condensate begins.
- Point (B) on the dashed reservoir pressure curve (P) corresponds to point (B) in Figure 1.
- the gas mixture is in two-phase (range (l + v)).
- the gas mixture is in single phase (area (av)).
- the proportion of liquid natural gas condensate is plotted on the vertical axis (KG) and is shown by the solid curve (KG) in Figure 2. Above a certain concentration of liquefied natural gas condensate, the well zone is blocked, which reduces or completely stops the production rates of natural gas and / or natural gas condensate from the gas condensate reservoir.
- This critical area is represented by the gray-shaded area (KB) in FIG.
- the critical concentration of the liquid natural gas condensate in the gas mixture is represented by the point (KS) on the curve (KG) in FIG.
- FIG. 2 merely illustrates, by way of example, the conditions in a gas condensate deposit which has a gas mixture with retrograde condensation behavior, without limiting the present invention thereto.
- the production of natural gas and / or natural gas condensate from the underground gas condensate reservoir through the at least one production well is generally carried out until a reduction in the production rate of natural gas and / or natural gas condensate is registered.
- the reduction of the delivery rate is due to the formation of the critical area (KB), which is at least partially blocked by liquid natural gas condensate.
- the subject matter of the present invention is therefore also a process in which the underground gas condensate deposit before the implementation of process step b) has a critical area (KB) which is at least partially blocked by liquid natural gas condensate.
- the subject matter of the present invention is therefore also a process in which the process step a) involves the downsizing of at least one production well into the underground gas condensate deposit, the production of natural gas and / or natural gas condensate from the underground gas condensate deposit until formation a critical region (KB) which is at least partially blocked by liquid natural gas condensate and which comprises adjusting the production of natural gas and / or natural gas condensate from the underground gas condensate reservoir through the at least one production well.
- KB critical region
- step b) a solution (L) containing a solvent and urea is injected through the production well into the underground gas condensate deposit.
- the solution (L) contains 50 to 79% by weight of urea and 21 to 50% by weight of solvent, the solvent containing water, alcohol or a mixture of water and alcohol, based on the total weight of the solution (L).
- the solution (L) preferably contains from 60 to 78% by weight of urea and from 22 to 40% by weight of solvent, based on the total weight of the solution (L).
- the solution (L) particularly preferably contains 65 to 77% by weight of urea and 23 to 35% by weight of solvent, based on the total weight of the solution (L).
- the solution (L) contains 75 to 77 wt .-% urea and 23 to 25 wt .-% of solvent, based on the total weight of the solution (L).
- the present invention thus also provides a process in which the solution (L) contains 50 to 79% by weight of urea and 21 to 50% by weight of solvent, the solvent containing water, alcohol or a mixture of water and alcohol , in each case based on the total weight of the solution (L).
- solvent As a solvent, therefore, only water can be used. It is also possible to use only alcohol as solvent. The use of a solvent containing only alcohol is possible if there is sufficient formation water for the hydrolysis of the urea in the production well and / or the underground gas condensate reservoir. In addition, it is possible to use as solvent a mixture of water and alcohol. As alcohol, exactly one alcohol can be used. It is also possible to use a mixture of two or more alcohols. As the alcohol, methanol, ethanol, 1-propanol, 2-propanol or a mixture of two or more of these alcohols can be used. Preferred alcohol is methanol.
- the solution (L) contains urea and water in a stoichiometric ratio of water to urea of 1: 1. At this ratio, the urea contained in the solution (L) completely converts to water with ammonia and carbon dioxide. As a result, the water contained in the solution (L) is completely consumed and prevents contamination of the gas condensate reservoir by water. In the event that the solution (L) contains only water as a solvent, the solution (L) then contains water and urea in a wt .-% ratio of 23.1 wt .-% water to 76.9 wt .-% urea.
- the solution (L) can consist only of solvent and urea, the above statements and preferences apply accordingly. However, it is also possible to add at least one surface-active component (surfactant) to the solution (L).
- the solution (L) preferably contains 0.1 to 5 wt .-%, particularly preferably 0.5 to 1 wt .-% of at least one surfactant, based on the total weight of the solution (L).
- anionic, cationic and nonionic surfactants As surface-active components it is possible to use anionic, cationic and nonionic surfactants.
- Common nonionic surfactants are, for example, ethoxylated mono-, di- and trialkylphenols, ethoxylated fatty alcohols and polyalkylene oxides.
- polyalkylene oxides preferably C 2 -C 4 -alkylene oxides and phenylsubstituted C 2 -C 4 -alkylene oxides, in particular polyethyleneoxides, polypropyleneoxides and poly (phenylethyleneoxides), especially block copolymers, in particular polypropylene oxide and polyethylene oxide blocks or poly (phenylethylene oxide) and Polyethylene oxide blocks having polymers, and also random copolymers of these alkylene oxides suitable.
- Alkylenoxidblockcopolymerisate are known and commercially z.
- suitable anionic surfactants are alkali metal and ammonium salts of alkyl sulfates (alkyl radical: C 8 -C 12 ), of sulfuric monoesters of ethoxylated alkanols (alkyl radical: C 12 -C 18 ) and ethoxylated alkylphenols (US Pat. Alkyl radicals: C 4 -C 12 ) and of alkylsulfonic acids (alkyl radical: Ci 2 -Ci 8 ).
- Suitable cationic surfactants are for example C 6 -C having 8 alkyl, alkylaryl, or heterocyclic radicals, primary, secondary, tertiary or quaternary ammonium salts, pyridinium salts, imidazolinium salts, Oxozoliniumsalze, morpholinium, Propyliumsalze, sulfonium salts and phosphonium salts.
- Cetyltrimethylammoniumbromid and sodium lauryl sulfate called.
- thermohydrolysis The hydrolysis of urea with water under the action of heat is also referred to as thermohydrolysis. From a temperature of about 60 ° C, the hydrolysis of urea and water proceeds sufficiently quickly to completely hydrolyze the urea and water to carbon dioxide and ammonia in economically meaningful periods.
- the rate of hydrolysis of the urea contained in the solution (L) increases with increasing temperature.
- the solution (L) is usually provided above ground by dissolving the urea in the solvent.
- further additives for example surface-active components (surfactants).
- the urea is usually used as granules.
- the solution (L) can be heated.
- the subject matter of the present invention is thus also a method in which the solution (L) is heated before or during the injection according to method step b).
- the subject matter of the present invention is thus also a method in which the solution (L) is heated before or during the injection according to method step b).
- the solution (L) can be used as a true solution (L). It is also possible to use as solution (L) a mixture containing solvent and urea in dissolved form and urea in undissolved form, for example in the form of crystals. For the inventive method is sufficient if the solution (L) can be pumped by conventional pumps in the gas condensate reservoir. Preferably, a true solution is used as solution (L).
- the dissolution behavior of urea in water is shown in the phase diagram in FIG. On the horizontal axis, the urea content of the solution (L) is given in% by weight, based on the total weight of the solution (L). On the right vertical axis, the temperature is given in ° C.
- the proportion of remaining after the hydrolysis of the urea residual water (RW) is given, based on the total weight of the solution used (L).
- the dashed vertical line (2) in Figure 3 indicates the urea concentration (76.9% by weight) at which the water contained in the solution (L) is completely consumed in the hydrolysis of the urea, that is, the proportion of the remaining residual water (RW) after hydrolysis of the urea is equal to 0.
- residual water (RW) remains after the hydrolysis of the urea.
- RW residual water
- RW indicates therein the proportion of residual water (RW) remaining after hydrolysis of the urea in% by weight, based on the total weight of the solution (L) used, in the event that only water is used as the solvent.
- KH indicates therein the urea fraction of the solution (L) used in wt .-%, based on the total weight of the solution used (L).
- the proportion of hypothetical Residual water (RW) calculated in wt .-% which would remain in the urea hydrolysis of this hypothetical solution (L).
- the proportion of the calculated hypothetical residual water (RW) in the solution (L) is replaced by the corresponding amount by weight of an alcohol.
- Suitable alcohols are methanol, ethanol or mixtures of ethanol and methanol, with methanol being preferred.
- the solvent (L) solution preferably contains a mixture of water and alcohol.
- KA indicates the preferred amount of the alcohol contained in the solution (L).
- KH indicates therein the urea content of the solution (L) in% by weight.
- the solution (L) preferably contains 50% by weight of urea, 35% by weight of alcohol and 15% by weight of water.
- the solution (L) preferably contains 28.5% by weight of alcohol and 16.5% by weight of water.
- the solution (L) preferably contains 22% by weight of alcohol and 18% by weight of water.
- the solution (L) preferably contains 15.5% by weight of alcohol and 19.5% by weight of water.
- the solution (L) preferably contains 9% by weight of alcohol and 21% by weight of water.
- the solution (L) preferably contains 2.5% by weight of alcohol and 22.5% by weight of water.
- the sum of urea, alcohol and water preferably gives 100 wt .-%.
- the present invention furthermore relates to a process in which the solution (L)
- KA 100 wt .-% - (KH * 1, 3), in the KA the amount of alcohol contained in the solution (L) in wt .-% and KH indicates the amount of urea contained in the solution (L) in Indicates wt .-%.
- the sum of urea, alcohol and water preferably gives 100 wt .-%.
- the urea concentration is preferably selected so that the crystallization temperature (T K ) of the solution (L) is below the reservoir temperature (T L ) of the underground gas condensate reservoir, wherein below crystallization temperature (T K ) the temperature is understood to crystallize below the dissolved urea in the solution (L), so that the solution (L) contains water, urea in dissolved form and urea in undissolved form.
- the reservoir temperature T L is preferably above the crystallization temperature T K of the solution (L) used.
- the crystallization temperature T K of the solution (L) corresponds in FIG. 1 to the curve which separates the greyed area "solution” from the area "solution + crystals".
- T L is larger than T K , the crystallization of urea from the solution (L) in the underground gas condensate deposit can be surely avoided.
- the crystallization of urea in the underground gas condensate deposit could result in the blockage of the wellbore near the underground gas condensate deposit.
- the subject matter of the present invention is therefore also a process in which the solution (L) has a crystallization temperature (T K ) which is below the reservoir temperature (T L ) of the underground gas condensate reservoir.
- the subject of the present invention is further a method in which the reservoir temperature (T L ) of the underground gas condensate deposit is higher than the crystallization temperature (T K ) of the solution (L).
- Preferred solutions (L) used are solutions having a urea concentration in the range from 50 to 76.9% by weight, based on the total weight of the solution (L). At these urea concentrations, 60 to 100% by weight of the water originally contained in the solution (L) is consumed in the hydrolysis of the urea. This prevents or at least reduces the contamination of the underground gas condensate reservoir with water.
- the present invention furthermore relates to a process in which the duration of the quiescent phase is selected so that the urea originally contained in the solution (L) in the underground gas condensate deposit is completely hydrolyzed to carbon dioxide and ammonia and 60 to 100% by weight. % of the water originally contained in the Lösunt (L).
- the present invention thus also provides a process in which the solution (L) contains 50 to 76.9% by weight of urea and 23.1 to 50% by weight of water, in each case based on the total weight of the solution (L) .
- a solution (L) with 65 to 72 wt .-% urea, preferably with 69 to 71 wt .-% urea, based on the total weight of the solution (L) is used.
- these amounts of urea can be prepared at temperatures in the range of 50 to 55 ° C to form a true solution 5 (L).
- the relatively low temperatures of 50 to 55 ° C have the advantage that at these temperatures, the hydrolysis of the urea proceeds very slowly, so that no appreciable amounts of ammonia and carbon dioxide are formed.
- the heating of the solution (L) is carried out by conventional heating elements, such as an electric heater.
- container for the preparation of the solution 10 (L) for example, stirred tank with propeller mixer can be used.
- a heating element is mounted in the production well above the gas condensate reservoir to dissolve the urea present in the solution (L) in undissolved form.
- a heating element is not mandatory. It is sufficient as stated above, if the
- Frackspalte has a very high permeability and porosity and can "absorb" the crystals.
- the supersaturated solution (L) may be prepared as described above and then injected through the production well into the underground gas condensate reservoir.
- it is also possible to dissolve the urea in the solution (L) devistage only partially, so that the solution (L) contains water, urea in dissolved form and urea in undissolved form.
- This solution (L) is injected as described above, subsequently through the production well into the underground gas condensate deposit.
- this is not mandatory.
- the amount of solution (L) injected in step b) depends on the geological parameters of the underground gas condensate deposit, including the permeability of the deposit and the size of the area (critical area of Figure 2) in which the well zone is liquid Natural gas condensate is blocked.
- the solution (L) is injected in volumes corresponding at most to the pore volume of the critical area (KB) blocked by the liquid natural gas condensate.
- Suitable volumes of the solution (L) injected in process step b) are in the range of 1 to 10 m 3 per 1 m of the production well, which is surrounded by the critical region (KB), preferably in the range of 2 to 8 m 3 , more preferably in Range from 3 to 7 m 3 .
- the present invention thus also provides a process in which the solution (L) in process step b) is injected in volumes which, in the hydrolysis of urea, lead to a gas volume of carbon dioxide and ammonia which is at least the pore volume of the critical region (KB ) corresponds.
- methanol may be added to the solution (L).
- final phase means that at least 90% by weight of the solution (L) has been injected, based on the total weight of the solution (L) injected in process step b). It is also possible to completely inject solution (L) and subsequently inject methanol.
- the present invention thus also relates to a process in which, together with the injection of the solution (L) or after the injection of the solution (L) according to process step b), methanol is injected into the production well.
- the described solution (L) can also be used for flooding gas condensate deposits.
- at least one hole is used as a continuous injection well.
- the solution (L) is injected into this hole.
- the solution (L) forms gases in the deposit. This process can be used particularly efficiently in the development of deposits which were shut down due to the massive failure of a retrograde gas condensate.
- a quiescent phase is generally set up in which the urea in the underground gas condensate deposit is hydrolyzed to ammonia and carbon dioxide.
- the duration of this quiescent phase is chosen so that a complete hydrolysis of the urea takes place.
- the rate at which hydrolysis of the urea occurs depends on the reservoir temperature T L of the underground gas condensate reservoir and the temperature at which the solution (L) is injected in process step b).
- T L the reservoir temperature
- T L the temperature at which the solution (L) is injected in process step b).
- the period of rest is generally in the range of 1 to 10 days.
- the rest phase may be shorter, for example 1 to 5 days.
- the range of rest period is 5 to 10 days.
- the rest phase must be chosen correspondingly longer, for example in the range of 15 to 20 days.
- the urea contained in the solution (L) in the underground gas condensate deposit is completely hydrolyzed.
- the production well is closed in a preferred embodiment. This can be done by conventional means, such as packers. By closing the production well, the pressure in the critical region of the underground gas condensate deposit increases, whereby the efficiency of the method according to the invention is increased.
- the subject matter of the present invention is thus also a method in which the at least one production well is closed during the quiescent phase according to step c).
- the resulting carbon dioxide is partially dissolved in natural gas and mainly in the liquid natural gas condensate.
- the viscosity of the liquid natural gas condensate is lowered, whereby the mobility of the liquid natural gas condensate in the critical range (KB) of the gas condensate reservoir is significantly increased.
- the resulting ammonia dissolves in the formation water present in the deposit as well as in the water injected with the solution (L) and forms an alkaline ammonia buffer system having a pH of 9-10. If the deposit is slightly diluted, highly alkaline solutions are formed: Under certain conditions ammonia may also partially liquefy in the deposit. Liquid ammonia and aqueous ammonia solutions are very good solvents. This additionally increases the mobility of the gas condensate.
- This buffer system has a surfactant-like action in the underground gas condensate reservoir.
- the interfacial tension between the phases i. reduced between the natural gas phase and the liquid natural gas condensate phase and optionally the Formationswasserphase.
- the formation of the gases (ammonia and carbon dioxide) in the underground gas condensate deposit also has a purely mechanical displacement effect of the liquid natural gas condensate.
- the viscosity of the liquid natural gas condensate By lowering the viscosity of the liquid natural gas condensate and increasing the mobility of the liquid natural gas condensate, the production of natural gas and liquefied natural gas condensate from the underground gas condensate reservoir is facilitated. As a result, the delivery rate increases significantly.
- natural gas flushes the liquid natural gas condensate present in the critical area (KB) of the underground gas condensate deposit in the direction of the production well. This leads to a further increase in the production rate.
- the solution (L) in process step b) is introduced in such amounts that the volume of gas produced during the hydrolysis of urea corresponds at least to the pore volume of the critical region of the underground gas condensate reservoir.
- the present invention thus also relates to the use of a solution (L) containing water and urea as a means for increasing the delivery rates of natural gas and / or natural gas condensate from a gas condensate reservoir containing a gas mixture with retrograde condensation behavior.
- the solution (L) as a means for increasing the delivery rates, the above statements and preferences with regard to the solution (L) apply accordingly.
- Process step d) natural gas and / or natural gas condensate from the underground gas condensate deposit is promoted, that is resumed.
- the promotion takes place according to conventional methods.
- the natural gas and the natural gas condensate can be conveyed through the production well through which, in process step b), the solution (L) was injected into the underground gas condensate reservoir. It is also possible to drill additional wells into the underground gas condensate deposit.
- the production of natural gas and natural gas condensate can then be carried out through the production well or through further drilling.
- the production bore can also fulfill the function of an injection well through which a flood medium is pressed into the underground gas condensate deposit, the actual promotion then takes place via the one or more further holes. It is also possible to inject a flood medium via the one or more further holes into the underground gas condensate deposit and carry out the production through the production through which in step b) the solution (L) was injected.
- steps b) and c) are performed again.
- the steps b) and c) of the method according to the invention are thus always carried out when a critical area (KB) forms again in the underground gas condensate deposit which is blocked by liquid natural gas condensate.
- the subject matter of the present invention is therefore also the use of a solution (L) as a means for increasing the delivery rates of natural gas and / or natural gas condensate from a subterranean gas condensate deposit having a gas mixture with retrograde condensation behavior.
- a solution (L) as a means for increasing the delivery rates of natural gas and / or natural gas condensate from a subterranean gas condensate deposit having a gas mixture with retrograde condensation behavior.
- the present invention is further illustrated by the following Example and Figures 1, 2, 3 and 4, without being limited thereto.
- reference numerals have the following meanings: al single-phase liquid region bpc bubble point curve l + v two-phase region dpc dew point curve
- FIG. 1 A first figure in the underground gas condensate deposit
- FIG. 2 The phase behavior of gas mixtures with retrograde condensation behavior.
- phase diagram of an aqueous urea solution The phase diagram of an aqueous urea solution.
- Figure 4 shows different embodiments of a drilled hole 3.
- Figure 4a shows a vertical production bore. Region 4 represents the area which is blocked by liquid natural gas condensate.
- Figure 4b shows a 25 embodiment in which a deflected bore has been drilled.
- FIG. 4 c shows an embodiment in which a deflected bore has been drilled and in which the underground gas condensate deposit has a fracking gap 5.
- a deflected production well 3 For the development of a gas condensate deposit which is stored at a depth in the range of 3400 to 3700 m, a deflected production well 3 according to FIG. 4b or 4c is drilled.
- the thickness of the productive layer is 50 to 80 m.
- the reservoir temperature T L is 105 ° C.
- the reservoir is about
- the permeability of the deposit is low and is between 0.5 and 5.0 mD. After the deflection of the deflected production bore 3, it is fractured in the region of the productive layer, whereby a fracture zone 5 is formed.
- the porosity of the gas condensate deposit ranges from 0.2 to 0.25%. After the sinking and fracing of the production well 3 is with the
- the critical area 4 in which the blocking by liquid natural gas condensate has occurred, is estimated at a radius of about 20 m.
- the area has a cylindrical shape, in the center of which the production bore 3 is located.
- the solution (L) Immediately before injection of the aqueous solution (L), the solution (L) has a temperature of 50 ° C to prevent the crystallization of urea from the solution (L).
- the injection of the solution (L) by means of conventional pumps.
- a resting phase is introduced. The rest period is 3 to 5 days.
- the quiescent phase the urea in the underground gas condensate deposit is completely hydrolyzed.
- the production well is closed. This increases the pressure in the critical region of the underground gas condensate deposit, which increases the efficiency of the process according to the invention.
- additional methanol can be used.
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Abstract
Description
Claims
Priority Applications (4)
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EA201590646A EA201590646A1 (en) | 2012-09-27 | 2013-09-25 | METHOD FOR THE EXTRACTION OF NATURAL GAS AND NATURAL GAS CONDENSATE FROM UNDERGROUND GAS-CONDENSATE FIELD |
US14/431,001 US20150240608A1 (en) | 2012-09-27 | 2013-09-25 | Process For Producing Natural Gas And Natural Gas Condensate From Underground Gas Condensate Deposits |
EP13770677.6A EP2900792A1 (en) | 2012-09-27 | 2013-09-25 | Method for the recovery of natural gas and natural gas condensate from subterranean gas condensate reservoirs |
CA 2882932 CA2882932A1 (en) | 2012-09-27 | 2013-09-25 | Process for producing natural gas and natural gas condensate from underground gas condensate deposits |
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EP12186281.7 | 2012-09-27 | ||
EP12186281 | 2012-09-27 |
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PCT/EP2013/070007 WO2014049015A1 (en) | 2012-09-27 | 2013-09-25 | Method for the recovery of natural gas and natural gas condensate from subterranean gas condensate reservoirs |
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US (1) | US20150240608A1 (en) |
EP (1) | EP2900792A1 (en) |
CA (1) | CA2882932A1 (en) |
EA (1) | EA201590646A1 (en) |
WO (1) | WO2014049015A1 (en) |
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AR103391A1 (en) | 2015-01-13 | 2017-05-03 | Bp Corp North America Inc | METHODS AND SYSTEMS TO PRODUCE HYDROCARBONS FROM ROCA HYDROCARBON PRODUCER THROUGH THE COMBINED TREATMENT OF THE ROCK AND INJECTION OF BACK WATER |
US20190085235A1 (en) * | 2016-09-30 | 2019-03-21 | Jeffrey Harwell | Methods of enhancing oil recovery |
CN110005399B (en) * | 2019-04-16 | 2022-05-31 | 重庆科技学院 | Experimental method for measuring volume of retrograde condensate oil containing excessive water condensate gas |
EP4038159A1 (en) * | 2019-09-30 | 2022-08-10 | Saudi Arabian Oil Company | Methods for reducing condensation |
CN115788385B (en) * | 2022-12-29 | 2024-05-24 | 西南石油大学 | Determination method for condensate water-gas ratio of high Wen Ningxi gas reservoir |
CN116840192B (en) * | 2023-03-23 | 2024-01-09 | 西南石油大学 | Cross-scale condensate gas mist flow gravity settlement relaxation time testing method |
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US4572296A (en) * | 1984-09-20 | 1986-02-25 | Union Oil Company Of California | Steam injection method |
US4982789A (en) * | 1990-01-16 | 1991-01-08 | Texaco Inc. | Method of using urea as a sacrificial agent for surfactants in enhanced oil recovery |
US5209295A (en) * | 1991-12-02 | 1993-05-11 | Intevep, S.A. | In-situ reduction of oil viscosity during steam injection process in EOR |
EP2537910A1 (en) * | 2011-06-22 | 2012-12-26 | Wintershall Holding GmbH | Method for procuring viscous crude oil from an underground storage facility |
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US2767791A (en) * | 1954-10-07 | 1956-10-23 | Shell Dev | Method of preventing retrograde condensation in gas fields |
US4635721A (en) * | 1983-11-29 | 1987-01-13 | Amoco Corporation | Method of displacing fluids within a gas-condensate reservoir |
US4765407A (en) * | 1986-08-28 | 1988-08-23 | Amoco Corporation | Method of producing gas condensate and other reservoirs |
US6761868B2 (en) * | 2001-05-16 | 2004-07-13 | The Chemithon Corporation | Process for quantitatively converting urea to ammonia on demand |
GB2436576B (en) * | 2006-03-28 | 2008-06-18 | Schlumberger Holdings | Method of facturing a coalbed gas reservoir |
CN102317403A (en) * | 2008-12-18 | 2012-01-11 | 3M创新有限公司 | Method of contacting hydrocarbon-bearing formations with fluorinated ether compositions |
US9228424B2 (en) * | 2011-05-31 | 2016-01-05 | Riverbend, S.A. | Method of treating the near-wellbore zone of the reservoir |
US20140054050A1 (en) * | 2012-08-24 | 2014-02-27 | Halliburton Energy Services, Inc. | Gas Fracture Injection to Overcome Retrograde Condensation in Gas Wells |
-
2013
- 2013-09-25 US US14/431,001 patent/US20150240608A1/en not_active Abandoned
- 2013-09-25 WO PCT/EP2013/070007 patent/WO2014049015A1/en active Application Filing
- 2013-09-25 EP EP13770677.6A patent/EP2900792A1/en not_active Withdrawn
- 2013-09-25 CA CA 2882932 patent/CA2882932A1/en not_active Abandoned
- 2013-09-25 EA EA201590646A patent/EA201590646A1/en unknown
Patent Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
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US4572296A (en) * | 1984-09-20 | 1986-02-25 | Union Oil Company Of California | Steam injection method |
US4982789A (en) * | 1990-01-16 | 1991-01-08 | Texaco Inc. | Method of using urea as a sacrificial agent for surfactants in enhanced oil recovery |
US5209295A (en) * | 1991-12-02 | 1993-05-11 | Intevep, S.A. | In-situ reduction of oil viscosity during steam injection process in EOR |
EP2537910A1 (en) * | 2011-06-22 | 2012-12-26 | Wintershall Holding GmbH | Method for procuring viscous crude oil from an underground storage facility |
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EP2900792A1 (en) | 2015-08-05 |
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EA201590646A1 (en) | 2015-09-30 |
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