US20210115325A9 - Polymer flooding processes for viscous oil recovery in carbonate reservoirs - Google Patents
Polymer flooding processes for viscous oil recovery in carbonate reservoirs Download PDFInfo
- Publication number
- US20210115325A9 US20210115325A9 US16/557,297 US201916557297A US2021115325A9 US 20210115325 A9 US20210115325 A9 US 20210115325A9 US 201916557297 A US201916557297 A US 201916557297A US 2021115325 A9 US2021115325 A9 US 2021115325A9
- Authority
- US
- United States
- Prior art keywords
- polymer
- smart water
- composition
- ppm
- 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.)
- Granted
Links
- 229920000642 polymer Polymers 0.000 title claims abstract description 161
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 title claims abstract description 43
- 238000000034 method Methods 0.000 title description 38
- 238000011084 recovery Methods 0.000 title description 30
- 230000008569 process Effects 0.000 title description 23
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 130
- 239000000203 mixture Substances 0.000 claims abstract description 75
- 239000011435 rock Substances 0.000 claims abstract description 25
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 24
- 238000011065 in-situ storage Methods 0.000 claims abstract description 19
- 150000003839 salts Chemical class 0.000 claims abstract description 11
- 239000007787 solid Substances 0.000 claims abstract description 9
- 235000002639 sodium chloride Nutrition 0.000 claims description 17
- 229920001577 copolymer Polymers 0.000 claims description 15
- HRPVXLWXLXDGHG-UHFFFAOYSA-N Acrylamide Chemical compound NC(=O)C=C HRPVXLWXLXDGHG-UHFFFAOYSA-N 0.000 claims description 14
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 claims description 12
- 150000001768 cations Chemical class 0.000 claims description 11
- CSNNHWWHGAXBCP-UHFFFAOYSA-L Magnesium sulfate Chemical compound [Mg+2].[O-][S+2]([O-])([O-])[O-] CSNNHWWHGAXBCP-UHFFFAOYSA-L 0.000 claims description 8
- PMZURENOXWZQFD-UHFFFAOYSA-L Sodium Sulfate Chemical compound [Na+].[Na+].[O-]S([O-])(=O)=O PMZURENOXWZQFD-UHFFFAOYSA-L 0.000 claims description 6
- 239000011780 sodium chloride Substances 0.000 claims description 6
- 229910052938 sodium sulfate Inorganic materials 0.000 claims description 6
- TWRXJAOTZQYOKJ-UHFFFAOYSA-L Magnesium chloride Chemical compound [Mg+2].[Cl-].[Cl-] TWRXJAOTZQYOKJ-UHFFFAOYSA-L 0.000 claims description 5
- NIXOWILDQLNWCW-UHFFFAOYSA-M Acrylate Chemical compound [O-]C(=O)C=C NIXOWILDQLNWCW-UHFFFAOYSA-M 0.000 claims description 4
- OYPRJOBELJOOCE-UHFFFAOYSA-N Calcium Chemical compound [Ca] OYPRJOBELJOOCE-UHFFFAOYSA-N 0.000 claims description 4
- 239000011575 calcium Substances 0.000 claims description 4
- 229910001424 calcium ion Inorganic materials 0.000 claims description 4
- 229910052943 magnesium sulfate Inorganic materials 0.000 claims description 4
- 150000003467 sulfuric acid derivatives Chemical class 0.000 claims description 4
- UXVMQQNJUSDDNG-UHFFFAOYSA-L Calcium chloride Chemical compound [Cl-].[Cl-].[Ca+2] UXVMQQNJUSDDNG-UHFFFAOYSA-L 0.000 claims description 3
- JLVVSXFLKOJNIY-UHFFFAOYSA-N Magnesium ion Chemical compound [Mg+2] JLVVSXFLKOJNIY-UHFFFAOYSA-N 0.000 claims description 3
- 229910001425 magnesium ion Inorganic materials 0.000 claims description 3
- 235000019341 magnesium sulphate Nutrition 0.000 claims description 3
- 235000011152 sodium sulphate Nutrition 0.000 claims description 3
- ABUFMGLVKVVDFW-UHFFFAOYSA-N 2-methylpropane-2-sulfonic acid;prop-2-enamide Chemical compound NC(=O)C=C.CC(C)(C)S(O)(=O)=O ABUFMGLVKVVDFW-UHFFFAOYSA-N 0.000 claims description 2
- UIIMBOGNXHQVGW-DEQYMQKBSA-M Sodium bicarbonate-14C Chemical compound [Na+].O[14C]([O-])=O UIIMBOGNXHQVGW-DEQYMQKBSA-M 0.000 claims description 2
- 239000001110 calcium chloride Substances 0.000 claims description 2
- 229910001628 calcium chloride Inorganic materials 0.000 claims description 2
- 235000011148 calcium chloride Nutrition 0.000 claims description 2
- 229910001629 magnesium chloride Inorganic materials 0.000 claims description 2
- 235000011147 magnesium chloride Nutrition 0.000 claims description 2
- QAOWNCQODCNURD-UHFFFAOYSA-N Sulfuric acid Chemical compound OS(O)(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-N 0.000 claims 1
- 239000003921 oil Substances 0.000 description 54
- 150000002500 ions Chemical class 0.000 description 24
- 238000005755 formation reaction Methods 0.000 description 22
- 238000002347 injection Methods 0.000 description 22
- 239000007924 injection Substances 0.000 description 22
- 239000012530 fluid Substances 0.000 description 19
- 239000013535 sea water Substances 0.000 description 15
- 239000011148 porous material Substances 0.000 description 13
- 239000010779 crude oil Substances 0.000 description 11
- UIIMBOGNXHQVGW-UHFFFAOYSA-M Sodium bicarbonate Chemical compound [Na+].OC([O-])=O UIIMBOGNXHQVGW-UHFFFAOYSA-M 0.000 description 6
- 238000006073 displacement reaction Methods 0.000 description 6
- 241000237858 Gastropoda Species 0.000 description 5
- 239000000295 fuel oil Substances 0.000 description 4
- BHPQYMZQTOCNFJ-UHFFFAOYSA-N Calcium cation Chemical compound [Ca+2] BHPQYMZQTOCNFJ-UHFFFAOYSA-N 0.000 description 3
- FYYHWMGAXLPEAU-UHFFFAOYSA-N Magnesium Chemical compound [Mg] FYYHWMGAXLPEAU-UHFFFAOYSA-N 0.000 description 3
- 239000007832 Na2SO4 Substances 0.000 description 3
- QAOWNCQODCNURD-UHFFFAOYSA-L Sulfate Chemical compound [O-]S([O-])(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-L 0.000 description 3
- 239000000654 additive Substances 0.000 description 3
- 230000004075 alteration Effects 0.000 description 3
- 150000001450 anions Chemical class 0.000 description 3
- 229910052791 calcium Inorganic materials 0.000 description 3
- 125000003178 carboxy group Chemical group [H]OC(*)=O 0.000 description 3
- 230000002349 favourable effect Effects 0.000 description 3
- 230000003993 interaction Effects 0.000 description 3
- 239000011777 magnesium Substances 0.000 description 3
- 229910052749 magnesium Inorganic materials 0.000 description 3
- 230000035699 permeability Effects 0.000 description 3
- 229920002401 polyacrylamide Polymers 0.000 description 3
- 229910000030 sodium bicarbonate Inorganic materials 0.000 description 3
- 239000000243 solution Substances 0.000 description 3
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 description 2
- VEXZGXHMUGYJMC-UHFFFAOYSA-M Chloride anion Chemical compound [Cl-] VEXZGXHMUGYJMC-UHFFFAOYSA-M 0.000 description 2
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 description 2
- 230000000996 additive effect Effects 0.000 description 2
- 230000008901 benefit Effects 0.000 description 2
- LLSDKQJKOVVTOJ-UHFFFAOYSA-L calcium chloride dihydrate Chemical compound O.O.[Cl-].[Cl-].[Ca+2] LLSDKQJKOVVTOJ-UHFFFAOYSA-L 0.000 description 2
- 230000001186 cumulative effect Effects 0.000 description 2
- 238000005516 engineering process Methods 0.000 description 2
- 239000008398 formation water Substances 0.000 description 2
- DHRRIBDTHFBPNG-UHFFFAOYSA-L magnesium dichloride hexahydrate Chemical compound O.O.O.O.O.O.[Mg+2].[Cl-].[Cl-] DHRRIBDTHFBPNG-UHFFFAOYSA-L 0.000 description 2
- 239000011734 sodium Substances 0.000 description 2
- 229910052708 sodium Inorganic materials 0.000 description 2
- 239000003643 water by type Substances 0.000 description 2
- OBRHFMNBWAWJRM-UHFFFAOYSA-N (prop-2-enoylamino) 2-methylpropane-2-sulfonate Chemical compound CC(C)(C)S(=O)(=O)ONC(=O)C=C OBRHFMNBWAWJRM-UHFFFAOYSA-N 0.000 description 1
- BVKZGUZCCUSVTD-UHFFFAOYSA-M Bicarbonate Chemical compound OC([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-M 0.000 description 1
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 238000006424 Flood reaction Methods 0.000 description 1
- 239000008186 active pharmaceutical agent Substances 0.000 description 1
- 125000000129 anionic group Chemical group 0.000 description 1
- 239000008346 aqueous phase Substances 0.000 description 1
- 239000012267 brine Substances 0.000 description 1
- 229910000019 calcium carbonate Inorganic materials 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 125000005587 carbonate group Chemical group 0.000 description 1
- 125000002843 carboxylic acid group Chemical group 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 238000001311 chemical methods and process Methods 0.000 description 1
- 239000003795 chemical substances by application Substances 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 230000001627 detrimental effect Effects 0.000 description 1
- 238000007865 diluting Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 238000013213 extrapolation Methods 0.000 description 1
- 239000013505 freshwater Substances 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 230000007062 hydrolysis Effects 0.000 description 1
- 238000006460 hydrolysis reaction Methods 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 229920000058 polyacrylate Polymers 0.000 description 1
- 239000002244 precipitate Substances 0.000 description 1
- 230000000135 prohibitive effect Effects 0.000 description 1
- 230000009257 reactivity Effects 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 238000000518 rheometry Methods 0.000 description 1
- -1 salt ions Chemical class 0.000 description 1
- 229920006395 saturated elastomer Polymers 0.000 description 1
- 239000002455 scale inhibitor Substances 0.000 description 1
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 1
- 239000003381 stabilizer Substances 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
- 230000008961 swelling Effects 0.000 description 1
- 239000011800 void material Substances 0.000 description 1
Images
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
- C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
- C09K8/588—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific polymers
-
- C—CHEMISTRY; METALLURGY
- C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
- C08K—Use of inorganic or non-macromolecular organic substances as compounding ingredients
- C08K3/00—Use of inorganic substances as compounding ingredients
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/20—Displacing by water
Definitions
- This invention relates to methods and compositions for polymer flooding operations. More specifically, the invention relates to methods and compositions using smart water and polymers for polymer flooding operations in carbonate reservoirs.
- Polymer flooding processes are one of the matured enhanced oil recovery (EOR) technologies and are currently gaining some importance for viscous oil recovery in carbonate reservoirs. Increased aqueous phase viscosities due to polymer addition decrease the mobility of injection water to provide some mobility control and mitigate viscous fingering with such crude oils in the displacement process.
- Polyacrylamide based polymers or co-polymers are the most widely employed polymers for EOR today in the industry. These polymers are anionic in nature and their viscosifying characteristics are hindered by salinity and the monovalent/divalent cations present in the makeup water.
- the negative carboxyl groups of partially hydrolyzed EOR polymers interact strongly with positively charged ions such as monovalent and divalent cations present in the makeup water.
- high salinity water is typically limited to situations in which the availability of high salinity water, such as seawater, is readily available.
- high polymer dosage can become cost prohibitive to apply polymer flooding technology in certain formations containing viscous crude oils.
- the formation temperatures and in-situ water composition can impact the type of polymer chosen for EOR.
- the polymer concentration is typically 1000 ppm or greater in the injection fluid.
- the injection fluid is typically injected as a finite slug of at least 0.3 pore volumes for processes involving carbonate reservoirs and viscous oil recovery.
- This invention relates to methods and compositions for polymer flooding operations. More specifically, the invention relates to methods and compositions using smart water and polymers for polymer flooding operations in carbonate reservoirs.
- a first aspect of a composition for use in a polymer flooding operation in a viscous oil containing carbonate reservoir formation with in situ rock includes a polymer, the polymer operable to increase the viscosity of the composition, and a smart water, the smart water operable to alter a wettability of the in situ rock.
- the smart water has a total dissolved solids of between 5,000 ppm and 7,000 ppm, the total dissolved solids comprises a salt, and the composition has a viscosity between 4 cP and 100 cP.
- the polymer comprises a copolymer of acrylamide and acrylate. In certain aspects, the polymer comprises a copolymer of acrylamide and acrylamide tertiary butyl sulfonate (ATBS).
- the salt can be selected from the group consisting of sodium chloride, calcium chloride, magnesium chloride, sodium sulfate, magnesium sulfate, sodium bicarbonate, and combinations thereof.
- the smart water comprises 300 ppm or less of divalent cations. In certain aspects, the smart water comprises 400 ppm or greater divalent anions. In certain aspects, the polymer is present in an amount between 1,000 ppm by weight and 3,000 ppm by weight.
- a method of recovering an oil from a carbonate reservoir formation includes the steps of injecting a smart water/polymer slug into the carbonate reservoir formation, where the smart water/polymer slug includes a smart water and a polymer, allowing the smart water/polymer slug to alter the wettability of the carbonate reservoir formation, and injecting a seawater chase, where the seawater chase is operable to recover the oil from the carbonate reservoir formation.
- the method further includes the step of injecting a smart water slug into the carbonate reservoir formation after the step of allowing the smart water/polymer slug to alter the wettability of the carbonate reservoir formation.
- the method further includes the step of injecting one or more tapered smart water/polymer plugs into the carbonate reservoir formation after the step of allowing the smart water/polymer slug to alter the wettability of the carbonate reservoir formation.
- the smart water/polymer slug has a volume of at least 0.3 pore volumes.
- the oil is a viscous oil. In certain aspects, the oil is a heavy oil.
- the smart water wherein the smart water has a total dissolved solids of between 5,000 ppm and 7,000 ppm, wherein the total dissolved solids comprises a salt.
- the smart water/polymer slug has a viscosity between 4 cP and 100 cP.
- FIG. 1 is a graphical comparison of viscosity versus temperature for the two different compositions of Example 1.
- FIG. 2 is a graphical representation of the EOR Oil Recovery versus pore volumes injected from core flood study in Example 2.
- the present invention is directed to compositions and methods related to the use of smart water and polymers.
- the compositions and methods of the present invention can be used in polymer flooding processes involving viscous oil recovery in carbonate reservoirs.
- the compositions and methods described herein lower the required polymer concentration by up to 50% due to the lower salinity and specific ionic composition of the smart water.
- the specific ionic composition favorably interacts with the in-situ rock and fluids, including crude oil and formation water, of the carbon reservoir to alter the wettability of the in-situ rock and improve microscopic sweep efficiency at the pore scale.
- the lower salinity and specific ion composition can increase the viscosifying characteristics of the polymer resulting in a reduction in the polymer concentration required as compared to conventional polymer flooding fluids, such as seawater.
- the polymer provides better mobility control of the smart water, which increases macroscopic sweep efficiency.
- the compositions and methods of the present invention have a synergy that results in additional incremental oil recovery (up to 5 to 10%).
- the compositions and methods of the present invention exhibit improved efficiency and economics due to lower polymer volume compared to conventional polymer flooding process used for viscous oil recovery in carbonate reservoirs.
- smart water refers to an injection water of tuned water chemistry; tuned in terms of both salinity and specific individual ion compositions.
- smart water is a lower salinity water containing between about 5,000 ppm and 7,000 ppm TDS, 300 ppm or less of the total amount of divalent cations and 400 ppm or greater of the total amount of divalent anions.
- the divalent anion is sulfates, such that the smart water contains 400 ppm or greater sulfates.
- the viscosity of smart water at surface conditions can be in the range of between about 0.9 cP and 1.0 cP.
- the viscosity of smart water at carbonate reservoir conditions can be in the range between about 0.2 cP and 0.3 cP.
- smart water can be prepared by diluting seawater with fresh water.
- the smart water is in the absence of external compounds or additives, other than the TDS and ions specified above.
- Depletion of monovalent ions and enrichment of divalent ions is desired in a smart water.
- higher amounts of sulfates and lower amounts of both monovalent cations and divalent cations are preferred in a smart water for polymer floods so as to advantageously minimize the interaction of positively charged ions with negative carboxyl groups present in the polymer.
- Carbonate surfaces typically exhibit a positive charge at formation water salinities, composition and pH at reservoir conditions.
- the negative carboxylic acid groups of crude oil are attached to the carbonate rock surface.
- the mechanism can be understood as follows. Initially, sulfate ions adsorb on the in situ rock surface to reduce the attraction of the surface to the negatively charged carboxylic groups in crude oil.
- the calcium ions further reduce this attraction by bonding to the oil side of the interface.
- the calcium ions are later substituted by magnesium ions due to the increasing reactivity of these ions at higher temperatures.
- These favorable ion interactions at the rock surface change the wettability of the in situ rock towards intermediate-wet or water-wet state to release oil from the pores of reservoir rock.
- the presence of non-active monovalent ions can prevent the accessibility of the divalent ions to interact at the in situ rock surface thereby reducing the effectiveness of the process. Therefore, it is advantageous to provide an injection fluid with a reduced amount of monovalent ions.
- water refers to a high salinity water on the order of about 35,000 ppm to 56,000 ppm TDS that includes significant amounts of divalent cations.
- Table 1 shows a comparison of a typical seawater to a representative smart water.
- divalent ions includes, but is not limited to calcium, magnesium, and sulfate. As will be understood by one of the art, calcium and magnesium are cations.
- “monovalent ions” includes, but is not limited to, sodium and chloride.
- the monovalent ions and divalent ions can be present in the form of salts.
- the smart water can include one or more salts.
- salts useful in the present invention can include sodium chloride (NaCl), calcium chloride (CaCl 2 ), magnesium chloride (MgCl 2 ), sodium sulfate (Na 2 SO 4 ), magnesium sulfate (MgSO 4 ), NaHCO 3 and combinations of the same.
- in situ reservoir conditions can refer to elevated pressure and temperature conditions, rock mineralogical compositions, and fluid compositions locally existing in the reservoir.
- viscous oil or “viscous crude oil” refers to in-situ reservoir crude oil having a viscosity of greater than about 2 and less than 100 cP at in-situ reservoir conditions.
- heavy oil refers to crude oil of less than 22.3° API gravity or more than 100 cP viscosity at in-situ reservoir conditions.
- incremental oil recovery refers to an increase in oil recovery in terms of percent original oil in place over any base case, or conventional recovery process as a regular water flood.
- the pore scale refers to the scale corresponding to the pore size range of the pore space of the in-situ rock, typically on the order of a 2-5 microns.
- microscopic sweep efficiency refers to sweep efficiency of displacing fluid at the pore scale. Microscopic sweep efficiency is a measure of how effectively the injection fluid mobilizes and displaces oil from the pores in the reservoir rock.
- Macroscopic sweep efficiency or “volumetric sweep efficiency” refers to sweep efficiency of displacing fluid at the reservoir scale. Macroscopic sweep efficiency is a measure of how effectively the displacing fluid contacts the volume of a reservoir both areally and vertically.
- “synergy” refers to the additive effect of the favorable interaction of a secondary recovery process (such as smart water) to improve the performance and economics of a primary recovery process (such as polymer) without losing the individual recovery benefit of two processes when combined.
- carbonate reservoirs refers to a sedimentary rock condition deposited in a marine environment and mostly made up of calcium carbonate. Carbonate reservoirs are chemically active and can undergo a range of physical and chemical processes known as diagenesis. Diagenesis alters the rock structure to show large abrupt variations in rock properties such as porosity.
- polymer flooding refers to the use of viscosified injection waters to reduce the mobility of injection water for better reservoir contact.
- a polymer flooding differs from a water flooding process in that water flooding processes use plain water such as seawater for injection into reservoirs to provide some pressure support and physically displace oil from the injection wells to the producing wells.
- total dissolved solids refers to the sum of the combined amount of all inorganic salts contained in the injection water in the form of charged ions, such as monovalent ions and divalent ions. TDS can also be considered a measure of the salinity of a smart water.
- a composition for a polymer flooding process involving viscous oil recovery in carbonate reservoir formations with in situ rock is herein provided.
- the composition is a smart water/polymer composition.
- the composition can include a smart water and a polymer.
- composition of the smart water can be selected based on the carbonate reservoir formation.
- the smart water compositions of the present invention are not suitable for sandstone reservoirs.
- Sandstone reservoirs require injection fluids enriched in monovalent ions with lower concentrations of divalent ions.
- the polymer can be any polymer capable of increasing the viscosity of the smart water.
- polymer suitable for use in the present invention include copolymers of acrylamide and acrylate and copolymers of acrylamide and acrylamido tertiary butyl sulfonate (ATBS).
- ATBS acrylamido tertiary butyl sulfonate
- copolymers of acrylamide and ATBS can tolerate reservoir temperatures up to 95° C. as in the prevailing carbonate reservoirs.
- the copolymer of acrylamide and acrylate can be from the standard FlopaamTM series polymers from SNF Floerger, France.
- the copolymer of acrylamide and ATBS can be from the FlopaamTM AN series of polymers from SNF Floerger, France.
- the polymer can be added to the smart water at concentrations in the range from 0.05 to 0.30 weight percent (wt %) (500 ppm by weight to 3000 ppm by weight), alternately in the range from 0.1 wt % (1000 ppm) to 0.3 wt % (3000 ppm), alternately in the range from 0.1 wt % to 0.2 wt %, alternately in the range from 0.1 wt % to 0.15 wt %, and alternately in the range from 0.15 wt % to 0.2 wt % to produce the smart water/polymer composition.
- the polymer concentration in the smart water/polymer composition is in the range from 1000 ppm to 3000 ppm.
- the polymer concentration in the smart water/polymer composition is in the range from 1000 ppm to 2000 ppm.
- the injection smart water is used as the makeup water to dissolve the polymer and carry the polymer into the carbonate reservoir formation.
- the smart water/polymer composition can alter a wettability of the in situ rock in the carbonate reservoir formation with improved mobility control. When the rock wettability is altered towards a more favorable intermediate-wet or water-wet state, it reduces capillary trapping of residual oil to release more oil from pores. In other words, the alteration of rock wettability advantageously improves microscopic sweep efficiency.
- the increased viscosity of smart water due to polymer addition will also increase the reservoir contact, both vertical contact and areal contact, of the injection fluid to mobilize the remaining oil.
- the viscosity of smart water due to the presence of the polymer improves macroscopic sweep efficiency as compared to a smart water in the absence of polymer.
- the enhancements in both microscopic sweep efficiency and macroscopic sweep efficiency can result in a higher incremental oil recovery as compared to an injection fluid that does not have improved efficiencies.
- the smart water/polymer composition is in the absence of additives.
- Additives can include, but are not limited to, viscosifiers, surfactants, stabilizers, pH control agents, scale inhibitors.
- the smart water/polymer compositions include only water, divalent ions, monovalent ions and polymer.
- a polymer flooding process for use in viscous oil recovery in carbonate reservoirs is provided.
- the polymer flooding process of the present invention can be used in any carbonate reservoir containing oil to be recovered.
- the oil to be recovered can include viscous oil and heavy oil.
- the polymer flooding process of the present invention uses the smart water/polymer composition to recover viscous oil.
- polymer flooding process is limited to use in carbonate reservoirs.
- concentration of polymer in a smart water/polymer composition can be chosen based on the desired viscosity and to achieve water-oil mobility ratio for the specific viscous oil of interest in a carbonate reservoir.
- the “mobility ratio” as used herein refers to the ratio of mobility of injection fluid (such as water) to that of the displaced fluid (such as crude oil). Mobility is defined as the ratio of effective permeability to viscosity. The effective permeability can be determined at the water saturation ahead of the displacement front for oil while at the water saturation behind the displacement front for injection fluid. Typically, a mobility ratio of less than or equal to one is preferred to provide piston like displacement and avoid viscous fingering.
- the polymer flooding process for use in oil recovery can include in a first step, injecting an initial slug of the smart water/polymer composition into a carbonate reservoir formation, the volume of the initial slug of the smart water polymer composition can be at least 0.3 pore volumes (PV).
- PV pore volumes
- pore volume refers to a unit of measure for void space available in the reservoir rock material.
- the polymer flooding process for use in oil recovery can include in a first step of injecting a smart water/polymer slug into a carbonate reservoir formation, the volume of the smart water polymer slug can be at least 0.3 PV.
- a smart water slug can be injected into the carbonate reservoir formation, the volume of the smart water slug can be at least 0.5 PV.
- the polymer flooding process can include a continuous injection of seawater chase.
- seawater chase refers to the use of seawater as a chase fluid.
- the polymer flooding process for use in oil recovery can include in a first step of injecting a smart water/polymer slug into a carbonate reservoir formation, the volume of the smart water polymer slug can be at least 0.3 PV.
- a second step one or more tapered smart water/polymer slugs can be injected into the carbonate reservoir formation, the cumulative volume of all such tapered smart water/polymer slugs can be at least 0.2 PV.
- “Tapered” as used herein refers to successively reducing the polymer concentration from an initial maximum value to zero. By way of example, if the smart water/polymer slug in the first step is at a concentration of 3000 ppm, the tapered smart water/polymer slugs can follow the concentration as shown in Table 2.
- the polymer flooding process can include a continuous injection of a seawater chase.
- the present invention advantageously provide methods and compositions for recovering heavy oil and viscous oil from carbonate reservoir formations.
- Example 1 is a comparison study of rheology data on a high salinity water (HSW)/polymer composition and a smart water/polymer composition conducted at different temperatures.
- a copolymer of acrylamide and ATBS was used as the polymer.
- the copolymer of acrylamide and ATBS was a sulfonated polyacrylamide, AN-125, from SNF Floerger, France.
- the copolymer of acyrlamide and ATBS had a molecular weight of 12 million Dalton, a polyacrylamide hydrolysis degree of 5%, and contained a polymer content of 25% ATBS and 75% acrylamide.
- the HSW was prepared to have a TDS of about 69,000 ppm containing 55,786 mg/L of NaCl; 10,654 mg/L of CaCl 2 .2H 2 O; 4,483 mg/L of MgCl 2 .6H 2 O; 2,610 mg/L of Na 2 SO 4 ; and 503.9 mg/L NaHCO 3 .
- the smart water was prepared to have a TDS of about 6,900 ppm, making it a 10-times diluted version of the HSW containing 5,578.6 mg/L of NaCl; 1,065.4 mg/L of CaCl 2 .2H 2 O; 448.3 mg/L of MgCl 2 .6H 2 O; 261 mg/L of Na 2 SO 4 ; and 50.39 mg/L NaHCO 3 .
- the HSW/polymer composition and the smart water/polymer composition were prepared by dissolving powdered polymer in the respective fluid.
- the HSW/polymer composition contained 0.3 wt % copolymer of acrylamide and ATBS.
- the smart water/polymer composition contained 0.2 wt % copolymer of acrylamide and ATBS.
- Polymer viscosity of each composition was measured at three temperatures, 25° C., 40° C., and 60° C. using a MCR 301 Rheometer from Anton Paar.
- the MCR 301 is based on cone and plate geometry and can generate viscosity curves of polymer solutions at shear sweeps ranging from 0.1 sec ⁇ 1 to 1000 sec ⁇ 1 .
- the polymer viscosities were determined at a specific shear rate of 6.81 sec ⁇ 1 .
- FIG. 1 graphs viscosity of the composition versus temperature for the two compositions.
- Example 2 describes a reservoir condition core flood study using the same HSW and smart water compositions of Example 1.
- a carbonate reservoir core sample having a permeability of 2.0 Darcy was fully saturated with brine first and then a viscous crude oil having a viscosity of 4.5 cP was injected into the core to establish initial water saturation.
- the carbonate reservoir core sample was then submerged in the viscous crude oil and aged for four weeks. After four weeks, the carbonate reservoir core sample was loaded into a coreflooding system and then the oil displacement tests were conducted at reservoir conditions.
- oil was displaced by the injection of a high salinity water, in the absence of polymer with a composition as described in Example 1.
- a HSW/polymer slug of 0.3 wt % polymer in HSW was injected.
- a smart water/polymer slug of 0.2 wt % polymer in smart water was injected.
- the oil recovery data in terms of fraction original oil in core (OOIC) obtained during these different flooding stages are summarized in Table 4 and in FIG. 2 .
- the tertiary polymer flood with the HSW/polymer composition was able to recover 18.2% incremental oil over the secondary HSW flood.
- the post tertiary polymer flood with the smart water/polymer composition was able to add an additional 6.5% incremental oil, which can be considered as the individual contribution from the smart water.
- the incremental oil recovery from the tertiary smart water/polymer composition polymer flooding should be about 25%, which is about 6-7% higher than the incremental oil recovery from the HSW/polymer composition polymer flooding. This higher incremental oil recovery is due to the combined additive effect of smart water with polymer.
- Optional or optionally means that the subsequently described event or circumstances can or may not occur.
- the description includes instances where the event or circumstance occurs and instances where it does not occur.
- Ranges may be expressed herein as from about one particular value, and/or to about another particular value. When such a range is expressed, it is to be understood that another embodiment is from the one particular value and/or to the other particular value, along with all combinations within said range.
- first and second are arbitrarily assigned and are merely intended to differentiate between two or more components of an apparatus. It is to be understood that the words “first” and “second” serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location or position of the component. Furthermore, it is to be understood that that the mere use of the term “first” and “second” does not require that there be any “third” component, although that possibility is contemplated under the scope of the present invention.
Landscapes
- Chemical & Material Sciences (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Organic Chemistry (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Materials Engineering (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Geochemistry & Mineralogy (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Medicinal Chemistry (AREA)
- Polymers & Plastics (AREA)
- Health & Medical Sciences (AREA)
- Compositions Of Macromolecular Compounds (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
- Separation Of Suspended Particles By Flocculating Agents (AREA)
Abstract
Description
- This application claims priority from U.S. Non-Provisional application Ser. No. 15/358,449, filed Nov. 22, 2016, and titled “IMPROVED POLYMER FLOODING PROCESSES FOR VISCOUS OIL RECOVERY IN CARBONATE RESERVOIRS,” which claims priority from U.S. Provisional Application No. 62/280,446, filed Jan. 19, 2016, and titled “IMPROVED OIL RECOVERY PROCESS USING AN OIL RECOVERY COMPOSITION OF SMART WATER AND DILUTE POLYMER FOR CARBONATE RESERVOIRS.” For purposes of United States patent practice, this application incorporates the contents of both the Provisional Application and Non-Provisional Application by reference in their entirety.
- This invention relates to methods and compositions for polymer flooding operations. More specifically, the invention relates to methods and compositions using smart water and polymers for polymer flooding operations in carbonate reservoirs.
- Polymer flooding processes are one of the matured enhanced oil recovery (EOR) technologies and are currently gaining some importance for viscous oil recovery in carbonate reservoirs. Increased aqueous phase viscosities due to polymer addition decrease the mobility of injection water to provide some mobility control and mitigate viscous fingering with such crude oils in the displacement process. Polyacrylamide based polymers or co-polymers are the most widely employed polymers for EOR today in the industry. These polymers are anionic in nature and their viscosifying characteristics are hindered by salinity and the monovalent/divalent cations present in the makeup water. The negative carboxyl groups of partially hydrolyzed EOR polymers interact strongly with positively charged ions such as monovalent and divalent cations present in the makeup water. These salt ions bind tightly to the negatively charged carboxyl groups in the polymer chain to render a “coiled state” and prevent the elongation/swelling of polymer molecules in water for increased viscosibility. The divalent cations are much more detrimental when compared to monovalent cations due to their strong bridging effect with polymer chain and they can precipitate polymer from solution even at relatively lower ionic concentrations. As a result, EOR processes that employ high salinity water/seawater typically need much higher dosages of polymer as compared to low salinity water to achieve decent viscosities required for proper mobility control in viscous oil recovery processes. Therefore, the use of high salinity water is typically limited to situations in which the availability of high salinity water, such as seawater, is readily available. Such requirements of high polymer dosage can become cost prohibitive to apply polymer flooding technology in certain formations containing viscous crude oils.
- In addition, the formation temperatures and in-situ water composition can impact the type of polymer chosen for EOR.
- In conventional polymer flooding operations, the polymer concentration is typically 1000 ppm or greater in the injection fluid. The injection fluid is typically injected as a finite slug of at least 0.3 pore volumes for processes involving carbonate reservoirs and viscous oil recovery.
- This invention relates to methods and compositions for polymer flooding operations. More specifically, the invention relates to methods and compositions using smart water and polymers for polymer flooding operations in carbonate reservoirs.
- A first aspect of a composition for use in a polymer flooding operation in a viscous oil containing carbonate reservoir formation with in situ rock is provided. The composition includes a polymer, the polymer operable to increase the viscosity of the composition, and a smart water, the smart water operable to alter a wettability of the in situ rock. The smart water has a total dissolved solids of between 5,000 ppm and 7,000 ppm, the total dissolved solids comprises a salt, and the composition has a viscosity between 4 cP and 100 cP.
- In certain aspects, the polymer comprises a copolymer of acrylamide and acrylate. In certain aspects, the polymer comprises a copolymer of acrylamide and acrylamide tertiary butyl sulfonate (ATBS). In certain aspects, the salt can be selected from the group consisting of sodium chloride, calcium chloride, magnesium chloride, sodium sulfate, magnesium sulfate, sodium bicarbonate, and combinations thereof. In certain aspects, the smart water comprises 300 ppm or less of divalent cations. In certain aspects, the smart water comprises 400 ppm or greater divalent anions. In certain aspects, the polymer is present in an amount between 1,000 ppm by weight and 3,000 ppm by weight.
- In a second aspect, a method of recovering an oil from a carbonate reservoir formation is provided. The method includes the steps of injecting a smart water/polymer slug into the carbonate reservoir formation, where the smart water/polymer slug includes a smart water and a polymer, allowing the smart water/polymer slug to alter the wettability of the carbonate reservoir formation, and injecting a seawater chase, where the seawater chase is operable to recover the oil from the carbonate reservoir formation.
- In certain aspects, the method further includes the step of injecting a smart water slug into the carbonate reservoir formation after the step of allowing the smart water/polymer slug to alter the wettability of the carbonate reservoir formation. In certain aspects, the method further includes the step of injecting one or more tapered smart water/polymer plugs into the carbonate reservoir formation after the step of allowing the smart water/polymer slug to alter the wettability of the carbonate reservoir formation. In certain aspects, the smart water/polymer slug has a volume of at least 0.3 pore volumes. In certain aspects, the oil is a viscous oil. In certain aspects, the oil is a heavy oil. In certain aspects, the smart water wherein the smart water has a total dissolved solids of between 5,000 ppm and 7,000 ppm, wherein the total dissolved solids comprises a salt. In certain aspects, the smart water/polymer slug has a viscosity between 4 cP and 100 cP.
- These and other features, aspects, and advantages of the present invention will become better understood with regard to the following descriptions, claims, and accompanying drawings. It is to be noted, however, that the drawings illustrate only several embodiments of the invention and are therefore not to be considered limiting of the invention's scope as it can admit to other equally effective embodiments.
-
FIG. 1 is a graphical comparison of viscosity versus temperature for the two different compositions of Example 1. -
FIG. 2 is a graphical representation of the EOR Oil Recovery versus pore volumes injected from core flood study in Example 2. - While the invention will be described with several embodiments, it is understood that one of ordinary skill in the relevant art will appreciate that many examples, variations and alterations to the apparatus and methods described herein are within the scope and spirit of the invention. Accordingly, the exemplary embodiments of the invention described herein are set forth without any loss of generality, and without imposing limitations, on the claimed invention.
- The present invention is directed to compositions and methods related to the use of smart water and polymers. The compositions and methods of the present invention can be used in polymer flooding processes involving viscous oil recovery in carbonate reservoirs. Advantageously, the compositions and methods described herein lower the required polymer concentration by up to 50% due to the lower salinity and specific ionic composition of the smart water. The specific ionic composition favorably interacts with the in-situ rock and fluids, including crude oil and formation water, of the carbon reservoir to alter the wettability of the in-situ rock and improve microscopic sweep efficiency at the pore scale. In addition, the lower salinity and specific ion composition can increase the viscosifying characteristics of the polymer resulting in a reduction in the polymer concentration required as compared to conventional polymer flooding fluids, such as seawater. Advantageously, the polymer provides better mobility control of the smart water, which increases macroscopic sweep efficiency. Advantageously, the compositions and methods of the present invention have a synergy that results in additional incremental oil recovery (up to 5 to 10%). Advantageously, the compositions and methods of the present invention exhibit improved efficiency and economics due to lower polymer volume compared to conventional polymer flooding process used for viscous oil recovery in carbonate reservoirs.
- As used herein, “smart water” refers to an injection water of tuned water chemistry; tuned in terms of both salinity and specific individual ion compositions. In at least one embodiment, smart water is a lower salinity water containing between about 5,000 ppm and 7,000 ppm TDS, 300 ppm or less of the total amount of divalent cations and 400 ppm or greater of the total amount of divalent anions. In at least one embodiment, the divalent anion is sulfates, such that the smart water contains 400 ppm or greater sulfates. The viscosity of smart water at surface conditions can be in the range of between about 0.9 cP and 1.0 cP. The viscosity of smart water at carbonate reservoir conditions, such as temperatures at about 100° C., can be in the range between about 0.2 cP and 0.3 cP. In at least one embodiment, smart water can be prepared by diluting seawater with fresh water. In at least one embodiment, the smart water is in the absence of external compounds or additives, other than the TDS and ions specified above.
- Depletion of monovalent ions and enrichment of divalent ions is desired in a smart water. In at least one embodiment, higher amounts of sulfates and lower amounts of both monovalent cations and divalent cations are preferred in a smart water for polymer floods so as to advantageously minimize the interaction of positively charged ions with negative carboxyl groups present in the polymer. Carbonate surfaces typically exhibit a positive charge at formation water salinities, composition and pH at reservoir conditions. The negative carboxylic acid groups of crude oil are attached to the carbonate rock surface. Without being bound to a particular theory, the mechanism can be understood as follows. Initially, sulfate ions adsorb on the in situ rock surface to reduce the attraction of the surface to the negatively charged carboxylic groups in crude oil. The calcium ions further reduce this attraction by bonding to the oil side of the interface. The calcium ions are later substituted by magnesium ions due to the increasing reactivity of these ions at higher temperatures. These favorable ion interactions at the rock surface change the wettability of the in situ rock towards intermediate-wet or water-wet state to release oil from the pores of reservoir rock. The presence of non-active monovalent ions can prevent the accessibility of the divalent ions to interact at the in situ rock surface thereby reducing the effectiveness of the process. Therefore, it is advantageous to provide an injection fluid with a reduced amount of monovalent ions.
- As used herein, “seawater” refers to a high salinity water on the order of about 35,000 ppm to 56,000 ppm TDS that includes significant amounts of divalent cations.
- Table 1 shows a comparison of a typical seawater to a representative smart water.
-
TABLE 1 Seawater and Smart Water Compositions Ions Seawater (ppm) Smart Water (ppm) Sodium (Na+) 18,300 1,824 Calcium (Ca2+) 650 65 Magnesium (Mg2+) 2,110 211 Sulfate (SO4 2−) 4,290 429 Chloride (Cl−) 32,200 3,220 Bicarbonate (HCO3 −) 120 12 TDS 57,670 5,761 - As used herein, “divalent ions” includes, but is not limited to calcium, magnesium, and sulfate. As will be understood by one of the art, calcium and magnesium are cations.
- As used herein, “monovalent ions” includes, but is not limited to, sodium and chloride.
- The monovalent ions and divalent ions can be present in the form of salts. The smart water can include one or more salts. Examples of salts useful in the present invention can include sodium chloride (NaCl), calcium chloride (CaCl2), magnesium chloride (MgCl2), sodium sulfate (Na2SO4), magnesium sulfate (MgSO4), NaHCO3 and combinations of the same.
- As used herein, “in situ reservoir conditions” can refer to elevated pressure and temperature conditions, rock mineralogical compositions, and fluid compositions locally existing in the reservoir.
- As used herein, “viscous oil” or “viscous crude oil” refers to in-situ reservoir crude oil having a viscosity of greater than about 2 and less than 100 cP at in-situ reservoir conditions.
- As used herein, “heavy oil” refers to crude oil of less than 22.3° API gravity or more than 100 cP viscosity at in-situ reservoir conditions.
- As used herein, “incremental oil recovery” refers to an increase in oil recovery in terms of percent original oil in place over any base case, or conventional recovery process as a regular water flood.
- As used herein, “the pore scale” refers to the scale corresponding to the pore size range of the pore space of the in-situ rock, typically on the order of a 2-5 microns.
- As used herein, “microscopic sweep efficiency” refers to sweep efficiency of displacing fluid at the pore scale. Microscopic sweep efficiency is a measure of how effectively the injection fluid mobilizes and displaces oil from the pores in the reservoir rock.
- As used herein, “macroscopic sweep efficiency” or “volumetric sweep efficiency” refers to sweep efficiency of displacing fluid at the reservoir scale. Macroscopic sweep efficiency is a measure of how effectively the displacing fluid contacts the volume of a reservoir both areally and vertically.
- As used herein, “synergy” refers to the additive effect of the favorable interaction of a secondary recovery process (such as smart water) to improve the performance and economics of a primary recovery process (such as polymer) without losing the individual recovery benefit of two processes when combined.
- As used herein, “carbonate reservoirs” refers to a sedimentary rock condition deposited in a marine environment and mostly made up of calcium carbonate. Carbonate reservoirs are chemically active and can undergo a range of physical and chemical processes known as diagenesis. Diagenesis alters the rock structure to show large abrupt variations in rock properties such as porosity.
- As used herein, “polymer flooding” refers to the use of viscosified injection waters to reduce the mobility of injection water for better reservoir contact. A polymer flooding differs from a water flooding process in that water flooding processes use plain water such as seawater for injection into reservoirs to provide some pressure support and physically displace oil from the injection wells to the producing wells.
- As used herein, “total dissolved solids” or “TDS” refers to the sum of the combined amount of all inorganic salts contained in the injection water in the form of charged ions, such as monovalent ions and divalent ions. TDS can also be considered a measure of the salinity of a smart water.
- A composition for a polymer flooding process involving viscous oil recovery in carbonate reservoir formations with in situ rock is herein provided. The composition is a smart water/polymer composition. The composition can include a smart water and a polymer.
- The composition of the smart water can be selected based on the carbonate reservoir formation. In at least one embodiment, the smart water compositions of the present invention are not suitable for sandstone reservoirs. Sandstone reservoirs require injection fluids enriched in monovalent ions with lower concentrations of divalent ions.
- The polymer can be any polymer capable of increasing the viscosity of the smart water. Examples of polymer suitable for use in the present invention include copolymers of acrylamide and acrylate and copolymers of acrylamide and acrylamido tertiary butyl sulfonate (ATBS). Advantageously, copolymers of acrylamide and ATBS can tolerate reservoir temperatures up to 95° C. as in the prevailing carbonate reservoirs. In at least one embodiment, the copolymer of acrylamide and acrylate can be from the standard Flopaam™ series polymers from SNF Floerger, France. In at least one embodiment, the copolymer of acrylamide and ATBS can be from the Flopaam™ AN series of polymers from SNF Floerger, France.
- The polymer can be added to the smart water at concentrations in the range from 0.05 to 0.30 weight percent (wt %) (500 ppm by weight to 3000 ppm by weight), alternately in the range from 0.1 wt % (1000 ppm) to 0.3 wt % (3000 ppm), alternately in the range from 0.1 wt % to 0.2 wt %, alternately in the range from 0.1 wt % to 0.15 wt %, and alternately in the range from 0.15 wt % to 0.2 wt % to produce the smart water/polymer composition. In at least one embodiment, the polymer concentration in the smart water/polymer composition is in the range from 1000 ppm to 3000 ppm. In at least one embodiment, the polymer concentration in the smart water/polymer composition is in the range from 1000 ppm to 2000 ppm. The injection smart water is used as the makeup water to dissolve the polymer and carry the polymer into the carbonate reservoir formation. The smart water/polymer composition can alter a wettability of the in situ rock in the carbonate reservoir formation with improved mobility control. When the rock wettability is altered towards a more favorable intermediate-wet or water-wet state, it reduces capillary trapping of residual oil to release more oil from pores. In other words, the alteration of rock wettability advantageously improves microscopic sweep efficiency. The increased viscosity of smart water due to polymer addition will also increase the reservoir contact, both vertical contact and areal contact, of the injection fluid to mobilize the remaining oil. In other words, the viscosity of smart water due to the presence of the polymer improves macroscopic sweep efficiency as compared to a smart water in the absence of polymer. The enhancements in both microscopic sweep efficiency and macroscopic sweep efficiency can result in a higher incremental oil recovery as compared to an injection fluid that does not have improved efficiencies.
- The smart water/polymer composition is in the absence of additives. Additives can include, but are not limited to, viscosifiers, surfactants, stabilizers, pH control agents, scale inhibitors. In at least one embodiment, the smart water/polymer compositions include only water, divalent ions, monovalent ions and polymer.
- A polymer flooding process for use in viscous oil recovery in carbonate reservoirs is provided. The polymer flooding process of the present invention can be used in any carbonate reservoir containing oil to be recovered. The oil to be recovered can include viscous oil and heavy oil. In at least one embodiment, the polymer flooding process of the present invention uses the smart water/polymer composition to recover viscous oil. In at least one embodiment, polymer flooding process is limited to use in carbonate reservoirs.
- The concentration of polymer in a smart water/polymer composition can be chosen based on the desired viscosity and to achieve water-oil mobility ratio for the specific viscous oil of interest in a carbonate reservoir.
- The “mobility ratio” as used herein refers to the ratio of mobility of injection fluid (such as water) to that of the displaced fluid (such as crude oil). Mobility is defined as the ratio of effective permeability to viscosity. The effective permeability can be determined at the water saturation ahead of the displacement front for oil while at the water saturation behind the displacement front for injection fluid. Typically, a mobility ratio of less than or equal to one is preferred to provide piston like displacement and avoid viscous fingering.
- In at least one embodiment, the polymer flooding process for use in oil recovery can include in a first step, injecting an initial slug of the smart water/polymer composition into a carbonate reservoir formation, the volume of the initial slug of the smart water polymer composition can be at least 0.3 pore volumes (PV). As used herein, “pore volume” refers to a unit of measure for void space available in the reservoir rock material. In a second step, a continuous of injection of smart water is injected into the carbonate reservoir formation.
- In an alternate embodiment, the polymer flooding process for use in oil recovery can include in a first step of injecting a smart water/polymer slug into a carbonate reservoir formation, the volume of the smart water polymer slug can be at least 0.3 PV. In a second step, a smart water slug can be injected into the carbonate reservoir formation, the volume of the smart water slug can be at least 0.5 PV. In a final step the polymer flooding process can include a continuous injection of seawater chase. As used herein, “seawater chase” refers to the use of seawater as a chase fluid.
- In an alternate embodiment, the polymer flooding process for use in oil recovery can include in a first step of injecting a smart water/polymer slug into a carbonate reservoir formation, the volume of the smart water polymer slug can be at least 0.3 PV. In a second step, one or more tapered smart water/polymer slugs can be injected into the carbonate reservoir formation, the cumulative volume of all such tapered smart water/polymer slugs can be at least 0.2 PV. “Tapered” as used herein refers to successively reducing the polymer concentration from an initial maximum value to zero. By way of example, if the smart water/polymer slug in the first step is at a concentration of 3000 ppm, the tapered smart water/polymer slugs can follow the concentration as shown in Table 2.
-
TABLE 2 Example of polymer concentration in tapered smart water/polymer slugs Tapered smart water/polymer slug # Polymer concentration Tapered smart water/polymer slug 1 2500 ppm Tapered smart water/ polymer slug 22000 ppm Tapered smart water/polymer slug 3 1500 ppm Tapered smart water/ polymer slug 41000 ppm Tapered smart water/ polymer slug 5500 ppm Tapered smart water/ polymer slug 60 ppm - In a final step following the one or more tapered smart water/polymer slugs, the polymer flooding process can include a continuous injection of a seawater chase.
- The present invention advantageously provide methods and compositions for recovering heavy oil and viscous oil from carbonate reservoir formations.
- Example 1 is a comparison study of rheology data on a high salinity water (HSW)/polymer composition and a smart water/polymer composition conducted at different temperatures. A copolymer of acrylamide and ATBS was used as the polymer. The copolymer of acrylamide and ATBS was a sulfonated polyacrylamide, AN-125, from SNF Floerger, France. The copolymer of acyrlamide and ATBS had a molecular weight of 12 million Dalton, a polyacrylamide hydrolysis degree of 5%, and contained a polymer content of 25% ATBS and 75% acrylamide. The HSW was prepared to have a TDS of about 69,000 ppm containing 55,786 mg/L of NaCl; 10,654 mg/L of CaCl2.2H2O; 4,483 mg/L of MgCl2.6H2O; 2,610 mg/L of Na2SO4; and 503.9 mg/L NaHCO3. The smart water was prepared to have a TDS of about 6,900 ppm, making it a 10-times diluted version of the HSW containing 5,578.6 mg/L of NaCl; 1,065.4 mg/L of CaCl2.2H2O; 448.3 mg/L of MgCl2.6H2O; 261 mg/L of Na2SO4; and 50.39 mg/L NaHCO3.
- The HSW/polymer composition and the smart water/polymer composition were prepared by dissolving powdered polymer in the respective fluid. The HSW/polymer composition contained 0.3 wt % copolymer of acrylamide and ATBS. The smart water/polymer composition contained 0.2 wt % copolymer of acrylamide and ATBS. Polymer viscosity of each composition was measured at three temperatures, 25° C., 40° C., and 60° C. using a MCR 301 Rheometer from Anton Paar. The MCR 301 is based on cone and plate geometry and can generate viscosity curves of polymer solutions at shear sweeps ranging from 0.1 sec−1 to 1000 sec−1. The polymer viscosities were determined at a specific shear rate of 6.81 sec−1.
- Table 3 contains the data from the study.
FIG. 1 graphs viscosity of the composition versus temperature for the two compositions. -
TABLE 3 Polymer solution viscosities as a function of temperature in two different makeup waters Viscosity with 0.3 wt % Viscosity with 0.2 wt % Temperature polymer in HSW polymer in smart water (° C.) (cP) (cP) 25 27.6 24.9 40 20.2 20.5 60 14.9 14.7 99* 10.6* 11.2* *The viscosity data at a reservoir temperature of 99° C. was obtained by the extrapolation of the measured data at the other three temperatures. - The data in Table 3 and in
FIG. 1 shows that a smart water/polymer composition with a polymer concentration of 2000 ppm by weight exhibits almost the same viscosities as a HSW/polymer composition with a polymer concentration of 3000 ppm. This illustrates that a smart water/polymer composition requires less polymer than a high salinity water to achieve the same target viscosity. In this example, the polymer consumption of a process using a smart water/polymer composition would be 33% (1/3) less than the polymer consumption of an HSW/polymer composition. - Example 2 describes a reservoir condition core flood study using the same HSW and smart water compositions of Example 1. A carbonate reservoir core sample having a permeability of 2.0 Darcy was fully saturated with brine first and then a viscous crude oil having a viscosity of 4.5 cP was injected into the core to establish initial water saturation. The carbonate reservoir core sample was then submerged in the viscous crude oil and aged for four weeks. After four weeks, the carbonate reservoir core sample was loaded into a coreflooding system and then the oil displacement tests were conducted at reservoir conditions.
- In a first step of the oil displacement tests, oil was displaced by the injection of a high salinity water, in the absence of polymer with a composition as described in Example 1. In a second step, a HSW/polymer slug of 0.3 wt % polymer in HSW was injected. Finally, a smart water/polymer slug of 0.2 wt % polymer in smart water was injected. The oil recovery data in terms of fraction original oil in core (OOIC) obtained during these different flooding stages are summarized in Table 4 and in
FIG. 2 . -
TABLE 4 Summary of Oil Recoveries from Core Flood Study Oil Recovery (fraction OOIC) Injection Fluid Incremental Cumulative HSW 0.453 0.453 HSW/polymer composition 0.182 0.635 Smart water/polymer composition 0.065 0.700 - As can be seen from these data, the tertiary polymer flood with the HSW/polymer composition was able to recover 18.2% incremental oil over the secondary HSW flood. The post tertiary polymer flood with the smart water/polymer composition was able to add an additional 6.5% incremental oil, which can be considered as the individual contribution from the smart water.
- By combining the results from both of these stages, it can be concluded that the incremental oil recovery from the tertiary smart water/polymer composition polymer flooding should be about 25%, which is about 6-7% higher than the incremental oil recovery from the HSW/polymer composition polymer flooding. This higher incremental oil recovery is due to the combined additive effect of smart water with polymer.
- Although the present invention has been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the invention. Accordingly, the scope of the present invention should be determined by the following claims and their appropriate legal equivalents.
- The singular forms “a,” “an,” and “the” include plural referents, unless the context clearly dictates otherwise.
- Optional or optionally means that the subsequently described event or circumstances can or may not occur. The description includes instances where the event or circumstance occurs and instances where it does not occur.
- Ranges may be expressed herein as from about one particular value, and/or to about another particular value. When such a range is expressed, it is to be understood that another embodiment is from the one particular value and/or to the other particular value, along with all combinations within said range.
- As used herein and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.
- As used herein, terms such as “first” and “second” are arbitrarily assigned and are merely intended to differentiate between two or more components of an apparatus. It is to be understood that the words “first” and “second” serve no other purpose and are not part of the name or description of the component, nor do they necessarily define a relative location or position of the component. Furthermore, it is to be understood that that the mere use of the term “first” and “second” does not require that there be any “third” component, although that possibility is contemplated under the scope of the present invention.
Claims (5)
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US16/557,297 US10988673B2 (en) | 2016-01-19 | 2019-08-30 | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
Applications Claiming Priority (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201662280446P | 2016-01-19 | 2016-01-19 | |
US15/358,449 US10457851B2 (en) | 2016-01-19 | 2016-11-22 | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
US16/557,297 US10988673B2 (en) | 2016-01-19 | 2019-08-30 | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
Related Parent Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US15/358,449 Division US10457851B2 (en) | 2016-01-19 | 2016-11-22 | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
Publications (3)
Publication Number | Publication Date |
---|---|
US20190382647A1 US20190382647A1 (en) | 2019-12-19 |
US20210115325A9 true US20210115325A9 (en) | 2021-04-22 |
US10988673B2 US10988673B2 (en) | 2021-04-27 |
Family
ID=59315232
Family Applications (6)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US15/358,449 Active US10457851B2 (en) | 2016-01-19 | 2016-11-22 | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
US15/358,435 Active US10287485B2 (en) | 2016-01-19 | 2016-11-22 | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US15/903,952 Active US10106726B2 (en) | 2016-01-19 | 2018-02-23 | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US16/235,562 Active US10590329B2 (en) | 2016-01-19 | 2018-12-28 | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US16/235,569 Active US10590330B2 (en) | 2016-01-19 | 2018-12-28 | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US16/557,297 Active US10988673B2 (en) | 2016-01-19 | 2019-08-30 | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
Family Applications Before (5)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US15/358,449 Active US10457851B2 (en) | 2016-01-19 | 2016-11-22 | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
US15/358,435 Active US10287485B2 (en) | 2016-01-19 | 2016-11-22 | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US15/903,952 Active US10106726B2 (en) | 2016-01-19 | 2018-02-23 | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US16/235,562 Active US10590329B2 (en) | 2016-01-19 | 2018-12-28 | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US16/235,569 Active US10590330B2 (en) | 2016-01-19 | 2018-12-28 | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
Country Status (4)
Country | Link |
---|---|
US (6) | US10457851B2 (en) |
EP (2) | EP3405548A1 (en) |
CN (2) | CN108603101A (en) |
WO (2) | WO2017127522A1 (en) |
Families Citing this family (17)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10723937B2 (en) | 2016-01-19 | 2020-07-28 | Saudi Arabian Oil Company | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US10781362B2 (en) | 2016-01-19 | 2020-09-22 | Saudi Arabian Oil Company | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US10457851B2 (en) | 2016-01-19 | 2019-10-29 | Saudi Arabian Oil Company | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
US10550312B2 (en) | 2016-01-19 | 2020-02-04 | Saudi Arabian Oil Company | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US10961831B2 (en) | 2016-01-19 | 2021-03-30 | Saudi Arabian Oil Company | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
US11041109B2 (en) * | 2017-12-27 | 2021-06-22 | Saudi Arabian Oil Company | Enhanced surfactant polymer flooding processes for oil recovery in carbonate reservoirs |
US10711582B2 (en) * | 2018-04-20 | 2020-07-14 | Saudi Arabian Oil Company | Salinated wastewater for enhancing hydrocarbon recovery |
WO2020030996A1 (en) * | 2018-08-09 | 2020-02-13 | King Abdullah University Of Science And Technology | Polymer-based enhanced oil recovery with compositionally-tuned slugs |
EP3850054A1 (en) * | 2018-09-24 | 2021-07-21 | Saudi Arabian Oil Company | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US10954764B2 (en) | 2019-03-04 | 2021-03-23 | Saudi Arabian Oil Company | Tailored injection water slug designs for enhanced oil recovery in carbonates |
CN110805408B (en) * | 2019-05-31 | 2021-08-31 | 大港油田集团有限责任公司 | Profile control process method for water injection well with packer pipe column |
US11066910B2 (en) * | 2019-08-28 | 2021-07-20 | Saudi Arabian Oil Company | Alkaline water flooding processes for enhanced oil recovery in carbonates |
US11274535B1 (en) * | 2020-08-28 | 2022-03-15 | Saudi Arabian Oil Company | Seismic assisted flooding processes for oil recovery in carbonates |
CN112852396B (en) * | 2021-01-06 | 2022-05-10 | 中国石油天然气股份有限公司 | Multifunctional blocking remover and preparation method thereof |
CN112727414B (en) * | 2021-01-10 | 2022-07-12 | 西南石油大学 | Method for improving crude oil recovery ratio by combining binary compound flooding and water flooding |
US11867039B2 (en) * | 2022-01-07 | 2024-01-09 | Saudi Arabian Oil Company | Alternating microsphere and smartwater injection for enhanced oil recovery |
WO2024083796A1 (en) * | 2022-10-18 | 2024-04-25 | Poweltec | Process for treating subterranean formations |
Family Cites Families (57)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US3330343A (en) | 1963-09-09 | 1967-07-11 | Marathon Oil Co | Viscosity control in miscible floods |
US3346047A (en) | 1965-08-19 | 1967-10-10 | Mobil Oil Corp | Multistage waterflood |
US3508612A (en) | 1968-08-15 | 1970-04-28 | Shell Oil Co | Waterflood oil recovery using calciumcompatible mixture of anionic surfactants |
US3603400A (en) | 1970-03-16 | 1971-09-07 | Marathon Oil Co | Fracturing subterranean formations using micellar dispersions |
US3687199A (en) | 1970-05-07 | 1972-08-29 | Dow Chemical Co | Process for the secondary recovery of petroleum |
US3827499A (en) * | 1972-10-02 | 1974-08-06 | Marathon Oil Co | Injectivity in supplemented oil recovery |
GB1484153A (en) | 1973-12-03 | 1977-09-01 | Texaco Development Corp | Micellar dispersions with tolerance for extreme water hardness for use in petroleum recovery |
US3908764A (en) * | 1974-11-25 | 1975-09-30 | Phillips Petroleum Co | Method of treating petroleum-bearing formations for supplemental oil recovery |
US4008767A (en) | 1975-10-24 | 1977-02-22 | Mobil Oil Corporation | Oil recovery by low tension waterflooding |
US4050513A (en) | 1976-07-15 | 1977-09-27 | Texaco Inc. | Method of treating a high temperature formation to permit the use therein of temperature sensitive hydrophilic, viscosity increasing polymers |
US4074755A (en) | 1977-03-21 | 1978-02-21 | Shell Oil Company | Ion exchange controlled chemically aided waterflood process |
US4137182A (en) | 1977-06-20 | 1979-01-30 | Standard Oil Company (Indiana) | Process for fracturing well formations using aqueous gels |
US4250961A (en) | 1979-04-23 | 1981-02-17 | Texaco Inc. | Oil recovery method utilizing a surfactant slug driven by water of a controlled salinity |
US4630678A (en) | 1985-06-03 | 1986-12-23 | Phillips Petroleum Company | In-situ formation of polyvalent metal ions for crosslinking polymers within carbonate rock-containing reservoirs |
DE3766121D1 (en) * | 1986-02-18 | 1990-12-20 | American Cyanamid Co | MOBILITY REGULATORS WITH HIGHER THERMAL STABILITY. |
US4762178A (en) | 1986-11-07 | 1988-08-09 | Shell Oil Company | Oil recovery with water containing carbonate salt and CO2 |
US4785028A (en) | 1986-12-22 | 1988-11-15 | Mobil Oil Corporation | Gels for profile control in enhanced oil recovery under harsh conditions |
US4915170A (en) | 1989-03-10 | 1990-04-10 | Mobil Oil Corporation | Enhanced oil recovery method using crosslinked polymeric gels for profile control |
FR2792678B1 (en) | 1999-04-23 | 2001-06-15 | Inst Francais Du Petrole | ASSISTED RECOVERY OF HYDROCARBONS BY COMBINED INJECTION OF AN AQUEOUS PHASE AND AT LEAST PARTIALLY MISCIBLE GAS |
US7055602B2 (en) * | 2003-03-11 | 2006-06-06 | Shell Oil Company | Method and composition for enhanced hydrocarbons recovery |
US7581594B2 (en) | 2006-03-15 | 2009-09-01 | Chemeor, Inc. | Surfactant method for improved oil recovery from fractured reservoirs |
WO2008029131A1 (en) | 2006-09-08 | 2008-03-13 | Bp Exploration Operating Company Limited | Hydrocarbon recovery |
GB2478217B (en) | 2006-09-08 | 2011-11-09 | Bp Exploration Operating | Hydrocarbon recovery process |
US20090148342A1 (en) | 2007-10-29 | 2009-06-11 | Bromberg Steven E | Hypochlorite Technology |
US8951954B2 (en) | 2008-02-20 | 2015-02-10 | Diversey, Inc. | Low volatile organic compounds cleaner composition |
US7913759B2 (en) * | 2008-09-29 | 2011-03-29 | E. I. Du Pont De Nemours And Company | Method for enhanced recovery of oil from oil reservoirs |
US8191416B2 (en) | 2008-11-24 | 2012-06-05 | Schlumberger Technology Corporation | Instrumented formation tester for injecting and monitoring of fluids |
FR2940348B1 (en) | 2008-12-18 | 2011-01-21 | Spcm Sa | IMPROVING THE ASSISTED RECOVERY OF PETROLEUM BY POLYMER WITHOUT EQUIPMENT OR COMPLEMENTARY PRODUCT. |
BRPI1008278B1 (en) * | 2009-02-13 | 2019-05-21 | Shell Internationale Research Maatschappij B.V. | METHOD FOR INCREASING RAW OIL RECOVERY FROM A POROUS UNDERGROUND FORMATION. |
JP2011046612A (en) | 2009-08-25 | 2011-03-10 | Toagosei Co Ltd | Method for producing 2-acrylamide-2-methylpropanesulfonic acid |
US8869892B2 (en) | 2010-02-12 | 2014-10-28 | Conocophillips Company | Low salinity reservoir environment |
BR112012021278A2 (en) | 2010-03-15 | 2016-10-25 | Spcm Sa | improved oil recovery process using water soluble high molecular weight polymer. |
US8550163B2 (en) | 2010-07-23 | 2013-10-08 | Saudi Arabian Oil Company | Oil recovery process for carbonate reservoirs |
US8550164B2 (en) | 2010-07-23 | 2013-10-08 | Saudi Arabian Oil Company | Oil recovery process for carbonate reservoirs |
CN107101922A (en) | 2010-08-06 | 2017-08-29 | 英国石油勘探运作有限公司 | Apparatus and method for testing multiple samples |
US8656996B2 (en) | 2010-11-19 | 2014-02-25 | Exxonmobil Upstream Research Company | Systems and methods for enhanced waterfloods |
GB2486875A (en) | 2010-12-17 | 2012-07-04 | Ronald Alexander Scot Young | Acidic anti-pathogenic cleaning composition |
US20140262275A1 (en) * | 2013-03-15 | 2014-09-18 | Chevron U.S.A. Inc. | Alkali polymer surfactant sandwich |
US9284480B2 (en) * | 2011-10-04 | 2016-03-15 | Saudi Arabian Oil Company | Polymer-enhanced surfactant flooding for permeable carbonates |
WO2013091023A2 (en) | 2011-12-21 | 2013-06-27 | Commonwealth Scientific And Industrial Research Organisation | Method for chemically adsorbing to carbonate surfaces |
FR2986034B1 (en) * | 2012-01-20 | 2016-08-12 | Snf Sas | PROCESS FOR ASSISTED OIL RECOVERY BY INJECTION OF A POLYMERIC SOLUTION |
EP2812409B1 (en) * | 2012-02-09 | 2018-11-28 | BP Exploration Operating Company Limited | Enhanced oil recovery process using low salinity water |
US20130274149A1 (en) | 2012-04-13 | 2013-10-17 | Schlumberger Technology Corporation | Fluids and methods including nanocellulose |
EP2839323A2 (en) | 2012-04-15 | 2015-02-25 | Nederlandse Organisatie voor toegepast-natuurwetenschappelijk Onderzoek TNO | Fluorescent nano-sensors for oil and gas reservoir characterization |
CN103965852B (en) | 2013-02-05 | 2016-12-28 | 中国石油化工股份有限公司 | Containing polymer and the compound oil displacement agent of negative and positive system surfactant and flooding method |
KR102057286B1 (en) | 2013-02-21 | 2019-12-19 | 삼성디스플레이 주식회사 | Organic Light Emitting Display |
EP2789670A1 (en) | 2013-04-08 | 2014-10-15 | S.P.C.M. Sa | Polymers for enhanced hydrocarbon recovery |
CN103242818B (en) | 2013-05-03 | 2015-07-15 | 西南石油大学 | AM (acrylamide)/NaAA (sodium acrylic acid)/AMPL (N-allyl morpholinium) ternary copolymer oil displacement agent and synthesis method thereof |
US10081762B2 (en) | 2013-09-17 | 2018-09-25 | Baker Hughes, A Ge Company, Llc | Well treatment methods and fluids containing synthetic polymer |
US20150233222A1 (en) | 2014-02-19 | 2015-08-20 | Tadesse Weldu Teklu | Enhanced oil recovery process to inject low salinity water and gas in carbonate reservoirs |
US20150233223A1 (en) | 2014-02-19 | 2015-08-20 | Waleed Salem AlAmeri | Enhanced oil recovery process to inject surfactant-augmented low-salinity water in oil-wet carbonate reservoirs |
US10442980B2 (en) | 2014-07-29 | 2019-10-15 | Ecolab Usa Inc. | Polymer emulsions for use in crude oil recovery |
US20170058187A1 (en) | 2015-08-28 | 2017-03-02 | Awad Rasheed Suleiman Mansour | Enhanced oil recovery method for producing light crude oil from heavy oil fields |
US10266750B2 (en) | 2015-09-02 | 2019-04-23 | Chevron U.S.A. Inc. | Oil recovery compositions and methods thereof |
US10781362B2 (en) | 2016-01-19 | 2020-09-22 | Saudi Arabian Oil Company | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
US10457851B2 (en) | 2016-01-19 | 2019-10-29 | Saudi Arabian Oil Company | Polymer flooding processes for viscous oil recovery in carbonate reservoirs |
US10723937B2 (en) | 2016-01-19 | 2020-07-28 | Saudi Arabian Oil Company | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs |
-
2016
- 2016-11-22 US US15/358,449 patent/US10457851B2/en active Active
- 2016-11-22 US US15/358,435 patent/US10287485B2/en active Active
-
2017
- 2017-01-19 EP EP17703281.0A patent/EP3405548A1/en not_active Withdrawn
- 2017-01-19 CN CN201780007402.6A patent/CN108603101A/en active Pending
- 2017-01-19 CN CN201780007311.2A patent/CN108495908A/en active Pending
- 2017-01-19 WO PCT/US2017/014099 patent/WO2017127522A1/en active Application Filing
- 2017-01-19 EP EP17702269.6A patent/EP3405547A1/en not_active Withdrawn
- 2017-01-19 WO PCT/US2017/014097 patent/WO2017127520A1/en active Application Filing
-
2018
- 2018-02-23 US US15/903,952 patent/US10106726B2/en active Active
- 2018-12-28 US US16/235,562 patent/US10590329B2/en active Active
- 2018-12-28 US US16/235,569 patent/US10590330B2/en active Active
-
2019
- 2019-08-30 US US16/557,297 patent/US10988673B2/en active Active
Also Published As
Publication number | Publication date |
---|---|
EP3405548A1 (en) | 2018-11-28 |
WO2017127522A1 (en) | 2017-07-27 |
CN108603101A (en) | 2018-09-28 |
EP3405547A1 (en) | 2018-11-28 |
US20180179436A1 (en) | 2018-06-28 |
CN108495908A (en) | 2018-09-04 |
US20190136117A1 (en) | 2019-05-09 |
US10287485B2 (en) | 2019-05-14 |
US20170204323A1 (en) | 2017-07-20 |
WO2017127520A1 (en) | 2017-07-27 |
US20190382647A1 (en) | 2019-12-19 |
US10457851B2 (en) | 2019-10-29 |
US10590330B2 (en) | 2020-03-17 |
US10988673B2 (en) | 2021-04-27 |
US20190136118A1 (en) | 2019-05-09 |
US20170204322A1 (en) | 2017-07-20 |
US10106726B2 (en) | 2018-10-23 |
US10590329B2 (en) | 2020-03-17 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US10988673B2 (en) | Polymer flooding processes for viscous oil recovery in carbonate reservoirs | |
US10961831B2 (en) | Polymer flooding processes for viscous oil recovery in carbonate reservoirs | |
US11041109B2 (en) | Enhanced surfactant polymer flooding processes for oil recovery in carbonate reservoirs | |
US10287486B2 (en) | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs | |
US10723937B2 (en) | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs | |
US10781362B2 (en) | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs | |
EP2945995A1 (en) | Method, system and composition for producing oil | |
US20150291875A1 (en) | Desorbants for enhanced oil recovery | |
US10920129B2 (en) | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs | |
US10563116B2 (en) | Ethoxylated desorbing agents for enhanced oil recovery | |
US10308863B2 (en) | Formation preconditioning using an aqueous polymer preflush | |
EP3168277A1 (en) | Process for preparing a synthetic anionic sulphur-containing surfactant composition and method and use for the recovery of oil | |
WO2020068443A1 (en) | Oil recovery process using an oil recovery composition of aqueous salt solution and dilute polymer for carbonate reservoirs | |
US20200284130A1 (en) | Tailored Injection Water Slug Designs for Enhanced Oil Recovery in Carbonates |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
AS | Assignment |
Owner name: SAUDI ARABIAN OIL COMPANY, SAUDI ARABIA Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:AYIRALA, SUBHASH CHANDRABOSE;AL-SOFI, ABDULKAREEM M.;AL-YOUSEF, ALI ABDALLAH;AND OTHERS;REEL/FRAME:050225/0249 Effective date: 20170131 |
|
FEPP | Fee payment procedure |
Free format text: ENTITY STATUS SET TO UNDISCOUNTED (ORIGINAL EVENT CODE: BIG.); ENTITY STATUS OF PATENT OWNER: LARGE ENTITY |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: DOCKETED NEW CASE - READY FOR EXAMINATION |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: NON FINAL ACTION MAILED |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: RESPONSE TO NON-FINAL OFFICE ACTION ENTERED AND FORWARDED TO EXAMINER |
|
FEPP | Fee payment procedure |
Free format text: PETITION RELATED TO MAINTENANCE FEES GRANTED (ORIGINAL EVENT CODE: PTGR); ENTITY STATUS OF PATENT OWNER: LARGE ENTITY |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: NOTICE OF ALLOWANCE MAILED -- APPLICATION RECEIVED IN OFFICE OF PUBLICATIONS |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: PUBLICATIONS -- ISSUE FEE PAYMENT RECEIVED |
|
STPP | Information on status: patent application and granting procedure in general |
Free format text: PUBLICATIONS -- ISSUE FEE PAYMENT VERIFIED |
|
STCF | Information on status: patent grant |
Free format text: PATENTED CASE |