US20130341012A1 - Method for tracking a treatment fluid in a subterranean formation - Google Patents
Method for tracking a treatment fluid in a subterranean formation Download PDFInfo
- Publication number
- US20130341012A1 US20130341012A1 US13/977,538 US201013977538A US2013341012A1 US 20130341012 A1 US20130341012 A1 US 20130341012A1 US 201013977538 A US201013977538 A US 201013977538A US 2013341012 A1 US2013341012 A1 US 2013341012A1
- Authority
- US
- United States
- Prior art keywords
- treatment fluid
- fluids
- tracer agents
- treatment
- tracer
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 239000012530 fluid Substances 0.000 title claims abstract description 115
- 238000011282 treatment Methods 0.000 title claims abstract description 92
- 238000000034 method Methods 0.000 title claims abstract description 49
- 230000015572 biosynthetic process Effects 0.000 title claims abstract description 34
- 239000000700 radioactive tracer Substances 0.000 claims abstract description 54
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 49
- 230000000704 physical effect Effects 0.000 claims abstract description 10
- 238000009826 distribution Methods 0.000 claims abstract description 6
- 238000002347 injection Methods 0.000 claims description 23
- 239000007924 injection Substances 0.000 claims description 23
- 239000007789 gas Substances 0.000 claims description 22
- 239000000203 mixture Substances 0.000 claims description 19
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 14
- 239000000243 solution Substances 0.000 claims description 13
- 229930195733 hydrocarbon Natural products 0.000 claims description 12
- 150000002430 hydrocarbons Chemical class 0.000 claims description 12
- 239000007788 liquid Substances 0.000 claims description 12
- 239000007787 solid Substances 0.000 claims description 11
- 239000004215 Carbon black (E152) Substances 0.000 claims description 10
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 claims description 10
- 230000005251 gamma ray Effects 0.000 claims description 9
- 239000002245 particle Substances 0.000 claims description 9
- 230000008569 process Effects 0.000 claims description 9
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 8
- 238000005481 NMR spectroscopy Methods 0.000 claims description 8
- 238000005315 distribution function Methods 0.000 claims description 7
- PNEYBMLMFCGWSK-UHFFFAOYSA-N Alumina Chemical compound [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 claims description 6
- YXFVVABEGXRONW-UHFFFAOYSA-N Toluene Chemical compound CC1=CC=CC=C1 YXFVVABEGXRONW-UHFFFAOYSA-N 0.000 claims description 6
- 239000000839 emulsion Substances 0.000 claims description 6
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims description 6
- 239000004094 surface-active agent Substances 0.000 claims description 6
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 claims description 5
- 238000005553 drilling Methods 0.000 claims description 5
- -1 ferrous chlorides Chemical class 0.000 claims description 5
- SZVJSHCCFOBDDC-UHFFFAOYSA-N iron(II,III) oxide Inorganic materials O=[Fe]O[Fe]O[Fe]=O SZVJSHCCFOBDDC-UHFFFAOYSA-N 0.000 claims description 5
- XLOMVQKBTHCTTD-UHFFFAOYSA-N Zinc monoxide Chemical compound [Zn]=O XLOMVQKBTHCTTD-UHFFFAOYSA-N 0.000 claims description 4
- 239000000654 additive Substances 0.000 claims description 4
- 150000002500 ions Chemical class 0.000 claims description 4
- 229910052757 nitrogen Inorganic materials 0.000 claims description 4
- GNRSAWUEBMWBQH-UHFFFAOYSA-N oxonickel Chemical compound [Ni]=O GNRSAWUEBMWBQH-UHFFFAOYSA-N 0.000 claims description 4
- 239000000377 silicon dioxide Substances 0.000 claims description 4
- 239000002904 solvent Substances 0.000 claims description 4
- 150000001298 alcohols Chemical class 0.000 claims description 3
- 239000003638 chemical reducing agent Substances 0.000 claims description 3
- 239000004088 foaming agent Substances 0.000 claims description 3
- 239000003349 gelling agent Substances 0.000 claims description 3
- 238000010438 heat treatment Methods 0.000 claims description 3
- 229910001872 inorganic gas Inorganic materials 0.000 claims description 3
- 238000002156 mixing Methods 0.000 claims description 3
- BHPQYMZQTOCNFJ-UHFFFAOYSA-N Calcium cation Chemical compound [Ca+2] BHPQYMZQTOCNFJ-UHFFFAOYSA-N 0.000 claims description 2
- RYGMFSIKBFXOCR-UHFFFAOYSA-N Copper Chemical compound [Cu] RYGMFSIKBFXOCR-UHFFFAOYSA-N 0.000 claims description 2
- CWYNVVGOOAEACU-UHFFFAOYSA-N Fe2+ Chemical compound [Fe+2] CWYNVVGOOAEACU-UHFFFAOYSA-N 0.000 claims description 2
- GWEVSGVZZGPLCZ-UHFFFAOYSA-N Titan oxide Chemical compound O=[Ti]=O GWEVSGVZZGPLCZ-UHFFFAOYSA-N 0.000 claims description 2
- 229910001424 calcium ion Inorganic materials 0.000 claims description 2
- XLJKHNWPARRRJB-UHFFFAOYSA-N cobalt(2+) Chemical compound [Co+2] XLJKHNWPARRRJB-UHFFFAOYSA-N 0.000 claims description 2
- IVMYJDGYRUAWML-UHFFFAOYSA-N cobalt(II) oxide Inorganic materials [Co]=O IVMYJDGYRUAWML-UHFFFAOYSA-N 0.000 claims description 2
- 229910052802 copper Inorganic materials 0.000 claims description 2
- 239000010949 copper Substances 0.000 claims description 2
- 239000010779 crude oil Substances 0.000 claims description 2
- 239000013078 crystal Substances 0.000 claims description 2
- 239000003792 electrolyte Substances 0.000 claims description 2
- 229910001448 ferrous ion Inorganic materials 0.000 claims description 2
- 229910052500 inorganic mineral Inorganic materials 0.000 claims description 2
- 239000000395 magnesium oxide Substances 0.000 claims description 2
- CPLXHLVBOLITMK-UHFFFAOYSA-N magnesium oxide Inorganic materials [Mg]=O CPLXHLVBOLITMK-UHFFFAOYSA-N 0.000 claims description 2
- AXZKOIWUVFPNLO-UHFFFAOYSA-N magnesium;oxygen(2-) Chemical compound [O-2].[Mg+2] AXZKOIWUVFPNLO-UHFFFAOYSA-N 0.000 claims description 2
- 229910001437 manganese ion Inorganic materials 0.000 claims description 2
- 239000011707 mineral Substances 0.000 claims description 2
- RVTZCBVAJQQJTK-UHFFFAOYSA-N oxygen(2-);zirconium(4+) Chemical compound [O-2].[O-2].[Zr+4] RVTZCBVAJQQJTK-UHFFFAOYSA-N 0.000 claims description 2
- 230000004044 response Effects 0.000 claims description 2
- OGIDPMRJRNCKJF-UHFFFAOYSA-N titanium oxide Inorganic materials [Ti]=O OGIDPMRJRNCKJF-UHFFFAOYSA-N 0.000 claims description 2
- 239000011787 zinc oxide Substances 0.000 claims description 2
- 229910001928 zirconium oxide Inorganic materials 0.000 claims description 2
- RTVHKGIVFVKLDJ-UHFFFAOYSA-N barium(2+);iron(3+);oxygen(2-) Chemical compound [O-2].[O-2].[O-2].[O-2].[Fe+3].[Fe+3].[Ba+2] RTVHKGIVFVKLDJ-UHFFFAOYSA-N 0.000 claims 1
- 238000005259 measurement Methods 0.000 description 14
- 238000004458 analytical method Methods 0.000 description 9
- 239000000126 substance Substances 0.000 description 9
- 238000012544 monitoring process Methods 0.000 description 7
- 150000003839 salts Chemical class 0.000 description 6
- VNDYJBBGRKZCSX-UHFFFAOYSA-L zinc bromide Chemical compound Br[Zn]Br VNDYJBBGRKZCSX-UHFFFAOYSA-L 0.000 description 6
- 229910052751 metal Inorganic materials 0.000 description 5
- 239000002184 metal Chemical class 0.000 description 5
- 239000002101 nanobubble Substances 0.000 description 5
- 239000003921 oil Substances 0.000 description 5
- 238000012360 testing method Methods 0.000 description 5
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 4
- 239000002253 acid Substances 0.000 description 4
- 238000001514 detection method Methods 0.000 description 4
- 239000011148 porous material Substances 0.000 description 4
- 238000011084 recovery Methods 0.000 description 4
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 3
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 description 3
- 150000007513 acids Chemical class 0.000 description 3
- XMBWDFGMSWQBCA-UHFFFAOYSA-N hydrogen iodide Chemical compound I XMBWDFGMSWQBCA-UHFFFAOYSA-N 0.000 description 3
- 239000000463 material Substances 0.000 description 3
- 230000007246 mechanism Effects 0.000 description 3
- 239000002105 nanoparticle Substances 0.000 description 3
- 238000012856 packing Methods 0.000 description 3
- 239000012071 phase Substances 0.000 description 3
- 239000000049 pigment Substances 0.000 description 3
- 230000002285 radioactive effect Effects 0.000 description 3
- UXVMQQNJUSDDNG-UHFFFAOYSA-L Calcium chloride Chemical compound [Cl-].[Cl-].[Ca+2] UXVMQQNJUSDDNG-UHFFFAOYSA-L 0.000 description 2
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 2
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 2
- TWRXJAOTZQYOKJ-UHFFFAOYSA-L Magnesium chloride Chemical compound [Mg+2].[Cl-].[Cl-] TWRXJAOTZQYOKJ-UHFFFAOYSA-L 0.000 description 2
- ZMZDMBWJUHKJPS-UHFFFAOYSA-M Thiocyanate anion Chemical compound [S-]C#N ZMZDMBWJUHKJPS-UHFFFAOYSA-M 0.000 description 2
- 239000007864 aqueous solution Substances 0.000 description 2
- 230000008901 benefit Effects 0.000 description 2
- 229910001622 calcium bromide Inorganic materials 0.000 description 2
- 239000001110 calcium chloride Substances 0.000 description 2
- 229910001628 calcium chloride Inorganic materials 0.000 description 2
- WGEFECGEFUFIQW-UHFFFAOYSA-L calcium dibromide Chemical compound [Ca+2].[Br-].[Br-] WGEFECGEFUFIQW-UHFFFAOYSA-L 0.000 description 2
- 230000008859 change Effects 0.000 description 2
- 239000000706 filtrate Substances 0.000 description 2
- 239000006260 foam Substances 0.000 description 2
- ZMZDMBWJUHKJPS-UHFFFAOYSA-N hydrogen thiocyanate Natural products SC#N ZMZDMBWJUHKJPS-UHFFFAOYSA-N 0.000 description 2
- 239000003112 inhibitor Substances 0.000 description 2
- 239000007791 liquid phase Substances 0.000 description 2
- 239000011159 matrix material Substances 0.000 description 2
- 230000035699 permeability Effects 0.000 description 2
- 239000001103 potassium chloride Substances 0.000 description 2
- 239000004576 sand Substances 0.000 description 2
- 229920006395 saturated elastomer Polymers 0.000 description 2
- 239000011780 sodium chloride Substances 0.000 description 2
- 125000006850 spacer group Chemical group 0.000 description 2
- 230000000638 stimulation Effects 0.000 description 2
- MYRTYDVEIRVNKP-UHFFFAOYSA-N 1,2-Divinylbenzene Chemical compound C=CC1=CC=CC=C1C=C MYRTYDVEIRVNKP-UHFFFAOYSA-N 0.000 description 1
- NLXLAEXVIDQMFP-UHFFFAOYSA-N Ammonia chloride Chemical compound [NH4+].[Cl-] NLXLAEXVIDQMFP-UHFFFAOYSA-N 0.000 description 1
- QGZKDVFQNNGYKY-UHFFFAOYSA-O Ammonium Chemical compound [NH4+] QGZKDVFQNNGYKY-UHFFFAOYSA-O 0.000 description 1
- CPELXLSAUQHCOX-UHFFFAOYSA-M Bromide Chemical compound [Br-] CPELXLSAUQHCOX-UHFFFAOYSA-M 0.000 description 1
- 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 1
- 229910002651 NO3 Inorganic materials 0.000 description 1
- NHNBFGGVMKEFGY-UHFFFAOYSA-N Nitrate Chemical compound [O-][N+]([O-])=O NHNBFGGVMKEFGY-UHFFFAOYSA-N 0.000 description 1
- 239000004280 Sodium formate Substances 0.000 description 1
- HPYIMVBXZPJVBV-UHFFFAOYSA-N barium(2+);iron(3+);oxygen(2-) Chemical compound [O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[Fe+3].[Fe+3].[Fe+3].[Fe+3].[Fe+3].[Fe+3].[Fe+3].[Fe+3].[Fe+3].[Fe+3].[Fe+3].[Fe+3].[Ba+2] HPYIMVBXZPJVBV-UHFFFAOYSA-N 0.000 description 1
- 239000011324 bead Substances 0.000 description 1
- 239000003139 biocide Substances 0.000 description 1
- 230000031018 biological processes and functions Effects 0.000 description 1
- 230000033228 biological regulation Effects 0.000 description 1
- 239000012267 brine Substances 0.000 description 1
- 239000001569 carbon dioxide Substances 0.000 description 1
- 229910002092 carbon dioxide Inorganic materials 0.000 description 1
- 150000004649 carbonic acid derivatives Chemical class 0.000 description 1
- 239000000919 ceramic Substances 0.000 description 1
- 238000006243 chemical reaction Methods 0.000 description 1
- 238000004587 chromatography analysis Methods 0.000 description 1
- 239000004927 clay Substances 0.000 description 1
- 230000000052 comparative effect Effects 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 229920001577 copolymer Polymers 0.000 description 1
- 238000004132 cross linking Methods 0.000 description 1
- 238000002425 crystallisation Methods 0.000 description 1
- 230000008025 crystallization Effects 0.000 description 1
- 239000006185 dispersion Substances 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 239000013505 freshwater Substances 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 230000005764 inhibitory process Effects 0.000 description 1
- 238000004255 ion exchange chromatography Methods 0.000 description 1
- 229910052742 iron Inorganic materials 0.000 description 1
- 230000001788 irregular Effects 0.000 description 1
- 239000004816 latex Substances 0.000 description 1
- 229920000126 latex Polymers 0.000 description 1
- 238000004811 liquid chromatography Methods 0.000 description 1
- 230000007774 longterm Effects 0.000 description 1
- 229910001629 magnesium chloride Inorganic materials 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- 229910044991 metal oxide Inorganic materials 0.000 description 1
- 150000004706 metal oxides Chemical class 0.000 description 1
- 229910001463 metal phosphate Inorganic materials 0.000 description 1
- 150000002739 metals Chemical class 0.000 description 1
- 239000003607 modifier Substances 0.000 description 1
- 150000002823 nitrates Chemical class 0.000 description 1
- 150000007524 organic acids Chemical class 0.000 description 1
- 235000005985 organic acids Nutrition 0.000 description 1
- 239000003208 petroleum Substances 0.000 description 1
- 229920000642 polymer Polymers 0.000 description 1
- WFIZEGIEIOHZCP-UHFFFAOYSA-M potassium formate Chemical compound [K+].[O-]C=O WFIZEGIEIOHZCP-UHFFFAOYSA-M 0.000 description 1
- 159000000001 potassium salts Chemical class 0.000 description 1
- 238000004445 quantitative analysis Methods 0.000 description 1
- 239000000941 radioactive substance Substances 0.000 description 1
- 238000005204 segregation Methods 0.000 description 1
- 239000011734 sodium Substances 0.000 description 1
- 229910052708 sodium Inorganic materials 0.000 description 1
- HLBBKKJFGFRGMU-UHFFFAOYSA-M sodium formate Chemical compound [Na+].[O-]C=O HLBBKKJFGFRGMU-UHFFFAOYSA-M 0.000 description 1
- 235000019254 sodium formate Nutrition 0.000 description 1
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 1
- 239000011973 solid acid Substances 0.000 description 1
- 230000006641 stabilisation Effects 0.000 description 1
- 238000011105 stabilization Methods 0.000 description 1
- 238000013517 stratification Methods 0.000 description 1
- 150000003467 sulfuric acid derivatives Chemical class 0.000 description 1
- 239000000725 suspension Substances 0.000 description 1
- 150000003567 thiocyanates Chemical class 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/10—Locating fluid leaks, intrusions or movements
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/10—Locating fluid leaks, intrusions or movements
- E21B47/11—Locating fluid leaks, intrusions or movements using tracers; using radioactivity
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B28/00—Vibration generating arrangements for boreholes or wells, e.g. for stimulating production
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/25—Methods for stimulating production
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
Definitions
- This invention relates generally to the recovery of hydrocarbons from a subterranean formation penetrated by a well bore and more particularly to non-radioactive tracers and methods of utilizing the non-radioactive tracers for tracking treatment and reservoir fluids in the formation in order to evaluate and understand the operations executed in the wellbore and/or in the reservoir, near wellbore and wellbore processes and fluid placements such as gravelling packing, hydraulic fracturing, sand control and cementing and drilling fluids flow and placement.
- Radioactive and/or chemical tracers which can be readily identified are used for monitoring of treatment fluids injection into the reservoir as a means to monitor hydraulic fracturing, acidizing, water control and other wellbore and reservoir treatments.
- U.S. Pat. No. 5,243,190 provides an example of radioactive elements incorporated within ceramic particles and used for tracing flow of proppant particles employed in the process of hydraulic fracturing of wells.
- the use of radioactive or chemical substances as tracers sometimes is not desirable and is even prohibited by environmental regulations.
- U.S. Pat. No. 6,725,926 proposes the use of tracer agents selected from the group consisting of water soluble inorganic salts, water soluble organic salts, metals, metal salts of organic acids, metal oxides, metal sulfates, metal phosphates, metal carbonates, metal salts, phosphorescent pigments, fluorescent pigments, photoluminescent pigments etc.
- thiocyanate, bromide, iodide or nitrate salts can be used (Hutchins, R. D. et al., Aqueous Tracers for Oilfield Applications, SPE International Symposium on Oilfield Chemistry, 20-22 Feb. 1991, Anaheim, Calif., 21049-MS).
- Fluorescent markers and tracers can be made for Water Based fluids and are used in concentration of 0.018 ml in 180 ml filtrate and fluorescent markers and tracers for Synthetic/Oil Based fluids (concentration from 9 to 36 microliters in 180 ml filtrate).
- It is therefore an object of the invention to provide a method for tracking a treatment fluid in a subterranean formation penetrated by a wellbore comprising the steps of providing the treatment fluid comprising a plurality of tracer agents, wherein each tracer agent is an object of submicron scale, injecting the treatment fluid with the plurality of tracer agents into the wellbore and the formation, and determining the location and distribution of the treatment fluid by detecting changes in the physical properties of the formation caused by the arrival of treatment fluid comprising a plurality of tracer agents.
- the treatment fluid is selected from the group consisting of fracturing fluids, drilling fluids, acidizing fluids, injection fluids, brines and completion fluids, fluids for EOR/IOR including reservoir flooding fluids.
- the plurality of tracer agents are low or insoluble gas bubbles having a diameter of not more than 500 nm and the treatment fluid with the plurality of tracer agents is a highly dispersed gas-liquid mixture.
- gases for use as the tracer agents are methane, higher molecular weight hydrocarbon gas, nitrogen or other insoluble inorganic gas or mixtures of thereof.
- the nano-bubbles are normally created by dispersion of above mentioned gas or gases in water- or hydrocarbon-based solutions
- Water solutions can be made with different conventional oilfield salts (NaCl, KCl, CaCl 2 , ZnBr 2 , CaBr 2 , and other inorganic or organic brines and their mixtures) that are used as completions solutions (brines and heavy brines) and other oilfield fluids.
- Nano-bubbles can be particularly strongly stabilized with electrolytes of ferrous ions, manganese ions, calcium ions, or any other mineral ion is added to the aqueous solution such that the electrical conductivity in the aqueous solution becomes not less than 300 ⁇ S/cm.
- the nano-bubble is a very tiny bubble having a diameter of not more than 500 nm, so that the nano-bubble does not experience buoyant forces and rupture near the fluid surface, which is observed in normal and micro-bubbles.
- the plurality of tracer agents are high viscous liquid droplets having a diameter of not more than 1000 nm and the treatment fluid with the plurality of tracer agents is an emulsion such as crude oil in water, toluene in water etc.
- water is fresh water
- solutions of different salts inorganic as NaCl, KCl, NH 4 Cl, CaCl 2 , MgCl 2 , NaBr 2 , ZnBr 2 , CaBr 2 , or of organic nature such as sodium formate, potassium formate and other brines and their mixtures commonly used in stimulation, gravel pack and completion operations including) in water (saturated or under-saturated), brines and water with other chemicals such as surfactants, biocides, clay control, iron control, scale control etc. used as additives. It is not unusual that the emulsions are stabilized with the use of nano-solid particles, such as silica, for example.
- Size of the silica nano-particles ranges between 2-500 nm,
- the loading of the solid nano-particles for the purpose of the stabilization has seen concentrations from 0.1 wt % to 15 wt % depending on the salinity and the temperature of the system, where the increase in salinity normally requires an increase in solids concentration for the stability of the emulsion to be increased.
- the plurality of tracer agents are solid particles. These particles can be silica, synthesized copper, magnetite (Fe3O4), ferri/ferrous chlorides, barium iron oxide (BaFe12O19), zinc oxide, aluminium oxide, magnesium oxide, zirconium oxide, titanium oxide, cobalt (II) and nickel (II) oxide, barium sulfate (BaSO4), etc. and the treatment fluid with the plurality of tracer agents is stabilized solution in aqueous fluids, solvent based fluids such as alcohols, [ethylene glycol], or hydrocarbon based fluids.
- solvent based fluids such as alcohols, [ethylene glycol], or hydrocarbon based fluids.
- the particles can be also of organic origin such as co-polymer suspensions such as latex, polysteren beads x-linked with di-vinyl benzene and others. Pyrolectric and piezoelectric crystals may also be used in the compositions herein.
- the treatment fluid comprising a plurality of tracer agents is provided by mixing the treatment fluid with the plurality of tracer agents by means of a generator placed in the wellbore or by surface located equipment.
- the treatment fluid comprising a plurality of tracer agents can be injected continuously during the treatment duration or periodically.
- the treatment fluid comprising a plurality of tracer agents can be injected at any stage of the treatment including pre and post-treatment injection, during the complete treatment or partially.
- the injection into the formation may be complemented with physical treatment such as vibration, heating acoustic treatments performed before, during or after the injection process is performed.
- the method can include adding to the treatment fluid comprising a plurality of tracer agents one or more additives selected from a group comprising gelling agents, foaming agents, friction reducers, surfactants, demulsifiers, inhibitors.
- Physical properties of the formation are acoustic impedance and/or electric conductivity and/or magnetic permittivity, nuclear magnetic resonance (NMR) response, thermal propagation and hydrodynamic flow capabilities.
- NMR nuclear magnetic resonance
- the detecting of physical properties of the formation is made by seismic, acoustic, electrical, electrokinetical, thermal, NMR, neutron or gamma-ray means that can be located on the surface and/or wellbore or cross wellbore.
- the treatment fluid with the plurality of tracer agents can be flowed back from the subterranean formation and analyzed for changes in the tracer agents concentration, size, type and distribution function between the injected and produced treatment fluid.
- the analysis of the changes in the tracer agents concentration, size and type distribution function between the injected and produced treatment fluids can be performed while flowing in the formation by the acoustics, electric, thermal, neutron or gamma-ray logging or by comparing samples of the injection and produced fluids.
- a treatment fluid comprising a plurality of tracer agents, wherein each tracer agent is an object of submicron scale, is injected into the wellbore and the formation.
- Typical diameter/length dimension of a tracer agent is within the range between 1-1000 nm.
- nano-tracers The injection or flow of objects of submicron scale (so called nano-tracers) that are contained within the treatment fluid serve as markers/tracers because their property of staying in bulk of the transport fluid without gravity segregation and no change in type of distribution function of the markers within time of the duration of the formation treatment and measurement operation.
- the nano-tracers have the main advantage that because of their size will occupy the whole volume that the fluid has created in the formation, including pore space or ultra small fissures where the fluid leaked off. This is in particular important in matrix acidizing where fluid is injected into pore space or in shale gas fracturing where swarms of fissures are created in the process of hydraulic fracturing.
- micro and nano-mixtures refer to a portion or full volume of the treatment fluid mixture of:
- the creation of the treatment fluid with the plurality of tracer agents is carried out by either down-hole nano-tracers mixture generator placed in the wellbore or by surface located equipment which can be in form of generators or various types of tanks or canisters supplying the volume required for injection of the mixture.
- surface generator of nano bubbles is well explained in U.S. Pat. No. 7,059,591.
- Various fine size bubble generators are described in Japanese Patent Application Publication No. 2001-276589. 2002-11335, 2002-166151, and No. 2003-117368, Japanese Patent No. 3682286, EP application 2020260 and similar can be envisioned.
- the mixture can be injected continuously during the treatment duration or periodically at any rate and concentration.
- the mixture can be injected at any stage of the treatment including pre and post-treatment injection, during the complete treatment or partially.
- the injection into the formation may be complemented with physical treatment such as vibration, heating, acoustic treatments performed before, during or after the injection process is performed.
- the mixtures can be different in terms of type of base fluid and/or gas utilized for each treatment, or during the stage of the treatment allowing to distinguish the various stages within the single treatment or the multiple treatments within the same wellbore or the multi-wellbore completion.
- measurements are then performed to determine the location and distribution of the treatment fluid and to evaluate its geometric distribution and diversion by the means of measuring the change in physical properties of porous environment of the formation and placed hydraulic or natural fractures and fissures. It also allows monitoring and evaluating of near wellbore and wellbore processes and fluid placements such as fracturing, frac-pack treatments, matrix acidizing, scale inhibition squeezes, gravel packing, sand control and cementing and drilling fluids flow and placement of other various chemical and physical treatments of underground formation such as injection of surfactants, wetability modifiers, demulsifiers, alcohols, solvents, hot water or hot chemical injections, under positive pressure compared to the formation pressure.
- the detection and measurement mechanism is based on seismic, acoustic, electrical, electrokinetical, thermal, neutron and gamma-ray measurements that can be conducted from surface and/or wellbore or cross wellbore.
- the fluid and nano-tracers can be analyzed for changes in the tracers concentration, size, type (if multiples types of mixtures of different markers are used) distribution function between the injected and produced fluid.
- the analysis can be performed either downhole or at surface with the adequate method of the analysis depending on the nature of the markers used.
- the analysis can then provide additional information on the space that the tracers have occupied such but not limited to the permeability and conductivity of the fracture, effective permeability of the formation, the fluids that the markers interacted with and the PVT conditions they were exposed, the amount of fluid returned to surface vs. the amount of fracturing fluid that has leaked off.
- the nano-tracers can have various subsurface applications.
- nano-tracers can be added to the proppant or to the fracturing fluid at different times during the placement of proppant or treatment fluids (such as main fracturing fluids, spacers or pre-flush or flush in proppant fracturing or acids, spacers, pre-flushes or flushes in acid fracturing) during or after the fracturing process.
- the injection can be done during the main fracturing treatments as well as during the test-fracturing that is typically performed before the main fracturing treatment (so called injection, calibration step rate tests or mini-frac tests), cool-down stages preceding the main frac treatment or even after the main fracturing treatment as post-treatment injection into the pre-existing fracture.
- the detection and measurement mechanism is based on seismic, acoustic, electrical, electrokinetical, neutron, thermal and gamma-ray measurements that can be conducted from surface and/or wellbore or cross wellbore.
- Nano-tracers can be added to the gravel and gravel pack fluids.
- Various measurements can be performed after the gravel packing operations to detect where the fluid and the gravel pack materials have been injected/placed.
- the detection and measurement mechanism is based on seismic, acoustic, electrical, electrokinetical, neutron, thermal and gamma-ray measurements that can be conducted from surface and/or wellbore or cross wellbore.
- the nano-tracers can be mixed with acids, solid acids pre-flushes and flushes such as brines, solutions of surfactants, chemical washes, scale and asphaltene inhibitor and their solutions, solvents and demuslfiers, gases, foams, diverter materials (solids, liquid and gaseous) or other compounds used in the treatment sequence to track/monitor completion related operations.
- acids solid acids pre-flushes and flushes such as brines, solutions of surfactants, chemical washes, scale and asphaltene inhibitor and their solutions, solvents and demuslfiers, gases, foams, diverter materials (solids, liquid and gaseous) or other compounds used in the treatment sequence to track/monitor completion related operations.
- the measurements on the placement of the fluids allow for fluid placement and fluid diversion detection in wellbores, multi zone stimulation and treatments, injection monitoring and flowback of the treatment and reservoir fluids.
- the release of tagging nano-tracers into the flow can be used to obtain flow velocity or flow profile.
- indication of fluid stratification, phase flow, fluid lagging, or fluid flow directions can be interpreted.
- Nano-tracers injection and/or release can be used for identification/monitoring, of flood front allocation, of various techniques of Enhanced Oil Recovery techniques, where water, foams, gases (nitrogen, carbon dioxide, steam and others), surfactants, miscible and immiscible hydrocarbon, are injected in injector wells and with or without additional application of heat to increase the recovery factor of the reservoir. While these techniques are widely used in the industry, further improvements in oil recovery can be achieved by monitoring the flood front and controlling and optimizing the injection and production system of the field or field sector.
- Enhanced Oil Recovery techniques where water, foams, gases (nitrogen, carbon dioxide, steam and others), surfactants, miscible and immiscible hydrocarbon, are injected in injector wells and with or without additional application of heat to increase the recovery factor of the reservoir. While these techniques are widely used in the industry, further improvements in oil recovery can be achieved by monitoring the flood front and controlling and optimizing the injection and production system of the field or field sector.
- Nano-tracers can be used to track fracturing fluids in tight gas shale where swarms of fissures are created in the process of hydraulic fracturing.
- the proposed method where the fracturing fluids contain nano tracers would allow for complete coverage of the hydraulically created fracture area.
- Nano-tracer types can be used in combination to perform any of the operations disclosed herein.
Abstract
A method of tracking a treatment fluid in a subterranean formation penetrated by a wellbore provides for injecting the treatment fluid with the plurality of tracer agents into the well and the formation. Each tracer agent is an object of submicron scale. The location and distribution of the treatment fluid is determined by detecting changes in the physical properties of the formation caused by the arrival of the treatment fluid comprising a plurality of tracer agents.
Description
- This invention relates generally to the recovery of hydrocarbons from a subterranean formation penetrated by a well bore and more particularly to non-radioactive tracers and methods of utilizing the non-radioactive tracers for tracking treatment and reservoir fluids in the formation in order to evaluate and understand the operations executed in the wellbore and/or in the reservoir, near wellbore and wellbore processes and fluid placements such as gravelling packing, hydraulic fracturing, sand control and cementing and drilling fluids flow and placement.
- The use of various kinds of markers/tracers in the oil and gas industry is well known. Radioactive and/or chemical tracers which can be readily identified are used for monitoring of treatment fluids injection into the reservoir as a means to monitor hydraulic fracturing, acidizing, water control and other wellbore and reservoir treatments.
- Thus, U.S. Pat. No. 5,243,190 provides an example of radioactive elements incorporated within ceramic particles and used for tracing flow of proppant particles employed in the process of hydraulic fracturing of wells. The use of radioactive or chemical substances as tracers sometimes is not desirable and is even prohibited by environmental regulations.
- Other techniques using non-radioactive tracers have also been proposed. U.S. Pat. No. 6,725,926 proposes the use of tracer agents selected from the group consisting of water soluble inorganic salts, water soluble organic salts, metals, metal salts of organic acids, metal oxides, metal sulfates, metal phosphates, metal carbonates, metal salts, phosphorescent pigments, fluorescent pigments, photoluminescent pigments etc.
- Inexpensive tracers and analysis, with a short reservoir lifetime of a week or so, thiocyanate, bromide, iodide or nitrate salts can be used (Hutchins, R. D. et al., Aqueous Tracers for Oilfield Applications, SPE International Symposium on Oilfield Chemistry, 20-22 Feb. 1991, Anaheim, Calif., 21049-MS).
- Analysis can be done with ion or liquid chromatography, which is lab based and expensive, but qualitative tests using “Spot Plate Tests” are available to detect nitrate, thiocyanate and iodide to roughly gauge the level by color intensity as simple and even on-site usage solution. Alternatively Iodide and thiocyanate salts have simple spectrometer tests that can be used instead chromatography for quantitative analysis. These ions should not interfere with the typical fluid crosslinking chemistry used in hydraulic fracturing, as they are used at levels of 1000 ppm or so and detectable to 1 ppm. The sodium, ammonium or potassium salts are soluble and have been used in tracing of fluid movements in the reservoir.
- Chemical tracers with the explanation of their use and the methodology of measurements in post frac and long term flowback analysis are published in Mahmoud Asadi et al., Comparative Study of Flowback Analysis Using Polymer Concentrations and Fracturing Fluid Tracer Methods: A Field Study, International Oil & Gas Conference and Exhibition in China, 5-7 Dec. 2006, Beijing, China, SPE 101614, and Mahmoud Asadi et al., Post-Frac Analysis Based on Flowback Results Using Chemical Frac-Tracers, International Petroleum Technology Conference, 3-5 Dec. 2008, Kuala Lumpur, Malaysia, IPTC 11891.
- Fluorescent markers and tracers can be made for Water Based fluids and are used in concentration of 0.018 ml in 180 ml filtrate and fluorescent markers and tracers for Synthetic/Oil Based fluids (concentration from 9 to 36 microliters in 180 ml filtrate).
- Though these methods are quite useful there is a need for an environmentally friendly high resolution method for tracking treatment fluids that are capable of entering the drilling mud cake, gravel pack, proppant pack and other large porous media and also capable of entering without plugging the pore throats into the pore space (or fractures and fissures) of the reservoir to a reasonable distance.
- It is therefore an object of the invention to provide a method for tracking a treatment fluid in a subterranean formation penetrated by a wellbore comprising the steps of providing the treatment fluid comprising a plurality of tracer agents, wherein each tracer agent is an object of submicron scale, injecting the treatment fluid with the plurality of tracer agents into the wellbore and the formation, and determining the location and distribution of the treatment fluid by detecting changes in the physical properties of the formation caused by the arrival of treatment fluid comprising a plurality of tracer agents.
- The treatment fluid is selected from the group consisting of fracturing fluids, drilling fluids, acidizing fluids, injection fluids, brines and completion fluids, fluids for EOR/IOR including reservoir flooding fluids.
- According to one embodiment, the plurality of tracer agents are low or insoluble gas bubbles having a diameter of not more than 500 nm and the treatment fluid with the plurality of tracer agents is a highly dispersed gas-liquid mixture. Suitable gases for use as the tracer agents are methane, higher molecular weight hydrocarbon gas, nitrogen or other insoluble inorganic gas or mixtures of thereof.
- The nano-bubbles are normally created by dispersion of above mentioned gas or gases in water- or hydrocarbon-based solutions Water solutions can be made with different conventional oilfield salts (NaCl, KCl, CaCl2, ZnBr2, CaBr2, and other inorganic or organic brines and their mixtures) that are used as completions solutions (brines and heavy brines) and other oilfield fluids. Nano-bubbles can be particularly strongly stabilized with electrolytes of ferrous ions, manganese ions, calcium ions, or any other mineral ion is added to the aqueous solution such that the electrical conductivity in the aqueous solution becomes not less than 300 μS/cm. The nano-bubble is a very tiny bubble having a diameter of not more than 500 nm, so that the nano-bubble does not experience buoyant forces and rupture near the fluid surface, which is observed in normal and micro-bubbles.
- According to another embodiment, the plurality of tracer agents are high viscous liquid droplets having a diameter of not more than 1000 nm and the treatment fluid with the plurality of tracer agents is an emulsion such as crude oil in water, toluene in water etc. where water is fresh water, solutions of different salts (inorganic as NaCl, KCl, NH4Cl, CaCl2, MgCl2, NaBr2, ZnBr2, CaBr2, or of organic nature such as sodium formate, potassium formate and other brines and their mixtures commonly used in stimulation, gravel pack and completion operations including) in water (saturated or under-saturated), brines and water with other chemicals such as surfactants, biocides, clay control, iron control, scale control etc. used as additives. It is not unusual that the emulsions are stabilized with the use of nano-solid particles, such as silica, for example. Size of the silica nano-particles ranges between 2-500 nm, The loading of the solid nano-particles for the purpose of the stabilization has seen concentrations from 0.1 wt % to 15 wt % depending on the salinity and the temperature of the system, where the increase in salinity normally requires an increase in solids concentration for the stability of the emulsion to be increased.
- According to yet another embodiment, the plurality of tracer agents are solid particles. These particles can be silica, synthesized copper, magnetite (Fe3O4), ferri/ferrous chlorides, barium iron oxide (BaFe12O19), zinc oxide, aluminium oxide, magnesium oxide, zirconium oxide, titanium oxide, cobalt (II) and nickel (II) oxide, barium sulfate (BaSO4), etc. and the treatment fluid with the plurality of tracer agents is stabilized solution in aqueous fluids, solvent based fluids such as alcohols, [ethylene glycol], or hydrocarbon based fluids. The particles can be also of organic origin such as co-polymer suspensions such as latex, polysteren beads x-linked with di-vinyl benzene and others. Pyrolectric and piezoelectric crystals may also be used in the compositions herein.
- The treatment fluid comprising a plurality of tracer agents is provided by mixing the treatment fluid with the plurality of tracer agents by means of a generator placed in the wellbore or by surface located equipment.
- The treatment fluid comprising a plurality of tracer agents can be injected continuously during the treatment duration or periodically.
- The treatment fluid comprising a plurality of tracer agents can be injected at any stage of the treatment including pre and post-treatment injection, during the complete treatment or partially.
- The injection into the formation may be complemented with physical treatment such as vibration, heating acoustic treatments performed before, during or after the injection process is performed.
- In another embodiment, the method can include adding to the treatment fluid comprising a plurality of tracer agents one or more additives selected from a group comprising gelling agents, foaming agents, friction reducers, surfactants, demulsifiers, inhibitors.
- Physical properties of the formation are acoustic impedance and/or electric conductivity and/or magnetic permittivity, nuclear magnetic resonance (NMR) response, thermal propagation and hydrodynamic flow capabilities.
- The detecting of physical properties of the formation is made by seismic, acoustic, electrical, electrokinetical, thermal, NMR, neutron or gamma-ray means that can be located on the surface and/or wellbore or cross wellbore.
- The treatment fluid with the plurality of tracer agents can be flowed back from the subterranean formation and analyzed for changes in the tracer agents concentration, size, type and distribution function between the injected and produced treatment fluid.
- The analysis of the changes in the tracer agents concentration, size and type distribution function between the injected and produced treatment fluids can be performed while flowing in the formation by the acoustics, electric, thermal, neutron or gamma-ray logging or by comparing samples of the injection and produced fluids.
- Another aspects and advantages of the invention will be apparent from the following description and the appended claims.
- A treatment fluid comprising a plurality of tracer agents, wherein each tracer agent is an object of submicron scale, is injected into the wellbore and the formation. Typical diameter/length dimension of a tracer agent is within the range between 1-1000 nm.
- The injection or flow of objects of submicron scale (so called nano-tracers) that are contained within the treatment fluid serve as markers/tracers because their property of staying in bulk of the transport fluid without gravity segregation and no change in type of distribution function of the markers within time of the duration of the formation treatment and measurement operation. Further the nano-tracers have the main advantage that because of their size will occupy the whole volume that the fluid has created in the formation, including pore space or ultra small fissures where the fluid leaked off. This is in particular important in matrix acidizing where fluid is injected into pore space or in shale gas fracturing where swarms of fissures are created in the process of hydraulic fracturing. In contrary to the microseismic measurements in the shale fracturing where the registration of events is scarce and not necessary related to the treatment fluid propagation within the formation and hence the monitoring is therefore incomplete, the proposed method would allow for complete coverage of the hydraulically created fracture area.
- Here the micro and nano-mixtures refer to a portion or full volume of the treatment fluid mixture of:
-
- Gas and liquid, whereas the gas is a low or no soluble gas bubbles in the liquid and liquid can be any mixture of water, brine, acids, hydrocarbons with any combination of additives such but not limited to as gelling agents, foaming agents, friction reducers etc. Gas used can be hydrocarbon gas such as methane or higher molecular weight hydrocarbon gas, nitrogen or other inorganic gas or mixtures of thereof. The liquid phase is the prime phase and the gas the secondary phase dispersed in the mixture with known size distribution, and life span and determines the physical and chemical properties of the mixture;
- Liquid-Liquid, so-called an emulsion which can be a presence of the high viscous liquid inside the low viscous liquid, as well as the presence of smaller droplets inside the larger one called double, triple etc. emulsion;
- Liquid-solids, where the presence of the solid object inside the main liquid phase can be produced by the introducing the solid particles, crystallization, chemical reaction, biological processes etc. The tracer agents can be of various shapes, ellipsoid, plate or needle-like, spherical, irregular etc. depending on the material used.
- The creation of the treatment fluid with the plurality of tracer agents is carried out by either down-hole nano-tracers mixture generator placed in the wellbore or by surface located equipment which can be in form of generators or various types of tanks or canisters supplying the volume required for injection of the mixture. The example of such surface generator of nano bubbles is well explained in U.S. Pat. No. 7,059,591. Various fine size bubble generators are described in Japanese Patent Application Publication No. 2001-276589. 2002-11335, 2002-166151, and No. 2003-117368, Japanese Patent No. 3682286, EP application 2020260 and similar can be envisioned.
- The generation of solid nano particles is explained in several instances and also in US patent application No. 2009/0107673 and PCT patent No. WO2009/079092.
- The mixture can be injected continuously during the treatment duration or periodically at any rate and concentration. The mixture can be injected at any stage of the treatment including pre and post-treatment injection, during the complete treatment or partially. The injection into the formation may be complemented with physical treatment such as vibration, heating, acoustic treatments performed before, during or after the injection process is performed. The mixtures can be different in terms of type of base fluid and/or gas utilized for each treatment, or during the stage of the treatment allowing to distinguish the various stages within the single treatment or the multiple treatments within the same wellbore or the multi-wellbore completion.
- Thereafter measurements are then performed to determine the location and distribution of the treatment fluid and to evaluate its geometric distribution and diversion by the means of measuring the change in physical properties of porous environment of the formation and placed hydraulic or natural fractures and fissures. It also allows monitoring and evaluating of near wellbore and wellbore processes and fluid placements such as fracturing, frac-pack treatments, matrix acidizing, scale inhibition squeezes, gravel packing, sand control and cementing and drilling fluids flow and placement of other various chemical and physical treatments of underground formation such as injection of surfactants, wetability modifiers, demulsifiers, alcohols, solvents, hot water or hot chemical injections, under positive pressure compared to the formation pressure.
- The detection and measurement mechanism is based on seismic, acoustic, electrical, electrokinetical, thermal, neutron and gamma-ray measurements that can be conducted from surface and/or wellbore or cross wellbore.
- In the instance where formation and treatment fluid is flown back to the wellbore and then to the surface the fluid and nano-tracers can be analyzed for changes in the tracers concentration, size, type (if multiples types of mixtures of different markers are used) distribution function between the injected and produced fluid. The analysis can be performed either downhole or at surface with the adequate method of the analysis depending on the nature of the markers used. The analysis can then provide additional information on the space that the tracers have occupied such but not limited to the permeability and conductivity of the fracture, effective permeability of the formation, the fluids that the markers interacted with and the PVT conditions they were exposed, the amount of fluid returned to surface vs. the amount of fracturing fluid that has leaked off.
- The nano-tracers can have various subsurface applications.
- Different types of nano-tracers can be added to the proppant or to the fracturing fluid at different times during the placement of proppant or treatment fluids (such as main fracturing fluids, spacers or pre-flush or flush in proppant fracturing or acids, spacers, pre-flushes or flushes in acid fracturing) during or after the fracturing process. The injection can be done during the main fracturing treatments as well as during the test-fracturing that is typically performed before the main fracturing treatment (so called injection, calibration step rate tests or mini-frac tests), cool-down stages preceding the main frac treatment or even after the main fracturing treatment as post-treatment injection into the pre-existing fracture. Thereafter various measurements are then performed to detect where the fluid has been injected. The detection and measurement mechanism is based on seismic, acoustic, electrical, electrokinetical, neutron, thermal and gamma-ray measurements that can be conducted from surface and/or wellbore or cross wellbore.
- Different types of nano-tracers can be added to the gravel and gravel pack fluids. Various measurements can be performed after the gravel packing operations to detect where the fluid and the gravel pack materials have been injected/placed. The detection and measurement mechanism is based on seismic, acoustic, electrical, electrokinetical, neutron, thermal and gamma-ray measurements that can be conducted from surface and/or wellbore or cross wellbore.
- The nano-tracers can be mixed with acids, solid acids pre-flushes and flushes such as brines, solutions of surfactants, chemical washes, scale and asphaltene inhibitor and their solutions, solvents and demuslfiers, gases, foams, diverter materials (solids, liquid and gaseous) or other compounds used in the treatment sequence to track/monitor completion related operations. The measurements on the placement of the fluids allow for fluid placement and fluid diversion detection in wellbores, multi zone stimulation and treatments, injection monitoring and flowback of the treatment and reservoir fluids.
- The release of tagging nano-tracers into the flow can be used to obtain flow velocity or flow profile. In inclined and horizontal wellbores indication of fluid stratification, phase flow, fluid lagging, or fluid flow directions can be interpreted.
- Nano-tracers injection and/or release can be used for identification/monitoring, of flood front allocation, of various techniques of Enhanced Oil Recovery techniques, where water, foams, gases (nitrogen, carbon dioxide, steam and others), surfactants, miscible and immiscible hydrocarbon, are injected in injector wells and with or without additional application of heat to increase the recovery factor of the reservoir. While these techniques are widely used in the industry, further improvements in oil recovery can be achieved by monitoring the flood front and controlling and optimizing the injection and production system of the field or field sector.
- Nano-tracers can be used to track fracturing fluids in tight gas shale where swarms of fissures are created in the process of hydraulic fracturing. In contrary to the microseismic measurements in the shale fracturing where the registration of events is scarce and not necessary related to the treatment fluid propagation within the formation and hence the monitoring is therefore incomplete and incorrect, the proposed method where the fracturing fluids contain nano tracers would allow for complete coverage of the hydraulically created fracture area.
- Different nano-tracer types can be used in combination to perform any of the operations disclosed herein.
- While the invention has been described with respect to a preferred embodiments, those skilled in the art will devise other embodiments of this invention which do not depart from the scope of the invention as disclosed therein. Accordingly the scope of the invention should be limited only by the attached claims.
Claims (24)
1. A method of tracking a treatment fluid in a subterranean formation penetrated by a wellbore comprising the steps of:
providing a treatment fluid comprising a plurality of tracer agents, wherein each tracer agent is an object of submicron scale,
injecting the treatment fluid with the plurality of tracer agents into the well and the formation, and
determining the location and distribution of the treatment fluid by detecting changes in the physical properties of the formation caused by the arrival of the treatment fluid comprising a plurality of tracer agents.
2. The method of claim 1 wherein the treatment fluid is selected from the group consisting of fracturing fluids, drilling fluids, acidizing fluids, injection fluids, brines and completion fluids, fluids for EOR/IOR including reservoir flooding fluids.
3. The method of claim 1 wherein the plurality of tracer agents are low or insoluble gas bubbles having a diameter not more than 500 nm, the treatment fluid is water- or hydrocarbon-based solution and the treatment fluid with the plurality of tracer agents is a highly dispersed gas-liquid mixture.
4. The method of claim 3 wherein the gas is selected from the group consisting of methane, higher molecular weight hydrocarbon gas, nitrogen or other insoluble inorganic gas or mixtures of thereof.
6. The method of claim 1 wherein the plurality of tracer agents are high viscous liquid droplets having a diameter not more than 1000 nm, the treatment fluid is water- or hydrocarbon-based solution and the treatment fluid with the plurality of tracer agents is an emulsion.
7. The method of claim 6 wherein the high viscous liquid is crude oil or toluene.
8. The method of claim 1 wherein the plurality of tracer agents are solid particles and the treatment fluid with the plurality of tracer agents is a stabilized solution in aqueous fluids, solvent based fluids such as alcohols or hydrocarbon based fluids.
9. The method of claim 8 wherein the solid particles are selected from the group consisting of silica, synthesized copper, magnetite (Fe304), ferri/ferrous chlorides, barium iron oxide (BaFe12019), zinc oxide, aluminium oxide, magnesium oxide, zirconium oxide, titanium oxide, cobalt (II) and nickel (II) oxide, barium sulfate (BaS04), pyrolectric and piezoelectric crystals etc.
10. The method of claim 1 wherein the treatment fluid comprising a plurality of tracer agents is provided by mixing the treatment fluid with the plurality of tracer agents by means of a generator placed in the wellbore.
11. The method of claim 1 wherein the treatment fluid comprising a plurality of tracer agents is provided by mixing the treatment fluid with the plurality of tracer agents by means of the surface located equipment.
12. The method of claim 1 wherein the treatment fluid comprising a plurality of tracer agents is injected continuously during the treatment duration.
13. The method of claim 1 wherein the treatment fluid comprising a plurality of tracer agents is injected periodically during the treatment duration.
14. The method of claim 1 wherein the treatment fluid comprising a plurality of tracer agents is injected at any stage of the treatment.
15. The method of claim 1 wherein the injection of the treatment fluid is accompanied by physical treatment performed before, during or after the injection process.
16. The method of claim 15 wherein the physical treatment is vibration, or heating, or acoustic treatments.
17. The method of claim 1 wherein the treatment fluid additionally comprises one or more additives selected from a group comprising gelling agents, foaming agents, friction reducers, surfactants.
18. The method of claim 1 wherein physical properties of the formation are acoustic impedance and/or electric conductivity and/or magnetic permittivity, nuclear magnetic resonance (NMR) response, thermal propagation and hydrodynamic flow capabilities
19. The method of claim 1 wherein detecting of physical properties of the formation is made by seismic, acoustic, electrical, electrokinetical, NMR, thermal, neutron or gamma-ray means.
20. The method of claim 19 wherein detecting of physical properties of the formation is made by seismic, acoustic, electrical, electrokinetical, NMR, thermal, neutron or gamma-ray means located on the surface.
21. The method of claim 19 wherein detecting of physical properties of the formation is made by seismic, acoustic, electrical, electrokinetical, NMR, thermal, neutron or gamma-ray means located in the wellbore.
22. The method of claim 1 wherein the treatment fluid with the plurality of tracer agents is flowed back from the subterranean formation and analyzed for changes in the tracer agents concentration, size, type and distribution function between the injected and produced treatment fluid.
23. The method of claim 22 wherein analyzing changes in the tracer agents concentration, size and type distribution function between the injected and produced treatment fluids is performed while flowing in the formation by the acoustics, electric, thermal, neutron or gamma-ray logging.
24. The method of claim 22 wherein analyzing changes in the tracer agents concentration, size and type distribution function between the injected and produced treatment fluids is performed by comparing samples of the injection and produced fluids.
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US20140000357A1 (en) * | 2010-12-21 | 2014-01-02 | Schlumberger Technology Corporation | Method for estimating properties of a subterranean formation |
US20140357534A1 (en) * | 2011-12-09 | 2014-12-04 | William Marsh Rice University | Methods, apparatus, and sensors for tracing frac fluids in mineral formations, production waters, and the environment using magnetic particles |
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WO2016144355A1 (en) * | 2015-03-11 | 2016-09-15 | Halliburton Energy Services, Inc. | Non-radioactive tracer materials for monitoring treatment fluids in subterranean formations |
US20180135403A1 (en) * | 2011-11-22 | 2018-05-17 | Baker Hughes, A Ge Company, Llc | Method of using controlled release tracers |
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Also Published As
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RU2013128234A (en) | 2015-02-10 |
US20150300157A1 (en) | 2015-10-22 |
RU2548636C2 (en) | 2015-04-20 |
WO2012091599A1 (en) | 2012-07-05 |
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