# US 10,480,314 B2 · Well treatment > Agents: this data is available as JSON from the patentgrep API and MCP server — see https://patentgrep.com/llms.txt - Number: US 10,480,314 B2 - Document ID: US10480314B2 - Status: Granted - Kind: B2 - Application number: 14/787,481 - Filed: 2014-07-28 - Published: 2016-03-17 - Granted: 2019-11-19 - Earliest claimed: 2013-07-26 - Assignees: Schlumberger Technology Corporation - Applicants: Schlumberger Technology Corporation - Inventors: Murtaza Ziauddin; Ahmed S. Zakaria; Hisham Nasr-El-Din - Web page: https://patentgrep.com/patent/US10480314B2 ## CPC - E21B 49/008: {by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor (measuring pressure E21B47/06)} - C09K 8/03: Specific additives for general use in well-drilling compositions - C09K 8/42: Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells (compositions for plastering C09K8/50) - C09K 8/52: Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning - C09K 8/60: Compositions for stimulating production by acting on the underground formation - C09K 8/74: combined with additives added for specific purposes - E21B 43/25: Methods for stimulating production {(by vibrating earth formations E21B43/003)} - G06F 17/16: Matrix or vector computation {, e.g. matrix-matrix or matrix-vector multiplication, matrix factorization (matrix transposition G06F7/78)} - G06F 30/00: Computer-aided design [CAD] - E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS - C09K: MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE - G06F: ELECTRIC DIGITAL DATA PROCESSING (computer systems based on specific computational models G06N) ## Abstract In one aspect, methods may include quantifying a pore-scale heterogeneity of a porous medium; determining an adjusted pore volume to breakthrough based on the pore scale heterogeneity determined; and designing a stimulating fluid treatment for the porous medium. Other aspects may include the development of a wellbore stimulation methodology that allows stimulation fluid breakthrough curves of differing formation samples to be plotted as a single curve that accounts for the varied pore structure of the respective samples. ## Claims ### Claim 1 A method, comprising: quantifying a pore-scale heterogeneity of a porous medium, wherein the pore-scale heterogeneity is an overall variance of pore-size distribution; determining an adjusted pore volume to breakthrough based on the pore scale heterogeneity; using the pore-scale heterogeneity and the adjusted pore volume to breakthrough to design a stimulating fluid treatment for the porous medium; and performing the stimulating fluid treatment by injecting a stimulating fluid into a subterranean formation. ### Claim 2 (depends on 1) The method of claim 1, wherein quantifying the pore-scale heterogeneity of a porous medium further comprises at least one of determining a flowing fraction or a Lorenz coefficient. ### Claim 3 (depends on 1) The method of claim 1, wherein quantifying the pore-scale heterogeneity of a porous medium further comprises determining a flowing fraction, wherein the flowing fraction is defined as the cumulative pore volume injected corresponding to a normalized tracer concentration at C/C0=0.5, wherein C is a tracer concentration in core effluent and C0 is a tracer concentration at a core inlet. ### Claim 4 (depends on 1) The method of claim 1, wherein quantifying the pore-scale heterogeneity of a porous medium comprises injecting a non-reactive tracer fluid through the porous medium. ### Claim 5 (depends on 1) The method of claim 1, wherein quantifying the pore-scale heterogeneity of a porous medium comprises at least one of collecting a NMR T2 log of the porous medium using an NMR tool, collecting a log of the porous medium using a formation micro-imager, or measuring a sample of the porous medium using mercury injection capillary pressure, wherein T2 is a transverse relaxation time. ### Claim 6 (depends on 1) The method of claim 1, further comprising analyzing the mineralogy of the porous medium using x-ray fluorescence measurements. ### Claim 7 (depends on 1) The method of claim 1, wherein determining an adjusted pore volume to breakthrough comprises correlating the pore-scale heterogeneity of a porous medium to the pore volume to breakthrough by a computerized calculation. ### Claim 8 (depends on 1) The method of claim 1, wherein the porous medium is a core taken from a subterranean formation. ### Claim 9 A method, comprising: injecting a non-reactive tracer fluid through a porous medium; measuring a flowing fraction; estimating an adjusted pore volume to breakthrough based on the measured flowing fraction; designing a stimulating fluid treatment for the porous medium; and performing the stimulating fluid treatment by injecting a stimulating fluid into a subterranean formation, wherein the non-reactive tracer comprises a fluid that contains a detectable species. ### Claim 10 (depends on 9) The method of claim 9, wherein the non-reactive tracer fluid is at least one of an aqueous fluid, a gelled fluid, an emulsion, an invert emulsion, or a foam. ### Claim 11 (depends on 9) The method of claim 9, further comprising using a computer to correlate the flowing fraction to the pore volume to breakthrough. ### Claim 12 (depends on 9) The method of claim 9, wherein the porous medium is a formation between at least two wellbores. ### Claim 13 (depends on 9) The method of claim 9, wherein injecting a non-reactive tracer fluid through a porous medium comprises injecting the non-reactive tracer fluid through a core taken from a subterranean formation to be treated and returned to the surface. ### Claim 14 (depends on 9) The method of claim 9, wherein designing the stimulation treatment for the porous medium comprises selecting at least one of: the stimulating fluid, the concentration of the stimulating fluid, and the injection pressure of the stimulating fluid into the porous medium. ### Claim 15 (depends on 9) The method of claim 9, wherein measuring a flowing fraction further comprises at least one measurement selected from a group consisting of measuring a NMR T2 response from a sample, collecting a log of the porous medium using an NMR tool, collecting a log of the porous medium using a formation micro-imager, collecting a micro CT scan of a sample, collecting a micro CT log of a well, and imaging using a scanning electron microscope, wherein T2 is a transverse relaxation time. ### Claim 16 (depends on 9) The method of claim 9, wherein the porous medium is a core sample. ### Claim 17 A method, comprising: determining a pore volume to breakthrough for a first porous medium having a first type of porosity; calculating a flowing fraction for a second porous medium having a second type of porosity; determining an adjusted pore volume to breakthrough for the second porous medium by adjusting the pore volume to breakthrough for the first porous medium using the calculated flowing fraction for the second porous medium; using the pore volumes to breakthrough for the first and second porous media to design a stimulation fluid treatment; and performing the designed stimulation treatment by injecting a stimulation fluid into a subterranean formation, wherein the first and second type of porosity comprises interparticle porosity, microporosity, vuggy porosity and moldic porosity. ### Claim 18 (depends on 17) The method of claim 17, wherein calculating a flowing fraction for the second porous medium comprises at least one measurement selected from a group consisting of measuring a T2 response from a sample by NMR, collecting a log of the porous medium using an NMR tool, collecting a log of the porous medium using a formation micro-imager, collecting a micro CT scan of a sample, collecting a micro CT log of a well, and imaging using a scanning electron microscope. ### Claim 19 (depends on 17) The method of claim 17, further comprising designing a stimulation treatment for the second porous medium based on the adjusted pore volume to breakthrough determined. ### Claim 20 (depends on 19) The method of claim 19, wherein the designing a stimulation treatment comprises selecting at least one of: the stimulating fluid, the concentration of the stimulating fluid, and the injection pressure of the stimulating fluid into the porous medium.