Fu, Q.

Ko, L.T.

Peng, S.

Periwal, P.

Sivil, E.

English

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Keywords:Cited as: Ko, L.T., Peng, S., Fu, Q., Periwal, P., and Sivil, E., 2023, Revisiting Mississippian Barnett Shale: Lithological and Geochemical Control on Varied Reservoir Heterogeneity and Fluid Saturation from Late Oil to Dry Gas Window, Fort Worth Basin, Texas, presented by Ko at the American Association of Petroleum Geologists Southwest Section (AAPG SWS) on May 6-9 2023.Revisiting Mississippian Barnett Shale: Lithological and Geochemical Control on Varied Reservoir Heterogeneity and Fluid Saturation from Late Oil to Dry Gas Window, Fort Worth Basin, TexasMay 2023Ko, L.T., Peng, S., Fu, Q., Periwal, P., and Sivil, E.Barnett Shale, permeability, fluid saturation, Fort Worth Basin, porosity, textureRevisiting Mississippian Barnett Shale: Lithological and Geochemical Control on Varied Reservoir Heterogeneity and Fluid Saturation from Late Oil to Dry Gas Window, Fort Worth Basin, TexasMay 9th, 2023 (Tuesday)08:50-09:15 amAAPG SWS, Wichita Falls, Texasbeg.utexas.eduLucy Tingwei Ko, Sheng Peng, Qilong Fu, Priyanka Periwal, Evan SivilMississippian: Paleogeography (Loucks and Ruppel, 2007)• FWB area occupied a narrow inland seaway, bounded on the west by a broad, shallow-water, carbonate shelf and on the east by an island arc chain, between the rapidly approaching continents of Laurentia and Gondwana(Gutschick and Sandberg, 1983)Sea Level Curves• Barnett deposition occurred during a second-order, sea level highstand (Osagean to Chesterian; 320–345 Ma)• A 25-m.y. time span for deposition with sedimentation rate averaged 14 mm/yr.• Estimated Barnett deposition water depth between 400 and 700 ft (120 to 215 m)(Loucks and Ruppel, 2007)FWBPBGreater Fort Worth Basin• The FWB is an elongate, asymmetric flexural foreland basin of the advancing Ouachita orogenic belt that formed during the Late Mississippian through Pennsylvanian• The northern bounding structural arches (Red River Arch, Muenster Arch) grew prior to and in sequence with the development of the FWB and migrated progressively NW over the basin• The FWB is deepest in the NE, with more than 12,000 ft of preserved sediment infill adjacent to the Muenster Arch and Ouachita thrust front and is shallowest in the south, where the lateral equivalent of the basin’s deepest stratigraphic intervals outcrop along the Llano Uplift (LU)(Horne et al., 2020)Studied AreaRFSCSHPJWRFS CSH PJWA A’(Pollastro et al., 2007)Barnett Stratigraphy• Barnett overlies Ellenburger and Viola Fms with the boundary represented by a series of erosive surfaces with sometimes evidence of oxidation, indicative of subaerial exposure• Barnett underlies the Marble Falls Fm consists of a progressive shift toward marly and lighter colored fine-grained rocks• Barnett in some areas cannot be clearly separated into lower and upper members, due to the fact that Forestburg LS is not evident both lithologicallyand on GR(Blakey, 2005; Loucks and Ruppel, 2007)Forestburg Limestone: Flow Barrier (Bowker, 2007)BEG Barnett Studies• Steve Ruppel, Bob Loucks• Kitty Milliken• Harry Rowe• Rob Reed, Bob Loucks, Steve Ruppel• Julia Gale, Rob Reed, Jon HolderGraduate students• Petros Papazis (2005), MS - Petrographic Characterization• Lauren Redmond (2016), MS – Depositional model southern FWB• Mauck (2017), MS – upper Barnett Two-finger sand, Midland Basin, TX(EIA, March 2023)Objectives• Comparison of facies and reservoir quality of Upper and Lower Barnett• Characterize Lower Barnett in the oil window and what might control high water production• Use texture, fabric, and grain composition to classify flow (P&P)-related litho-unit• Traditional lithofacies scheme defined by geological characteristics do not translate directly to geomechanical lithotype or flow-related (P&P) litho-unit • Attempt to re-classify murdocks based on their application on geomechanical and flow properties• Flow-related (P&P) litho-unit impacts drainage rock volume (DRV)• Geomechanical lithotype impacts stimulated rock volume (SRV)Barnett Cores• 11 cores in northern FWB (Wise & Denton Co.)• 28 cores in southern FWB(Redmond, 2016)OGIP (free gas)(Ikonnikova et al., 2014)Studied WellsRFSCSHPJWRFS CSH PJW• RFS: late oil to condensate window• CSH and PJW: dry gas window (area was actively drilled), thicker upper BarnettA A’• Thickness• Upper Barnett ≈ 40 ft• Forestburg ≈ 270 ft• Lower Barnett ≈ 410 ft• Spectral GR: U, K, Th in the Lower BarnettWireline Logs74907540759076407690774077907840789079400 200 400 600GR (API)0 20 40U (ppm)0.0 1.0 2.0%K0 10 20Th (ppm)RFSLower Barnett ZonationTop B4Top B5Top B0Top B1Top B2Top B3Top B7Top B8Top B6Top B9• HI index can be used to identify types of original kerogen (assume HI=200 refer to Type II)Zone of High Sw, lower TOC, High Porosity, Variable PermDetrital Elements (Al, K, Ti, Th, Rb, Zr, Si)%K(XRF)%K(CGR) Th(CGR)%Al RbZrLower Barnett Fluid SaturationsSEM (7634.4’)SEM (7799.3’)SEM (7787’)Studied WellsRFSCSHPJWRFS CSH PJW• RFS: late oil to condensate window• CSH and PJW: dry gas window (area was actively drilled), thicker upper BarnettA A’Measured Results for Total Porosity• 2 samples from Upper Barnett, 12 samples from Lower Barnett• Total porosity in dry gas window samples are higher than those in late oil windows from selected samplesupperupperMeasured Results for Permeability• Results from dry-gas window show similar ranges for permeability• Samples from late oil to condensate window show large variability in values• Sample selection based on interval of interests and measured P&P resultsupperupperupperupperlowerlowerWentworth Grain Size Chart(Wentworth, 1922; Williams et al., 2006)USGS Open-File Report 2006-1195• The Krumbein phi (φ) scale is a logarithmic scale computed by the equation• Most mudrocks contain grains from clay size (<4 µm) to silt size(<62.5 µm) and sometimes contains very fine sand (<125 µm)Sorting• In mudstones, silt fraction (size term) and clay mineral content (compositional term) are commonly mentioned but sorting is not• Grain size and sorting are challenging to analyze in mudrocks but they can be quantitatively described and used in data analysis • Two texture groups• Clay mineral + OM content (ductile materials)• Other minerals (carbonate, quartz, feldspar, phosphate, pyrite) (brittle materials)• To simply, let’s consider sorting in brittle materials first and add the mixture of ductile materials later• Example from Siliciclastic Chang 7 Formation, Ordos Basin • GSD and Sorting affects porosity values23silt-sizeclay-size(Ko et al., 2017)1.1%1.1%3.5% 5.6% 6.7%4.1%4%7.5 %(µm)How Sorting & Grain Sizes (Texture) Affect P&PCan you rank porosity by variations in texture (sorting and grain size distribution) ?24(Milliken et al., 2012)• A and C same silt content• B: least terrigenous content, more biogenic• A, C: terrigenous components,  abundant clay minerals, much silt is biogenicACBDP&P:1.8 %, 28.6 nD P&P:3.8 %, 27.8 nDP&P:2.8 %, 17.3 nD P&P:2.4 %, 20.5 nDD: terrigenous components, carbonateTOC = 2.9 wt%TOC = 3.7 wt%TOC = 2.2 wt%TOC = 2.2 wt%Barnett Core Lithofacies: RFS• Representative sampling is key (REA,REV)  and based on an integrated dataset• Basinal setting, below storm-weather wave-base, under predominantly anoxic bottom waters (Loucks and Ruppel, 2007)Variation on Barnett Lithofacies: Thin Section ScansMineralogy & Texture in PJW and CSHSample IDLog Depth (ft)Zone Measured PorosityMeasure Perm (1000 psi)Measure Perm(160 psi)Original ɸAmount of Clay MineralPJW-1 7785 upper 6.3 14.9 188 9.43PJW-6 8238 lower 2.85 1.45 4.92 N/ACSH-1 7298 upper 6.53 12.95 111.94 9.23CSH-5 7538 lower 3.8 2 15.9 N/APJW-1, 7785 ft, upper70 µmPJW-6, 8238 ft, lower60 µmPJWupperlowerCSHupperlowerLower Barnett has more terrestrial input and clay mineral (compacted) than upper Barnett. Upper Barnett more phosphate.dolalbqzpycalcal3% diff in ɸUpper Barnett in PJW• TOC = 4.7 wt%• Clay mineral content is low• Siliceous calcareous mudrock40 µm 100 µmcaldolqzcalalbK-sparqzdolalbLower Barnett in PJW • Quartz, detrital illite/mica, dolomite, pyrite, albite60 µm60 µmqzdolcalalbdoldolpyRFS: Texture, Composition, Clay Mineral TypesSample IDDepth (ft)Zone Measured PorosityMeasure Perm (1000 psi)Measure Perm(160 psi)Types of Clay Mineral Amount of Clay MineralFSR-2 7639 B8 4.3 36.5 227 Detrital Mg chlorite, illite/mica 3FSR-3 7664 B6 0.55 0.1 1.28 Detrital illite/mica 1 (highest amount)FSR-4 7718 B3 2.5 N/A 5.14 Detrital Mg chlorite 2FSR-5 7785 B1 0.1 0.01 0.1 Detrital illite/mica 5 (Least amount)RFS-4, 7718 ft, B340 µmalbRFS-2, 7639 ft, B850 µmqzRFS-5, 7785 ft, B170 µmcalmarRFS-3, 7664 ft, B630 µmdoldolMineral Composition & Distribution in RFSSample IDDepth (ft)Zone Measured PorosityMeasure Perm (1000 psi)Measure Perm(160 psi)Types of Clay Mineral Amount of Clay MineralFSR-2 7639 B8 4.3 36.5 227 Detrital Mg chlorite, illite/mica 3FSR-3 7664 B6 0.55 0.1 1.28 Detrital illite/mica 1 (highest amount)FSR-4 7718 B3 2.5 N/A 5.14 Detrital Mg chlorite 2FSR-5 7785 B1 0.1 0.01 0.1 Detrital illite/mica 5 (Least amount)RFS-4, 7718 ft, B360 µmRFS-2, 7639 ft, B840 µmqzRFS-5, 7785 ft, B170 µmcalmarRFS-3, 7664 ft, B630 µmdoldolSEM-EDS Maps Showing Types and Distribution of Clay MineralsRFS-2, 7639 ft, B8 Area: 196 µm* 196 µm RFS-3, 7664 ft, B6 (most clay mineral rich)Area: 196 µm* 196 µmHypothetical Model33TOCdepthHIType III, detrital dominated, oxygenatedType II, biogenic dominated, reducedRedox-enriched elements (XRF)Type II+III, biogenic + detrital, reducedDilution from high detritalGrain size distributioncoarsefinecoarsefineLowest porosity, ductileHighest porosity, brittleMedium porosityDepositional ControlP&P, anisotropy, mechanical propertiesImportant Implication Derived from This Study• Depositional facies (OM types) is the first order control on porosity and permeability• The impact of texture (grain size distribution and sorting) and fabric on porosity and pore connectivity (permeability) • Variations of measured matrix porosity and permeability across samples at different thermal maturation (late oil vs. dry-gas window). • Total porosity in dry gas window samples (4 to 8%) are higher than those in late oil windows from selected samples (0 to 5%)• XRF analyses show that samples from dry gas window deposited under relatively reduced condition and have higher nutrient compared to samples from condensate/late oil. This also implies that OM content is higher and OM quality is better.• Lower Barnett has more terrestrial input and clay mineral (compacted) than Upper Barnett. Dominant Type II kerogen in Upper Barnett implies good pore connectivity (permeability) in dry gas window• High water saturation in the Barnett Fm can be related to both clay-mineral-rich intervals and carbonate intervals (lithofacies is one major control)• The amount, size, and distribution of clay mineral, carbonate content (dolomitization) in condensate window vary among studied samples and greatly impact P&P.  Sources of Errors in P&P Measurements • Crushed rock (GRI) vs. core plug• Gas leakage in the system• Presence of residual oil in samples • Not so much of an issue for samples in dry gas window(Heller et al., 2014)• Reported Barnett permeabilityVertical permeability: 2.3×10−21m2 (2.3 nD) Horizontal permeability: 9.5×10−20m2(96.3 nD)(Bhandari et al., 2015)Porosity & Pores in RFSSample IDDepth (ft)Zone Measured PorosityMeasure Perm (1000 psi)Measure Perm(160 psi)FSR-2 7639 B8 4.3 36.5 227FSR-3 7664 B6 0.55 0.1 1.28FSR-4 7718 B3 2.5 N/A 5.14FSR-5 7785 B1 0.1 0.01 0.1RFS-2, 7639 ft RFS-3, 7664 ft RFS-4, 7718 ftRFS-7707.7RFS-5, 7785 ftArea: 0.5 mm*0.5 mmLow TOCdolomitizationdolomitizationHighest clay contentHigh clay contentUpper Barnett in PJW• ɸ = 6.3% (sheng), 9.43 (original)• NM-size OM spongy pores are common Type III (no pore)Type IIIUpper Barnett in PJW• NM-size OM spongy pores are commonphosphatePyritePhosphateQtzType III (no pore)Lower Barnett in PJW • Dominant pore type: nm-sized OM spongy pores• Porosity is related to OM, lower TOCOM Pores Are Slightly Larger in Late Oil & Condensate WindowRFS-5, 7785 ft, B1In quartz-rich areaWater-hosted Pores in Late Oil & Condensate WindowRFS-4, 7718 ft, B3, formation water location?Conclusions• Depositional facies is the first order control on porosity and permeability & OM types• The impact of composition, texture (grain size distribution and sorting) and fabric on porosity and pore connectivity (permeability) • Variations of measured matrix porosity and permeability across samples at different thermal maturation (late oil vs. dry-gas window)• Provide geological interpretations from an integrated facies, XRD, XRF, and petrography studyMaturity, TOC, and OM Type (Lower Barnett in RFS)74907540759076407690774077907840789079400 200 400 600GR (API)0 20 40U (ppm)0.0 1.0 2.0%K0 10 20Th (ppm)7500755076007650770077507800785079000.0 2.0 4.0 6.0 8.0TOC (wt%)0 100 200 300HIashCarbonate 0 2 4 6 8%Mg7490754075907640769077407790784078900 10 20 30 40%CaChlorite?0 500 1000 1500 2000Mn (ppm)0 1000 2000 3000 4000Sr (ppm)Summary for Porosity and Permeability in Dry Gas Window• Similar dominant pore type: nm-sized OM spongy pores• Porosity is related to TOC content• Mixed Type II+ Type III kerogen: dominant by Type II• Lower Barnett is low in TOC; Upper Barnet has high TOC content• Dilution from clay mineral or carbonate• Early dolomitization• Positive relationship between P&PSummary for P&P in Late Oil Window• Results from BEG’s lab are more consistent with SEM observation• Presence of residual oil in samples might result in relatively low porosity values• Facies, diagenesis, and texture play an important role in porosity and pore connectivity• Both OM bubble & spongy pores are present • Pores associated with clay mineral and grain replacement might host waterXRF Elemental Implication on Reservoir Quality • CSH & PJW have higher nutrient trace elements• Upper Barnett deposition is quite reducing in CSH & PJW• RFS-3 & RFS-5 have excessive Fe-rich dolomite replacementB2B7B6B8B8B6B9AB6B8B3B1upperupperdetrital redox nutrientWell Location & Production: RFS, Wise Co., TXCasto-Chief H (horizontal core)PJWHollingsworthSims ThomasBlakely 1Carpenter Sol HeirsRFSAdams Southwest 7• Production from Sept 2013 to Jan 2018: 4.5 years1 1 1Well Location & Production: FS Range, Wise Co., TXCasto-Chief H (horizontal core)Porter John W3HollingsworthSims ThomasBlakely 1Carpenter Sol HeirsJ P SmithThomas CherryhomeSmith EarnestF S Range GUAdams Southwest 7• Production from Sept 2013 to Jan 2018: 4.5 yearsPore Development in Type II vs. Type III Kerogen(Gensterblum et al., 2015)Permeability Ranges vs. Measurement Ranges of Different Experimental Methods(Sander et al., 2017)• Steady-state• Unsteady-state: Pulse decay, oscillating pressure and GRI methods Geomechanical Measurements & Properties• First level• Second level• Third levelTitle• First level• Second level• Third levelTitle• First level• Second level• Third levelMeasured vs. Visual Inspection of Pores & Porosity• Helium porosity = total porosity ≠ effective porosity (permeability)• Total porosity = N2 porosity (pores < 200 nm) + MICP• Helium porosity > SEM porosity (SEM resolution: 5 to 200 nm, scale dependent)• Important to identify REA (representative elemental area) when calculating SEM porosityUnder same sample cleaning/drying or uncleaned condition:• In dry gas window dominated by nm-sized OM pores, He ɸ = N2 ɸ > SEM ɸ• In late oil and condensate, He ɸ > N2 ɸ, He ɸ > SEM ɸ• In middle oil window, He ɸ > SEM ɸ > N2 ɸ(Reynolds et al., 2018)Lower Barnett ZonationTop B4Top B5Top B0Top B1Top B2Top B3Top B7Top B8Top B6Top B9• Sampling based on zones defined by wireline logs• A total of 14 plug samples were obtained from 3 cored wells• P&P measurement in Sheng’s lab using Modified Gas Expansion (MGE)• 4 samples from PJW (dry-gas window)• 6 samples from CSH (dry-gas window)• 4 samples from RFS (late oil to condensate window)Pore Connectivity (Permeability) Controlled by Matrix Texture, OM Types, Thermal Maturity • Type II OM (marine: algae, bacteria, etc.): convert to bitumen and oil, bitumen hosts OM pores• Type III OM (terrestrial, woody fragments etc): little or no pores, more brittle • TOC positively correlates to porosity in dry gas window, if majority of original kerogen is Type I or II • Abundant solid-bitumen hosted OM pores with little dead carbon could imply possible high gas permeability through connected bitumen networkHighest HILowest HIRelated to OM pore development(Dan Jarvie)SEM Petrography • 4+2 samples from RFS (late oil to condensate window)• 2 samples from CSH (dry-gas window; 1 from upper Barnett, 1 from lower P&P)• 2 samples from PJW (dry-gas window; 1 from upper Barnett, 1 from lowest P&P)• Pores under SEM might be slightly larger or smaller than pores in the subsurface (pore pressure, overburden pressure under reservoir condition)• Some solid bitumen or heavy oil can be mobile under the subsurfaceMeasured Porosity and Permeability at BEG• Sampling based on zones defined by wireline logs• A total of 14 plug samples were obtained from 3 cored wells• P&P measurement in Sheng’s lab using Modified Gas Expansion (MGE)• 4 samples from PJW (dry-gas window)• 6 samples from CSH (dry-gas window)• 4 samples from RFS (late oil to condensate window)• SEM petrography to (1) examine texture (sorting, grain size distribution), clay mineral types/sizes, OM types, pore affiliation/association, types, sizes, shapes, and implication on pore fluid distribution, (2) compare core area (dry gas) vs. none-core (late oil) development area (PJW, CSH vs. RFS)Pore Development in Type II vs. Type III Kerogen

Revisiting Mississippian Barnett Shale: Lithological and Geochemical Control on Varied Reservoir Heterogeneity and Fluid Saturation from Late Oil to Dry Gas Window, Fort Worth Basin, Texas

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Revisiting Mississippian Barnett Shale: Lithological and Geochemical Control on Varied Reservoir Heterogeneity and Fluid Saturation from Late Oil to Dry Gas Window, Fort Worth Basin, Texas

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