Anomalously High Porosity & Permeability S. Bloch

Anomalously High Porosity & Permeability S. Bloch Graphics: P.M. Kay

2001 The American Association of Petroleum Geologists and Salmon Bloch No slides, figures, text or other matter contained herein may be reproduced without the written permission of both the American Association of Petroleum Geologists and Salmon Bloch

Anomalously High p&p Quantitative Definition Origin and Predictability Grain Coats & Grain Rims Chlorite Coats Quartz Coats Clay Rims Early Hydrocarbon Emplacement Early Overpressure Secondary Porosity

Conclusions anomalous porosity - statistically higher than porosity values occurring in typical sandstone reservoirs of a given lithology, age, and burial / temperature history evaluation of anomalous p&p preserved by chlorite coats is a two-step process: evaluation of the likelihood of occurrence of chlorite coats as a function of sediment provenance and depositional facies diagenetic modeling to determine the constraints required to preserve economically viable p&p

Conclusions Impact of hydrocarbon emplacement on p&p can be quantified, prior to drilling, by integration of basin modeling and reservoir quality modeling p&p preservation due to fluid overpressure can be quantified, prior to drilling, by integration of basin modeling and reservoir quality modeling

Secondary porosity Unquestionable ubiquity Conclusions Importance overemphasized Effect on reservoir quality prediction Extent of preservation controlled by the same geological parameters as primary p&p Implicitly accounted for by calibration data sets used in empirical predictions Limited impact on reservoir scale - redistributional, not effective

Number of Measurements Normal Distribution of Porosity in a Sandstone with a Moderate Diagenetic Imprint 14 12 10 8 6 4 2 mean, median mode Tertiary, offshore West Africa maximum 0 22 24 26 28 30 32 34 36 38 40 42 Core Plug Porosity (%)

Lognormal Distribution of Porosity in Heavily Cemented Sandstones Number of Measurements 120 100 80 60 40 20 Ror Formation; 15,420-15,750 ft. maximum porosity 0 [0,2) [4,6) [8,10) [12,14) [16,18) Core Plug Porosity (%)

Bimodal Distribution of Porosity in Chlorite- Coated Sandstones Ile Formation; 15,100-15,420 ft. Number of Measurements 120 100 80 60 40 20 φ < 15%; n = 263 mean = 8.9 median = 8.9 mode = 9.0 maximum φ φ > 15%; n = 81 mean = 20.1 median = 20.4 mode = 20.0 anomalously high φ 0 [0,2) [4,6) [8,10) [12,14) [16,18) Core Plug Porosity (%) [20,22) [24,26)

Frequency Distribution of Porosity in U. Jurassic Sandstones, Central Graben (Ula & Gyda Fields), North Sea Frequency (%) 25 20 15 10 5 Well A bimodal porosity distribution Well B Well C bimodal porosity distribution 0 0 10 20 30 0 10 20 30 0 10 20 30 microquartz coats present no microquartz coats present Porosity (%) from Aase et al., 1996

Origin of Chlorite Coats depositionally-controlled Fe-rich coats in high-energy, shallow-marine sandstones shelf (Ehrenberg, 1993) depositionally-controlled coats in turbidites (Houseknecht & Ross, 1991) down-slope transport of coated shallow-marine sands (Sullivan et al., 1999) provenance-controlled (VRFs) coats (Thomson, 1979; Pittman et al., 1992) Mg-rich coats formed by interaction of precursor clay/iron oxide grain rims with Mg-rich saline brines (Kugler & McHugh, 1990)

Effect of Grain Coating & Burial History on Porosity Preservation - Diagenetic Models Miocene, Gulf of Mexico Jurassic, Norwegian Shelf 180 160 140 120 100 80 60 Temperature (ºC) 40 200 150 100 50 0 20 Time (Ma) (Bloch et al., 2002)

Effect of Grain Coating & Burial History on Porosity Preservation - Diagenetic Models Percent 30 25 20 15 10 5 0 Miocene, Gulf of Mexico 15% coat to preserve 15% porosity 0 25 50 75 90 98 Jurassic, Norwegian Shelf 82% coat to preserve 15% porosity 0 25 50 75 90 98 Grain Size = 0.40mm Grain Coat Coverage (%) Quartz Cement Intergranular Porosity (Bloch et al., 2002)

Prediction of p&p Preservation by Chlorite Coats the effect of coats on p&p cannot be accurately quantified prior to drilling the distribution pattern of coated sands is a function of coat origin the potential impact of coats on p&p can be evaluated by diagenetic models

Microquartz Coats Conclusions Geological Prediction of Anomalous p&p due to Microquartz Coats in Not Possible in Frontier Basins Distribution of sponge spicule-sourced coats - mapping sponge spicule-prone sedimentary facies and their reworking paths into sand-rich depo systems Distribution of coats sourced by dissolution of volcanic glass - occurrence within specific isochronous sandy intervals of the sedimentary column from Aase et al., 1996

Pitfalls: Effect of HC Emplacement on Preservation of p&p effect of wettability on cementation differences in texture, composition, and thermal exposure in samples from water legs versus hydrocarbon legs poor control on hydrocarbon filling and leakage histories

Effect of HC Emplacement on Preservation of p&p silica provided externally by advection ( open system ) - cementation stopped silica supplied internally ( closed system ) in water-wet reservoirs - cementation retarded, but not stopped silica supplied internally ( closed system ) in oil-wet reservoirs - cementation stopped From Worden et al. (1998)

Mid-Tertiary Hydrocarbon Emplacement Preserved 9% of Effective Porosity Depth (m) 4000 3500 3000 2500 2000 1500 1000 500 0 140 effective porosity evolution curve burial history curve 120 NW Shelf of Australia quartz cement 100 80 60 Time (Ma) 40 HC measured effective porosity measured qtz cement 20 35 30 25 20 15 10 5 0 0 Quartz Cement / Effective Porosity (%)

Effect of Overpressure on Porosity Preservation: Model Assumptions Compaction and quartz cementation are the primary controls on reservoir quality Linear burial to 4000 m at 30 ºC/km Present-day overpressure near fracture gradient Shallow scenario: develops 0-800 m Deep scenario: develops 2400-4000 m Sandstones are medium grained, well sorted, and clean Composition of sandstones: Quartzose : Q 84 F 8 L 8 Lithic : Q 50 F 0 L 50 (L = shale clasts)

Quartz Cement Abundance Vs. Effective Stress at 3.5-6.0 km, North Sea HPHT Clastic Reservoirs 7000 6000 Slightly Overpressured Effective Stress (psi) 5000 4000 3000 2000 1000 Highly Overpressured 0 0 1 2 3 4 5 6 % Quartz Cement (Ave) from Osborne & Swarbrick, 1999

Is the change in porosity gradient due to secondary porosity or provenance/facies-controlled change in lithology? M meters M feet depth 1 2 3 4 4 6 8 10 12 14 mainly primary porosity Sonic Porosities of Sandstone Intervals > 10 ft Gulf-Mobil SIKU C-55 (Mackenzie Delta) secondary porosity quartz arenites sandstones of intermediate mineralological maturity decline of primary porosity decline of secondary porosity 40 30 20 10 0 Percent Porosity IM- MATURE SEMI- MATURE MATURE A MATURE B T E R T I A R Y U.CR LOWER CRETACEOUS from Schmidt & McDonald, 1978

Plagioclase Dissolution Porosity

Conclusions much of the plagioclase dissolution porosity (PDP) at depths >5000 ft may be inherited shallow PDP if deep PDP is mostly inherited, there may be no aluminum problem the presence of PDP does not have a major impact on the accuracy of empirical predrill predictions of porosity in sandstones

The Dataset 216 Middle Eocene - Lower Miocene arkosic sandstone samples from 16 wells in southern San Joaquin basin (Metralla, San Emigdio, Vedder, and Jewett) depth range: 2480 ft - 14,710 ft similar composition secondary porosity formed predominately by dissolution of plagioclase 300 counts per thin-section 1000 counts on subset of 39 thin-sections

Reliability of Point-Count Data subjectivity of point-counting secondary porosity (primary vs. secondary, intragranular vs. moldic) errors implicit in point counting (accuracy is a function of true abundance of pores and the number of point counts)

QFL Diagram of Feldspathic Sandstones, Southern San Joaquin Basin, California Q subarkose 90% 90% sublitharenite F arkose lithic arkose feldspathic litharenite litharenite L

100 Intragranular φ > 50% of PDP in only 8% of samples Intragranular φ > 50% of PDP in 91% of samples Cumulative % 80 60 40 shallow (< 5000 ft) deep (> 5000 ft) 20 0 < 10 < 30 < 50 < 70 < 90 < 10 < 30 < 50 < 70 < 90 Plagioclase Intragranular Porosity / Total PDP (Bloch & Franks, 1994)

Conclusions Moldic porosity dominates PDP in shallow sandstones (<5000 ft) Intergranular porosity dominates PDP in deeper sandstones (>5000 ft)

Proposed Mechanism for PDP Formation < 5000 feet mostly moldic PDP generated - precipitation of some kaolinite - AI is mobilized beyond thin-section scale > 5000 feet mostly intragranular PDP generated - shielding of some shallow moldic PDP by rigid grain framework + cement - collapse of some shallow moldic PDP - precipitation of authigenic clays; redistributional secondary porosity

Generation of PDP in the Subsurface - Approximate Balance Calculations Burial Average Primary Porosity (% v/v) Relative Loss (%) Average Plagioclase Intragranular Secondary Porosity Balance Average Plagioclase Intragranular Secondary Porosity Balance Shallow (< 5,000 ft) Deep (> 5,000 ft) 16.2 3.1 1.8 73% loss gives 0.8%; no gain in moldic porosity 4.4 73 0.5 1.5 73% loss gives 0.4%; gain of 1.1% (maximum) (Bloch & Franks, 1994)

Evolution of Plagioclase Dissolution Porosity Surface and shallow subsurface dissolution Major dissolution Net porosity gain likely Meteoric water Depth (T, P) Gradual collapse of primary and moldic porosity Deep dissolution Minor dissolution Redistributional secondary porosity Silicate hydrolysis (?), organic acids (?)

N Fan Delta Model, Cross-Section Proximal Fan Delta Mid Fan Delta Distal Fan Delta Delta Front Pro- Delta S Sea Level depth (ft) 15 10 10 8 5 6 0 4 2 Conglomerate 0 10 6 4 2 Sandstone 0 8 6 4 2 0 7 6 5 4 3 2 1 0 6 5 4 3 2 1 0 Mudstone - Siltstone from McGowen & Bloch, 1985

Depositional Facies Control of Porosity and Permeability, Prudhoe Bay Field FACIES MID FAN DELTA LOWER MID FAN DELTA UPPER DISTAL FAN DELTA DISTAL FAN DELTA DELTA FRONT WELL 17-1 k (md) φ (%) 639 512 685 349 13 22.5 18.9 25.2 22.6 14.9 COMMENTS No Conglomerate - 16 Conglomerate Samples k = 359md - 19 Sandstone Samples k = 640md No Conglomerate - 13 Samples Coarser than Fine k = 33md - 30 Samples Fine and Less k = 7md PRODELTA NR NR

Depositional Facies Control of Porosity and Permeability, Prudhoe Bay Field FACIES WELL 17-1 k (md) φ (%) COMMENTS MID FAN DELTA LOWER MID FAN DELTA 639 512 22.5 18.9 No Conglomerate - 16 Conglomerate Samples k = 359md - 19 Sandstone Samples k = 640md UPPER DISTAL FAN DELTA 685 25.2 No Conglomerate DISTAL FAN DELTA 349 22.6 DELTA FRONT 13 14.9-13 Samples Coarser than Fine k = 33md - 30 Samples Fine and Less k = 7md PRODELTA NR NR

Generalized Burial History of Ivishak Sandstone, Prudhoe Bay Area Depth of Burial x 1000 Feet 0 2 4 6 8 10 Triassic Jurassic Cretaceous Tertiary shallow burial subaerial exposure final burial 200 150 100 50 Time, Millions of Years B.P. (from Shanmugam & Higgins, 1988)

Generation of Secondary Porosity during Subaerial Exposure SHUBLIK SADLEROCHIT

Unconformities and Secondary Porosity Ivishak ss - Prudhoe Bay (N. Slope of Alaska) favorable reservoir quality of zone 4 of the Ivishak sandstone due to secondary porosity formed by meteoric water leaching of chert beneath the Neocomian unconformity macroporosity formed by chert dissolution tends to increase toward the Neocomian unconformity a lateral increase in core porosity (from 15% at about 30 km from the unconformity to 30% near the unconformity) and in permeability (from 50 md at about 30 km from the unconformity to 800 md near the unconformity). This increase occurs within the fluvial facies (zone 4) of nearly uniform grain size and framework composition (chert (from Shanmugam & Higgins, 1988) litharenite)

Cross Section is Interpreted to Show Porosity Increase with Increasing Proximity to Unconformity A API #61 0 API #40 API #27 UNCONFORMITY A API API API API API #67 #279 #294 #64 #263 100 200 Average Core Porosity in Zone 4 of Ivishak Formation 24.7 22.8 23 25 Meters 300 400 20 500 600 17.5 18 21 A UNCONFORMITY UNCONFORMITY A from Shanmugam & Higgins, 1988 SCALE 2000 M A --A Line of of Cross Section Prudhoe Bay Field, Alaska

There is a Casual Correlation between Porosity and Proximity to Unconformity Meters A API #61 0 100 200 300 400 500 600 API #40 API #27 UNCONFORMITY API #67 Average Core Porosity in Zone 4 of Ivishak Formation 17.2 18.0 21.4 20.3 API #177 23.3 API #279 25.3 22.8 API #294 A API #64 22.9 API API #263 #480 24.4 UNCONFORMITY UNCONFORMITY A 21.8 A Decreasing Grain Size SCALE 2000 M A --A Line of of Cross Section Prudhoe Bay Field, Alaska

Average Permeability of the Ivishak Sandstone Correlates Well with Grain Size Permeability (md) 600 400 200 r = 0.81 27 67 61 294 279 480 263 0 0 10 20 30 40 50 Proportion of Medium- & Coarser-Grained Sandstones (%) 64 64 = Well number

Depth (m) Modeled Porosity Evolution of the Ivishak Sandstone 3000 2500 2000 1500 1000 500 Porosity Depth (m) Quartz cmt (%) 0 0 250 200 150 100 50 0 Time (Ma) depth = 9,300 ft; grain size = 0.40mm; mod. well sorted; quartz cement = 6%; modeled TS φ = 20%; est. ambient core φ = 23% In situ φ = 22%; in situ k = 850md 40 35 30 25 20 15 10 5 Porosity (%) / Quartz Cement (%)

Reservoir Quality of the Ivishak Sandstone is Controlled by Texture and Burial History Increasing Burial History Sediment Transport High Proportion of Coarse-Grained Sandstones High Proportion of Fine-Grained Sandstones 0 5 10 Miles (Bloch et al., 1991)