Classification and characterizations of biogenically enhanced permeability

Pemberton, S. George; Gingras, Murray K.

doi:10.1306/07050504121

Cited by 139 publications

(61 citation statements)

References 41 publications

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“…The differences in permeability could also be explained by variations in bioturbation intensity observed at the mm-scale: The three higher permeability samples (RA1, RA2 and RA6) exhibit a more homogeneous host sediment containing isolated silt-filled burrows bearing high concentrations of pyrite (Figure 2a). Where packages of coarser grained sediment occur within a low permeability substrate, they have been shown to increase permeability (Pemberton & Gingras 2005). The texture of the lower permeability samples (RA12, RA13…”

Section: Microstructural Controls On Permeabilitymentioning

confidence: 99%

Microstructural controls on the pressure-dependent permeability of Whitby mudstone

Mckernan

Mecklenburgh²,

Rutter³

et al. 2017

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A combination of permeability and ultrasonic velocity measurements allied with image analysis is used to distinguish the primary microstructural controls on effective-pressure dependent permeability. Permeabilities of cylindrical samples of Whitby Mudstone were measured using the oscillating pore pressure method at confining pressures ranging between 30-95 MPa and pore pressures ranging between 1-80 MPa. The permeability-effective pressure relationship is empirically described using a modified effective pressure law in terms of confining pressure, pore pressure and a Klinkenberg effect. Measured permeability ranges between 3×10 -21 m 2 and 2 ×10 -19 m 2 (3 and 200 nd), and decreases by ~1 order of magnitude across the applied effective pressure range. Permeability is shown to be less sensitive to changes in pore pressure than changes in confining pressure, yielding permeability effective pressure coefficients ( ) between 0.42 and 0.97. Based on a pore-conductivity model which considers the measured changes in acoustic wave velocity and pore volume with pressure, the observed loss of permeability with increasing effective pressure is attributed dominantly to the progressive closure of bedding-parallel, crack-like pores associated with grain boundaries.Despite only constituting a fraction of the total porosity, these pores form an interconnected network that significantly enhances permeability at low effective pressures.The pre-publication reference is: Mckernan, R., Mecklenburgh, J., Rutter, E. H. and Taylor Progress in understanding fluid transport properties of mudstones is currently hindered by a scarcity of published experimental data. However, the ongoing expansion of the hydrocarbon industry into low-permeability unconventional resources is driving the demand for research and development in this field. Even when hydraulic fracture treatment is used to enhance production, flow of hydrocarbons into the fractures will be controlled ultimately by the microporous, low permeability matrix. Furthermore, during reservoir production pore-fluid pressure is progressively reduced, which acts to increase the in-situ Terzaghi effective pressure (defined as overburden pressure minus pore pressure), thereby decreasing permeability. The evolution of permeability of the matrix therefore determines the prediction of long-term production, which must take into account the effects of flow regime, multiphase flow, sorption effects, permeability anisotropy and, most importantly, the pressuredependence of permeability.Laboratory measurements of permeability of intact mudstone samples performed under reservoir conditions has yielded values between 10 -22 m 2 and 10 -12 m 2 (0.1 nD and 1 D) for flow both parallel and normal to layering (Morrow et al.

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Section: Microstructural Controls On Permeabilitymentioning

confidence: 99%

Microstructural controls on the pressure-dependent permeability of Whitby mudstone

Mckernan

Mecklenburgh²,

Rutter³

et al. 2017

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“…Further investigations found other examples in distributary channel deposits and upper shoreface sands, but in most cases, cryptic bioturbated sands were limited in thickness and lateral extent (Blanpied and Bellaiche, 1981;Dashtgard and Gingras, 2003;Gingras et al, 2008;Howard and Frey, 1975;Naruse and Masuda, 2006;Pemberton and Gingras, 2005;Pemberton et al, 2008;Rouble and Walker, 1997;Sohn, 1997). Many ancient marginal-marine examples have been reported in Talang Akar fields of Indonesia, North Ranklin Field of Australia, Fureal and Misoa fields of Venezuela, the Frontier Formation in the United States, and the Kuparuk and Sag River formations in Alaska (see Pemberton et al, 2008, for additional references).…”

Section: Cryptic Bioturbation and Cryptobioturbation In Marginal-marimentioning

confidence: 97%

The significance of deep-water cryptic bioturbation in slope-channel massive sand deposits of the lower Rio Dell Formation, Eel River basin, California

Greene

Gingras

Gordon

et al. 2012

Marine and Petroleum Geology

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“…The observed porosity in thin-section (micron scale), shows that the porosity is associated with: 1) dissolution of organic matter or dolomitic material caused by diagenesis; 2) bioturbation-enhanced porosity resulting from burrows by organisms; and 3) fracture porosity along bedding planes. [89] [90] have shown that reservoir enhancement in unconventional thinly bedded, silty to muddy lithologies of unconventional reservoir with low permeability can be enhanced by the activity of burrows.…”

Section: Interpretation Permeabilitymentioning

confidence: 99%

Petroleum Source-Rock Evaluation and Hydrocarbon Potential in Montney Formation Unconventional Reservoir, Northeastern British Columbia, Canada

Egbobawaye¹

2017

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Source-rock characteristics of Lower Triassic Montney Formation presented in this study shows the total organic carbon (TOC) richness, thermal maturity, hydrocarbon generation, geographical distribution of TOC and thermal maturity (Tmax) in Fort St. John study area (T86N, R23W and T74N, R13W) and its environs in northeastern British Columbia, Western Canada Sedimentary Basin (WCSB). TOC richness in Montney Formation within the study area is grouped into three categories: low TOC (<1.5 wt%), medium TOC (1.5 -3.5 wt%), and high TOC (>3.5 wt%). Thermal maturity of the Montney Formation source-rock indicates that >90% of the analyzed samples are thermally mature, and mainly within gas generating window (wet gas, condensate gas, and dry gas), and comprises mixed Type II/III (oil/gas prone kerogen), and Type IV kerogen (gas prone). Analyses of Rock-Eval parameters (TOC, S2, Tmax, HI, OI and PI) obtained from 81 samples in 11 wells that penetrated the Montney Formation in the subsurface of northeastern British Columbia were used to map source rock quality across the study area. Based on total organic carbon (TOC) content mapping, geographical distribution of thermal maturity (Tmax), including evaluation and interpretation of other Rock-Eval parameters in the study area, the Montney Formation kerogen is indicative of a pervasively matured petroleum system in the study area of northeastern British Columbia.

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Classification and characterizations of biogenically enhanced permeability

Cited by 139 publications

References 41 publications

Microstructural controls on the pressure-dependent permeability of Whitby mudstone

Microstructural controls on the pressure-dependent permeability of Whitby mudstone

The significance of deep-water cryptic bioturbation in slope-channel massive sand deposits of the lower Rio Dell Formation, Eel River basin, California

Petroleum Source-Rock Evaluation and Hydrocarbon Potential in Montney Formation Unconventional Reservoir, Northeastern British Columbia, Canada

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