31 results found
Onyenanu G, Hampson GJ, Fitch P, et al., 2019, Effects of erosional scours on reservoir properties of heterolithic, distal lower shoreface sandstones, Petroleum Geoscience, Vol: 25, Pages: 235-248, ISSN: 1354-0793
Distal intervals of interbedded sandstones and mudstones in shallow-marine, wave-dominated shoreface and deltaic reservoirs may contain significant hydrocarbon resources, but their reservoir properties are difficult to predict. Relatively small-scale (200 × 100 × 20 m) three-dimensional object-based reservoir models, conditioned to outcrop analogue data, have been used to investigate the controls on the proportion of sandstone, the proportion of sandstone beds that are connected by sandstone-filled erosional scours and the effective vertical-to-horizontal permeability ratio (kv/kh) of such intervals. The proportion of sandstone is controlled by sandstone-bed and mudstone-interbed thickness, and by parameters that describe the geometry, dimensions and lateral-stacking density of sandstone-filled scours. Sandstone-bed connectivity is controlled by the interplay between the thickness of mudstone interbeds and sandstone-filled erosional scours. Effective kv/kh is controlled by the proportion of sandstone, which represents the effects of variable distributions and dimensions of mudstones produced by scour erosion, provided that scour thickness is greater than mudstone-interbed thickness. These modelling results provide a means of estimating the effective kv/kh at the scale of typical reservoir-model grid cells using values of mudstone-interbed thickness and the proportion of sandstone that can potentially be provided by core data.
Jackson CA-L, Zhang Y, Herron D, et al., 2019, Subsurface expression of a salt weld, Gulf of Mexico, Petroleum Geoscience, Vol: 25, Pages: 102-111, ISSN: 1354-0793
Salt welds form due to salt expulsion and thinning by mechanical (e.g. salt flow) and/or chemical (e.g. salt dissolution) processes. Despite being ubiquitous in salt-bearing sedimentary basins, where they may trap large volumes of hydrocarbons, little is published on weld thickness and composition. We here use 3D seismic reflection, borehole, and biostratigraphic data from the Atwater Valley protraction area of the northern Gulf of Mexico to constrain the thickness and composition of a tertiary salt weld. Seismic data image an ‘apparent weld’ (sensu Wagner & Jackson 2011) at the base of a Plio-Pleistocene minibasin that subsided into allochthonous salt. Borehole data indicate the weld is actually ‘incomplete’, being c. 24 m thick, and containing an upper 5 m thick halite and a lower 15 m thick halite, separated by a 4 m thick mudstone. The age and origin of the intra-weld mudstone is unclear, although we speculate it is either: (i) Late Jurassic, representing material transported upwards from the autochthonous level within a feeder, and subsequently trapped as allochthonous salt thinned and welded, or, perhaps more likely; (ii) Pliocene, representing a piece of salt carapace reworked from the top of and eventually trapped in, the now locally welded sheet. We show that 3D seismic reflection data may not resolve salt weld thickness, with the presence of relatively thin remnant salt lending support to models of welding based on viscous flow. Furthermore, the halite-dominated character of the weld supports the hypothesis that tectonic purification may occur during salt flow.
Onyenanu GI, Jacquemyn CEMM, Graham GH, et al., 2018, Geometry, distribution and fill of erosional scours in a heterolithic, distal lower shoreface sandstone reservoir analogue: Grassy Member, Blackhawk Formation, Book Cliffs, Utah, USA, Sedimentology, Vol: 65, Pages: 1731-1760, ISSN: 0037-0746
Many shoreface sandstone reservoirs host significant hydrocarbon volumes within distal intervals of interbedded sandstones and mudstones. Hydrocarbon production from these reservoir intervals depends on the abundance and proportion of sandstone beds that are connected by erosional scours, and on the lateral extent and continuity of interbedded mudstones. Cliff‐face exposures of the Campanian ‘G2’ parasequence, Grassy Member, Blackhawk Formation in the Book Cliffs of east‐central Utah, USA, allow detailed characterization of 128 erosional scours within such interbedded sandstones and mudstones in a volume of 148 m length, 94 m width and 15 m height. The erosional scours have depths of up to 1·1 m, apparent widths of up to 15·1 m and steep sides (up to 35°) that strike approximately perpendicular (N099 ± 36°) to the local north–south palaeoshoreline trend. The scours have limited lateral continuity along strike and down dip, and a relatively narrow range of apparent aspect ratio (apparent width/depth), implying that their three‐dimensional geometry is similar to non‐channelized pot casts. There is no systematic variation in scour dimensions, but ‘scour density’ is greater in amalgamated (conjoined) sandstone beds over 0·5 m thick, and increases upward within vertical successions of upward‐thickening conjoined sandstone beds. There is no apparent organization of the overall lateral distribution of scours, although localized clustering implies that some scours were re‐occupied during multiple erosional events. Scour occurrence is also associated with locally increased amplitude and laminaset thickness of hummocky cross‐stratification in sandstone beds. The geometry, distribution and infill character of the scours imply that they were formed by storm‐generated currents coincident with riverine sediment influx (‘storm floods’). The erosional scours increase the vertical and lateral connectivity
We examine the effect of viscous forces on the displacement of one fluid by a second, immiscible fluid along parallel layers of contrasting porosity, absolute permeability and relative permeability. Flow is characterized using five dimensionless numbers and the dimensionless storage efficiency, so results are directly applicable, regardless of scale, to geologic carbon storage. The storage efficiency is numerically equivalent to the recovery efficiency, applicable to hydrocarbon production. We quantify the shock-front velocities at the leading edge of the displacing phase using asymptotic flow solutions obtained in the limits of no crossflow and equilibrium crossflow. The shock-front velocities can be used to identify a fast layer and a slow layer, although in some cases the shock-front velocities are identical even though the layers have contrasting properties. Three crossflow regimes are identified and defined with respect to the fast and slow shock-front mobility ratios, using both theoretical predictions and confirmation from numerical flow simulations. Previous studies have identified only two crossflow regimes. Contrasts in porosity and relative permeability exert a significant influence on contrasts in the shock-front velocities and on storage efficiency, in addition to previously examined contrasts in absolute permeability. Previous studies concluded that the maximum storage efficiency is obtained for unit permeability ratio; this is true only if there are no contrasts in porosity and relative permeability. The impact of crossflow on storage efficiency depends on the mobility ratio evaluated across the fast shock-front and on the time at which the efficiency is measured.
Bell RE, Orme H, Lenette K, et al., Geometry and kinematics of accretionary wedge faults inherited from the structure and rheology of the incoming sedimentary section; insights from 3D seismic reflection, EGU General Assembly
Fitch PJR, Jackson MD, Hampson GJ, et al., 2017, Interaction of stratigraphic and sedimentological heterogeneities with flow in carbonate ramp reservoirs: Impact of production strategy
As invited speaker for the "Best of Petroleum Geoscience" session (7.07), We present a summary of the work by Fitch et al. (2014), investigating the relative impact of stratigraphic and sedimentological heterogeneities on flow behaviour and simulated recovery under two production strategies, which promote a dominance of either horizontal or vertical flow. Integrated flow simulation and experimental design techniques were used to investigate the first-order impact of stratigraphic and sedimentological heterogeneities on simulated recovery in carbonate reservoirs. Heterogeneities controlling the value of rock properties, and the volume and lateral continuity of EOD-belts were found to be key controls on flow behaviour in displacements dominated by either horizontal and vertical flow. The significance of heterogeneities controlling vertical flow paths, such as continuous, impermeable barriers and permeability anisotropy increases when vertical flow dominates.
Bell RE, Orme H, Jackson CA-L, et al., Geometry and growth of segmented thrust faults influences hydraulic connectivity in accretionary wedges: New Insights from 3D seismic reflection data, AGU Fall meeting
Debbabi Y, Jackson MD, Hampson GJ, et al., 2016, The interplay of capillary and viscous forces driving flow through layered porous media
We examine the impact of viscous and capillary forces on immiscible, two-phase flow parallel and perpendicular to continuous layers of contrasting material properties. We consider layers of contrasting porosity and relative permeability, in addition to the contrasts in absolute permeability investigated previously. We define a set of dimensionless numbers which characterize flow. Some of these are common to flow both parallel and perpendicular to layering, such as the longitudinal permeability ratio σ and the ratio Rs of the moveable pore volumes (MPV) in each layer. Others are specific to a given flow direction, such as the dimensionless capillary to viscous ratio Ncv, and the effective aspect ratio RL that quantifies crossflow for layer-parallel flow. We examine how variations in the dimensionless numbers affect the trapping/recovery efficiency, defined as the fraction of the model MPV occupied by the injected phase after 1 MPV injected, and which is numerically equivalent to the fraction of the displaced phase recovered from the model after 1 MPV injected. The results are directly applicable to geological carbon storage and hydrocarbon production. We find that the trapping efficiency is clearly controlled by the dimensionless numbers. When flow is perpendicular to layering, heterogeneity only influences flow when capillary forces are significant (Ncv>0). As Ncv is increased, a larger fraction of the non-wetting phase is trapped if the layers have contrasting capillary pressure curves. When flow is parallel to layering, both viscous and capillary forces are important. In the viscous limit (Ncv=0), heterogeneity reduces trapping efficiency if σ≠Rs. As capillary forces become more significant (Ncv increases) and if crossflow between layers can occur (RL>0), the trapping efficiency also increases in response to capillary crossflow and reaches a maximum at a given Ncv. At higher Ncv, the benefit of crossflow is outweighed by along layer diffusion
Villamizar CA, Hampson GJ, Flood YS, et al., 2015, Object-based modelling of avulsion-generated sandbody distributions and connectivity in a fluvial reservoir analogue of low to moderate net-to-gross ratio, Petroleum Geoscience, Vol: 21, Pages: 249-270, ISSN: 1354-0793
Data from a large-scale outcrop analogue (Upper Cretaceous Blackhawk Formation, Wasatch Plateau, centralUtah, USA) were used to construct three-dimensional, object-based reservoir models of low to moderate net-to-gross (NTG)ratios (11–32%). Two descriptive spatial statistical measures, lacunarity and Ripley’s K function, were used to characterizesandbody distribution patterns in the different models. Lacunarity is sensitive to sandbody abundance and NTG ratio, whileRipley’s K function identifies clustered, random and regular spacing of sandbodies. The object-based modelling algorithmreproduces sandbody dimensions and abundances, but patterns of sandbody distribution generated by river avulsion arepoorly replicated because pseudo-well spacing provides only limited constraint on sandbody positions.In common with previous studies, the connected sand fraction in the reservoir models increases with increasing NTGratio and increasing range of sandbody orientations, but there is significant stochastic variation around both of these trends.In addition, low NTG reservoir models in which sandbodies exhibit strong clustering may also have a low connected sandfraction across the model volume because the sandbody clusters are widely spaced and, thus, tend to be isolated from eachother. Consequently, connected sand fraction could be overestimated if avulsion-generated sandbody clusters are not identifiedand replicated in models of such reservoirs.
Fitch PJR, Lovell MA, Davies SJ, et al., 2015, An integrated and quantitative approach to petrophysical heterogeneity, Marine and Petroleum Geology, Vol: 63, Pages: 82-96, ISSN: 1873-4073
Exploration in anything but the simplest of reservoirs is commonly more challenging because of the intrinsic variability in rock properties and geological characteristics that occur at all scales of observation and measurement. This variability, which often leads to a degree of unpredictability, is commonly referred to as “heterogeneity”, but rarely is this term defined. Although it is widely stated that heterogeneities are poorly understood, researchers have started to investigate the quantification of various heterogeneities and the concept of heterogeneity as a scale-dependent descriptor in reservoir characterization.Based on a comprehensive literature review we define “heterogeneity” as the variability of an individual or combination of properties within a specified space and/or time, and at a specified scale. When investigating variability, the type of heterogeneity should be defined in terms of grain – pore components and the presence or absence of any dominant features (including sedimentological characteristics and fractures). Hierarchies of geologic heterogeneity can be used alongside an understanding of measurement principles and volumes of investigation to ensure we understand the variability in a dataset.Basic statistics can be used to characterise variability in a dataset, in terms of the amplitude and frequency of variations present. A better approach involves heterogeneity measures since these can provide a single value for quantifying the variability, and provide the ability to compare this variability between different datasets, tools/measurements, and reservoirs. We use synthetic and subsurface datasets to investigate the application of the Lorenz Coefficient, Dykstra–Parsons Coefficient and the coefficient of variation to petrophysical data – testing assumptions and refining classifications of heterogeneity based on these measures.
Fitch PJR, Jackson MD, Hampson GJ, et al., 2014, Interaction of stratigraphic and sedimentological heterogeneities with flow in carbonate ramp reservoirs: impact of fluid properties and production strategy, PETROLEUM GEOSCIENCE, Vol: 20, Pages: 7-26, ISSN: 1354-0793
Fitch P, Lovell M, Davies S, et al., 2014, A multi-scale investigation of heterogeneity and reservoir quality, using core and well log petrophysical property data, Geological Society London, Reservoir Quality of Clastic and Carbonate Rocks
Fitch P, Jackson M, Hampson G, et al., 2014, The impact of stratigraphic and facies architecture on flow in carbonate reservoirs; an integrated approach using comparative modeling techniques, AAPG ACE
Fitch P, Jackson M, Hampson G, et al., 2013, Interaction of production strategy with stratigraphic and sedimentologic heterogeneity in carbonate reservoirs, AAPG Annual Conference & Exhibition 2013
Fitch P, Davies S, Lovell M, et al., 2013, Reservoir Quality and Reservoir Heterog eneity: Petrophysical Application of theLorenz Coeffi cient, Petrophysics, Vol: 54, Pages: 465-474
Fitch P, Davies S, Lovell M, et al., 2013, The petrophysical link between reservoir quality and heterogeneity: application of the Lorenz Coefficient, SPWLA Annual Symposium 2013 (Paper Q)
Fitch P, Jackson M, Hampson G, et al., 2012, Quantifying the impact of stratigraphic and sedimentologic heterogeneities on flow in carbonate reservoirs through integrated flow simulation experiments, AAPG/SEG/SPE Hedberg conference “Fundamental Controls on Flow in Carbonates”
Pälike H, Lyle M, Nishi H, et al., 2012, A Cenozoic record of the equatorial Pacific carbonate compensation depth, Nature, Vol: 7413, Pages: 609-614
Westerhold T, Röhl U, Wilkens R, et al., 2012, Revised composite depth scales and integration of IODP Sites U1331–U1334 and ODP Sites 1218–1220, IN Pälike, H., Lyle, M., Nishi, H., Raffi, I., Gamage, K., Klaus, A., and the Expedition 320/321 Scientists, Proc. IODP, 320/321: Tokyo
Fitch P, Jackson M, Hampson G, et al., 2012, Investigating the impact of stratigraphic and sedimentological heterogeneities on flow in carbonate reservoir models, using a hierarchical approach with experimental design, AAPG ACE
Fitch P, 2011, Exploring heterogeneity in carbonate petrophysical properties: from recent sediments to subsurface reservoirs, London Petrophysical Society October 2011 seminar
Fitch P, Jackson M, Hampson G, et al., 2011, A Hierarchical Approach to Characterizing the Impact of Stratigraphic and Sedimentological Heterogeneities on Flow in Carbonate Reservoirs, AAPG ICE
Fitch P, Jackson M, Hampson G, et al., 2011, How do stratigraphic heterogeneities impact on flow in carbonate ramp reservoirs?, British Sedimentological Research Group annual meeting
Fitch P, Jackson M, Hampson G, et al., 2011, A hierarchical approach to characterising the impact of stratigraphic and sedimentological heterogeneities on flow in carbonate reservoirs, 14th Bathurst Meeting of Carbonate Sedimentologists
Fitch P, Davies S, Lovell M, et al., 2011, Quantification of heterogeneity in carbonate reservoirs:; application to geological and petrophysical property characterization, AAPG ACE
Fitch P, Jackson M, Hampson G, et al., 2011, A hierarchical approach to characterizing the impact of stratigraphic and sedimentological heterogeneities on flow in carbonate reservoirs., AAPG ICE
Fitch P, Lofts J, Morris S, et al., 2010, Petrophysical and image log facies of a carbonate dominated sectionof the Cap Mountain Limestone Member, Riley Formation, BlancoCounty, Texas., Geol. Soc. Petroleum Geoscience Collaboration Conference, November 2007
Fitch P, Davies S, Lovell M, et al., 2010, Quantifying Numerical Heterogeneity in Carbonate Petrophysical Properties: application to geological and fluid flow unit characterisation, Geol.Soc. Petroleum Group; Advances in Carbonate Exploration and Reservoir Analysis, November 2010
Fitch P, Davies S, Lovell M, et al., 2010, Heterogeneity in Carbonate Petrophysical Properties: application to fluid flow units and sampling strategies, SPWLA 51st Annual Logging Symposium, June 2010
Fitch P, Davies S, Lovell M, et al., 2010, Heterogeneity in Carbonate Petrophysical Properties: application to fluid flow units and sampling strategies., SPWLA Perth 2010 Transactions, Paper 92910, Pages: 1-10
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