T. Manzocchi

Fault transmissibility multipliers for flow simulation models

Fault zone properties are incorporated in production flow simulators using transmissibility multipliers. These are a function of properties of the fault zone and of the grid-blocks to which they are assigned. Consideration of the geological factors influencing the content of fault zones allows construction of high resolution, geologically driven, fault transmissibility models. Median values of fault permeability and thickness are predicted empirically from petrophysical and geometrical details of the reservoir model. A simple analytical up-scaling scheme is used to incorporate the influence of likely small-scale fault zone heterogeneity. Fine-scale numerical modelling indicates that variability in fault zone permeability and thickness should not be considered separately, and that the most diagnostic measure of flow through a heterogeneous fault is the arithmetic average of the permeability to thickness ratio. The flow segregation through heterogeneous faults predicted analytically is closely, but not precisely, matched by numerical results. Identical faults have different equivalent permeabilities which depend, in part, on characteristics of the permeability field in which they are contained.

Scaling relationships of joint and vein arrays from The Burren, Co. Clare, Ireland

We present a study of the systematics of veins and joints in Carboniferous limestones of The Burren, Ireland. Scaling relationships were established for fracture arrays mapped from low elevation aerial photographs that image fractures on numerous limestone pavements for areas up to ca 1 km 2 . The veins and joints occur in the same sequence, but have contrasting scaling properties. The veins strike north-south and cut many beds to form vertically persistent, non-stratabound arrays. They are strongly clustered and have scale invariant geometric properties. Vein geometries suggest they grew sub-critically under relatively high differential stresses, during north-south directed Variscan compression. The joints form stratabound arrays, with regular spacings that scale with bed thickness. They show greater strike variation than the veins and have lognormal length distributions. The joints formed during uplift, under low-differential stress conditions. The contrasting scaling properties of the joints and veins are attributed to different overburden stresses at the time of formation. The veins formed at greater depths than the joints, in conditions that favoured fracture propagation across mechanical discontinuities, resulting in the development of non-stratabound scaling properties. q 2001 Elsevier Science Ltd. All rights reserved.

Sedimentological parameterization of shallow-marine reservoirs

The key causes of heterogeneity within progradational shallow-marine reservoirs have been defined as: shoreline type (wave vs. fluvial dominated); shoreline trajectory; the presence of permeability contrasts associated with dipping clinoform surfaces within the shoreface or delta front; the presence of cemented barriers between parasequences; and the progradation direction of the shoreline (described with respect to the main waterflood direction in the simulated reservoir). These parameters were recorded from a series of 56 modern and ancient depositional systems from a variety of climatic and tectonic settings. These data were then used to build the 408 synthetic sedimentological models that formed the basis for the SAIGUP study.

Faults in conventional flow simulation models: a consideration of representational assumptions and geological uncertainties

Even when geologically based methods are used to determine fault rock permeabilities and thicknesses for input into flow simulators, a wide range of simplifying assumptions regarding fault structure and content are still present. Many of these assumptions are addressed by defining quantitative and flexible methods for realistic parameterization of fault-related uncertainties, and by defining automated methods for including these effects routinely in full-field flow simulation modelling. The fault effects considered include: the two-phase properties of fault rocks; the spatial distributions of naturally variable or uncertain single-phase fault rock properties and fault throws; and the frequencies and properties of sub-resolution fault system or fault zone complexities, including sub-seismic faults, normal drag and damage zones, paired slip surfaces and fault relay zones. Innovative two-phase or geometrical upscaling approaches implemented in a reservoir simulator pre-processor provide transmissibility solutions incorporating the effect, but represented within the geometrical framework of the full-field flow simulation model. The solutions and flexible workflows are applied and discussed within the context of a sensitivity study carried out on two faulted versions of the same full-field flow simulation model. Significant influence of some of these generally neglected fault-related assumptions and uncertainties is revealed.

Faulting and fault sealing in production simulation models: Brent Province, northern North Sea

Faults can severely compartmentalize pressures and fluids in producing reservoirs, and it is therefore important to take these effects into account when modelling field production characteristics. The Brent Group fields, northern North Sea, contain a complex arrangement of fault juxtapositions of a well-layered sand-shale reservoir stratigraphy, and fault zones containing a variety of fluid flow-retarding fault rock products. It has been our experience that these fault juxtapositions impact the ‘plumbing’ of the faulted layering system in the reservoirs and the models that are built to mimic them – and are, in fact, a first-order sensitivity on compartmentalization of pressures and fluid flow during production simulation. It is important, therefore, to capture and validate the geological feasibility of fault- horizon geometries, from the seismic interpretation through to the static geocellular model, by model building in conjunction with the interpretation. It is then equally important to preserve this geometrical information during geocellular transfer to the simulation model, where it is critical input data used for calculation of fault zone properties and fault transmissibility multipliers, used to mimic the flow-retarding effects of faults. Application of these multipliers to geometrically weak models tends to produce ambiguous or otherwise potentially misleading simulation results. We have systematically modelled transmissibility multipliers from the upscaled cellular structure and property grids of geometrically robust models – with reference to data on clay content and permeability of fault rocks present within drill core from the particular reservoir under study, or from similar nearby reservoirs within the same stratigraphy. Where these transmissibility multipliers have been incorporated into the production simulation models, the resulting history matches are far better and quicker than had been achieved previously. The results are particularly enhanced where the fault rock data are drawn from rocks that have experienced a similar burial–strain history to the reservoir under study.

Sensitivity of the impact of geological uncertainty on production from faulted and unfaulted shallow-marine oil reservoirs: objectives and methods

Estimates of recovery from oil fields are often found to be significantly in error, and the multidisciplinary SAIGUP modelling project has focused on the problem by assessing the influence of geological factors on production in a large suite of synthetic shallow-marine reservoir models. Over 400 progradational shallow-marine reservoirs, ranging from comparatively simple, parallel, wave-dominated shorelines through to laterally heterogeneous, lobate, river-dominated systems with abundant low-angle clinoforms, were generated as a function of sedimentological input conditioned to natural data. These sedimentological models were combined with structural models sharing a common overall form but consisting of three different fault systems with variable fault density and fault permeability characteristics and a common unfaulted end-member. Different sets of relative permeability functions applied on a facies-by-facies basis were calculated as a function of different lamina-scale properties and upscaling algorithms to establish the uncertainty in production introduced through the upscaling process. Different fault-related upscaling assumptions were also included in some models. A waterflood production mechanism was simulated using up to five different sets of well locations, resulting in simulated production behaviour for over 35 000 full-field reservoir models. The model reservoirs are typical of many North Sea examples, with total production ranging from c. 15×106 m3 to 35×106 m3, and recovery factors of between 30% and 55%. A variety of analytical methods were applied. Formal statistical methods quantified the relative influences of individual input parameters and parameter combinations on production measures. Various measures of reservoir heterogeneity were tested for their ability to discriminate reservoir performance. This paper gives a summary of the modelling and analyses described in more detail in the remainder of this thematic set of papers.

Strain localisation and population changes during fault system growth within the Inner Moray Firth, Northern North Sea

Abstract The evolution of fault populations is established for an area within the Late Jurassic Inner Moray Firth sub-basin of the North Sea. Sedimentation rates outstripped fault displacement rates resulting in the blanketing of fault scarps and the preservation of fault displacement histories. Displacement backstripping is used to establish the growth history of the fault system. Fault system evolution is characterised by early generation of the main fault pattern and progressive localisation of strain onto larger faults. This localisation is accompanied by the death of smaller faults and an associated change in the active fault population from power-law to scale-bound. Fault length populations evolve from a power-law frequency distribution containing all faults, to a power-law distribution with a marked non-power-law tail containing the largest faults. This change in population character is synchronous with the development of a fully-connected fault system extending across the mapped area and the accommodation of displacements almost exclusively on the largest faults. Strain localisation onto fewer and better connected faults represents the most efficient means of accommodating fault-related deformation and is considered to be a fundamental characteristic of the spatio-temporal evolution of fault systems. Progressive strain localisation requires complementary changes in the characteristics of associated earthquake populations.

Flow through fault systems in high-porosity sandstones

Abstract Small-scale faults in high-porosity sandstones form highly connected systems over a range of length scales. The effective permeability and oil recovery in such systems are strongly controlled by their geometrical architecture. This paper describes partially sealing faults in terms of: (a) characterization of their spatial distribution; (b) their effects on reservoir compartmentalization; and (c) their significance for fluid flow. Four suites of numerical flow simulations in highly compartmentalized fault systems are used to assess the influence of geometrical variability on single- and two-phase flow. The single-phase suites demonstrate that effective permeability is approximately linearly related to the number of fault-enclosed compartments present in a fault system. Use of a fault heterogeneity measure allows effective permeability for a geometrical case to be estimated from fault density and fault and matrix permeability. The two-phase simulations model water-floods, and show the relationships between length scale, fault system geometry and oil recovery. In a self-similar fault system, oil recovery is preferentially inhibited at the smaller length scales. Oil recovery is influenced by compartment volume distribution and is therefore sensitive to fault clustering. The fault density necessary to severely affect either single- or two-phase flow is likely to occur only close to structures which are large relative to the scale under consideration. This improved understanding of the relative influences of fault system geometry, density and petrophysics should lead to significantly improved hydrocarbon recovery from faulted high-porosity sandstones.

Definition of a fault permeability predictor from outcrop studies of a faulted turbidite sequence, Taranaki, New Zealand

Abstract Post-depositional normal faults within the turbidite sequence of the Late Miocene Mount Messenger Formation of the Taranaki Basin, New Zealand are characterized by granulation and cataclasis of sands and by the smearing of clay beds. Clay smears maintain continuity for high ratios of fault throw to clay source bed thickness (c. 8), but are highly variable in thickness, and gaps occur at any point between the clay source bed cut-offs at higher ratios. Although cataclastic fault rock permeabilities may be appreciably lower (c. two orders of magnitude) than host rock sandstone permeabilities, the occurrence of continuous clay smears, combined with low clay permeabilities (10s to 100s nD) means that the primary control on fault rock permeability is clay smear continuity. A new permeability predictor, the Probabilistic Shale Smear Factor (PSSF), is developed which incorporates the main characteristics of clay smearing from the Taranaki Basin. The PSSF method calculates fault permeabilities from a simple model of multiple clay smears within fault zones, predicting a more heterogeneous and realistic fault rock structure than other approaches (e.g. Shale Gouge Ratio, SGR). Nevertheless, its averaging effects at higher ratios of fault throw to bed thickness provide a rationale for the application of other fault rock mixing models, e.g. SGR, at appropriate scales.

Assessing the effect of geological uncertainty on recovery estimates in shallow-marine reservoirs: The application of reservoir engineering to the SAIGUP project

Reservoir management is a balancing act between making timely operational decisions and the need to obtain data on which such decisions can be made. There is a further problem: estimates of recovery for prospective development plans are subject to uncertainty because of the uncertainty of the geological description within the simulation model. The SAIGUP project was designed to analyse the sensitivity of estimates of recovery due to geological uncertainty in a suite of shallow-marine reservoir models. However, although it was generic, it had the hallmarks of active reservoir management, because those members of the team responsible for deriving the notional development plans for individual models via reservoir simulation, and computing the recoveries, had to work in parallel with others under time and budget constraints. This paper describes the way the reservoir engineering was carried out to achieve these objectives, the assumptions made, the reasoning behind them, and how the principles could be used in other studies. Sample results are also presented, although the bulk of the results are presented in other papers in the project series. One surprising result was that faults that impede flow can improve recovery. The underlying physical explanation for this behaviour is provided.