Petroleum Geoscience - Volume 17, Issue 4, 2011

The reduction of fluid pressure during reservoir production promotes changes in the effective and total stress distribution within the reservoir and the surrounding strata. This stress evolution is responsible for many problems encountered during production (e.g. fault reactivation, casing deformation). This work presents the results of an extensive series of 3D numerical hydro-mechanical coupled analyses that study the influence of reservoir geometry and material properties on the reservoir stress path. The stress path is defined in terms of parameters that quantify the amount of stress arching and stress anisotropy that occur during reservoir production. The coupled simulations are performed by explicitly coupling independent commercial geomechanical and flow simulators. It is shown that stress arching is important in reservoirs with low aspect ratios that are less stiff than the bounding material. In such cases, the stresses will not significantly evolve in the reservoir, and stress evolution occurs in the over- and sideburden. Stiff reservoirs, relative to the bounding rock, exhibit negligible stress arching regardless of the geometry. Stress anisotropy reduces with reduction of the Young's modulus of the bounding material, especially for low aspect ratio reservoirs, but as the reservoir extends in either or both of the horizontal directions, the reservoir deforms uniaxially and the horizontal stress evolution is governed by the Poisson's ratio of the reservoir. Furthermore, the effect of the stress path parameters is introduced in the calculation of pore volume multiplier tables to improve non-coupled simulations, which otherwise overestimate the average reservoir pore pressure drawdown when stress arching is taking place.

In reservoir characterization, rock-physics models provide the link between seismic observables (density, compressional and shear wave speeds) and reservoir parameters, such as porosity, lithology and fluid saturation. However, the accuracy of these predictions is rarely explored. In fact, the validation of a model representing a dataset is often limited to the analysis of a cross-plot of two arbitrary magnitudes. The objective of this paper is to improve the calibration procedure through a quantitative assessment of the reservoir property predictions using various rock-physics models. The analysis is based on an inverse rock-physics modelling that organizes the rock-physics transforms into constraint data so that the seismic variables are direct functions of the reservoir parameters. It is revealed that the predictions of reservoir quality can assist in the diagnosis of the rock microstructure itself, such as the location of clay particles in clay-rich sediments. In addition, we found that a quantitative analysis is the only way to evaluate accurately the performance of various models when studying heterogeneous datasets.

Although reservoir quality cut-off criteria have been used for more than 50 years as a guide for economic decisions, there is still no rational procedure for identifying and applying them in Iranian oil and gas fields. In other words, there are different ‘rules-of-thumb’ in different sections of the National Iranian Oil Companies for determination of cut-off values. For instance, in one section, values of 10%, 50% and 50% are used for porosity, water saturation and shale content cut-offs, respectively; in another section, cut-off criteria are not used at all, simply an estimate of the time when 20% of oil-in-place could be produced. This paper addresses the optimization of cut-off value estimation from raw and processed petrophysical data based on extracting the most appropriate relationship for permeability as a function of porosity, water saturation and shale content – k = ƒ(ϕ, S w, V sh). The procedure starts by looking at permeability as the key parameter in choosing a cut-off value because sometimes the minimum value (the permeability cut-off) is directly related to economic circumstances and is defined by the client. Regression analysis coefficients of 0.936 and 0.870 were achieved for relationships of the form k = ƒ (ϕ, S w, V sh) in the two petrofacies intervals studied. This leads to specification of minimum k values of permeability and determination of optimum cut-off values for ϕ, S w and V sh. This method is then used to determine optimum cut-off values for the Burgan Member (sandstone) in the Kazhdumi Formation in an offshore oil field in the Persian Gulf. The calculated cut-off values for this case for k = 1.0 mD are ϕ = 12.5%, S w = 60% and V sh = 27%, as opposed to the ‘standard’ corporate values of ϕ = 10%, S w = 50% and V sh = 50%.

A detailed seismic stratigraphic interpretation of a previously unpublished, well-calibrated 3D seismic volume and regional 2D seismic lines in the Northern Porcupine Basin, west of Ireland has provided significant insights into the basin development, sedimentary fill and petroleum prospectivity within this area of the Irish Atlantic continental margin. The results of the seismic interpretation presented here provide a detailed description of the evolution of the Connemara discovery and have resulted in a revised model for the tectonic development and stratigraphic evolution of the fault block structure containing the oil accumulation. The new seismic stratigraphic analysis also provides the basis for an alternative interpretation of Early Cretaceous ‘clinoform’ features based on the results of the 3D seismic interpretation which supports a genesis through structural rotation of onlapping horizons rather than depositional downlap favoured by previous interpretations. This new-found structural and stratigraphic understanding not only has significant implications for determining the main controls on the Connemara discovery, but also provides a basis upon which to place other prospective structures in their regional context, including the identification and risking of exploration plays and prospects in the area.

Accurate rock property prediction is often a critical success factor for wells targeting hydrocarbons. This applies not only to reservoir porosity and permeability affecting productivity directly, but also to acoustic velocity, seismic time-to-depth conversion and depth prognosis. A detailed analysis of variation in the overburden rock velocity in the Southern North Sea has shown that Triassic velocity variations of up to 18% occur within short distances (e.g. <1 km). A correlation was found between increased acoustic velocities and the presence of an underlying salt weld. Salt Induced Stress Anomaly (SISA), a geomechanical model, is presented that can explain these observations and is based on the principles of buoyancy and point-loading. In the initial state, prior to salt movement, the vertical effective rock stresses resulting from the overburden weight are transmitted uniformly and cause laterally even compaction in the sediments. However, once the salt layer is able to flow and redistribute itself under the influence of buoyancy forces, the overburden stress will concentrate itself near the salt welds. This locally increased stress gives rise to higher velocities in the overburden. The same stress concentration model can also explain deterioration in the porosities of the Rotliegend reservoir as observed underneath salt welds.

Effective permeability to water in a petroleum column was estimated from routinely-measured mercury injection capillary pressure data of reservoir rocks, by applying a well-known reservoir engineering formula. The gradient of hydraulic potential across the column for a simplified petroleum trap model was then calculated to assess the realistic magnitude of hydrodynamic effects on capillary seal capacity under abnormally pressured conditions. The estimated effective permeability to water in the column ranges from 10–2 to 10–3 mD, even at several hundreds of metres above the free water level where it must become minimal. Since this figure is significantly larger than permeability of typical seals, it results in a negligible gradient of hydraulic potential in the column. The calculation, though including inherent uncertainties, indicates that hydrodynamics play a minor role on capillary sealing of typical petroleum traps, providing the reservoirs are water-wet, their tortuosity does not change with water saturation, and their anisotropy is not significantly large.

World-wide exploration for unconventional hydrocarbon accumulations has been increasing in the last decade. The deep Makó Trough of the Pannonian Basin in southeast Hungary has become a new target for companies looking for unconventional gas resources, but so far the exploration drilling has been unsuccessful.

To investigate the size of the assumed basin-centred gas accumulation we have studied the hydrocarbon potential of the source rocks in the Makó Trough using 3D basin and petroleum system modelling technology. The thermal and maturity history and timing of hydrocarbon generation were assessed, and the generated volume of hydrocarbons estimated and compared with the pore volume of the assumed unconventional reservoirs. The estimated mean volume of gas generated in the drainage area (490–650 × 109 Sm3) [given at surface conditions] is much less than the volume (>14 × 1012 Sm3) needed to fill the basin-centred gas accumulation. Therefore, the Makó Trough is unlikely to contain a large tight-gas sand accumulation. The Endrőd Marl is a fair quality, gas-prone source rock with average original TOC values of 0.75 wt%, reaching 1.5 wt% in the Hód-I and Makó-7 wells. These are below the TOC values of the proven gas shales of North America.