The value of fault analysis for field development planning

Faults play an important role in reservoir compartmentalization and can have a significant impact on recoverable volumes. A recent petroleum discovery in the Norwegian offshore sector, with an Upper Jurassic reservoir, is currently in the development planning phase. The reservoir is divided into several compartments by syn-depositional faults that have not been reactivated and do not offset the petroleum-bearing sandstones completely. A comprehensive fault analysis has been conducted from core to seismic scale to assess the likely influence of faults on the production performance and recoverable volumes. The permeability of the small-scale faults from the core were analyzed at high confining pressures using formation compatible brines. These permeability measurements provide important calibration points for the fault property assessment, which was used to calculate transmissibility multipliers (TM) that were incorporated into the dynamic reservoir simulation model to account for the impact of faults on fluid flow. Dynamic simulation results reveal a range of more than 20% for recoverable volumes depending on the fault property case applied and for a base case producer/injector well pattern. The fault properties are one of the key parameters that influence the range of cumulative recoverable oil volumes and the recovery efficiency

PETMiner - A visual analysis tool for petrophysical properties of core sample data

The aim of the PETMiner software is to reduce the time and monetary cost of analysing petrophysical data that is obtained from reservoir sample cores. Analysis of these data requires tacit knowledge to fill ‘gaps’ so that predictions can be made for incomplete data. Through discussions with 30 industry and academic specialists, we identified three analysis use cases that exemplified the limitations of current petrophysics analysis tools. We used those use cases to develop nine core requirements for PETMiner, which is innovative because of its ability to display detailed images of the samples as data points, directly plot multiple sample properties and derived measures for comparison, and substantially reduce interaction cost. An 11-month evaluation demonstrated benefits across all three use cases by allowing a consultant to: (1) generate more accurate reservoir flow models, (2) discover a previously unknown relationship between one easy-to-measure property and another that is costly, and (3) make a 100-fold reduction in the time required to produce plots for a report

Probabilistic analysis and comparison of stress-dependent rock physics models

A rock physics model attempts to account for the nonlinear stress dependence of seismic velocity by relating changes in stress and strain to changes in seismic velocity and anisotropy. Understanding and being able to model this relationship is crucial for any time-lapse geophysical or geohazard modelling scenario. In this study, we take a number of commonly used rock physics models and assess their behaviour and stability when applied to stress versus velocity measurements of a large (dry) core data set of different lithologies. We invert and calibrate each model and present a database of models for over 400 core samples. The results of which provide a useful tool for setting a priori parameter constraints for future model inversions. We observe that some models assume an increase in VP/VS ratio (hence Poisson’s ratio) with stress. A trait not seen for every sample in our data set. We demonstrate that most model parameters are well constrained. However, third-order elasticity models become ill-posed when their equations are simplified for an isotropic rock. We also find that third-order elasticity models are limited by their approximation of an exponential relationship via functions that lack an exponential term. We also argue that all models are difficult to parametrize without the availability of core data. Therefore, we derive simple relationships between model parameters, core porosity and clay content. We observe that these relationship are suitable for estimating seismic velocities of rock but poor when comes to predicting changes related to effective stress. The findings of this study emphasize the need for improvement to models if quantitatively accurate predictions of time-lapse velocity and anisotropy are to be made. Certain models appear to better fit velocity depth log data than velocity–stress core data. Thus, there is evidence to suggest a limitation in core data as a representation of the stress dependence of the subsurface. The differences in the stress dependence of the subsurface compared to that measured under laboratory conditions could potentially be significant. Although potentially difficult to investigate, its importance is of great significance if we wish to accurately interpret the stress dependence of subsurface seismic velocities

The Role of Texture, Cracks, and Fractures in Highly Anisotropic Shales

Organic shales generally have low permeability unless fractures are present. However, how gas, oil, and water flows into these fractures remains enigmatic. The alignment of clay minerals and the alignment of fractures and cracks are effective means to produce seismic anisotropy. Thus, the detection and characterization of this anisotropy can be used to infer details about lithology, rock fabric, and fracture and crack properties within the subsurface. We present a study characterizing anisotropy using S wave splitting from microseismic sources in a highly anisotropic shale. We observe very strong anisotropy (up to 30%) with predominantly VTI (vertical transverse isotropy) symmetry, but with evidence of an HTI (horizontal transverse isotropy) overprint due to a NE striking vertical fracture set parallel to the maximum horizontal compressive stress. We observe clear evidence of a shear wave triplication due to anisotropy, which to our knowledge is one of only a very few observations of such triplications in field‐scale data. We use modal proportions of minerals derived from X‐ray fluorescence data combined with realistic textures to estimate the contribution of intrinsic anisotropy as well as possible contributions of horizontally aligned cracks. We find that aligned clays can explain much of the observed anisotropy and that any cracks contributing to the vertical transverse isotropy (VTI) must have a low ratio of normal to tangential compliance (ZN/ZT), typical of isolated cracks with low hydraulic connectivity. Subhorizontal cracks have also been observed in the reservoir, and we propose that their reactivation during hydraulic fracturing may be an important mechanism to facilitate gas flow

STRESS SENSITIVITY OF MERCURY INJECTION MEASUREMENTS

Many petrophysical properties (e.g. permeability, electrical resistivity etc.) of tight rocks are very stress sensitive. However, most mercury injection measurements are made using an instrument that does not apply a confining pressure to the samples. Here we further explore the implications of the use and analysis of data from mercury injection porosimetry or mercury capillary pressure measurements (MICP). Two particular aspects will be discussed. First, the effective stress acting on samples analysed using standard MICP instruments (i.e. Micromeritics Autopore system) is described. Second, results are presented from a new mercury injection porosimeter that is capable of injecting mercury at up to 60,000 psi into 1.5 or 1 in core plugs while keeping a constant net stress up to 15,000 psi. This new instrument allows monitoring of the electrical conductivity across the core during the test so that an accurate threshold pressure can be determined. Although no external confining pressure is applied (unconfined) when using the standard MICP instrument, this doesn’t mean that the measurements can be considered as unstressed. Instead, the sample is under isostatic compression by the mercury until it enters the pore space of the sample. As an approximation, the stress that the mercury places on the sample is equal to its threshold pressure. Thus, the permeability calculated from standard MICP data is equivalent to that measured at its threshold pressure. Not all the samples have the same stress dependency thus comparing measured permeabilities at a single stress with values calculated from standard MICP data, corresponding at different threshold pressures, can lead to erroneous correlations. Therefore, the estimation of permeabilities from standard MICP data can be flawed and uncertain unless the stress effect is included. Results obtained from the new mercury injection system, porosimeter under net stress, are radically different from those obtained from standard MICP instruments such as the Autopore IV. In particular, the measurements at reservoir conditions produce threshold pressures that are three times higher and pore throat sizes that are 1/3rd of those measured by the standard MICP instrument. The results clearly indicate that calculating capillary height functions, sealing capacity, etc. from the standard instrument can lead to large errors that can have significant impact on subsurface characterization

Predicting Transmissibilities of Carbonate-hosted Fault Zones

It is common practice to incorporate deterministic transmissibility multipliers into simulation models of siliciclastic reservoirs to take into account the impact of faults on fluid flow, but this not common practice in carbonate reservoirs due to the lack of data on fault permeability. Calculation of fault transmissibilities in carbonates is also complicated by the variety of mechanisms active during faulting, associated with their high heterogeneity and increased tendency to react with fluids. Analysis of the main controls on fault rock formation and permeability from several carbonate-hosted fault zones is used to enhance our ability to predict fault transmissibility. Lithological heterogeneity in a faulted carbonate succession leads to a variety of deformation and/or diagenetic mechanisms, generating several fault rock types. Although each fault rock type has widely varying permeabilities, trends can be observed dependent on host lithofacies, juxtaposition and displacement. These trends can be used as preliminary predictive tools when considering fluid flow across carbonate fault zones. At lower displacements (<30 m), fewer mechanisms occur, creating limited fault rock types with a narrow range of low permeabilities, regardless of lithofacies juxtaposition. At increased displacements, more fault rock types are produced at juxtaposition of different lithofacies, with a wide range of permeabilities

Nanoindentation of Horn River Basin Shales: The Micromechanical Contrast Between Overburden and Reservoir Formations

We present a micromechanical characterization of shales from the Horn River Basin, NW Canada. The shales have contrasting mineralogy and microstructures and play different geomechanical roles in the field: the sample set covers an unconventional gas reservoir and the overburden unit that serves as the upper fracture barrier. Composition and texture were characterized using X-ray diffraction, mercury injection porosimetry, and scanning electron microscopy (SEM). Grid nanoindentation testing was used to obtain the mechanical response of the dominant phases in the shale microstructure. Samples were indented parallel and perpendicular to the bedding plane to assess mechanical anisotropy. Chemical analysis of the grids with SEM-EDS (energy dispersive X-ray spectroscopy) was undertaken and the coupled chemo-mechanical data was used in a statistical clustering procedure (Gaussian mixture model) to reveal the mechanical properties of each phase. The results show that the overburden consists of a soft clay matrix with highly anisotropic elastic stiffness, and stiffer but effectively isotropic inclusions of quartz and feldspar; the significant anisotropy of the overburden has been previously observed on a much larger scale using microseismic data. Creep displacement is concentrated in the clay matrix, which is the key phase for fracture barrier and seal applications. The reservoir units are harder and have more isotropic mechanical responses, primarily due to their lower clay content. Despite varied compositions and microstructures, the major phases of these shales (clay/organic matrix, quartz/feldspar, dolomite, and calcite) have unique mechanical signatures, which will aid identification in future micromechanical characterizations and facilitate their use in upscaling schemes

Permeability of fault rocks in siliciclastic reservoirs: Recent advances

It is common practice to create geologically realistic production simulation models of fault compartmentalized reservoirs. Data on fault rock properties are required, to calculate transmissibility multipliers that are incorporated into these models, to take into account the impact of fault rocks on fluid flow. Industry has generated large databases of fault rock permeability, which are commonly used for this purpose. Much of the permeability data were collected using two inappropriate laboratory practices with measurements being made at low confining pressure with distilled water as the permeant. New fault rock permeability measurements have been made at high confining pressures using formation compatible brines as the permeant. Fault permeability decreases by an average of five fold as net confining pressure is increased from that used in previous measurements (i.e. ∼70 psi) to that approaching in situ conditions (i.e. 5000 psi). On the other hand, permeability increases by around the same amount if reservoir brine is used as the permeant instead of distilled water. So overall, these two inappropriate laboratory practices used in previous studies cancel each other out meaning that legacy fault rock property data may still have value for modelling cross-fault flow in petroleum reservoirs. A poor correlation exists between clay content and fault rock permeability, which is easily explained by the application of a simple clay-sand mixing model. This emphasises the need to gather fault permeability data directly from the reservoir of interest. The cost of such studies could be significantly reduced by screening core samples using a CT scanner so that only samples that are likely to impact fluid flow are analyzed in detail. The stress dependence of fault permeability identified in this study is likely to be primarily caused by damage generated during or following coring. So it is probably not necessary to take into account the impact of stress on fault permeability in simulation models unless the faults of interest are likely to reach failure and reactivate

A multimethod Global Sensitivity Analysis to aid the calibration of geomechanical models via time-lapse seismic data

Time-lapse seismic attributes are used extensively in the history matching of production simulator models. However, although proven to contain information regarding production induced stress change, it is typically only loosely (i.e. qualitatively) used to calibrate geomechanical models. In this study we conduct a multimethod Global Sensitivity Analysis (GSA) to assess the feasibility and aid the quantitative calibration of geomechanical models via near-offset time-lapse seismic data. Specifically, the calibration of mechanical properties of the overburden. Via the GSA, we analyse the near-offset overburden seismic traveltimes from over 4000 perturbations of a Finite Element (FE) geomechanical model of a typical High Pressure High Temperature (HPHT) reservoir in the North Sea. We find that, out of an initially large set of material properties, the near-offset overburden traveltimes are primarily affected by Young's modulus and the effective stress (i.e. Biot) coefficient. The unexpected significance of the Biot coefficient highlights the importance of modelling fluid flow and pore pressure outside of the reservoir. The FE model is complex and highly nonlinear. Multiple combinations of model parameters can yield equally possible model realizations. Consequently, numerical calibration via a large number of random model perturbations is unfeasible. However, the significant differences in traveltime results suggest that more sophisticated calibration methods could potentially be feasible for finding numerous suitable solutions. The results of the time-varying GSA demonstrate how acquiring multiple vintages of time-lapse seismic data can be advantageous. However, they also suggest that significant overburden near-offset seismic time-shifts, useful for model calibration, may take up to 3 yrs after the start of production to manifest. Due to the nonlinearity of the model behaviour, similar uncertainty in the reservoir mechanical properties appears to influence overburden traveltime to a much greater extent. Therefore, reservoir properties must be known to a suitable degree of accuracy before the calibration of the overburden can be considered

Key controls on the hydraulic properties of fault rocks in carbonates

A significant knowledge gap exists when analysing and predicting the hydraulic behaviour of faults within carbonate reservoirs. To improve this, a large database of carbonate fault rock properties has been collected from 42 exposed faults, from seven countries. Faults analysed cut a range of lithofacies, tectonic histories, burial depths and displacements. Porosity and permeability measurements from c. 400 samples have been made, with the goal of identifying key controls on the flow properties of fault rocks in carbonates. Intrinsic and extrinsic factors have been examined, such as host lithofacies, juxtaposition, host porosity and permeability, tectonic regime, displacement, and maximum burial depth, as well as the depth at the time of faulting. The results indicate which factors may have had the most significant influence on fault rock permeability, improving our ability to predict the sealing or baffle behaviour of faults in carbonate reservoirs. Intrinsic factors, such as host porosity, permeability and texture, appear to play the most important role in fault rock development. Extrinsic factors, such as displacement and kinematics, have shown lesser or, in some instances, a negligible control on fault rock development. This conclusion is, however, subject to two research limitations: lack of sufficient data from similar lithofacies at different displacements, and a low number of samples from thrust regimes