Patrick William Michael Corbett

Immiscible flow behaviour in laminated and cross-bedded sandstones

Abstract In this paper, we describe models of water/oil displacement in typical, geologically-structured media. We focus specifically on laminated and cross-bedded structures, since these are almost ubiquitous in clastic sedimentary reservoirs. The importance, for field-scale models, of properly representing the interaction of viscous, capillary and gravitational forces with small-scale heterogeneity is clearly demonstrated. Because the length-scale, δχ, of sedimentary lamination is of order 10−3 to 10−2 m, capillary forces, which are inversely proportional to δχ, may play a very significant role in determining the effective flow behaviour at larger scales. We show that there are important differences in oil recovery between cross-layer flow and along-layer flow. Differences of up to a factor of two in ultimate recovery may be produced by different representations of realistic clastic sedimentary structure (such as parallel lamination, cross-lamination and small-scale faulting). The significance of these findings is in determining the correct scale-up procedure for the multiphase effective flow parameters. We use the term geopseudo to describe correctly-scaled, multi-phase, pseudofunctions which capture the effects of small-scale sedimentary structure. Field-scale reservoir models must take account of these small-scale effects in order to lay claim to reasonable accuracy in production forecasts.

Permeability semivariograms, geological structure, and flow performance

Clastic sediments may have a strong deterministic component to their permeability variation. This structure may be seen in the experimental semivariogram, but published geostatislical studies have not always exploited this feature during data analysis and covariance modeling. In this paper, we describe sedimentary organization, its importance for flow modeling, and how the semivariogram can be used for identification of structure. Clastic sedimentary structure occurs at several scales and is linked to the conditions of deposition. Lamination, bed, and bedset scales show repetitive and trend features that should be sampled carefully to assess the degree of organization and levels of heterogeneity. Interpretation of semivariograms is undertaken best with an appreciation of these geological units und how their features relate to the sampling program. Sampling at inappropriate intervals or with instruments having a large measurement volume, for example, may give misleading semivariograms. Flow simulations for models which include and ignore structure show that the repetitive features in permeability can change anisotropy and recovery performance significantly. If systematic variation is present, careful design of the permeability fields therefore is important particularly to preserve the structure effects.

Modeling combined fluid and stress change effects in the seismic response of a producing hydrocarbon reservoir

Editors note: A fuller version of this article can be downloaded in pdf format from the GUMPA project Web site at the following URL - http://www.pet.hw.ac.uk/research/gumpa/index.html The exploration and production of hydrocarbons are generally accomplished with the aid of 3-D seismic to image reservoir structure and, in some instances, reservoir properties and direct hydrocarbon indicators. Repeated seismic surveys over a period are termed time-lapse seismic (and sometimes 4-D seismic ). Changes observed in the seismic character with time have been attributed to impedance changes as a result of production (e.g. Gawith and Gutteridge, 1996). These changes have been used in a few producing fields to monitor reservoir performance. Identifying observed differences in repeat 3-D surveys and relating these to either in-situ saturation or stress-state changes, or both, has been difficult because of the lack of control data. It has been noted that in some fields (Watts et al., 1995), the sensitivity to stress changes can be very much greater than the sensitivity to saturation changes. In other fields (Landro et al., 1999), the saturation changes are thought to be more significant. To aid understanding, a need for greater integration of geophysics and reservoir engineering has been noted and was the motivation for this study (Jack, 2001). There is a limited window of opportunity in a fields producing life when there are sufficient changes (saturation or stress) in the subsurface to show a surface seismic response. These changes have to be monitored before the field has reached significant decline for the observed changes to be exploited for reservoir management (through in-fill drilling for by-passed, compartmentalized or attic oil). Reservoir modeling is an essential tool for managing the development of and production from hydrocarbon reservoirs. Many technical issues however surround the realism and validity of the models on which management decisions are based. …

Reservoir Geochemistry: A Link Between Reservoir Geology and Engineering?

Geochemistry provides a natural but poorly exploited link between reservoir geology and engineering. The authors summarize some current applications of geochemistry to reservoir description and stress that because of their strong interactions with mineral surfaces and water, nitrogen and oxygen compounds in petroleum may exert an important influence on the PVT properties of petroleum, viscosity and wettability. The distribution of these compounds in reservoirs is heterogeneous on a sub-meter scale and is partly controlled by variations in reservoir quality. The implied variations in petroleum properties and wettability may account for some of the errors in reservoir simulations.

Quantification of illite content in sedimentary rocks using magnetic susceptibility - A rapid complement or alternative to X-ray diffraction

ABSTRACT The paramagnetic clay mineral illite can have important controls on fluid permeability and microporosity in sedimentary rocks. Increases in illite content of a few percent can reduce permeability by several orders of magnitude. Traditional X-ray diffraction (XRD) techniques for quantifying illite content can be very time consuming, requiring significant sample preparation, and generally examine only a relatively small sample volume. In contrast, a technique based on magnetic susceptibility described here is very rapid, cheap, sensitive, nondestructive, and requires no extra preparation of the sample. It is representative of a much larger sample volume, and in the present paper utilizes standard 1 inch diameter cylindrical core plugs, but it can be applied to other sample shapes and volumes. The magnetic-susceptibility-derived estimates of illite content from core plugs correspond well with XRD results from small powdered samples of the same material, in terms of both absolute values and overall trends with depth. However, neither the magnetic method nor XRD should be regarded as definitive. Each technique has merits and limitations, and these help to explain some observed differences in the illite determinations by each method. XRD may underestimate the illite content, particularly in muddy rocks, whereas the magnetic method theoretically provides an upper limit for the illite content. The magnetic method is also capable of simultaneously estimating the quartz content in the present samples. Changes in the concentration and distribution of illite during core cleaning or core flooding experiments can also be potentially quantified by the magnetic technique. The development of portable field sensors potentially allows the magnetic method to provide high-resolution illite profiles on slabbed cores, outcrops, and unconsolidated samples without the need to cut core plugs. The method could also be applied to whole-core measurements and to downhole magnetic susceptibility data. The processing of the magnetic susceptibility signal can also be extended to quantify other minerals in simple systems.

Layered fluvial reservoirs with internal fluid cross flow: a well-connected family of well test pressure transient responses

A new well testing response from lateral cross flow within layers is described. The response occurs when there is extremely low effective vertical permeability in the system at the larger scale. Low vertical permeability actually accentuates the layering and reduces vertical cross flow whilst enhancing lateral cross flow from within-layer heterogeneities. The response is investigated using numerical simulation of flow in end-member models of complex and geologically realistic architecture in high net-to-gross fluvial systems. This ‘ramp’ response is shown to form one member of a family of well test pressure transient responses. The other members of the family include previously-described negative geoskin and geochoke. The use of well test data to characterize these particular types of layered fluvial reservoirs is an important step in the static-dynamic integration of geological and reservoir engineering models.

Uncertainty in well test and core permeability analysis: a case study in fluvial channel reservoirs, northern North Sea, Norway

Reservoir permeability is one of the important parameters derived from well test analysis. Small-scale permeability measurements in wells are commonly made using core plugs or, more recently, probe permeameter measurements. Upscaling of these measurements for comparisons with the permeability derived from drill stem tests (DSTs) can be completed by statistical averaging methods. DST permeability is commonly compared with one of the core plug averages: arithmetic, geometric, or harmonic. Questions that commonly arise are which average does the DST-derived permeability represent and over what region is this average valid? Another important question is how should the data sets be reconciled where there are discrepancies? In practice, the permeability derived from well tests is commonly assumed to be equivalent to the arithmetic (in a layered reservoir) or geometric (in a randomly distributed permeability field) average of the plug measures. These averages are known to be members of a more general power-average solution. This pragmatic approach (which may include an assumption on the near-well geology) is commonly flawed, owing to several reasons that are expanded in this article. The assessment of in situ reservoir permeability requires an understanding of both core (plug and probe) and well test measurements in terms of their volume scale of investigation, measurement mechanism, interpretation, and integration. This article presents a comparison of core and well test measurements in a North Sea case study. We undertook evaluation of three DSTs and associated core plug and probe data sets from Jurassic fluvial channel sandstones in a single field. The well test permeabilities were generally found to differ from the core estimates, (Begin page 1930) and no consistent explanation could be found for the group of wells. However, the probe permeameter data were able to further constrain the core estimates. This study highlights the uncertainty in effective in situ reservoir permeability, resulting from the interpretation of small (core) and reservoir (well test) scale permeability data. The techniques used are traditional upscaling combined with the Lorenz plot to identify the dominant flowing interval. Fluvial sandstones are very heterogeneous, and this exercise is instructive in understanding the heterogeneity for the guidance of reservoir models in such a system.

Hierarchical benchmark case study for history matching, uncertainty quantification and reservoir characterisation

Benchmark problems have been generated to test a number of issues related to predicting reservoir behaviour (e.g. Floris et al., 2001, Christie and Blunt, 2001, Peters et al., 2010). However, such cases are usually focused on a particular aspect of the reservoir model (e.g. upscaling, property distribution, history matching, uncertainty prediction, etc.) and the other decisions in constructing the model are fixed by log values that are related to the distribution of cell properties away from the wells, fixed grids and structural features and fixed fluid properties. This is because all these features require an element of interpretation, from indirect measurements of the reservoir, noisy and incomplete data and judgments based on domain knowledge. Therefore, there is a need for a case study that would consider interpretational uncertainty integrated throughout the reservoir modelling workflow. In this benchmark study we require the modeller to make interpretational choices as well as to select the techniques applied to the case study, namely the geomodelling approach, history matching algorithm and/or uncertainty quantification technique. The interpretational choices will be around the following areas: (1)Top structure interpretation from seismic and well picks. (2)Fault location, dimensions and the connectivity of the network uncertainty. (3)Facies modelling approach. (4)Facies interpretations from well logs cutoffs. (5)Petrophysical property prediction from the available well data. (6)Grid resolution-choice between number of iterations and model resolution to capture the reservoir features adequately. A semi-synthetic study is based on real field data provided: production data, seismic sections to interpret the faults and top structures, wireline logs to identify facies correlations and saturation profile and porosity and permeability data and a host of other data. To make this problem useable in a manageable time period multiple hierarchically related gridded models were produced for a range of different interpretational choices.

The third porosity system: understanding the role of hidden pore systems in well-test interpretation in carbonates

Well testing is a critical part of any evaluation of a carbonate reservoir discovery. Well-test interpretation in carbonate reservoirs poses additional challenges to those normally faced in the interpretation process in clastic reservoirs. The range of different boundary and crossflow relationships that are generated during well testing by the complex porosity systems are often poorly quantified and understood. The volume over which the pressure response is effective is also a source of great uncertainty and could be critical at the exploration/appraisal stage in any project. In this paper, which describes a generic modelling approach, we consider carbonate reservoirs which contain three pore sytems (or porosity types): (1) microporosity (end-member) with low permeability and high porosity; (2) macroporosity (end-member) with high permeability and high porosity; and (3) fracture porosity with high permeability and low porosity. These occur in various nested geometrical distributions and varying contrasts. The observed well-test responses (i.e. fracture flow, fracture–matrix interactions) tend to ‘obscure’ one of these systems when compared with theoretical models. Micro- (meso-) and macroporosity can merge into a single matrix porosity system where the permeability contrasts are not great and the correlation lengths short (which can often be the case in carbonates). Macroporosity can also appear in well testing to ‘merge’ with the fracture response, i.e. the contributions of flow in the fractures and (high-permeability) porous matrix are indistinguishable. As a result of the homogenizing attributes of pressure dissipation away from the well, it is not generally possible to see the effects of a ‘triple-porosity’ response (i.e. where three different pore systems have a separate and identifiable signature on the well-test response) and a classical double-porosity response in the well test, despite three different pore systems being present, is possible. The apparent double-porosity response, which might obscure a triple-porosity system, therefore needs careful interpretation in order to attribute the appropriate properties during reservoir characterization in carbonates. In this work we use ‘geological’ well testing (i.e. well testing through numerical simulation of hypothetical geological models) to systematically analyse the effects of microporosity, macroporosity and fracture porosity on pressure dissipation and their apparent homogenization. While recent studies have proposed that a triple-porosity system should result in a ‘W-shaped’ response, we do not observe this behaviour in our simulations, although we specifically designed our geological models with a triple-porosity system. Instead we observe how macroporosity merges with the fractures or micro- and macroporosity merge, creating a ‘sub-dominant’ matrix or a ‘dominant’ fracture system, respectively and follow a traditional ‘V-shaped’ double-porosity response.

Application of probe permeametry to the prediction of two-phase flow performance in laminated sandstones (lower Brent Group, North Sea)

Abstract The Rannoch Formation (lower Brent Group, North Sea) is an important laminated, oil-bearing reservoir in the northern North Sea. Recent work has shown that, at the estimated field frontal advance rates for the Rannoch Formation, capillary effects in laminated sandstones might significantly affect the two-phase (oil and water) flow characteristics. Previous published reservoir simulation models of the Rannoch have not accounted for this. Newly acquired probe permeameter measurements have been used to map the fine scale permeability structure and develop geologically reasonable effective properties. Permeability and capillary pressure data were combined for geologically meaningful groups of laminae to define dynamic pseudo-properties (absolute permeability, relative permeability and capillary pressure) by numerical simulation. A geological model for packages of lamination was then used to combine these lamina groups at a scale of the grid block. The flow performance of this geologically reasonable grid block (containing the laminated structure) is compared with that of ‘simple’ models based on conventional procedure — i.e. the arithmetic average (in a horizontal direction) or harmonic average (vertical) permeability and rock curves. At this scale, the formation is highly anisotropic using the more detailed model, with quite different flow characteristics in the horizontal and vertical directions. The simple homogeneous models show more isotropic recovery characteristics and give significantly higher recoveries for vertical displacements. From these findings, it is suggested that previous models of the Rannoch Formation should be modified to include the capillary effects associated with lamination. The procedure outlined here is referred to as the ‘geopseudo’ approach. The approach is widely applicable to laminated reservoirs.