e-Core – application to Heidrun, a north sea sandstone reservoir; a Numerical Rocks case study

The technology
Numerical Rocks was founded in 2004 to commercialise a pioneering technology, e-Core. The development of the technology was started 11 years ago at Statoil’s research centre in Trondheim, Norway and following a spin-off, Numerical Rocks have continued the product R&D work and are working towards the launch of the first commercial version of the e-Core software package, V 2.0. e-Core is currently being evaluated at several oil majors, Version 1.3 was launched in June 2008.

e-Core imports micro-CT images or generates 3D rock models based on thin sections from reservoir core plugs or drill cuttings. Petrophysical properties such as permeability, formation factor, elastic properties, and sonic velocities, are then calculated from the rock models or micro-CT images. Finally, multi phase fluid flow and calculation of transport properties, such as relative permeability and capillary pressure, are performed. The e-Core platform is essentially a Digital Rock Core Laboratory for calculation of petrophysical properties and calculation of multiphase flow parameters on computer generated rock models or imported micro-CT images.

The Heidrun field
Heidrun was discovered in the spring of 1985 and began production in October 1995. The field lies in blocks 6507/7 and 6507/8 on the Halten Bank, 175 kilometres off mid-Norway. Heidrun has been developed with a concrete hulled tension leg platform (TLP), which is moored to the seabed by 16 steel tethers. The field produces a mix of oil, gas and water, which is separated on the TLP.

Production strategy
The sandstone reservoir was deposited 170 million years ago in the Jurassic. Gas is found both as a cap and blended with the oil (associated gas). The oil reservoir beneath the gas cap measures 140 metres thick overall, and is underlain by an aquifer. When Heidrun was developed, estimates of its recoverable oil amounted to roughly 750 million barrels (120 million m ³). This figure has been increased to 1,100 million barrels (180 million m ³) thanks to improved recovery measures.

Daily oil production in 2005 averaged roughly 150,000 barrels. Heidrun is expected to have a producing life of about 35 years. Plans call for 75 wells, including 50 producers. A third of the field’s gas production is piped to Tjeldbergodden, while another third is sent through Åsgard Transport. The remaining third is injected into the gas cap.

Drilling of new wells and sidetracks in existing producers will continue beyond 2012. New production methods are under consideration, such as increased use of gas injection. Work is also under way on improving the drainage strategy and on positioning wells to increase reserves recovered per well. Repeated collection of seismic data (four dimensional surveying) is carried out to monitor and locate remaining oil resources.

The issue under consideration
Multiphase properties, such as relative permeability and capillary pressure, vary considerably

throughout a reservoir depending on the local pore structure and wettability. The description of the spatial variability of multiphase properties is not nearly as detailed as that for single phase properties. Measurements of multiphase properties are scarce and there is no easy way to account for variations of these in the field, due to different pore structures and/or wettability trends. Pore scale modelling offers exciting possibilities of bridging the gap between detailed descriptions of the variability of single phase properties and the lack thereof for multiphase properties. Recent studies have shown that a realistic characterization of the pore structure can be used to produce a model that accurately predicts both single and multiphase properties. In the present work, relative permeability and capillary pressure curves for different rock types in the Heidrun Fangst and Båt groups were determined by a pore-to-core up-scaling procedure. The procedure is illustrated in Fig. 1 – workflow. It involves three major elements: (i) thin section analysis, (ii) geologically based reconstruction of the rock type, and (iii) network modelling of the relevant displacement processes.

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Figure 1. Micro-CT image (left) and process based model (PBM) (right) for a heterogeneous North Sea reservoir sandstone, indicating pore space (black), clay (dark gray), quartz (gray), feldspar (lighter gray) and carbonate cement (light gray). The side length of the images is 2.68 mm and the voxel resolution is 2.62 m m.

The case study process

A geologically-based reconstruction technique was applied to generate virtual rock models of complex sandstone lithofacies (bayfill setting) in Heidrun. The samples were heterogeneous due to complex diagenetic alterations, i.e., the formation of authigenic clay minerals (9%) and patchy carbonate cementation (7-15%).

The reservoir rock samples had an average grain-size diameter between 25 µm and 200 µm, a porosity f of 0.23 to 0.28 and a permeability range between 0.1 and 1 Darcy. A mosaic of 256 SEM images taken from a thin section was used to extract the input parameters for the geologically based reconstruction of the sample.

High-resolution micro-CT images were acquired for one sample of the rock type for comparison with the process-based model (PBM). The resolution of the micro-CT data was 2.62 µm for an extracted sample size of 10 mm in diameter. Cross-sections of the micro-CT image, and a PBM reconstructed sample were compared. Both samples were voxel based with a size of 512 3 and a resolution of 2.62 µm. Important effective material and petrophysical properties were calculated and compared for these two models.

Extracting the pore network

The connectivity of the pore network was determined by extracting the skeleton of the pore space by an ultimate dilation of the grains followed by detailed measurements along the entire ‘skeleton’ network to acquire size, volume and shape for every pore body and pore throat.

Multiphase flow simulations

Constitutive relationships, such as capillary pressure and relative permeability curves, were determined by simulating two-phase displacements (e.g., primary drainage, waterflood, secondary drainage) on the pore network representation of the reconstructed rocks. In all the multiphase flow simulations, it was assumed that capillary forces dominate at the pore scale.

SCAL data for comparison

Available Special Core Analysis for the rock type includes Amott wettability measurements, centrifuge measured oil/water relative permeabilities and steady state relative permeabilities. The Amott wettability index, I wo, ranged from 0.1 to 0.8, with an average value of 0.5 .

The results

‘Recommended’ water-oil relative permeability and imbibition capillary pressure curves for each rock type at the suggested wettability for each formation were determined.

Future of the field
Substantial efforts are being devoted to improving the expected level of recovery from Heidrun’s reservoirs by up to 410 million barrels (65 million m ³). This work includes a commitment to adapting and applying new drilling and completion technologies.

DRUN FIELD LIES IN

The potential of the e-Core technology
The case study data demonstrates the potential of combining computer-generated rock models with numerical calculations to predict rock and flow properties for reservoir rocks over a wide range of porosities. The technology offers the possibility of bridging the gap that exists today between detailed geological reservoir models and the lack of associated reservoir parameters; i.e., relative permeabilities and capillary pressure curves.

CEO Ivar Erdal explains “We see an additional pivotal role for e-Core later in a reservoir's lifecycle when SCAL data needs verification, further analysis, and interpretation. It is at this point that e-Core’s time advantages become indisputable…With a wide range of technical service products available to new and existing clients, e-Core data can be supplied within much shorter time frames than conventional core analysis”.

e-Core offers operators an alternative to time consuming laboratory experiments by going from thin sections to flow parameters in days. Understanding of the pore structure and physics of reservoir rocks is greatly improved, as is its effect on reservoir properties. The new technology allows sensitivity testing of reservoir parameters such as wettability and irreducible water saturation, and population of reservoir parameters to the reservoir simulation models improves decision making.

“Our aim is to develop geological statistics of multi phase flow properties”, Erdal said, “which will make it possible to account for variations in flow properties with the same level of detail as used for static properties”. He adds, “everything in oil recovery is integrated – we plan to secure e-Core’s position in the workflow ”.

The Company
Numerical Rocks celebrated its 3 rd anniversary in December 2007 after being spun-off from Norwegian oil giant Statoil (now StatoilHydro) in 2004. Started by a senior reservoir engineer, Pål-Eric Øren and a senior geologist, Stig Bakke, today the company has some 24 employees representing 8 nationalities. Ivar Erdal joined as CEO in 2005 after running a traditional core laboratory services company. Numerical Rocks is a ‘daughter-company’ to StatoilHydro who continue to own the majority shares with the founders, senior managers and employees owning the rest.