First Break - Volume 20, Issue 4, 2002

In this extensive review Nigel J. P. Smith of the British Geological Survey offers a thought-provoking assessment of hydrogen’s potential as the ultimate environmentally friendly fuel and finds plenty of reasons why the geoscience community and energy specialists should be putting hydrogen high on their R&D priorities.

New Zealand has a relatively small oil and gas industry built around the giant Maui Field and the downstream industries developed in tandem with it. With the depletion of this field approaching, there have been some encouraging new exploration successes, and emerging attention to long-neglected frontiers including a very extensive deep-water territory. How effectively will a small country distant from services and markets be able to attain the scale of investment required to realise the full potential of its endowment of petroleum resources? In this paper presented at the biennial New Zealand Petroleum Conference in February, J. Mac Beggs*, principal of GeoSphere, attempts to answer some of these questions in a summary of New Zealand’s hydrocarbons experience over the past two years.

Prof. Anton Ziolkowski, Bruce Hobbs and David Wright from the Department of Geology and Geophysics, University of Edinburgh present results from a transient electromagnetic experiment claimed to be the first to detect hydrocarbons and to monitor their movement within a reservoir. The method is illustrated with data obtained from two Multi-channel Transient ElectroMagnetic (MTEM) surveys carried out in 1994 and 1996 over an underground gas storage reservoir at St. Illiers la Ville in France.

The adaptation of 3D techniques to very high and ultra high (multi-kHz) frequency marine seismic investigations is progressing steadily. In recent years, the Renard Centre of Marine Geology (University of Gent) has scaled down the shallow marine 3D method to very high resolutions, thereby entering the world of small-scale geological structures (Henriet et al. 1992). VHR 3D seismic data were acquired in a modest and cost-effective way, using a compact field system with close streamer and channel spacing. Despite good results, the data were not of optimum quality due to a number of technical shortcomings (low sampling rate, positioning restrictions, coverage difficulties). In order to further increase the resolution, adaptation and optimization of the 3D acquisition method were required, taking into account recent developments in positioning and data sampling techniques. In doing so, the seismic strategy must be chosen as a function of the geological target, sampling laws, the desired resolution and the acquisition and processing costs. Based on past 3D experience, a new compact 3D acquisition system was developed in the framework of the EC MAST3 Project ‘Very high resolution marine 3D seismic method for detailed site investigation – VHR3D’. The acquisition array is flexible, which allows it to be tailored to specific site characteristics. The system is designed for studies in shallow water (< 30 m), providing limited penetration (< 50 m bsf) and is aimed at target sites of limited areal extent (approximately 100-100 m2). The desired resolution (both horizontal and vertical) is in the decimetre range.

A multitude of factors control the flow of fluids through fracture systems in hydrocarbon reservoirs. For example, closed fractures i.e. (deformation bands) may seal or baffle hydrocarbon flow (Fossen & Hesthammer 1998 ) whereas open fractures are considered to be conductive to hydrocarbon flow. However, fracture surface roughness has much control upon fluid flow through open fractures and is demonstrated to effect significant departures from the Cubic Law for predicting flow through fracture apertures (Isakov et al. 2001a). Such considerations are crucial in igneous and metamorphic reservoir rocks since fractures in these rocks may form the only significant pathways for fluid migration (Isakov et al. 2001b) (Fig. 1). We present a five-stage approach for the full characterization of rough fracture surfaces in rocks and their incorporation into reservoir flow models. Each stage is aided by in-house developed software (Fig. 2). 1. Optical profiling of resin replicas of rough fracture surfaces in a suite of rocks (Fig. 2), using OPTPROF (Isakov et al. 2001a; Ogilvie et al. 2001a), 2. Parameterization and statistical analysis of the surfaces using PARAFRAC software (Isakov et al. 2001c), 3. Creation of synthetic fractures tuned to the properties of the real rock fractures using SYNFRAC software (Isakov et al. 2001c), 4. Experimental investigation of fluid flows (Ogilvie et al. 2001b). 5. Computational fluid flow modelling in 2D cross sections of fractures [boundary conditions from 1 to 4]. The objective is to replace the parallel-plate model assumed in larger multi-fracture models with a model that fully accounts for rough fractures at a range of scales.