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Spontaneous Potentials in Hydrocarbon Reservoirs during Waterflooding: Application to Waterfront Monitoring

M. D. Jackson, M. Y. Gulamali, E. Leinov, J. H. Saunders, and J. Vinogradov
Department of Earth Science and Engineering, Imperial College, London, UK

Spontaneous potential (SP) is routinely measured using wireline tools during reservoir characterization [e.g. 1]. However, SP signals are also generated during hydrocarbon production, in response to gradients in the water phase (i) pressure (relative to hydrostatic), which gives rise to electrokinetic (EK) or streaming potentials, (ii) chemical composition, which gives rise to electrochemical (EC) potentials, and (iii) temperature, which gives rise to thermoelectric (TE) potentials. We use numerical modelling to investigate the likely magnitude of the SP in an oil reservoir during production, and suggest that measurements of SP, using electrodes permanently installed downhole, could be used to detect and monitor water encroaching on a well while it is several tens to hundreds of meters away. We simulate the SP generated during production from a single vertical well, with pressure support provided by water injection. We vary the production rate, and the temperature and salinity of the injected water, to vary the contribution of the different components of the SP signal. We also vary the values of the so-called ‘coupling coefficients’ which relate gradients in water phase pressure, salinity and temperature, to gradients in electrical potential.

These results suggest that waterfronts could be tracked and imaged using downhole measurements of SP at one or more production wells. In wells equipped with inflow control valves, this information would allow proactive control of inflow, to delay or prevent water breakthrough. However, the magnitude of the signal recorded at a well will depend upon a number of reservoir and production parameters, including production rate, reservoir permeability and permeability heterogeneity, formation brine salinity and temperature, and the coupling coefficients that relate gradients in water phase pressure (relative to hydrostatic), concentration and temperature, to gradients in electrical potential. Consequently, the SP signal will be specific to a given reservoir and production scenario. Moreover, the values of the coupling coefficients are still poorly understood. Future work will need to address three key issues. The first of these concerns the downhole hardware required to acquire SP data during production and transmit these data to surface. The second concerns interpretation of the measured signals for reservoir properties of interest. Our forward models demonstrate that SP signals at a well are sensitive to the location and geometry of an encroaching waterfront; the next step is to develop methods to determine the waterfront location and geometry from the measured signals in conjunction with other reservoir data. The third concerns the nature of the SP coupling coefficients; further laboratory work is required to characterize these at oilfield conditions. Finally, a field trial is required to confirm the modelling results.

 

AAPG Search and Discovery Article #120034©2012 AAPG Hedberg Conference Fundamental Controls on Flow in Carbonates, Saint-Cyr Sur Mer, Provence, France, July 8-13, 2012