Real-Time Measurements of Spontaneous Potential for Inflow Monitoring in Intelligent Wells
- Matthew David Jackson (Imperial College) | Murtaza Gulamali (Imperial College) | Eli Leinov (Imperial College) | Jon Saunders (Imperial College) | Jan Vinogradov (Imperial College)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 19-22 September, Florence, Italy
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 6.5.2 Water use, produced water discharge and disposal, 4.3.4 Scale, 5.1.1 Exploration, Development, Structural Geology, 2.3 Completion Monitoring Systems/Intelligent Wells, 5.4.2 Gas Injection Methods, 4.2.3 Materials and Corrosion, 4.1.2 Separation and Treating, 1.11 Drilling Fluids and Materials, 5.1 Reservoir Characterisation, 5.2 Reservoir Fluid Dynamics, 4.1.5 Processing Equipment, 5.4.6 Thermal Methods, 5.4.1 Waterflooding, 5.6.1 Open hole/cased hole log analysis, 5.3.4 Reduction of Residual Oil Saturation, 1.2.3 Rock properties
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Spontaneous potential (SP) is routinely measured using wireline tools during reservoir characterization. However, SP signals are also generated during hydrocarbon production, because of gradients in the water phase pressure (relative to hydrostatic), chemical composition and temperature. We suggest that measurements of SP during production, using electrodes permanently installed downhole, could be used to detect water encroaching on a well while it is several tens to hundreds of meters away. We simulate numerically 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 fluid potential, salinity and temperature, to gradients in electrical potential. The values of these coupling coefficients at reservoir conditions are poorly constrained.
We demonstrate that the SP signal peaks at the location of the moving waterfront, where there are steep gradients in water saturation and salinity. The signal decays with distance from the front, typically over several tens to hundreds of meters; hence the encroaching water can be detected before it arrives at the well. The SP signal at the well is dominated by the electrokinetic and electrochemical components arising from gradients in fluid potential and salinity. Larger signals will be obtained in low permeability reservoirs produced at high rate, saturated with formation brine of low salinity, or with brine of a very different salinity from that injected. Inversion of the measured signals in conjunction with normally available reservoir data could be used to determine the water saturation in the vicinity of the well, and to regulate flow into the well using control valves in order to maintain or increase oil production and delay or prevent water production.
Measurements of spontaneous potential (SP), logged prior to production or injection using wireline tools, have long been used to characterize reservoir properties such as permeable bed boundaries and formation brine resistivity (e.g. Schlumberger et al., 1934; Mounce and Rust, 1944; Doll, 1948; Hallenburg, 1971). The SP signal recorded during logging is primarily electrochemical (EC) in origin; contrasts in chemical composition between formation and drilling fluids give rise to so-called ‘junction' or ‘diffusion' potentials in permeable beds, while the exclusion of (typically negative) ions from the pore-space of fine-grained rocks such as mudstones and shales results in so-called ‘membrane' potentials. Together, these EC potentials typically dominate the SP log, although in some cases, electrokinetic (EK or streaming) potentials, which arise from gradients in fluid pressure (relative to hydrostatic), may also contribute (e.g. Mounce and Rust, 1944; Doll, 1948; Wyllie, 1949; 1951; Wyllie et al., 1953). However, gradients in fluid pressure, in chemical composition and in temperature, will also be present during hydrocarbon production, particularly during water- or steamflooding when colder or hotter water, of a different chemical composition to the formation brine, is injected into the reservoir. Consequently, SP signals will be observed during production. The aim of this paper is to characterize the likely magnitude of these SP signals, and determine whether their measurement, using electrodes permanently installed downhole, may be of use in monitoring fluid flow.
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