Restoration of carbonate reservoir core material for special core analysis has been debated in the literature for some time. An important goal of core restoration is to reproduce initial reservoir wetting properties because wettability dictates important reservoir parameters, such as capillary pressure and relative permeability of oil and water. It has previously been found that acidic polar components in crude oil dictate the wetting properties in carbonate core material. In this paper, the effects on chalk wettability from crude oil flooding, core aging, and mild core cleaning were investigated experimentally. The experimental results confirmed that adsorption of acidic polar components is an instantaneous process and that a dynamic equilibrium was achieved with a specific adsorption capacity of the initially very water-wet chalk surface. The crude oil flooding reduced the water-wet surface area. Core aging for 2 weeks at the test temperature reduced the water-wet surface area even further, which appeared to be closer to a thermodynamic equilibrium. Spontaneous imbibition tests confirmed mixed-wet conditions, regardless of aging or not. A second oil flooding was performed on a mildly cleaned, initially mixed-wet chalk core. The dynamic adsorption equilibrium of polar organic components was now drastically reduced. On the basis of the results from this experimental study, the wetting in outcrop chalk is dependent upon the amount of crude oil allowed to contact the rock surface and the time period of contact, i.e., the aging period. A core restoration procedure involving mild core cleaning and a controlled small volume of crude oil injection could be a more optimal core restoration procedure for reservoir chalk and limestone cores.

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Forward modelling was applied to correct formation pressures measured while drilling on a wiper run for the effects of supercharging. Supercharging is increased sand face pressure caused by drilling fluid filtrate leak-off. The study is carried on one of the well-known carbonate reservoir of the North Sea. This reservoirs, in general, exhibit good porosity; however they have poor permeability because of small pores. Pressure variations near the wellbore are primarily influenced by near-wellbore drilling fluid filtrate invasion and filter-cake formation. In general, the lower the sand-face permeability, the higher the variations. Considerable progress has been made towards understanding how filter cake forms and how it influences the near-wellbore pressure stability. Available analytical and numerical models in generally focus on dealing with "initial spurt loss" only, remaining transition and dynamic periods are assumed to be negligible. However the dynamic period, which incorporates possible erosion, plastering, clogging, and other implications, can be modelled if the sand-face (near-wellbore) is exposed to controllable and quantifiable influences. The greater number of planned quantifiable influences, the better the forward modelling. The coupled filter cake growth and formation pressure model incorporates; the geometry of the well and the drilling assembly, the time sequence of the drilling or wiper operation, and drilling fluid and formation properties. A total of 52 formation pressures were acquired during wiper run, across several thousands of horizontal section drilled in to the chalk reservoir. Pressure tests were evenly distributed to evaluate possible faults, depletion, and pressure barriers, and, more importantly, to calibrate the flow model for the future drilling campaigns. Tests acquired at same depth interval with different circulation rates were used as primary the calibration point for the forward model calibration. A secondary calibration point was obtained by from two consecutive tests, during which first circulation was kept off, and then turned on. These simulations are also applicable to exploring system behavior and responses when planning and executing the job, assessing the feasibility and suitability of the methodology to check that assumptions are satisfied, and building some expectations about the likely measured pressures and their behavior over time.

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Summary In preferentially oil-wet porous media, laboratory waterflooding experiments are prone to capillary end effects. The wetting phase (oil) will tend to accumulate at the outlet where the capillary pressure is zero and leave a highly remaining-oil saturation at steady state (defined by a stable pressure drop and a zero oil-production rate) compared to the residual-oil saturation. Andersen et al. (2017c) derived analytical solutions describing how the capillary pressure and relative permeability of water (the injected phase) could be determined on the basis of pressure drop and average saturation at steady states obtained at different water-injection rates. Plotting these values against inverse rate reveals linear trends at high rates, with slopes and intercepts that directly quantify the saturation functions in the range of negative capillary pressures. The method is similar to the Gupta and Maloney (2016) intercept theory but quantifies entire functions rather than a single point and provides the trends also at low rates, thus using all the information. Our aim is to demonstrate how pressure drop and oil production at steady state for different water-injection rates can be used to derive relative permeability and capillary pressure from waterflooding. This is done in three ways. First, synthetic transient waterflooding tests are generated (using a core-scale simulator), applying the same saturation-function correlations as assumed in the analytical solution. Then, more-general correlations are assumed when generating the synthetic data. This is to test the robustness of the analytical solution in producing functions similar to the “true” ones. Finally, we perform a waterflooding experiment in the laboratory on a high-permeability (3 darcies) Bentheimer sandstone core, altered to an oil-wet state. Forced imbibition was started at a rate of 0.4 pore volumes (PV) per day, which was increased stepwise after approaching a steady state. Twelve rates were applied, differing overall by a factor of ≈1,000 to yield states governed by capillary forces and advective forces. The results were interpreted using both full history matching of the transient data and matching of the steady-state data with the analytical solution. The experimental procedure and model demonstrate that only water relative permeability and capillary pressure determine the steady state during waterflooding, and hence can be estimated accurately. The analytical solution could simultaneously match the trends and magnitude of a steady-state pressure drop and production with injection rate to give an estimation of the saturation functions. The estimated saturation functions from the analytical solution agreed well with the estimates from full history matching.