Low Salinity waterflooding is an emerging Enhanced Oil Recovery technique in which the salinity of the injected water is controlled to improve oil recovery vs. conventional, higher salinity waterflooding. The objective of this work is the evaluation of low salinity water injection as EOR process in an on-shore field in West Africa. The field is heavily faulted and highly heterogeneous. The reservoir fluid is light crude oil; very different productive behaviours are present in the field. An experimental work was performed to verify the effectiveness of the process and make deeper investigation about the chemical and physical mechanisms involved in low salinity water injection. Core flooding experiments on reservoir porous media were carried out, giving promising results in terms of matrix additional oil recovery with low salinity waterflood. Furthermore, a simulation work to predict the benefits in the field was executed. Core experiments were reproduced using a wettability change model to obtain low salinity water parameters, the salt-dependent relative permeability curves. The process was scaled up to a fine sector model, calibrated on historical production data, representing the area of interest for low salinity water pilot. Simulations of low salinity water injection were run in different forecast scenarios and additional recovery was compared with sea water injection. In order to evaluate the global effect of low salinity water injection as EOR process, all the aspects were taken into consideration, decrease in residual oil saturation, permeability reduction, expected sweep efficiency on effective reservoir matrix volume. The experimental and simulation results were used for an economical feasibility study for a desalination plant in the field to reduce the salinity of current injected sea water.
Enhanced Oil Recovery through CO 2 injection allows to reach a twofold valuable objective, increasing the amount of crude oil extracted from an oil field while mitigating the contribution of emissions to global warming. Such an intervention is planned in an oil production field in Sicily (Italy) by employing a CO 2 stream already available from an oil refinery located near to the field. The oil is currently produced through a pump artificial lift and fluidized by a fluidizing stream injected at the bottom of the well, due to its characteristics: it is an heavy, asphaltene-rich oil. Just these characteristics worried about the possibility that injected CO 2 could destabilize the asphaltene fraction, leading to the formation a of a sludge or a solid phase, that would plug the formation pores and, ultimately, decrease injectivity and productivity. In order to assess this risk, the eni in-house-developed asphaltene deposition model was employed to investigate various conditions close to the expected operating conditions. At the same time, a lab activity was undertaken, in order to have an experimental check at least on a narrow range of conditions. Results of these activities showed that no deposition happens in the expected range of operating conditions. A description of both simulation and experimental activities is reported, in order to show how it is possible to assess the risk of asphaltene deposition before operations potentially dangerous to the field productivity. Case studyThe field object of this study lies in south-east Sicily and has been discovered in the early '80. Heavy oil mineralization (API gravity around 10°) has been detected both into a lower dolomites formation (300 cp viscosity at reservoir conditions) and into limestones of the overlying formation (40 cp viscosity at reservoir conditions). The reservoir depth is more than 3200 mssl, corresponding to an initial pressure and temperature of 326.5 bara (@3200 m) and 102 °C, respectively. The lowermost formation has been put in production in September 1990 with the drilling of five wells, one of which has been sidetracked in 2003. The uppermost formation has never been put in production. In order to optimize the investment, a study has been performed to evaluate carbon-dioxide injection scenarios for the field (both formations), which could be implemented. The reservoir is characterized by the following geological features: complex and interacting processes of initial facies deposition, progressive faulting/fracturing and several diagenetic phases of secondary porosity creation; oil migration through the fracture system only. The relevant conceptual model can be summarized by the existence of two main flow components: one vertical (fracture corridors) and one layer-driven (pseudo-matrix system, i.e. an interaction between macro-meso porous system and diffuse fractures). In order to improve the oil recovery factor, CO 2 injection was proposed, as it is possible to have a CO 2 stream from a refinery plant located near the field. The best CO 2 injecti...
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