A high level screening has been performed of UKCS oil fields to identify the most likely LSWF candidates utilising screening criteria with a focus on kaolinite clay content. The screening results suggest that approximately 57% of the fields have 6 % or higher kaolinite clay content. Of these fields 26 % were water-wet and 74 % were mixed-wet in terms of wettability. This suggests that a significant number of fields would fall within the eligibility for consideration of LSWF EOR although their suitability will depend on field maturity (current recovery factor and facilities constraints). The difficulty in applying LSWF in tertiary mode unlike secondary mode, is in obtaining a reasonable prediction of how the reservoir is likely to respond. The question of core availability and quality has been raised in a number of studies in terms of LSWF and electrical property testing. We propose a methodology which can be applied to compensate for the lack of usable core based on petrophysical log response. The logs can be utilised to determine the clay types present (including fractions) from which the cation exchange capacity can be calculated. Selected compositions from anonymised field data from core was used to provide quality control the log derived values. The most likely recovery mechanism, multi-component ion exchange (MIE), requires the input of key electrical properties into the models (cation exchange capacity, reactive surface area, activation energy and mineral fraction) in order to predict the response of the reservoir to LSWF. In this study the effect of clay content on the reservoir response was modelled indirectly by altering the cation exchange capacity relative to the clay mineral fraction present in the reservoir to determine its effect. Utilising a mechanistic modelling approach, homogeneous Cartesian models were run in the compositional finite difference reservoir simulator GEM to assess the impact on oil recovery. The simulated coreflood tests reveal that under secondary LSWF recovery was 68.4 % compared to 63.6 % for formation water (high salinity). The conservative nature of the relative permeability curves limited the incremental recovery. An analysis of the tertiary recovery utilising a coreflood based on Fjelde et al. (2012) revealed that cation exchange impacts the predicted recovery by up to 2.65 % OOIP for the range of 5 - 30 % clay content. Given that the recovery under tertiary conditions is considered in the literature to be between 6 and 12 %, this is significant and highlights that if idealised data is selected rather than real field data, then significant potential exists to under or over-predict the incremental recovery.

Low salinity waterflooding (LSWF), versus high salinity waterflooding (HSWF) has been the focus of significant research at various centres around the world, yet there is still considerable debate over the exact mechanism that provides incremental oil recovery. The use of the LSWF technique is not widespread in the United Kingdom continental shelf (UKCS). However, it has been announced that the Clair Ridge development will deploy low salinity waterflooding (LSWF) in secondary mode from the start of field life, and a number of companies are currently assessing the applicability of the technique through high level screening and core flooding. Forecasting the potential oil recovery under LSWF is heavily influenced by the simulation technique that is used. Presently the most widely discussed approach is the use of a weighting table with relative permeabilities representing the high and low salinity cases. As the grid block falls below threshold salinity, the simulator utilises the weighting table to assign an interpolated value of salinity. This value of salinity is utilised to represent a change in wettability. While this approach approximates the net effect of LSWF, it does not capture the oil/rock/brine interaction. This study examines the modelling approach to LSWF utilising an in-house generic Forties Palaeocene model in CMG's STARS simulator. The conventional approach of modelling LSWF using high and low salinity relative permeabilities is compared to the latest Multi-component Ion Exchange (MIE) methods by numerical simulation to assess the impact on incremental oil recovery. A sensitivity analysis is then carried out on the effects of specific parameters on incremental oil recovery, utilising published data from fields in the Forties Palaeocene fan system. A discussion is provided. The impact on secondary recovery was accessed with respect to wettability alteration; injection salinity (LSWF versus HSWF); oil viscosity and aquifer influx. The application of LSWF in secondary mode to the Forties Palaeocene Sandstones was found to be favourable for the case of mixed-wet reservoirs.

One main mechanism for Low Salinity Water Flooding (LSWF) is the change of reservoir wettability from oil or mixed wet to more and more water wet, resulting in higher oil recovery, in the process. If, however, the injected water is switched back to sea water due to economic or operational issues such as combining LSWF with other processes such as miscible flooding, polymer flooding, or foam injection, will a wettability reversal occur thereby halting the improvement in the oil recovery? This paper is based on the belief that the wettability change is permanent. It accordingly presents a novel technique to modelling irreversible wettability during LSWF and demonstrates its effect on the oil recovery. Wettability alteration is modelled by interpolation between multiple sets of relative permeability (Kr) curves corresponding to different wettability states of the reservoir. The interpolating parameter used is dependent on the reservoir lithology and the mechanism modelled. In carbonate reservoirs, the mechanism for wettability alteration is still under investigation, but one theory is that anion exchange with decreasing SO4−− concentration in the injected brine changes the wettability to increased water wetness and improves the oil recovery. Chemical reactions could be used to represent this ion exchange and the resulting wettability alteration. These reactions are reversible, in nature, and any subsequent increase in the salinity of the injected water leads to wettability reversal. To model irreversible wettability, a hypothetical aqueous component (WAT_INT) is introduced. This component, having the same properties as water, is generated from water by a reaction catalyzed by a salinity component (Sulphate) and serves as a tracer that tracks the salinity. WATER + SULPHATE → WAT _ INT + SULPHATE This reaction is modeled as a partial equilibrium reaction that deviates from equilibrium. This causes the reaction rate to be directly proportional to the difference between the sulphate concentration and its specified equilibrium composition. The reaction rate increases when the sulphate concentration decreases below this equilibrium concentration, and it does not occur when the sulfate concentration is higher than this equilibrium concentration. Setting the equilibrium sulphate concentration to be very close to, but slightly higher than that in the low salinity water ensures that the reaction occurs only when the low salinity slug passes through. When the injected fluid is switched to the sea water having higher salinity, thisreaction ceases to occur. This results in the maximum concentration of this component when the low salinity slug is injected. An irreversible adsorption isotherm is modeled for the new WAT_INT component, and its adsorbed phase concentration is used as the interpolating parameter. This parameter reaches its maximum value when the low salinity slug passes through. The irreversible adsorption isotherm ensures that it remains at its maximum value when the injection water is switched to sea water/formation water. It also ensures that the wettability alteration is irreversible and relative permeability does not switch back to a more mixed/oil wet value. Operators typically inject LSW continuously to prevent a wettability reversal from occurring if the composition of the injected water is altered. This study, however, presents the idea that reversal of wettability may not occur, and potentially allowing for the injection of formation brine/sea water after a slug of LSW. In addition, this paper presents a novel technique to model the concept of irreversible wettability during LSWF.

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In the United Kingdom Continental Shelf (UKCS), a significant heavy oil prize of 9 billion barrels has been previously identified, but not fully developed. In the shallow unconsolidated Eocene reservoirs of Quads3 and 9, just under 3 billion barrels lie in the discovered, but undeveloped fields, of Bentley and Bressay. Discovered in the 1970s, they remain undeveloped due to the various technology challenges associated with heavy oil offshore and the presence of a basal aquifer. The Eocene reservoirs represent significant challenges to recovery due to the unconsolidated nature of the hydrocarbon bearing layers. The traditional view has been that such a nature represents a risk to successful recovery due to sand mobility; reservoir and near wellbore compaction; wormhole formation; and injectivity issues. We propose improving the ultimate oil recovery by a combination of aquifer water production and compaction drive. By interpreting public domain data from well logs, the range of geomechanical properties of Eocene sands have been determined. A novel approach to producing the heavy oil unconsolidated reservoirs of the UKCS is proposed by producing the aquifer via dedicated water producers situated close to the oil-water contact. The location was determined by sensitivity analysis of water producer location and production rates. By locating water producers at the OWC with a production rate of 20,000 bbls/day of fluids, the incremental recovery at the end of simulation is increased by 4.1% OOIP of the total modelrelative to the ‘no aquifer production’, casesuggesting a significant increase in recovery can be achieved by producing the aquifer. A rate of 30,000 bbld/day located at the OWC was found to increase incremental recovery by 5.8 %OOIP relative to the ‘no aquifer case’. In all cases, as the reservoir fluid pressure is reduced, oil recovery increases via compaction and reduced water influx into the oil leg. This reduced pressure leads to a higher tendency towards reservoir compaction which is expressed as a change in mean effective stress and porosity reduction.