As brine composition profoundly influences reservoir wettability and hence microscopic sweep, careful design of injection brine is part of a strategy to improve on oil production in existing and future water flooding projects, in both sandstone and carbonate reservoirs and in combination with follow-up EOR projects. The following results were found:Formation water with higher salinity level correlates to a higher content of multivalent cations. This causes the (sandstone) reservoir wettability to be more oilwet;The field-observed temporary reduction in watercut during breakthrough of so-called "Designer Waterflood" water in a Middle Eastern sandstone reservoir with highly saline formation water was interpreted to be caused by an oil bank ahead of the slug of injected water;The oil bank results from improved sweep by wettability modification to more waterwet state. The interpretation was confirmed by laboratory experiments;Experiments in limestone core plugs demonstrate similar wettability modification, if the sulphate ion content in the invading brine is far in excess of the calcium ion content. Based on these results the following conclusions were drawn:Designer Waterflooding may increase the Ultimate Recovery of oil by at least a few percent;There is scope for further improvement in oil production by flood front stabilization by adding low concentration polymer to the optimised slug;If future EOR projects are planned, a Designer Waterflooding pre-flush is recommended to obtain more favourable oil desaturation profiles and savings on polymer costs;In case of seawater injection into reservoirs with formation water of low salinity level, removal of multivalent cations from the seawater should be considered to avoid the potential risk that the reservoir becomes more oilwet, which will result in reduced sweep. Introduction In the past decade, injection of brines with well-selected ionic composition in sandstone and carbonate reservoirs has been developed into an emerging IOR technology, aiming for improved microscopic sweep efficiency with reduction in remaining oil saturation as result (Tang and Morrow, 1997, 1999, 2002; Maas et al, 2001; Webb et al, 2003 and McGuire et al, 2005). Recently, some evidence of the beneficial impact of injection of brines with well-selected ionic composition from historical field data was published (Robertson, 2007). In-house research on this subject covered a broad range of disciplines, including core flow and Amott imbibition experiments, Colloid Chemistry and Petroleum Engineering. In this paper we describe the major results from our study and indicate where this technology can be most favourably applied.

Modifying the chemistry of injection water yields improved wettability behavior on carbonate rock surfaces. Previous work has focused on demonstrating the effect of modified brine formulation on particular carbonate samples. Here the results of a more general screening study consisting of Amott spontaneous imbibition experiments on the samples from oil-bearing zones and from outcrops of different carbonate formations are reported. Tertiary incremental oil production due to increased water-wetness was observed upon transition to brine of lower ionic strength. Additional oil recovery from the spontaneous imbibition tests ranged from 4 to 20% of OIIP (Oil Initially In Place), reflecting a large variability in the response and indicating a high complexity of the mechanism(s). Consistent with numerous published reports, Stevns Klint outcrop chalk samples were a clear exception and exhibited increased oil recovery with increasing sulfate ion concentration. These did not respond to lowering the salinity of the imbibing brine. Tertiary oil recovery from samples containing evaporites occurred simultaneously with dissolution of salt minerals, as evident from brine analysis. However, incremental oil recovery in the same range was measured for samples without evaporites but from the same geological formation. Hence, mineral dissolution as a mechanism for enhanced oil recovery could not be confirmed. The results show that injection of low salinity brine into carbonate reservoirs has potential as an EOR technology. However, additional research is needed to improve the understanding of the underlying chemical and physical mechanisms and improve a priori predictability.

Advancing production from the Groningen gas field to full depletion generates substantial, field-scale deformation, and surface subsidence. Quantifying associated risk requires understanding physical processes in the subsurface, in particular those related to deformation of the Permian sandstone reservoir. Here, we report the results of a large experimental study, using fresh core material taken from the center of the field. By subjecting the material to depletion and slight unloading, complemented with a range of rock property measurements, we determine what rock physical properties control production-induced compaction in the material. Our results show that, although a large part of the deformation can be explained by classical linear poroelasticity, the contribution of inelastic (permanent) deformation is also significant. In fact, it increases with progressing pressure depletion, i.e. with increasing production. Utilizing univariate and multivariate statistical methods, we explain the additional inelastic deformation by direct effects of porosity, packing, and mineral composition. These proxies are in turn related to the depositional setting of the Permian reservoir. Our findings suggest that field-scale subsidence may not only be related to the often-used rock porosity, but also to packing, and composition, hence the local depositional environment. This motivates alternative assessments of human-induced mechanical effects in sedimentary systems.

a b s t r a c tGeological storage of CO 2 in clastic reservoirs is expected to have a variety of coupled chemical-mechanical effects, which may damage the overlying caprock and/or the near-wellbore area. We performed conventional triaxial creep experiments, combined with fluid flow-through experiments (brine and CO 2 -rich brine) on samples of poorly consolidated, carbonate-and quartz-cemented Captain Sandstone from the Goldeneye field. The main goal was to study the effect of carbonate cement dissolution on mechanical and ultrasonic properties, as well as on the failure strength of the material. Our experiments were performed under in situ reservoir conditions, mimicking reservoir depletion and injection. Although total dissolution of calcite was observed, and confirmed by microstructural and fluid chemistry analyses, it did not affect the rock mechanical properties, nor was any measurable rock strength reduction observed. This is most likely because grain-to-grain contacts were sufficiently quartz-cemented and quartz is not affected by CO 2 -rich brine. Failure data for the Captain Sandstone showed that the stress conditions under which CO 2 injection will take place remain far away from the failure envelope. Therefore, CO 2 injection is not expected to lead to shear failure of the reservoir. However, longer-term chemical reactions, involving minerals such as feldspar, clays or micas, still require more research.

The storage of carbon dioxide (CO 2 ) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO 2 SINK (CO 2 Storage by Injection into a saline aquifer at Ketzin) project is a research and development (R&D) project, mainly supported by the European Commission, the German Federal Ministry of Education and Research, and the German Federal Ministry of Economics and Technology, targeted at developing an in-situ laboratory for CO 2 storage.The preparatory phase of the project involved a baseline geological-site exploration and the drilling of one injection and two observation wells, as well as the acquisition of a geophysical baseline and geochemical monitoring, in Ketzin, located near Berlin. The target saline aquifer is the lithologically heterogeneous Triassic Stuttgart formation, situated at approximately 630-to 710-m (2,070-to 2,330-ft) depth. A comprehensive borehole-logging program was performed consisting of routine well logging complemented with an enhanced logging program for one well that recorded nuclear-magnetic-resonance (NMR) and boreholeresistivity images, to characterize the storage formation better. A core analysis program carried out on reservoir rock and caprock included measurements of helium porosity, nitrogen permeability, and brine permeability at different pressure conditions.The saline aquifer at Ketzin shows a variable porosity/permeability distribution, which is related to grain size, facies variation, and rock cementation with values in the range from 5 to > 35% and 0.02 to > 5,000 md for porosity and permeability, respectively. On the basis of core analysis and logging data, an elemental loganalysis model for the target formation was established for all three wells. In addition, permeability was estimated using the Coates equation and compared with core data and NMR log-derived permeability, which seems to provide meaningful permeability estimates for the Ketzin reservoir. On the basis of the good core control that guided the petrophysical well-log interpretation in the first two CO 2 SINK wells, a porosity and permeability prediction by analogy for the third well is appropriate and applicable. The availability of cores was crucial for a sophisticated formation evaluation at borehole scale that characterizes the real subsurface conditions.