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.
Knowing the wetting condition of a reservoir at an early stage is crucial for selecting optimum field-development options. Paying insufficient attention to the wetting condition (e.g., assuming water-wet behavior) may result in incorrect oil-in-place estimates and in unexpected dynamic behavior (e.g., under-waterflooding).A novel method is presented to determine the wettability of rocks from nuclear-magnetic-resonance (NMR) data. The method is based on the additional nuclear relaxation that fluids experience when in direct contact with the rock surface. Reduction of oil relaxation time away from its bulk value is generally known as a qualitative wettability indicator, assuming external factors to be negligible and/or invariant from one experiment to another. Through detailed modeling of the NMR response, this concept has been developed further to provide a quantitative wettability index. It is based on a model for the microscopic distribution of the crude oil and the wetting state of the rock at any given overall saturation. The method requires an NMR measurement on a sample containing two reservoir fluids (i.e., brine and crude oil). Multiacquisition schemes including diffusion effects make the interpretation more robust, but a normal NMR acquisition suffices as can be made with all available NMR tools (wireline and while-drilling).The new NMR-based method has been verified extensively on core data against standard wettability tests. Application to NMR logs is in progress. -1 for fully oil-wet. The U.S. Bureau of Mines (USBM) index is defined as log(A i /A d ), where A i is the area under the first imbibition capillary pressure curve (at negative P c ), and A d is the area under the second drainage capillary pressure curve (at positive P c ). This index runs from +ϱ for fully water-wet to -ϱ for fully oil-wet. Both analyses are rather time-consuming and expensive. Consequently, they are performed on only a limited number of core samples, if at all. Another complication is that these analyses change the fluid saturations in the sample, and thus are not suitable to monitor (i.e., without interfering) changes in wettability as a function of time or of changes in other experimental parameters.The work described here aims at the development of a technique that can provide a fast and inexpensive wettability indication for laboratory experiments, in particular to monitor wettability changes over time (e.g., caused by aging) or to study the effect of additives to the brine. However, above all, it is a technique that can be applied to measurements taken by a logging tool provided that external factors affecting the NMR response are accounted for or eliminated. This would then provide a continuous wettability profile along the entire reservoir interval, rather than on a few small core samples. Because the interpretation of the data can, in principle, be done in real time, the results can be available at the time of logging. Concept and Application of an NMR Wettability IndexConcept. The NMR relaxation of fluids contained ...
Improved oil recovery by low salinity waterflooding (LSF) represents an attractive emerging oil recovery technology, as it is relatively easy to implement and low-cost compared to other Improved and Enhanced Oil Recovery (IOR and EOR, respectively) processes. Even though LSF leads to extra oil recovery in most laboratory experiments and some promising data from the field have been presented, the mechanism underlying LSF is still unclear. Therefore it is difficult to predict a favorable performance of LSF in one field a priori, while dismissing others. This paper describes a series of spontaneous imbibition experiments on Berea outcrop core plugs, and some reservoir rock core plugs, that were designed to determine the impact of formation water, imbibing water and crude oil composition on wettability and on wettability modification by LSF. The data presented in this paper lead us to conclude that: Spontaneous imbibition experiments with formation brine and low salinity brine executed on Berea outcrop material aged with a crude oil show excellent reproducibility;An increasing concentration of divalent cations in the formation brine makes a Crude Oil/Brine/Rock system more oil-wet;The extent of wettability modification towards more oil-wet upon aging also depends on the types of cations in the formation brine;Improved oil recovery by exposure of the aged plugs to NaCl brines occurred when the imbibing phase was either higher or lower in salinity than the formation brine;Aging of the same brine/rock system with different crudes having diverse physico-chemical properties led to:○A spread in wettabilities after aging○A crude oil-dependent low salinity effect These results are discussed within the context of several mechanisms that have been put forward previously as an explanation for the low salinity effect.
Flow in porous media described by Darcy's law extended to two-phase flow using the concept of relative permeabilities k r naturally assumes a maximum value of 0 ≤ k r ≤ 1. Reports in literature and our own experimental data show endpoint relative permeabilities k r > 1. In the porous medium, the flux of the non-wetting phase is in many cases about 2-4 times higher when a small amount of the wetting phase is present. Here, we draw an analogy between k r > 1 and a slip-boundary condition for the pore scale flow. We use a model description assuming flow in capillary tubes with a slip boundary condition. This model predicts that the flux increase due to slip depends on the equivalent capillary radius of the flow channels. Our k r data specifically follows this dependence indicating that slip is a plausible explanation for the observation of k r > 1.
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