Overcoming Design Challenges of Chemical EOR in High-Temperature, High Salinity Carbonates

Abstract

The optimization of chemical floods for a low-permeability, high-salinity, high-temperature carbonate formation presents several unique design challenges, which may be overlooked in short coreflood experiments. Low permeability formations require the optimization of polymer molecular weight distribution such that both mobility reduction and injectivity are maximized. The effects of high core-scale heterogeneity must be understood and mitigated, for example, by increasing core length. These subjects are explored in the context of an ongoing flood design project. Understanding and mitigation of pressure build-up issues -possibly related to high surfactant adsorption -is an ongoing challenge. Additionally, an attempt will be made to shed light on the discrepancy between available carbonate capillary desaturation curves for carbonates and the near-complete recovery reported in surfactant-polymer corefloods. Effect of dispersivity on chemical floodsGash and Griffith (1980) suggest that, for rocks with low dispersivity, such as Berea, cores as short as 30 cm may yield high recovery in laboratory chemical floods. Clastic reservoirs often contain high-correlation length heterogeneities (e.g. stratification), which, when averaged across an entire section, may add a length scale-dependent megascopic component to dispersion measurements (Arya et al., 1988;Gelhar et al., 1992;Barth et al., 2001). Thus, Arya et al. (1988) differentiate between megascopic dispersivity, which controls volumetric sweep efficiency, and macroscopic dispersivity which determines real mixing in porous media and is under interest of miscible EOR. The ratio of mean correlation length of permeability field to mean distance travelled is proposed as a factor of nature of mixing: if this ratio is much less than one, dispersivity represents true mixing, and is proportional to the mean correlation length. In the opposite case, measured dispersivity results from megascopic heterogeneity as well as dispersion. The criteria α/L<<1 can thus be applied to determine whether the nature of dispersion measurements is truly mixing, or rather an artifact due to large scale heterogeneity. Too much of either can be detrimental to chemical flood performance, the former yielding dilution of the surfactant slug, the latter yielding poor sweep.

Updated Perceptions on Polymer-Based Enhanced Oil Recovery toward High-Temperature High-Salinity Tolerance for Successful Field Applications in Carbonate Reservoirs

“…Moreover, when temperatures exceed 60 C, the acrylamide groups within the HPAM polymer hydrolyze to form acrylate clusters. Furthermore, when temperatures exceed 75 C and there is a proximity of divalent cations, the degree of hydrolysis rapidly increases, triggering precipitations [ 99 , 100 , 101 , 102 ]. Additionally, it was noticed that the polymers with a greater degree of hydrolysis at the start tend to precipitate much faster, and this precipitation is even more aggravated at higher temperature and salinity/hardness [ 66 , 68 , 72 ].…”

Optimization and comparison between polymer, surfactant-polymer and water flooding recoveries in a pre-salt carbonate reservoir considering uncertainties.

“…With this results, it can be discarded losses of surfactant as an issue on the performance of the technique inside of the reservoir, additionally, the area that covered went from the center to the producers indicating a good movement of the surfactant through the reservoir especially in the direction of producers 1 and 2. This movement indicated that in this wells, if a surface facility was built, they will be the first requiring microemulsion treatments because of the arrival of the emulsion front (LEVITT et al, 2013). Moreover, the incremental oil volumes given by the SP when compared to the PF were related to this IFT reduction.…”

“…Later Levitt et al (2013), evaluated on a laboratory scale the challenges of SP flooding in a low permeability carbonate with high temperature and salinity conditions. The methodology consisted of the selection of polymer and surfactants, to later evaluate their performance on different core plugs: limestones, sandstone, and original reservoir cores.…”