Previous studies of crude oil/brine/rock ͑COBR͒ and related systems showed that wettability and its effect on oil recovery depend on numerous complex interactions. In the present work, the wettability of COBR systems prepared using Prudhoe Bay crude oil, a synthetic formation brine, and Berea Sandstone was varied by systematic change in initial water saturation and length of aging time at reservoir temperature ͑88°C͒. All displacement tests were run at ambient temperature. Various degrees of water wetness were achieved and quantified by a modified Amott wettability index to water, the relative pseudowork of imbibition, and a newly defined apparent advancing dynamic contact angle.Pairs of spontaneous imbibition ͑oil recovery by spontaneous imbibition of water͒ and waterflood ͑oil recovery vs. pore volumes of water injected͒ curves were measured for each of the induced wetting states. Several trends were observed. Imbibition rate, and hence, water wetness, decreased with increase in aging time and with decrease in initial water saturation. Breakthrough recoveries and final oil recovery by waterflooding increased with decrease in water wetness. Correlations between water wetness and oil recovery by waterflooding and spontaneous imbibition are presented. Experiments Fluids.A Prudhoe Bay, Alaska, crude oil ͑A'93͒ was used as the oil phase. The crude oil was evacuated before use to reduce the possibility of gas evolution during the course of an experiment. The evacuated crude oil had a viscosity o of 39.25 cP and density o of 0.895 g/cc at 25°C. A refined oil, Soltrol 220, o ϭ3.98 cP, was used to obtain a set of imbibition and waterflood data for very strongly water-wet conditions. A synthetic formation ͑SF͒ brine was prepared: 21.3 g/L NaCl, 0.6 g/L CaCl 2 "6H 2 O, 0.1

More than half of the global oil reserves are in carbonate reservoirs. Carbonate rocks, however, in most cases tend to be mixed-wet or oil-wet. Wettability alteration of carbonate reservoir rock has been proven to increase oil recovery significantly. Several chemicals have shown their effect on wettability; however, selection of an appropriate wettability modifier should be made on the basis of the underlying mechanisms and their behavior at reservoir conditions. This review discusses techniques that can help in assessing wettability alteration or reflect on the underlying mechanism and describes several categories of wettability modifiers focusing on their structure−property relationship and factors affecting their performance at reservoir conditions. Surfactants, nanoparticles, salts, and alkalis are four major categories of wettability modifiers that are discussed in this review. Among surfactants, gemini surfactants have great potential and could be a major focus of future research in this area. Nanoparticles are relatively novel materials for wettability alteration with the capability to reduce contact angle significantly at low cost. This review also identifies the current and future challenges related to the performance of various wettability modifiers at high-temperature and high-salinity conditions.

The application of foam in the upstream petroleum industry has gained significant interest in the past few years. Foam usage can mitigate challenges associated with the gas flooding; it simply reduces the gas’s mobility, which could significantly enhance the sweep efficiency. Foam is generated using CO2 or N2 and stabilized by different materials such as surfactants, nanoparticles, polymers, or a combination thereof. The success of foam injection mainly depends on the stability of the flowing foam; the harsh reservoir conditions is one of the major challenges in this regard. Historically, surfactants have been used to generate and stabilize foams. However, recently, nanoparticles have gained attention due to their higher adsorption energy at the gas–liquid interface. In this paper, foam stabilizers such as surfactants, nanoparticles, and polymers are reviewed. Relevant advantages/disadvantages of different foam stabilizers and associated challenges are also highlighted. The results obtained in previous studies are discussed, and conflicting findings are highlighted and critically analyzed. Field applications of CO2 foam are also discussed in this Review. There are only a few field trials using surfactant stabilized foam. However, nanoparticle stabilized foam has not been tested in the field.

Thw psper was selected for presentation by an SPE Prcgram Commdtee following rewew of mformat,on contained in an abstracl subm,fted by the authorsContents of the paper, as presented, have not been rev!ewed by Ihe Scciety of Petro!uum Eng!neers and are subpcl 10 wrecton by the authors The material, as presented, does not necessarily reflect any posmon of the Society of Petroleum Engineers, M ofhcers, or members. Papers presented at SPE mee{mgs are subject to publcai(on reww by Editcmal Committees of the Soaet y of Petroleum Engineers. Pwm!$skm to COPY IS restricted to an abstract of not more than 300 words IIlushalons may not be cop ted The abstrad should contain conspicuous acknowledgment of where and by whwn Ihe pape is presented. Wrte L] Mar@n, SPE, TX 75083-3836, USA fax 01.214.952.9435. AbstractPrevious studies of crude oil/brine/rock (COBR) and related ensembles showed that nettability and its effect on oil recovery depend on numerous complex interactions, In the present work, the nettability of COBR ensembles prepared using Prudhoe Bay crude oil, a synthetic formation brine, and Berea Sandstone was varied by systematic change in initial water saturation and length of aging time at reservoir temperature (880 C). All displacement tests were run at ambient temperature. Various degrees of water wetness were achieved and quantified by a modified Amott nettability index to water, the relative pseudo work of imbibition and a newly defined apparent advancing dynamic contact angle. Pairs of spontaneous imbibition (oil recovery by spontaneous imbibition of water) and waterflood (oil recovery vs pore volumes of water injected) curves were measured for each of the induced wetting states.Several trends were observed. Imbibition rate, and hence water wetness, decreased with increase in aging time and with decrease in initial water saturation. Breakthrough recoveries and final oil recovery by waterflooding increased with decrease in water wetness. Correlations between water wetness and oil recovery by waterflooding and spontaneous imbibition are presented.