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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAcid fracturing is performed to improve well productivity in acid-soluble formations such as limestone, dolomite, and chalk. Hydrochloric acid is generally used to create an etched fracture, which is the main mechanism for maintaining the fracture open during the life of a well. Proppant fracturing is an alternative option that has been applied in carbonate formations. In certain areas, proppant fracturing has been used as a standard stimulation method for carbonate formations. There is no quantitative method to provide an answer of whether acid fracturing or proppant fracturing is an appropriate stimulation method for a given carbonate formation.In proppant fracturing, proppant is used to sustain the effect of the minimum horizontal stress from closing the fracture. In acid fracturing the etched, non-smooth, surface with sufficient roughness should leave open channels upon closing. The effect of elastic, plastic, and creeping deformations in acid fracturing and the proppant crushing and embedment in proppant facturing, on reducing fracture permeability is investigated. The viscous effect, creeping, is a slow displacement that incurred over a long period of time. The creeping effect on fracture closure following an acid fracturing treatment is demonstrated in this paper.Laboratory experiments have been performed to simulate acid and proppant fracturing treatments. The effect of elastic, plastic and viscoelastic rock behavior on fracture conductivity was studied for acid and proppant fracturing treatments, using full core samples. Comparison of acid vs. proppant fracturing conductivity in carbonate formation is also presented.

Acid fracturing is performed to improve well productivity in acid-soluble formations such as limestone, dolomite, and chalk. Hydrochloric acid is generally used to create an etched fracture, which is the main mechanism for maintaining the fracture open during the life of a well. Proppant fracturing is an alternative option that has been applied in carbonate formations. In certain areas, proppant fracturing has been used as a standard stimulation method for carbonate formations. There is no quantitative method to provide an answer of whether acid fracturing or proppant fracturing is an appropriate stimulation method for a given carbonate formation. In proppant fracturing, proppant is used to sustain the effect of the minimum horizontal stress from closing the fracture. In acid fracturing the etched, non-smooth, surface with sufficient roughness should leave open channels upon closing. The effect of elastic, plastic, and creeping deformations in acid fracturing and the proppant crushing and embedment in proppant facturing, on reducing fracture permeability is investigated. The viscous effect, creeping, is a slow displacement that incurred over a long period of time. The creeping effect on fracture closure following an acid fracturing treatment is demonstrated in this paper. Laboratory experiments have been performed to simulate acid and proppant fracturing treatments. The effect of elastic, plastic and viscoelastic rock behavior on fracture conductivity was studied for acid and proppant fracturing treatments, using full core samples. Comparison of acid vs. proppant fracturing conductivity in carbonate formation is also presented. Introduction Hydraulic fracturing (acid or proppant) is used to create a conductive fracture in the formation to enhance well productivity. The induced fracture will tend to close due to the effect of the minimum horizontal stress. Fracture closure is controlled by elastic, plastic, and viscous rock properties. In acid fracturing the etched, non-smooth, fracture surfaces would leave open pathways upon closing in addition to wormholes and channels created from the fracture into the formation. Fracture conductivity is generated by the quantity of rock removed and the pattern of rock removal. Depending on the pattern of natural fracture system, acid solubility of the formation, magnitude of the minimum horizontal stress, and reservoir temperature, acid fracturing vs. proppant fracturing should be evaluated to select the most effective stimulation treatment for a given formation. Interesting observations relavant to stimulation of carbonate reservoirs, have been reported in the literature. Fracture conductivity does not increase with increasing amounts of dissolved rock1. After successful application of proppant fracturing in a chalk formation, it was concluded that proppant fracturing yielded sustained production rate and became the standard stimulation treatment2. Chalk formations are usually soft with Brinell hardness less than 10 Kg/mm2 and therefore creeping is pronounced. The effect of increased effective stress, due to reservoir depletion, on fracture and matrix permeabilities, was reported3. Proppant's importance in sustaining fracture conductivity in carbonate formation was demonstrated4.

Wettability has a significant impact on the flow of oil during enhanced oil recovery (EOR) and profound effect on fluid distribution in oil fields. Mechanisms that influence the interaction between the injected water and the components of crude oil in the presence of carbonate rock samples were investigated. The main objectives of this study were to investigate the role of both rock mineralogy and the compositions of various oils as a function of asphaltene content on the destabilization of the aqueous film separating the oil from the substrate rock surface of carbonates using aqueous phases such as brine and carbonated water. The contact angles as a function of time were measured using brine and carbonated water and two types of crude oil on four types of rock samples. Once the exact contact angle has been determined, the compositions of various oils, based on asphaltene contents, were characterized to investigate the role of oil composition on the destabilization of the aqueous film separating the oil from the rock surface. Interfacial tensions (IFTs) of brine and two types of crude oil were also measured. Four types of rock samples from carbonate reservoirs, with different compositions, selected based on X-ray diffraction results were as follows: (1) 100% dolomite D(100), (2) 100% calcite C(100), (3) 67% dolomite + 33% calcite (D67 + C33), and (4) 37% dolomite + 63% calcite (D37 + C63). Two types of crude oil were used based on the asphaltene content obtained using the saturate, aromatic, resin, and asphaltene analysis. The contents of asphaltenes for crude-1 and crude-2 were 11.6 and 6.4 wt % and represented as (I-11.6) and (II-6.4), respectively. In this study, crude oil/brine/carbonate systems showed that (D37 + C63) gave the lowest contact angle value of 67° with 6.4 wt % of asphaltene content (II-6.4) and that D(100) gave the highest contact angle of 136° with 11.6 wt % of asphaltene content (I-11.6). Brine was used as the external phase on both tests. On the other hand, using carbonated water as the external phase, the contact angle decreased from 97.6° (D67 + C33) to 75.5° (D37 + C63) for mixed dolomite/calcite systems. Decreasing the dolomite content in mixed dolomite/calcite systems caused a shift in contact angle from the oil negative intermediate wet to weakly water wet regardless of the saturating fluid phase. Also, using the adhesion tension approach, in defining surface wettability, shows that with the decrease in the contact angle values, adhesion tension shifted to positive directions with an increase in the degree of water wetness. This behavior was mainly due to the effect of type-II crude oil. The novelty of this study stems from studying the effect of rock mineralogy based on dolomite and calcite distribution and oil composition based on the asphaltene content in wettability alteration using aqueous phases such as brine and carbonated water. The results of both contact angle and IFT were implemented in adhesion tension using the Thomas Young equation as an alternative approach in defining s...

Summary Carbonated water injection has gained wide interest as an enhanced oil recovery technique. The efficiency of oil displacement during an ordinary waterflood is dictated and governed mainly by the viscous and capillary forces between oil and water. These forces are controlled by the interfacial tension (IFT) between the fluids and the contact angle (CA) with the rock surface. In this study, the pendant drop technique and molecular dynamics (MD) simulation were combined to investigate the effect of adding carbon dioxide on the water/oil/rock interfaces. CA measurement is rather a macroscopic assessment of the wettability while molecular simulation can provide further microscopic insights. The multiscale approach involves direct wettability assessment of asphaltene-containing oil against pure water or carbonated water, both exposed to two types of carbonate rock samples. Molecular characterization of asphaltenes was carried out by analytical means and different asphaltene structures were recreated on a computational platform for asphaltene-water and asphaltene-carbonated water molecular simulations. The experimental data revealed that the carbonated water caused the CA to change from weakly oil-wet to intermediate to water-wet wettability. Molecular simulation was invoked to shed more light into the underlying mechanisms behind the observed wettability alteration. In particular, molecular simulation of IFT and asphaltene swelling effect driven by the interactions with carbon dioxide were analyzed. The results were found consistent with the experiments. The findings presented in this paper highlight the viability of carbonated water for enhanced oil recovery and provide in-depth insights into the underlying mechanisms.