Shubham, Agrawal (Texas A&M University at Qatar) | Martavaltzi, Christina (Texas A&M University at Qatar) | Dakik, Ahmad Rafic (Texas A&M University at Qatar) | Gupta, Anuj (Texas A&M University at Qatar)
It is well known that the majority of carbonate reservoirs are neutral to oil-wet. This leads to much lower oil recovery during waterflooding since there is no spontaneous imbibition of water in heterogeneous reservoir displacement. It has been verified by a number of researchers that Adjustment of ion concentration in brine solutions, or adding surfactant solutions can enhance the oil recovery by altering the wettability. In the published literature, contact angle studies usually refer to measurement on calcite crystals and there are no results for the contact angle of carbonate porous media representative of reservoir rocks. Moreover, there are few studies on the effect of non-ionic surfactants, compared to those for ionic surfactants. Understanding the effect of various ions and their concentration in the injection brine on the wettability of the Limestone outcrop core samples is the first step for tailoring of the optimum injection brine. This will be followed by a study of the effect of surfactant on the wettability of calcite crystal samples. The evaluation of the results may provide guidelines for the design of injection brines for efficient enhanced oil recovery from carbonate reservoirs.
In this work, a procedure is established for the measurement of the contact angle on limestone outcrop core samples. Results showed that, at atmospheric conditions, low salinity CaCl2 solution induced the most significant improvement on the wettability of the outcrop sample. Moreover, among all the non-ionic surfactants studied, only the presence of the two first members of the 15S analogous series might lead to a slight decrease of the contact angle.
Low sa linity waterflooding (LSF) research has been gaining more momentum in recent years for both sandstone and carbonate reservoirs. Published laboratory data and field tests have shown an increase in oil recovery by changing injected brine salinity, especially for sandstone reservoirs. It is widely accepted that low salinity water alters the wettability of the reservoir rock from less to more water-wet conditions, oil is then released from rock surfaces and recovery is increased. The main objectives of the current study are to: test the potential of increasing oil recovery by LSF of a carbonate reservoir and to investigate the factors that control it. The impact of LSF on oil recovery was investigated by conducting coreflood and spontaneous imbibition experiments at 70 oC using core samples from a carbonate reservoir, crude oil and synthetic brine (194,450 ppm) which was mixed with distilled water in four proportions twice, 5 times, 10 times and 100 times dilution brines. Moreover, both crude oil/brine interfacial tension measurements (IFT) and ionic exchange experiments were carried out at room temperature (25 oC).
The results of the study show higher oil recovery as a result of reducing injected water salinity in both coreflood and spontaneous imbibition experiments. Coreflood experiments showed an increase in oil recovery by 3 to 5 % of OOIP, while spontaneous imbibition experiments showed an increased by 16 to 21 %. Additionally, spontaneous imbibition experiments provide direct evidence of wettability change by the LSF. The study also shows that the increase in oil recovery was obtained at much higher water salinity than the one observed in the case of sandstone rock.
Hsu, Tzu-Ping (U Of Oklahoma) | Lohateeraparp, Prapas (U. of Oklahoma) | Roberts, Bruce L. (University of Oklahoma) | Wan, Wei (U. of Oklahoma) | Lin, Zhixun (University of Oklahoma) | Wang, Xiaoguang (U. of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Shiau, Ben (University of Oklahoma) | Harwell, Jeffrey H.
Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+and Mg2+, the presence of iron in the brine can be a challenging issue. Different surfactant formulations incorporating cosurfactants and co-solvents are studied. These formulations minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations are further studied in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at 42?C. Using similar injection protocols, 0.5 PVs surfactant/polymer, oil recoveries ranging from 50 % to 70% of the residual oil (Sor) after waterflooding are observed. The level of surfactant loading is less than 0.6 wt%. A single-well test is conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 165,000 mg/L total dissolved solids (TDS). The test is considered to be a technical success and confirms the effectiveness of a high-salinity surfactant-polymer formulation composed of 0.23 wt% of surfactant and 1,800 ppm of polymer loading. Approximately 87% of the residual oil was mobilized.
Suijkerbuijk, Bart (Shell) | Hofman, Jan (Shell Intl. E&P BV) | Ligthelm, Dick Jacob (Shell Intl. E&P BV) | Romanuka, Julija (Shell Global Solutions Intl BV) | Brussee, Niels (Shell Intl. E&P BV) | van der Linde, Hilbert (Shell Intl. E&P BV) | Marcelis, Fons (Shell International Exploration and Production B.V.)
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:
o A spread in wettabilities after aging
o 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.