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Accelerators speed up or shorten the reaction time required for a cement slurry to become a hardened mass. In the case of oilfield cement slurries, this indicates a reduction in thickening time and/or an increase in the rate of compressive-strength development of the slurry. Acceleration is particularly beneficial in cases where a low-density (e.g., high-water-content) cement slurry is required or where low-temperature formations are encountered. Of the chloride salts, CaCl2 is the most widely used, and in most applications, it is also the most economical. The exception is when water-soluble polymers such as fluid-loss-control agents are used.
Alhuraishawy, Ali K. (Missan Oil Company, Missouri University of Science and Technology) | Almansour, Abdullah (King Abdulaziz City for Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Imqam, Abdulmohsin (Missouri University of Science and Technology) | Geng, Jiaming (Missouri University of Science and Technology)
Abstract The latest oil price decline simply increases the demand for enhanced oil recovery (EOR) and pushes research developers to keep improvements in oil recovery. The goal is always to recover as much oil as possible at the lowest possible cost. Low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods, which makes it a preferred area of interest for oil industry economists, who continue to call for EOR costs to come down. The objective of this study was to test the ability of low-salinity waterflooding to improve oil recovery from low permeability sandstone reservoirs. Four types of tests were conducted: imbibition, interfacial, core flooding, and zeta potential tests. Three key factors were studied: salinity of the injected water, type of salt, and aging time. Their influence on the amount of oil recovery, stabilized injection pressure, pH, and permeability reduction was determined. Berea sandstone was used in all experiments. Sodium chloride (NaCl) and calcium chloride (CaCl2) were used to prepare the brine. The imbibition test and core flooding results showed that the oil recovery increased as brine concentration decreased for both sodium chloride and calcium chloride. Sodium chloride resulted in higher oil recovery than calcium chloride at a certain salinity in both imbibition and core flooding tests. The oil recovery factor results during the second water flooding cycle (after aging for 24 hrs.) showed more oil recovered during low salinity waterflooding. The stabilized inaction pressure was higher for CaCl2 than NaCl injection at certain flow rate and brine concentrations. Effluent pH values became more basic during low salinity water flooding for both sodium and calcium chloride. The zeta potential results showed that decreasing the salinity of injected water resulted in a decrease of the zeta potential value for both injection cycles, before and after aging for 24 hours. Results also imply Low- salinity water flooding redistributes the flowing paths by releasing sand particles and some fine minerals causing the flow path to narrow. Thus, low salinity water flooding can create a new streamline (fluid flow diversion) and improve both displacement and sweep efficiency.
Most common brines are sodium chloride NaCl, potassium chloride KCl and calcium chloride CaCl2. Brine densities may range from 8.33 to 19 lb/gal (1 to 2.28 g/cc). The USGS definition of a brine is a salinity of more than 35,000 mg/L (after USGS, 1984). Water having more than 30,000 mg/L dissolved material, but not necessarily corresponding to ocean water with respect to ionic ratios. Most common brines are sodium chloride NaCl, potassium chloride KCl and calcium chloride CaCl2.
Calcium sulfate (CaSO4) in the form of gypsum and anhydrite is one of the more prevalent evaporite minerals typically found in the carbonate rocks of the western Canadian sedimentary basin (WCSB). Most calcium sulfate scale inhibitors used for acid treatments rely on either the retardation of CaSO4crystal growth or the creation of soluble complex salts with the calcium ions. A broad-spectrum scale inhibitor has been specially formulated for high-salinity and acid solutions that not only prevents the precipitation of CaSO4but also helps inhibit the initial dissolution of CaSO4. Covering a vast extension of 1.4 million km2, the WCSB is between the southwestern border of the Canadian shield in Manitoba and the eastern flank of the Canadian Rocky Mountain system in British Columbia. Approximately half of the WCSB is composed of carbonate reservoirs.
Abstract Xanthan gum and other naturally obtained polymers have been used extensively in the petroleum industry as a "viscosifier" in drilling, completion, workover and hydraulic fracturing fluids. Other than the effects of shear rate, pH and temperature, the performance of various polymers can be greatly affected by salinity, due to their sensitivity to metal ions of different salts contained in the commonly used solvents. In today’s oilfield operations, it is not uncommon to combine polymers with sea water or brine of a known salt concentration in order to generate certain desired fluid properties. Consequently, the importance of understanding the compatibility and shear properties of polymer fluids in brine solvents for coiled tubing operations cannot be underemphasized. However, while there are several existing literatures on the various methods of viscosifying brine solutions with polymers, only a handful have attempted to describe the flow properties of viscosified brine. In order to bridge this knowledge gap, the present experimental study examines the compatibility and flow characteristics of Xanthan gum at various polymer loadings with different concentrations of Calcium Chloride (CaCl2) brine. An unprecedented set of flow data was acquired using an experimental flow-loop comprising of ½ in. straight and coiled tubing sections. The data demonstrated a continual decrease in drag reduction and increased friction pressure loss with increasing brine density. A comparison of those data with predicted data show that the hydraulic properties of viscosified brine can be fairly estimated using existing friction factor correlations. Nevertheless, additional flow data must be acquired with various brines and polymers to develop correlations with better accuracy.
Getliff, J. M. (Chevron Energy Technology Company) | Swartz, F. R. (Chevron Global Upstream & Gas) | Trotter, R. N. (Chevron Energy Technology Company) | Malachosky, E.. (Chevron Energy Technology Company)
Abstract Use of a Non-Aqueous Drilling Fluid (NADF) on the Chuandongbei (CDB) gas project wells will increase the rate of penetration (ROP) and decrease non productive time (NPT) and thus the overall development costs. The use of non aqueous fluids instead of water based drilling fluids (WBM) will however, require significant changes and improvements to the waste management practices previously used in the region which are not suitable for use with non aqueous drilling fluids. A non-aqueous drilling fluid based on a proprietary synthetic paraffin base fluid and a potassium acetate internal phase will be used to maximize the bioremediation potential of the drilling fluid and allow the use of an enhanced bioremediation process that combines the use of fertilizer, top soil and organic amendments to speed up the rate of degradation to produce a useful soil that is able to support plant growth that can be used for reclamation and landscaping of the drill site. This paper provides a concise overview of the proof of concept studies that were carried out at the University of Tulsa (Phase I and II) and the subsequent refinements using locally sourced soils and organic amendments at the South Western Petroleum University in China (Phase III). The data show that the synthetic based drilling fluid can be successfully biodegraded in soil bio-piles composed of soil and organic amendments from the CDB operating area. The resultant product was successfully used as a plant growth medium.
Summary The effect of salinity on the alteration of wettability from waterwetting to intermediate gas-wetting is studied in this work. We find that NaCl salinity increases water-wetting when a core is saturated with brine. NaCl also reduces gas absolute permeability, as reported in the literature. CaCl2 salinity effect is dramatically different from that of NaCl brine and has a minor effect on permeability. The NaCl, KCl, and CaCl2 brines have an adverse effect on wettability alteration. To alleviate the effect of salt on chemical treatment, we suggest pretreatment by displacement of brine with water and subsequent drainage by nitrogen.
Abstract The synergetic effect of salinity and fluorochemicals on the alteration of wettability from water-wetting to intermediate gas-wetting is studied in this work. We find that NaCl salinity increases water-wetting when a core is saturated with brine. NaCl also reduces absolute gas permeability as reported in the literature. CaCl2 salinity is drastically different from NaCl brine, and has a minor effect on permeability. The NaCl, KCl and CaCl2 brines have an adverse effect on wettability alteration. To alleviate the effect of salt on treatment, we suggest pre-treatment by displacement of brine with water and subsequent drainage by nitrogen. Introduction A reduction in effective gas permeability observed in tight formations and in low permeability gas reservoirs is often attributed to water blocking and condensate accumulation. The water blocking is induced by the injection of water in hydraulic fracturing (Engineer, 1985; Cimolai, et al. 1993). The condensate accumulates at the wellbore as the pressure drops below the dew-point pressure (Barnum et al. 1995; El-Banbi et al. 2000). A major factor of liquid retention in a rock is the liquid's low mobility due to strong liquid wetting (Anderson, 1987a, b). By altering the wettability of the rock from liquid-wetting to intermediate gas-wetting, an increase in liquid mobility can be achieved resulting in a high rate of gas production. In 2000, Li and Firoozabadi pioneered the alteration of wettability by fluorochemical treatment, and demonstrated significant changes in contact angle, and imbibition testing for cores after treatment. Following their work, there have been a number of experimental studies on wettability alteration to intermediate gas-wetting (Tang and Firoozabadi, 2002, 2003; Kumar et al. 2006; Fahes and Firoozabadi, 2007; Panga et al. 2007; Al-Anazi, et al. 2007). Most of the work on wettability alteration has been performed by injection of chemicals into a core initially saturated with air or nitrogen, i.e., the dry core. In some cases the rock has been saturated with water or oils. The reservoir rock before the chemical treatment is partially saturated with liquid condensate and the aqueous phase that may be connate water, condensed water from the gas, or from the aquifer. There is always a definite amount of ions in the subsurface water. For example, condensed water from gas may have 140–150 mg/l of chloride ion, and the fracturing fluid water may have ~ 25 mg/l chloride ion. One of the main parameters in wettability and imbibition studies is the water composition that can affect the wettability. Based on spontaneous imbibition and waterflooding tests at reservoir temperature in Berea sandstone with three crude oils and three reservoir brines, Tang and Morrow (1997) found that the salinity of the connate water and invading brines can have a major influence on wettability and oil recovery. Zhang and Austad (2006) verified that the ions Ca and SO4 could increase the water-wetting of chalk, and thereby increase the water-oil capillary pressure of matrix blocks. There is an abrupt change in the zeta potential when only small amounts of ions are added to the aqueous solution. Tweheyo et al. (2006) have studied the effect of divalent ions on wettability alteration of carbonates and the subsequent effect on oil recovery by spontaneous imbibition. They found that SO4, Ca and Mg ions can change the wettability to more water wetting at 100ºC and above without surfactants in the system. The three divalent ions seem to play different effects in the two processes: wettability alteration and spontaneous imbibition.