Polymer enhanced oil recovery (EOR) operation has been implemented for the production of oil from difficult mature oilfields in Oman. The polymer used in this EOR technique to sweep oil toward production wells is resulting in the generation of polymer flood produced water (PFPW) of increasing viscosity. Current methods of treating oilfield produced water must be reconsidered for the effective treatment of such PFPW of changing quality.
In a previous study, the utilization of polyaluminum chloride (PAC) chemical was proposed for the coagulation of oil in produced water to be separated by flotation and filtration. As such, laboratory tests were conducted to evaluate the applicability of PAC and other chemicals for treatment of PFPW that has higher viscosity than ordinary oilfield produced water. These tests clearly indicated that aluminum sulfate (AS) chemical was more effective for treatment of such higher viscosity water.
A pilot plant developed during the earlier study, was utilized to conduct coagulation/flocculation, flotation, filtration, and adsorption treatment trials for PFPW from an oilfield where polymer EOR is underway. For the final trial, the inlet PFPW viscosity was 1.4 cP at 40 °C and oil concentration was above 200 mg·L-1. AS was applied for coagulation/flocculation and flotation stages, and was found to be effective in reducing oil concentration to 1 mg·L-1. Filtration and adsorption stages resulted in further improvement of water quality. Most of the polymer used for EOR was believed to have been removed along with oil and suspended solids.
Oman’s main oil production company, Petroleum Development Oman (PDO), produces roughly 8 m3 water·m-3 oil totaling 4.5 million bpd of water (Al-Manhal, 2009). Much of this produced water is re-injected back into the oil reservoirs for pressure maintenance, and some is used to generate steam for enhanced oil recovery (EOR) projects.
For the remaining produced water, as currently all Oman’s production facilities are onshore, well inland of the coast, marine disposal is not an option. Disposal to shallow aquifers was phased out in 2005 (Breuer, 2010) to avoid any contamination of these aquifers and preserve them for future use (Al-Manhal, 2009). While reed plants are being used in recent years to treat large quantities of this produced water, in the case of lower salinity brines (Al-Manhal, 2010); much of the water is still disposed into deep-lying aquifers, a costly energy-intensive process due to the high levels of pressure needed to pump the water down to a depth of up to 2 km below the surface (Al-Manhal, 2010). Some concerns also exist for deep well disposal over the long run, in terms of clogging of the reservoirs by oil, and of increasing saturation pressure due to the finite limit of water that can be absorbed by the aquifers (Al-Manhal, 2009, 2010). As such, less expensive, environmentally acceptable alternatives for produced water have been sought. In fact, PDO has been looking for ways to convert this liability into a water resource. Suitable treatment and utilization of produced water represents an attractive alternative to disposal. In terms of possible utilization of treated produced water, the relatively low salinity of the water currently disposed, increases the utilization options of such water after treatment. In light of such need, the authors have been working to identify simple, highly efficient treatment systems for produced water in Oman, through laboratory tests and treatment trials.
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.
Al-maamari, Rashid Salim (Sultan Qaboos University) | Sueyoshi, Mark (Institute of Technology, Shimizu Corporation) | Tasaki, Masaharu (Institute of Technology, Shimizu Corporation) | Okamura, Kazuo (Institute of Technology, Shimizu Corporation) | Al Lawati, Yasmeen Mohammed (Petroleum Development Oman) | Nabulsi, Randa Zaki (Petroleum Development Oman) | Battashi, Mundhir (Petroleum Development Oman)
As an oil field matures, it produces larger quantities of produced water. Appropriate treatment levels and technologies depend on a number of factors such as disposal methods or reutilization aims, environmental impacts, and economics.
In this study, a pilot plant of capacity 50 m3•day-1 was utilized to conduct flotation, filtration, and adsorption trials for produced water treatment at a crude oil gathering facility. The plant's flexible design allows for the testing of different combinations of these processes based on the requirements of the water to be treated. The subject water during this study was a complex and changing mixture of brine and oil from different oilfields.
Induced gas flotation trials were conducted, with different coagulant (poly-aluminum chloride or PAC) addition rates from 0-820 mg•L-1. Inlet oil-in-water (OIW) concentrations were quite varied during the trials, ranging from 39-279 mg•L-1 (fluorescence analysis method) and 12-340 mg•L-1 (infrared analysis method). Turbidity also varied, ranging from 85-279 FTU. Through flocculation/coagulation and flotation, dispersed oils were removed from the water. PAC addition ranging from 60-185 mg•L-1 resulted in reduction of dispersed oil concentration to below 50 mg•L-1 in treated water. PAC addition ranging from 101-200 mg•L-1 resulted in reduction of dispersed oil concentration below 15 mg•L-1 in treated water. Turbidity was also reduced through flotation, trial average reductions ranging from 57-78%. Filtration further reduced turbidity at rates above 80% through the removal of any suspended solids remaining from flotation. Activated carbon adsorption reduced OIW concentrations of flotation/filtration treated water to 5 mg•L-1 through the removal of dissolved oil remaining in the water. Results confirmed that such adsorption treatment would be more practical for water with lower COD concentration, due to high COD concentrations in water drastically reducing the lifetime of activated carbon.
Morvan, Mikel (Rhodia) | Degre, Guillaume (Rhodia) | Beaumont, Julien (Rhodia) | Colin, Annie (LOF (CNRS-Rhodia-Bx1)) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (POWELTEC) | Al-maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman)
Injections of polymer solutions have been used to improve oil recovery in heavy oil reservoirs (Zaitoun et al. 1998). Most of those polymer flood experiences refer to conditions where the polymer solution propagates through the porous media under low shear rate and exhibits mostly a Newtonian behaviour. On the other hand recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically oil recovery of more than 20% OOIP compared to waterflooding has been reported for light oil (Wang et al; 2011). However injectivity issues have to be considered when injecting concentrated polymer solutions. This study examines whether non polymeric elastic fluids derived from surfactant solutions can represent an alternative approach to elastic polymer floods. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity).
Bulk flow properties as well as rheology in a confined geometry have been used to compare flow properties of surfactant and high molecular weight polymer solutions. The elastic properties of both fluids have been characterized in terms of Weissenberg numbers. The data indicate the surfactant solution as opposed to the polymer one is highly elastic at low shear rates even in the presence of brine. Those results are confirmed by comparative experiments made using a Particle Image Velocimetry (PIV) technique. Injectivity of concentrated surfactant solutions has been tested in single-phase conditions and indicated a good in depth propagation of the fluid. A series of core-flood experiments has been performed using heavy oil reservoir cores. The surfactant slug has been combined with a conventional low-concentration polymer flooding to benefit from surfactant elasticity and improve oil recovery.
Morvan, Mikel (Rhodia) | Degre, Guillaume (Rhodia) | Beaumont, Julien (Rhodia) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (POWELTEC) | Al-maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman)
Recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically more than 20% OOIP compare to waterflooding have been reported (Wang et al; 2011). However injectivity issues have to be considered when injecting such concentrated polymer solutions. This work describes an alternative approach based on surfactant-based fluids. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitation even when considering very viscous surfactant solutions (ie up to 1000 cps) and low permeability cores.
Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high molecular weight polymer solutions. The degree of non linearity in the mechanical properties for both fluids has been expressed by Weissenberg number. The surfactant solution has much larger Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir.
The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of core-flood experiments has been performed in reservoir cores. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of ?Sw = 10-15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.