Efficiency and bacterial diversity of an improved anaerobic baffled reactor for the remediation of wastewater from alkaline-surfactant-polymer (ASP) flooding technology

Alkaline-surfactant-polymer (ASP) flooding technology is used to maximize crude oil recovery. However, the extensive use of alkaline materials makes it difficult to treat the water used. Here, an improved multi-zone anaerobic baffled reactor (ABR) using FeSO4 as electron acceptor was employed to treat the wastewater from ASP flooding technology, and the effects on major pollutants (hydrolyzed polyacrylamide, petroleum substances, surfactants suspended solids) and associated parameters (chemical oxygen demand, viscosity) were evaluated. Gas chromatography-mass spectrometry (GC-MS) was used to follow the degradation and evolution of organic compounds while high-throughput DNA sequencing was used to determine the bacterial diversity in the ABR. The results obtained after 90 d of operation showed decreases in all parameters measured and the highest mean removal rates were obtained for petroleum substances (98.8%) and suspended solids (77.0%). Amounts of petroleum substances in the ABR effluent could meet the requirements of a national standard for oilfield reinjection water. GC-MS analysis showed that a wide range of chemicals (e.g. aromatic hydrocarbons, esters, alcohols, ketones) could be sequentially removed from the influent by each zone of ABR. The high-throughput DNA sequencing showed that the bacteria Micropruina, Saccharibacteria and Synergistaceae were involved in the degradation of pollutants in the anaerobic and anoxic reaction zones, while Rhodobacteraceae and Aliihoeflea were the main functional microorganisms in the aerobic reaction zones. The results demonstrated that the improved ABR reactor had the potential for the treatment of wastewater from ASP flooding technology.

Advancement Towards the Full-Field Implementation of Marmul Alkaline-Surfactant-Polymer in the Sultanate of Oman

In 2015-2016, the Alkaline-Surfactant-Polymer (ASP) flood Pilot in Marmul was successfully completed with ∼30% incremental oil recovery and no significant operational issues. In parallel to the ASP pilot, several laboratory studies were executed to identify an alternative and cost-efficient ASP formulation with simpler logistics. The studies resulted in a new formulation based on mono-ethanolamine (MEA) as alkali and a blend of commercially available and cheaper surfactants. To expediate the phased full field development, Phase-1 project was started in 2019 with the following main objectives are confirm high oil recovery efficiency of the new ASP formulation and ensure the scalability and further commercial maturation of ASP technology; de-risk the injectivity of new formulation; and de-risk oil-water separation in the presence of produced ASP chemicals. The Phase 1 project was executed in the same well pattern as the Pilot, but at a different reservoir unit that is more heterogeneous and has a smaller pore volume (PV) than those of the Pilot. This set-up allowed comparing the performance of ASP formulations and taking advantage of the existing surface facilities, thus reducing the project cost. The project was successfully finished in December 2020, and the following major conclusions were made: (1) with the estimated incremental recovery of around 15-18% and one of the producers exhibiting water cut reversal of more than 30%, the new ASP formulation is efficient and will be used in the follow-up phased commercial ASP projects; (2) the injectivity was sustained throughout the entire operations within the target rate and below the fracture pressure; (3) produced oil quality met the export requirements and a significant amount of oil-water separation data was collected. With confirmed high oil recovery efficiency for the cheaper and more convenient ASP formulation, the success of ASP flooding in the Phase-1 project paves the way for the subsequent commercial-scale ASP projects in the Sultanate of Oman.

Scale Mitigation for Field Implementation of Alkaline-Surfactant-Polymer ASP Flooding in a Heterogeneous High Temperature Carbonate Reservoir with High Divalent Cation Concentration in Formation Water

An alkaline-surfactant-polymer (ASP) pilot in a regular five spot well pattern is underway in the Sabriyah Mauddud (SAMA) reservoir in Kuwait. High divalent cation concentrations in formation water and high carbonate concentration of the ASP formulation makes the formation of calcite scale a concern. The main objective of this study is to investigate the severity of the calcium carbonate (CaCO3) scaling issues in the central producer in pursuit of a risk mitigation strategy to treat the potential scale deposition and reduce the flow assurance challenges. Calcite scaling risk in terms of Saturation Ratio (SR) and scale mass (in mg/L of produced water) in the pilot producer is potentially very severe and the probability of forming calcium carbonate scale at the production well is high. Produced Ca2+ concentration is high (> 800 mg/l), which makes the equilibrated calcite SR severe (> 500) and results in significant amount of scale mass precipitation. Different flooding strategies were modelled to evaluate a variety of flood design options to mitigate scale risks (varying slug size, Na2CO3 concentration, and volume of softened pre-flush brine), with marginal impact on scale formation. When the high permeability contrast of the different layers is reduced (to mimic gel injection), calcite SR and precipitated scale mass is significantly reduced to manageable levels. The option of injecting a weak acid in the production well downhole can suppress most of the expected calcite scale through reduction of the brine pH in the produced fluid stream for the ASP flood. Weak acid concentrations in the range of 4,000 to 5,000 mg/l are forecast to mitigate scale formation.

An Experimental Study on Efficient Demulsification for Produced Emulsion in Alkaline/Surfactant/Polymer Flooding

Tertiary oil recovery technologies, exampled as alkaline/surfactant/polymer (ASP) flooding, can enhance oil recovery (EOR) as an important oil displacement technology noteworthy in the present oilfields. However, it is the fact that the produced emulsion droplets have strong electronegativity, which will lead to the destabilization of electric field and affect the dehydration effect in the process of electric dehydration. This paper innovatively proposed an efficient demulsification scheme, which uses platinum chloride (PAC) as a chemical regulator to control electric field destabilization through the charge neutralization mechanism, and then introduces demulsifier to promote oil-water separation. Furthermore, the dehydration temperature, power supply mode and electric field parameters are optimized so as to achieve superior dehydration effect of ASP flooding produced liquid. The results indicate that PAC as a chemical regulator by exerting charge neutralization and electrostatic adsorption mechanism could reduce the electronegativity of the emulsified system, decrease the peak current of dehydration, shorten the duration of peak current of dehydration, improve the response performance of the electric field, and increase dehydration rate in ASP flooding dehydration process. When the demulsifier dosage is 100 to 120 mg/L, using the composite separation process with the dehydration temperature of 45 to 50 °C for the thermochemical separation stage and 60 °C in the electrochemical dehydration stage and AC-DC composite electric field or pulse electric field can achieve better dehydration effect. The investigations in this study will provide support and basis for the efficient treatment of ASP flooding produced emulsion.

Adsorption of anionic surfactant on surface of reservoir minerals in alkaline-surfactant-polymer system

Alkaline-surfactant-polymer (ASP) flooding is significant to the oil and gas industry due to synergistic interaction between alkaline, surfactant and polymer. However, chemical losses due to adsorptions of surfactant and polymer on the rock surface could lead to inefficiency of the process. There are also significant uncertainties on adsorption mechanism when surfactant is flooded with presence of alkaline and polymer. This study highlights the static adsorption tests using anionic sodium dodecyl sulphate (SDS), hydrolysed polyacrylamide (HPAM) and sodium carbonate (Na2CO3) as the surfactant, polymer and alkaline, respectively. Sand particles and kaolinite clay were used as the reservoir minerals. The adsorption tests were conducted at various surfactant concentrations ranging from 50 to 2000 ppm. Sodium chloride (NaCl) concentration was investigated from 0 to 2 wt.%, while the local sand and kaolinite was mixed in surfactant solution at a fixed mass to volume ratio of 1:5. The static adsorption test was conducted by shaking the mixture samples and centrifugation before analysing the supernatant liquid using UV-Visible spectrophotometer. The results showed that the surfactant adsorption was higher on kaolinite compared to sand particle. The higher the salinity, the higher the adsorption of surfactant due to higher ionic strength. The adsorption of SDS surfactant on sand particles and kaolinite was lesser in ASP system compared to the presence of surfactant solution alone. Thus, it can be concluded that the presence of polymer and alkaline in ASP solution have great potential to reduce the surfactant adsorption on both sand particle and kaolinite.

The Effect of Silica Dissolution on Reservoir Properties during Alkaline-Surfactant-Polymer (ASP) Flooding

Chemical flooding is one of the effective methods to recover large volumes of oil from sandstone formations after primary depletion. However, silica dissolution often occurs during Alkaline-Surfactant-Polymer (ASP) flooding, affecting the petro-physical properties of the formation. To address this issue, samples from Berea sandstone formations were treated with various brine solutions, through static tube tests and core flooding experiments. Analytical tests such as DR/2800 spectrophotometer and scanning electron microscope were used to evaluate the silica solubility and the alteration in mineral content. The results indicated that the silicate contents decreased after the saturation due to silica solubility in the solution. Increasing brine salinity to 40,000ppm and introducing Magnesium and Calcium ions to the solution, reduces the silicate contents by 5.03 % and 7.32 %. Moreover, saturating the samples with ASP solution, further reduced the silicate contents by 14.86 %. This reduction is associated with a relative increase in silica solubility and pH of the solution. Silica dissolution affects the pore microstructure, which resulted in increasing the porosity and pore volume after the core flooding. The injection of the ASP solution increased the porosity by 5.83%, thus the pore volume increased from 17.72 to 18.76cc. This is associated with the high silica solubility and the increase of solution pH in the ASP solution. The permeability of the samples generally reduced after the core flooding, due to the silica solubility. However, injecting the ASP solution, resulted in a major reduction of the permeability by more than 75%. These changes in the petro-physical properties can lead to severe formation damage, and affect hydrocarbon production. This study assists in understanding the impact of silica dissolution during ASP treatment and addresses the factors involved. Efficient utilization of chemical flooding can help mitigating silicate scaling within the formation, and extend field productivity.