Evaluating scale deposition and scale tendency of effluent water mix with seawater for compatible injection water

Abstract

Water injection technique is contributing millions of oil barrels on a daily basis to the global oil supply; one of the challenges faced by such an important production method is scale buildup due to the different dissolved solids and high salinity of the injected water. For produced water or effluent water, pretreatment is a critical step before the injection process to reduce the risk of scale potential and well formation damage. One of the beneficial treatments of the effluent water is to be mixed in a compatible ratio with seawater, especially for those countries with easy access to seawater. Thus, the objective is to find a compatible mix ratio with seawater as one way of solving effluent water reuse without increasing the risk of scale and formation damage during water injection operation. In this study, effluent water samples were collected from different oilfield geographical locations in Kuwait, and then the samples were analyzed in the laboratory for their physical and chemical properties to select the most compatible one for mixing with seawater. The selected effluent water was then mixed with seawater in 1:1 ratio to evaluate the compatibility of the mix in terms of sulfate formation and scale tendency. The selected North field/seawater was tested under 75 ºC and 1000 PSi in an autoclave. The filtered precipitates were characterized by energy-dispersive spectroscopy (EDS) and scanning electronic microscope (SEM) micrographs. Further, the formations of sulfate were detected by X-ray diffraction (XRD). The OLI ScaleChem software was used to investigate the composition of mineral scales that may occur in the water mix at different ratios ranging from 0 to 100% to compare it with the actual water mix finding. In the effluent waters comparison part, North field water showed low pH (4.6) and alkalinity, as well as moderate TDS (190,000 MG/L). The main constituents of the scale deposited at the selected water mixing ratio were calcium sulfate CaSO 4 and silicon oxide detected by XRD. However, the amount of barium sulfate was not presented in the precipitates indicating that all of it went in the liquid phase. The study concludes that at downhole conditions, the compatible mix of North Kuwait effluent water with seawater has high risk of barium sulfate in comparison with other common scale such as calcium sulfate, calcium carbonate and strontium sulfate (SrSO 4). Also the study revealed that the prediction of different seawater ratios showed that at 70% seawater concentration, the barium sulfate concentration drops and consequently the scale risk reduced.

Seawater-Based Fracturing Fluid: A Review

“…Other scaling issues that occur from sulfate scaling are with barium sulfate (BaSO 4 ), which is a serious concern in most production areas across the world (e.g., the North Sea, West Africa, offshore Brazil, and the Gulf of Mexico). ,, Because of their strong reactivity, barium cations produce a barium sulfate deposit wherever sulfate ions are present. This deposit has the lowest solubility of any mineral scale and is resistant to acid treatment. − Phosphonate or polymeric scale inhibitors are the most commonly used SIs to inhibit the formation of barium sulfate. In addition, the synergistic effect of mixing two (or more) SIs for improved scale inhibition efficacy can be employed …”

“…This deposit has the lowest solubility of any mineral scale and is resistant to acid treatment. 113 − 115 Phosphonate or polymeric scale inhibitors are the most commonly used SIs to inhibit the formation of barium sulfate. In addition, the synergistic effect of mixing two (or more) SIs for improved scale inhibition efficacy can be employed.…”

Enhanced Oil Recovery in Terrigenous Oil Fields Using Low-Salt Water

“…The effectiveness of the low-salt method of enhanced oil recovery (EOR) was proven both in secondary and tertiary development methods, where an increase in oil production by up to 15% was observed. When using the secondary recovery method, the use of the technology under discussion results in a later water breakthrough into the well compared to the injection of seawater or high-salinity water (Mahmoud, Elkatatny & Abdelgawad 2017;Al-Samhan et al 2020;. During the tertiary recovery method, lightly salted water has shown the potential to displace additional oil (Rock et al 2018;Maya Toro et al 2020).…”

Enhanced removal of scaling cations from oilfield produced water by carrier mineral floatation

“…Various protocols have been proposed to inhibit oilfield scale, mainly divided into reinjection water quality adjustment and chemical methods (Ghalib & Almallah 2017;Al-Ghouti et al 2019). Al-Samhan et al (2020) mixed the produced water with seawater in a compatible ratio to reduce the risk of scaling potential and well formation damage. When treating the North Kuwait effluent water, they pointed out that the barium sulfate concentration drops and consequently the scale risk reduced at 70% seawater concentration.…”