1.1 Introduction
Produced water (PW) is the wastewater separated from production fluid during oil and gas (O&G) production (Larson, 2018; WEF, 2018; Jiménez et al., 2018). PW is generated from both conventional and unconventional sources such as the coal bed methane, tight sands, and gas shale (Jiménez et al., 2018). PW includes formation/connate water, flowback water (injected water), and condensation water. Amount of PW generated during production of crude oil and natural gas can be as high as ten times the volume of hydrocarbon produced. PW volume can rise to as much as 98% of production fluids (e.g., at late stage of oil (gas) production), when production is no longer economical (Larson, 2018; Gray, 2020; Lusinier et al., 2019). Thus, the ratio of PW to oil varies from well to well, and over the life of the well. Typically, PW to oil volume ratio is over 3:1 and can be as high as over 20:1 (Larson, 2018; Jiménez et al., 2018). The global PW production is approximately 10.44 billion gallons/day (Jiménez et al., 2018), whereas the U.S. produced an estimated 890 billion gallons/year of PW in 2012 (GWPC, 2019).
PW contains numerous chemicals, some of which are toxic organic and inorganic compounds (Jiménez et al., 2018). Physical and chemical properties of PW vary, depending on the geographic location of the field, the geological formation, the extraction method, and the type of hydrocarbon product being produced. Furthermore, PW may include chemical additives, which are dosed in during drilling to treat or prevent operational problems and to enhance subsequent oil/water separation (Jiménez et al., 2018). Thus, both the flow rate and PW composition change over time, leading to varying PW management strategies (WEF, 2017). Multiple separation steps are typically required to separate oil and water from PW (WEF, 2017). Most regulatory policies and technical requirements focus on treatment of O&G content; salt content is also critical in onshore operations (Jiménez et al., 2018). The major PW constituents of concern may be categorized in the following groups: salts, expressed as salinity, total dissolved solids (TDS), or electrical conductivity; oil and grease; BTEX (benzene, toluene, ethylbenzene, and xylenes); PAHs (polyaromatic hydrocarbons); organic acids; phenol; natural inorganic and organic compounds, e.g., chemicals that cause hardness and scaling such as calcium, magnesium, barium, carbonate, and sulfates; and chemical additives used in drilling, fracturing, and operating the well (e.g., biocides and corrosion inhibitors) (Arthur et al., 2011).
The degree of PW management depends on the site’s treatment requirements and typically includes deep well injection/disposal, reinjection, evaporation ponds, surface water discharge, treatment, and reuse (WEF, 2017; Dores et al., 2012). Local water scarcity, legislation, risk of formation plugging, high costs associated with PW disposal, quality of water used in enhanced oil recovery (EOR), and increasing demand for water in production operations are some of the drivers for appropriate PW management techniques. Due to scarcity of water resulting from climate change-induced drought, regulations have become more stringent, disposal method costs have increased, and beneficial reuse is becoming a more viable option (Larson, 2018; WEF, 2018). PW disposal includes deep well injection and discharge into surface water, which requires treatment to remove dispersed and dissolved oil, solids, and toxic compounds. In offshore operations, the common practice is to discharge treated PW to the sea. Hence the main treatment objective is to reduce oil and grease to levels required to meet discharge regulations and environmental standards (Dores et al., 2012).
Reinjection into petroleum formations for hydraulic fracturing, waterflooding to maintain the pressure in the reservoir and displace the petroleum fluids, and EOR are the most widely used PW management strategies practiced in the industry. Reinjection of PW is generally considered the most environmentally friendly option because it substantially reduces the freshwater or seawater consumption (Lusinier et al., 2019). Reinjection of PW requires removal of suspended solids (SS) to avoid formation plugging. In addition, scale forming constituents such as barium (Ba) and calcium (Ca) must also be removed to minimize scaling.
Water injection is usually utilized as a secondary oil recovery technique in oil fields when reservoirs deplete. By contrast, water is not typically injected in gas reservoirs; hence, PW from gas fields is mostly formation water and condensed water. PW from gas reservoirs is generally much less in volume than that produced from oil fields (Ahmadun et al., 2009). However, due to the higher concentrations of volatile hydrocarbons, PW discharged from gas fields is much more toxic than the PW from oil wells (Duraisamy et al., 2013; Jiménez et al., 2018).
Currently, the majority of PW generated at onshore O&G facilities is reinjected underground either for disposal or for EOR processes. Thus, the major focus of onshore facilities is the types of treatment technologies mainly designed for dispersed O&G and SS to avoid plugging and pumps damage (WEF, 2017, 2018). The common practice for offshore operations is to discharge the treated PW to the sea, leading to the main treatment objective of reducing O&G to acceptable levels and mitigating toxicity impacts on aquatic fauna and flora. Moreover, the requirement for fracturing fluid has changed over the years, leading to different treatment requirements (WEF, 2017). Depending on the location of the onshore O&G facilities, different types of treatment technologies are available, including primary (e.g., hyd...
