Oilfields are producing more water than ever, pushing operators toward compact, multi‑stage treatment trains that strip oil from thousands of mg/L down to discharge‑ or reinjection‑grade. The data and design logic point the same way: gravity, flotation, then membranes — sized and sequenced to the local rulebook.
Oil wells have a water problem. For every barrel of oil, fields typically bring up 3–4 barrels of water (water–oil ratio ≈3–4:1) (www.sciencedirect.com). Globally, daily produced water volumes have swelled from under 30 million barrels per day in 1990 to about 100 million barrels per day by 2015 (www.sciencedirect.com).
In Indonesia, where oil output is roughly 860,000 barrels per day, mature fields generate on the order of 8 million barrels per day of produced water — around 1.27×10^6 m^3 per day — with water cuts rising to ~90% in older reservoirs (www.researchgate.net) (www.researchgate.net) (www.researchgate.net).
What comes up is a complex brine: dispersed crude oil (both free and emulsified droplets), suspended solids (formation sand and clays), dissolved organics and salts (total dissolved solids, TDS, often 10^4–10^5 mg/L), plus trace metals and NORM (naturally occurring radioactive material) (www.grafiati.com) (www.researchgate.net). Before treatment, oil concentrations typically sit in the hundreds to thousands of mg/L (www.researchgate.net).
Regulatory discharge thresholds and reuse specs
Environmental limits set the engineering targets. Indonesia’s Ministry of Environment Regulation 19/2010 caps onshore oil and gas wastewater at Oil & Grease ≤25 mg/L and COD ≤200 mg/L (www.researchgate.net). If offshore produced water is offloaded onshore, it must meet these stricter onshore standards (www.researchgate.net) (www.researchgate.net).
Many offshore regimes target ≤30 mg/L oil in water (e.g., OSPAR) with emerging goals of 15 mg/L or even “zero discharge” on new facilities (pubs.acs.org) (pmc.ncbi.nlm.nih.gov). Reinjection specifications are tighter still (often ≤5 mg/L oil and ≤10 mg/L solids) (www.researchgate.net). That reality makes multistage treatment necessary: operators must knock oil down from ~1000+ mg/L to single‑digit mg/L for reuse or into the 10–30 mg/L range for discharge (www.researchgate.net) (www.researchgate.net).
Primary separation: gravity and hydrocyclones
The first stage removes “free” oil and coarse solids, with typical primary units sized to remove 70–90% of oil by volume. Two‑ or three‑phase gravity separators (API tanks) and corrugated‑plate interceptors (CPIs) coalesce large droplets (>100 μm). An API separator usually yields effluent oil around 150–300 mg/L, often cutting concentration from ~2000 mg/L down to a few hundred mg/L (www.researchgate.net).
De‑oiling hydrocyclones use centrifugal force to strip smaller droplets; at an optimal inlet velocity of ~4 m/s, a cyclone can remove about 90% of dispersed oil (www.mdpi.com). One reported test of a 60 mm cyclone reduced oil from 330 mg/L to 120 mg/L (≈64% removal) (www.researchgate.net). In practice, about 90% of offshore produced‑water units incorporate cyclonic separators — often multiple units in parallel — to leverage their small footprint (www.mdpi.com).
On compact skids, operators often specify de‑oiling packages such as hydrocyclone deoilers. Primary trains that include screens and skimming systems are part of standard physical separation toolkits used upstream.
Outcome: after primary separation, >80% of suspended solids and most large oil droplets are removed, but residual oil remains in the hundreds of mg/L.
Secondary flotation and media filtration
The second stage targets emulsified oil droplets and fine solids. Flotation units — induced gas flotation (IGF) or dissolved‑air flotation (DAF) — inject fine gas bubbles so 5–50 μm droplets attach and float for skimming, often with a small dose of coagulant. Field operators commonly deploy packaged systems such as a DAF unit to achieve this separation.
Flotation is highly effective, typically removing ≥90% of residual oil (www.researchgate.net) (www.researchgate.net). Under lab‑optimized conditions, a cyclone‑based air flotation unit removed 93.1% of oil, dropping from 1189 mg/L to ≈83 mg/L (www.researchgate.net).
In full‑scale operation, a well‑designed IGF stage typically reduces the few‑hundred mg/L residual oil down into the tens of mg/L, meeting common offshore discharge targets of <30 mg/L (pubs.acs.org). One reported combination — hydrocyclones plus flotation trains — achieved ∼90% removal (www.researchgate.net). Media/coalescer filters then trap remaining particulates: industrial multi‑media filters after IGF typically cut TSS to single‑digit mg/L.
Chemical aids matter. Coagulants or demulsifiers, added ahead of IGF, can break stubborn emulsions and enable ∼70–90% O&G removal, with final oil ≪50 mg/L. This is where upstream teams turn to dosing programs with coagulants in flotation cells. In emulsified streams, an upstream demulsifier injection is often paired with the flotation step.
As performance benchmarks: secondary treatment normally yields effluent O&G in the 10–30 mg/L range. Meeting Indonesia’s 25 mg/L “produced water” limit is routine with a primary + IGF system (www.researchgate.net). Combined primary + secondary stages typically remove >95% of total oil by volume. Dissolved hydrocarbons (COD) are largely untouched at this point, but after IGF/filtration, suspended solids are often <10 mg/L and oil‑in‑water falls to ~15–25 mg/L (pubs.acs.org) (www.researchgate.net).
For solids polishing ahead of membranes, operators commonly specify dual‑media beds using sand/silica media. Where fine particulate spikes occur, a final cartridge filter protects downstream units.
Tertiary membranes and reuse targets
When reuse or reinjection is on the table, tertiary treatment targets near‑zero oil and very low solids. Typical targets here are <5 mg/L oil and <10 mg/L total suspended solids; for reinjection, strict specifications demand oil <5 mg/L and particles <10 μm (www.researchgate.net).
Membranes are the industry standard at this stage. Tangential‑flow ultrafiltration (UF) or microfiltration (MF) produces filtrate with <5 mg/L dispersed oil (www.researchgate.net). Packaged UF systems such as ultrafiltration skids are standard pretreatment to reverse osmosis.
One field test using spiral‑wound UF + RO on produced water reported 98% salt rejection and oil‑in‑water essentially zero (100% COD removal) (www.grafiati.com). In practice, tertiary units are prefaced by fine filters to <1 NTU (a turbidity unit) to limit fouling. Reverse osmosis, depending on salt content, can then remove dissolved salts to irrigation/drinking‑grade quality. Integrated packages — for example, UF/RO membrane systems — are deployed where reuse value or discharge mandates justify the cost.
Operators choose RO modules to match feed salinity, including brackish water RO for appropriate TDS ranges. Where dissolved organics persist and membranes are not used, highly absorbent media such as activated carbon or advanced oxidation can polish trace hydrocarbons/organics, though these are less common offshore.
Performance data are clear: UF/RO systems routinely deliver single‑digit oil and turbidity. Ciarapica et al. report MF/UF membranes yielding <5 mg/L hydrocarbons in filtrate (www.researchgate.net). A field case in Montana achieved 100% COD removal and a 98% conductivity reduction on produced water via UF + RO, concluding that treatment was cheaper than reinjection (www.grafiati.com). In Indonesia’s context, such polishing would allow reuse for injection or even industrial water. The trade‑off is cost: membranes need periodic cleaning and chemical pretreatment, so tertiary stages are typically justified when reuse value or strict mandates exist.
Data trends and design economics
Rising volumes: worldwide produced water grew about 70% from 1990 to 2015 (www.sciencedirect.com). Offshore water fractions in new wells still reach ~75–80% (www.sciencedirect.com), so any long‑term field plan must budget for large volumes (e.g., India’s aging fields).
Regulatory push: many global operators now aim for “zero discharge” (pubs.acs.org). Indonesia’s 25 mg/L limit for produced water effectively demands near‑zero oil in discharged water (www.researchgate.net), so gravity alone cannot meet target quality for most fields.
Economics: produced water treatment typically accounts for 5–15% of drilling and production costs (www.sciencedirect.com). Reuse can offset this: one study found treating produced water was cheaper than reinjection because the treated water has value (agriculture or injection) (www.grafiati.com). Adding tertiary stages increases CAPEX, but can yield OPEX savings and assured compliance.
Technology adoption: modern platforms favor compact, automated systems. About 90% of offshore produced‑water plants use hydrocyclones due to efficiency and small footprint (www.mdpi.com). Emerging trends include real‑time monitoring, chemical dosing control, and integrated membranes (www.sciencedirect.com). Chemical dosing programs are increasingly automated with equipment such as a dosing pump. Secondary and tertiary units are increasingly skid‑mounted and modular, supported by ancillary systems.
Multi‑barrier design and performance example
A robust treatment train layers stages: an API separator (or CPI) plus a hydrocyclone bank to capture >80% of oil; followed by an induced gas flotation (IGF) unit to float out most remaining oil, achieving ≤25 mg/L O&G then media cartridge/sand filters for fine suspended solids; and, if reuse is desired, UF/RO membranes to polish to <5 mg/L (www.researchgate.net) (www.researchgate.net). Each stage is sized (flow rate, residence time, pressure) for the required throughput and removal. This multi‑barrier approach is aligned with regulations and field data: it meets Indonesia’s 25 mg/L oil limit for discharge (www.researchgate.net) or the ≲5 mg/L target for reinjection (www.researchgate.net).
Sources: industry reviews and case studies (www.sciencedirect.com) (www.researchgate.net) (www.researchgate.net), regulatory documents (www.researchgate.net) (pubs.acs.org), and Indonesian field data (www.researchgate.net) (www.researchgate.net), as cited.
