Produced Water Explained: Where It Comes From, What It Carries and Where It Is Allowed to Go
Crude oil rarely travels alone. What reaches the surface at an oilfield is a three-phase mixture, and once gas and bulk liquids are separated out, the remaining water — the produced water — becomes one of the largest waste streams the industry has to manage. Understanding where it comes from, what it carries and where regulations allow it to go is the starting point for any treatment design.
Two Sources, One Stream
Produced water is the oilfield wastewater left after the water-laden production fluid lifted from the reservoir has passed through oil, gas and water separation. It combines two origins: formation water trapped in the reservoir since deposition, and injected water introduced in mid-to-late field life to maintain reservoir pressure and sweep oil toward the wells. As a field matures, the water cut climbs and the volume of this stream can dwarf the oil itself.
The Regulatory Numbers That Reshaped Practice
Rules, more than any single technology breakthrough, drove modern treatment design. In 1992, fifteen North Atlantic states and the European Union signed the OSPAR Convention for the Protection of the Marine Environment of the North-East Atlantic, which required reductions in oil and gas discharges and set a limit of 40 mg/L of dispersed oil for non-land-based oily water. Norway went further: White Paper No. 58 of 1998 called for a substantial cut in oily waste and hazardous chemicals by 2005 and a target of zero environmentally harmful discharges, and required that from 2006 produced water discharged offshore contain less than 30 mg/L of dispersed oil. The response worked — by 2003 the average oil content of produced water discharged in the Norwegian sector of the North Sea had fallen to 16.9 mg/L.
China followed a parallel track. The Integrated Wastewater Discharge Standard (GB 8978-2002) caps oil in discharged water at 10 mg/L for primary and secondary discharge and 30 mg/L for tertiary discharge. The Code for Design of Oilfield Produced Water Treatment (GB 50428-2015) goes a step further and requires treatment facilities to be designed, built and commissioned together with the crude oil dehydration facilities they serve.
Why This Water Is Difficult
- Volume and variability: flow rates and quality swing widely with geological conditions, development stage and site operations.
- Oil in four physical states: concentrations reach 1,000–2,000 mg/L, present as free oil (droplets above 100 μm), dispersed oil (10–100 μm), emulsified oil (0.1–10 μm) and dissolved oil with droplets down to a few nanometres.
- Corrosive biology: sulfate-reducing bacteria (SRB), saprophytic bacteria (TGB) and iron bacteria multiply in the stream and accelerate equipment corrosion.
- Residual chemicals: chemical flooding, polymer flooding and alkali-surfactant-polymer flooding leave polymers and additives behind that resist conventional separation.
- Fracturing flowback: high in suspended solids, oil, chemical oxygen demand, salinity and toxicity — a recognised bottleneck for green development.
Three Destinations for Treated Water
Worldwide, produced water ends up in one of three places: reinjection into the formation, reuse after simple treatment, or treatment to discharge standard. Which route wins depends on local regulation, the production environment, water characteristics and treatment cost.
Shengli Oilfield shows what full-loop resource recovery looks like. Of the 780,000 tonnes of produced water generated there every day, 651,000 tonnes go back by reinjection, and the remaining 129,000 tonnes are converted into a resource through biological technology. Reverse osmosis cuts salinity from 19,000 mg/L to 110 mg/L and hardness from 1,450 mg/L to zero — every index better than tap water. In shale oil development at Jimsar, Tuha Oilfield has blended and reused 11,294 m³ of produced water for fracturing, saving about RMB 426,000 in water purchase and reinjection fees.
When Treatment Falls Short
Skipping or under-treating this stream is expensive in every direction. Discharged untreated, it pollutes soil and water sources and can even create air pollution or fire risks. Reinjected without adequate treatment, it breeds bacteria and lets mechanical impurities plug the formation, raising injection pressure and eroding waterflood performance and ultimate recovery. Every tonne of poorly treated water also adds load back onto the dehydration and water treatment facilities downstream.
New Directions Worth Watching
Treatment objectives have shifted from plain compliance toward resource recovery, low cost and high efficiency. Sinopec completed China's first produced water resource-recovery station at the Yuanba high-sulfur gas field in 2018, using electrocatalytic oxidation combined with high- and low-pressure reverse osmosis. Shengli's biological dual-membrane train at the Dan-14 water injection station treats 200 m³ per day and has run stably for more than three years. Even waste heat is on the table: produced water leaves the process fairly warm, at 50–80 °C, and recovering that heat matters for energy-saving field design. Changqing Oilfield has gone as far as trialling on-site hydrogen production by electrolysis of gas-field produced water without purification — the first industrial wastewater application of direct seawater hydrogen technology.
The engineering conclusion is straightforward. Produced water is not one problem but a family of them, and the right train depends on oil droplet size distribution, salinity, chemical residues and the destination you need to hit. Operators who match the process to those variables — rather than copying a neighbour's flowsheet — are the ones who stay compliant at a cost they can live with.