Produced water: composition, treatment and disposal

There is water in every reservoir. In the oil-bearing part it fills some of the pores and does not move; this is irreducible water. Below the oil–water contact (the level under which there is only water) and outside the oil-bearing contour (the edge of the oil zone), the water fills the pores completely. While a well gives water-free oil, no water appears in the production. It appears when bottom water (water from below the oil) or edge water (water from around the oil zone) is drawn up to the well, or when the front of the injected water arrives (Why water is injected: pressure maintenance and oil displacement, Water and gas coning). Gas wells also bring up condensation water: vapour that was in the reservoir gas and condensed on cooling. It is almost fresh.

The share of water in the produced liquid is called the water cut $\text{WC}$, and the ratio of water to oil is the water–oil ratio: $\text{WOR} = \text{WC}/(1 - \text{WC})$. At a water cut of 50% there is one cubic metre of water for every cubic metre of oil, at 90% there are nine, and at 95% nineteen. So in a mature field the main work is to lift, separate and inject water.

In a field under waterflooding, with time there is several times more water than oil (loads on the facilities over the life of the field). In the example of the lesson on field facilities, in year 20 of the project the field produces 12,148 m³/d of water and 652 m³/d of oil: the water cut is 94.9%, and there are 18.6 m³ of water for every cubic metre of oil. The water is separated in stages. Most of it is removed first, at the preliminary water removal unit at the booster pump station (the station that pumps the liquid onward), and the rest during oil treatment at the central processing facility. From there the water (in Russian-language practice often called “water from under the oil”) goes to treatment, and then to the water injection pump stations of the pressure maintenance system.

Other waste streams of the field join the produced water: the wash water of the oil desalting unit, the water drained from the bottom of sales tanks, rain and snowmelt runoff from the sites, and at offshore facilities the water used to wash equipment and the water displaced from oil storage. We treat them together with the produced water, but first we check that they are compatible with it (that mixing does not form deposits).

Formation water is a solution of salts, from fractions of a gram to more than three hundred grams per litre. The lesson on formation water covers how salinity (the amount of dissolved salt) is expressed, and how grams per litre differ from ppm. Most of the salt is sodium and chloride ions (charged particles of dissolved salt). For the field, more important are the ions that form poorly soluble compounds with each other: calcium, barium, strontium, iron, bicarbonate and sulfate. Besides salts, the water carries everything it met on the way from the reservoir to the separator.

There are two kinds of oil in water. Dispersed oil is droplets from fractions of a micrometre to several hundred micrometres in size. They can be separated, because oil is lighter than water. Dissolved hydrocarbons and organic matter are individual molecules, above all aromatic hydrocarbons and organic acids. Settling cannot separate them. For injection into the reservoir, dispersed oil matters most. For discharge into a water body, both kinds matter.

The droplet size decides almost everything. Large droplets form when the phases separate in a separator. Small ones form when the flow passes a choke, a control valve or a centrifugal pump at high velocity: in the shear (the rubbing of fast layers of liquid against each other), droplets break up, and one droplet of 100 µm turns into hundreds of droplets of 10–20 µm. Small droplets are also stabilised by fine solids, asphaltenes (heavy components of oil) and surfactants (surface-active substances), which coat them and keep them from merging. This gives the first rule of water treatment: separate the oil before the flow passes through devices that break up droplets, and choose pumps and valves with low shear.

Two forces act on an oil droplet in still water: the buoyancy force (the difference between the weights of water and oil in the volume of the droplet) and the resistance of the water, which grows with velocity. Very soon they balance, and the droplet rises at a constant velocity. For small droplets, around which the water flows slowly and smoothly, this velocity is given by Stokes' law, the same law that describes the settling of drilled cuttings in tanks and centrifuges (drilling fluid cleaning).

Now suppose that the water does not stand still but flows through a settling tank of area $A$ (seen from above) at a rate $q$, and that we skim the collected layer of oil off the top. The droplet must rise to this layer before the water carries it to the outlet. The deeper the tank, the longer the droplet must rise, but also the longer the water stays in it: the retention time $AH/q$ grows with the depth $H$ in exactly the same way as the path of the droplet. The depth cancels, and a droplet that started at the bottom has time to rise if its rising velocity is not less than the surface loading (or overflow rate) $v_c = q/A$, the flow rate divided by the area. The loading is often expressed in metres per hour: this is cubic metres of water per hour per square metre of area.

This is how plate separators (thin-layer settlers, also called corrugated plate interceptors) are built: a pack of parallel plates inclined at 45–60°, with a gap of a few centimetres. The horizontal projection (the area covered when seen from above) of a pack of $n$ plates of length $L$ and width $b$ at an inclination $\theta$ is $nLb\cos\theta$. The plates are made corrugated: the oil collects on the ridges, the droplets merge there into large ones and rise along the plates, and the suspended solids slide down.

The smallest droplet that is caught does not yet say how much oil will leave with the water. This depends on what share of the oil is in small droplets. We measure the droplet size distribution on samples, under a microscope or with laser particle analysers, and express it as shares of the oil volume in size classes. An ideal settling tank with a horizontal flow catches the droplets of each class in the share $(d/d_{\min})^2$, but not more than one. Adding up the contributions of the classes gives the share of the oil that it will catch.

The water separated in the separators and at the preliminary water removal unit (Oil treating: separators, dehydration, desalting and stabilisation) carries from hundreds to several thousand milligrams of oil per litre. One vessel cannot clean it. Each stage takes the droplets that the previous one did not hold, from large to small. The oil that is caught (recovered oil) goes back to oil treatment, and the sediment and sludge are collected and disposed of separately.

A hydrocyclone replaces gravity with centrifugal force (the outward push in spinning water). In a vessel about 35 mm in diameter the water spins at a velocity of the order of 10 m/s, and at a radius of 1 cm the centrifugal acceleration $v^2/r$ = 10,000 m/s². This is about 1019 times the acceleration due to gravity. By Stokes' law a droplet moves towards the axis that many times faster. A droplet of 10 µm, which in a settling tank rises 5.4 cm in an hour, shifts by a centimetre in 0.65 s in a hydrocyclone. So a few tens of such vessels in one casing do the work of a tank, and the rolling of an offshore platform does not disturb them. The estimate is rough: the acceleration and the path of the droplet change along the length of the vessel.

Chemicals help too. We dose demulsifiers, which break the emulsion of water in oil, already into the production of the wells. For the reverse emulsion (oil droplets in water) we use other chemicals: reverse demulsifiers and flocculants. They neutralise the electric charges of droplets and particles and gather them into flocs (loose clumps), which rise more easily or are caught by a filter. We choose the chemicals by tests on fresh samples, because an unsuitable chemical can even make the emulsion more stable.

The oil in water content (OiW) is the main indicator of how well the treatment works. We measure it at the inlet and the outlet of each stage and before injection or discharge, and we express it in milligrams per litre. For almost fresh water this is the same as ppm, and for brines the numbers differ by the density of the solution. The difficulty is that “oil” in water is a mixture of substances, and different methods see different things in it. In Russian-language analysis methods and standards this indicator is usually called the content of petroleum products.

• Place of sampling. We take the sample after a section where the flow is mixed, not from the upper or stagnant (still) part of the pipe, where droplets collect.
• Containers and time. Oil sticks to plastic and to walls, droplets rise in the bottle, and bacteria break the oil down. So we take the whole sample into glass, extract it in the same container, and analyse it quickly or preserve it.
• Inline analysers (usually fluorescence ones) show changes in real time, but their readings are checked regularly against the laboratory method accepted for this water.
• Average and instantaneous values. Discharge limits are usually set on the average over a period, weighted by flow rate. A short peak during filter washing or start-up can be several times higher than the average.

Scale starts when the water becomes supersaturated with a salt (it holds more of the salt than it can keep dissolved; salts, saturation index and the mass of the precipitate). In a treatment system there are three causes. The first is a fall of pressure: carbon dioxide leaves the water, the pH (the acidity of the water) rises, and calcium carbonate drops out, in separators, at chokes and in heat exchangers, where heating also lowers its solubility. The second is the mixing of incompatible waters, either produced waters of different horizons (producing layers) or produced water with water from another source: barium and strontium sulfates drop out right in the pipes and vessels (water compatibility). The third is hydrogen sulfide and iron: iron sulfide drops out as a fine black suspension, which clogs filters and stabilises emulsions.

Against salts, we dose scale inhibitors, in parts per million but into all of the water, so a field uses tonnes of them a year. We inject the inhibitor before the place where supersaturation starts. We choose it for the salt, the temperature and the other chemicals, and we monitor its residual concentration and the ion balance: if there is less barium at the outlet of the system than at the inlet, barite (barium sulfate) is dropping out somewhere. Deposits of barium and strontium sulfates can be weakly radioactive, and they are handled under the radiation safety rules.

Corrosion in a produced water system is caused by dissolved gases and bacteria. Carbon dioxide forms carbonic acid with water. The corrosion rate grows with its partial pressure and with temperature, until at high temperatures a protective film of iron carbonate forms on the steel. Hydrogen sulfide gives a film of iron sulfide, pitting corrosion (corrosion that eats small deep holes) and, for high-strength steels, sulfide stress cracking. There is no oxygen in formation water. It gets into the water through open tanks, pump seals and breather valves (valves through which a tank “breathes” air in and out), and it is the most dangerous: even tenths of a milligram per litre noticeably speed up corrosion and cause pits, and together with hydrogen sulfide, oxygen produces elemental sulfur and speeds up corrosion still more. Sulfate-reducing bacteria (SRB) live under deposits, produce hydrogen sulfide and cause pitting corrosion.

• A closed system: tanks under a gas blanket, sealed pumps, and no contact of the water with air.
• Materials: fibreglass pipes and pipes with an internal coating for water, and resistant steels where needed. Outside, buried pipelines are protected by a coating and by cathodic protection (a small electric current that keeps the steel from corroding).
• Chemicals: corrosion inhibitors that form a film on the metal, and biocides, either continuously in small doses or from time to time in shock doses.
• Monitoring: corrosion coupons (small metal samples left in the flow and weighed later) and corrosion rate probes, wall thickness measurements, and water analyses for iron and bacteria.

We decide where materials resistant to hydrogen sulfide are needed from its partial pressure in the gas that the steel and the water are in contact with. The international standard ISO 15156 (NACE MR0175) requires carbon and low-alloy steels to resist sulfide stress cracking when the partial pressure of hydrogen sulfide is 0.3 kPa (0.05 psi) or more. Partial pressure is not concentration: with the same share of hydrogen sulfide in the gas, it grows with pressure.

• Injection into the productive reservoir for pressure maintenance is the main route on land: the water is disposed of and at the same time displaces oil. The requirements for its quality and compatibility are set by the reservoir (Water injection systems).
• Injection into disposal horizons (disposal wells) means injection into non-productive formations that are reliably isolated from fresh underground water. A formation that takes water, a reliable well casing and pressure monitoring are needed. The water brings no benefit to production, and energy is spent on injection.
• Discharge into water bodies and into the sea is allowed only after treatment to the set standards, and under permits.
• Storage facilities: storage ponds, filtration fields (fields where the water seeps into the ground) and evaporation ponds (this is what the Water Code calls them). They need permits and protection of the groundwater, because evaporation leaves salts and petroleum products on the surface.
• Reuse after desalination (removing the salt), for industrial needs or irrigation. It is rare, because desalination of brines is expensive.

Water Code (2025), Article 123, paragraph 4

Underground water taken out incidentally in subsoil use may be discharged, or injected into the subsoil, only with environmental permits and permits for special water use, except for the injection of formation water produced with hydrocarbons for pressure maintenance.

Environmental Code (2021), Article 213, paragraph 3

The injection for pressure maintenance of formation water produced with hydrocarbons, of sea water and desalinated water, and of industrial water with a salinity of 2000 mg/L or more is not considered a discharge of pollutants, and no limits on permissible discharge are set for it.

Subsoil Code, Article 148

When subsoil users under different contracts develop fields jointly, one of them may inject its treated formation water into the reservoir of the other's field to maintain pressure. A subsoil user may entrust the treatment of produced and other water, including sea water, for injection into the reservoir to the owners of the necessary infrastructure.

Subsoil Code, Article 159

In offshore exploration and production, the discharge of waste into the sea and its burial on the seabed are prohibited. Industrial and other wastewater is discharged into the sea only with the permission and under the control of the authorised body in the field of environmental protection, and after treatment to the set standards.

Environmental Code, Article 273, subparagraphs 8 and 9

In the state nature reserve zone in the northern part of the Caspian Sea, the discharge of waste into the sea is prohibited, and so is the discharge of wastewater, except for a limited list of treated waters (for example, sea water cleaned of oil). They are discharged only under permits of the authorised bodies.

A practical conclusion follows from these rules: returning produced water to the reservoir to maintain pressure is the simplest route as far as permits go, while injection into disposal horizons and discharge need separate permits and standards. This summary is short and follows the texts of the codes as of October 2026. The project of a particular field and the permits for its facilities set the exact requirements (State regulation of field development).

The pressure maintenance system injects water that replaces the underground withdrawal (the volume of fluid taken out of the reservoir; voidage replacement). While there is little produced water, almost all the water for injection is taken from a source: an aquifer (an underground layer that holds water), the sea or a river. As the water cut grows there is more produced water, and it displaces the water of the source. The water balance shows where the boundary will lie and whether there will be more produced water than needs to be injected.