Produced water refers to reservoir formation water that is co-produced with oil or gas. It incurs operational cost and challenges because it must be separated from the hydrocarbons before sales and can cause production problems such as, emulsion, scale, corrosion, hydrate, etc.

What Is Produced Water?

Difference between Pure Water and Oil & Gas Water.

There are three major fluids that come out of a well, and these are gas, crude oil and water. During the production stages the well not only flow hydrocarbons it also flow water. Produced water is water trapped in underground formations that is brought to the surface along with oil or gas. It is by far the largest volume byproduct or waste stream associated with oil and gas production and also represents a significant component in the cost of producing oil and gas. Management of produced water presents challenges and costs to operators.

The composition of this produced fluid includes a mixture of either liquid or gaseous hydrocarbons, produced water, dissolved or suspended solids, produced solids such as sand or silt, and recently injected fluids and additives that may have been placed in the formation as a result of exploration and production activities. [1]

Sources of water in reservoir

In subsurface formations, naturally occurring rocks are generally permeated with fluids such as water, oil, or gas (or some combination of these fluids). It is believed that the rock in most oil-bearing formations was completely saturated with water prior to the invasion and trapping of petroleum .The less dense hydrocarbons migrated to trap locations, displacing some of the water from the formation in becoming hydrocarbon reservoirs. Thus, reservoir rocks normally contain both petroleum hydrocarbons (liquid and gas) and water. Sources of this water may include flow from above or below the hydrocarbon zone, flow from within the hydrocarbon zone, or flow from injected fluids and additives resulting from production activities. This water is frequently referred to as “connate water” or “formation water” and becomes produced water when the reservoir is produced and these fluids are brought to the surface. Produced water is any water that is present in a reservoir with the hydrocarbon resource and is produced to the surface with the crude oil or natural gas. [2]

Water production Mechanism in oil wells

Numerous technologies have been developed to control unwanted water production, but the nature of the water production must be known in order to design an effective treatment. Once the water production mechanism is understood, an effective strategy can be formulated to control water production. The flow of water to the wellbore can occur through two types of paths. In the first type, the water usually flows to the wellbore through a separate path from that of the hydrocarbons. This type of water production directly competes with oil or gas production. Reducing water production in this case often leads to increased oil and gas production rates and higher recovery efficiencies.

Fig: Production of water from oil and gas well with time.

This type of water production should be the primary candidate for water control treatments. The second type of water production is water that is co-produced with oil usually later in the life of a water flood. Reducing production of this type of water will result in corresponding reduction in oil production.

For water flow to take place in the reservoir, three factors must be present:

Source of Water: The sources of produced water include formation water, aquifer, and injected water. The formation water can be originated from a water saturated zone within the reservoir or zones above or below the pay zone. Many reservoirs are adjacent to an active aquifer and are subject to bottom or edge water drive. Water is often injected into oil reservoirs for pressure maintenance or secondary recovery purposes. The injected water is one of sources of water production problem.

Pressure Gradient: Production of oil and gas from reservoir can only be achieved by applying a pressure draw-down at the wellbore which create a pressure gradient within the formation. Production from a fully penetrating and perforated well results in a horizontal pressure gradient in the formation. However, flow from a partially penetrated well will result in a vertical pressure gradient near the wellbore as well as the horizontal gradient in the formation.

Favorable Relative Permeability to Water: For water to flow through a zone, the water saturation in that zone must exceed irreducible water saturation. As water saturation increases beyond the irreducible saturation, the relative permeability to water increases and relative permeability to hydrocarbon decreases. Oil, gas, and naturawater flow mainly along the path of least resistance, which are usually the higher permeability parts of the reservoir. If the reservoir permeability was uniform throughout the reservoir (horizontally and vertically), and if the reservoir had a uniform geometry, flow will be along a simple line into the wellbore. Because of permeability variations, flow of fluids can be quite complex and not necessarily along the shortest distance to the wellbore. In water-drive reservoirs and reservoir that are subject to water flooding, water sweeps the formation and displaces the hydrocarbon toward producing wells. In such situations, reservoir heterogeneity can result in water channeling through high permeability streaks. Examples of reservoir heterogeneity that could result in channeling include fractures, faults, discontinuous layers, and layering.

Natural fractures, depending on their size, opening and frequency can have significant impact on fluid flow. Natural fractures are usually caused by tectonics, and as such may have preferred patterns. Most reservoirs consist of layers of different permeability either immediately adjacent to each other or separated by impermeable layers (usually shale’s). In the absence of barriers, cross flow can take place between layers. Layering and associated permeability variations are major causes of channeling in the reservoir. As the water sweeps the high permeability intervals, permeability to subsequent flow of the water becomes even higher in those intervals and lower permeability intervals remain upswept.

This leads to premature water breakthrough. Channeling can be further exacerbated by lower water viscosity as compared to oil particularly during water flooding. [3]

Major Components of Produced Water

Knowledge of the constituents of specific produced waters is needed for regulatory compliance and for selecting management/disposal options such as secondary recovery and disposal. Oil and grease are the constituents of produced water that receive the most attention in both onshore and offshore operations, while salt content (expressed as salinity, conductivity, or TDS) is a primary constituent of concern. In addition, produced water contains many organic and inorganic compounds. These vary greatly from location to location and even over time in the same well. Organic constituents are normally either dispersed or dissolved in produced water and include oil and grease and a number of dissolved compounds.

Dispersed Oil: It is an important discharge contaminant, because it can create potentially toxic effects near the discharge point. Dispersed oil consists of small droplets suspended in the aqueous phase. If the dispersed oil contacts the ocean floor, contamination and accumulation of oil on ocean sediments may occur, which can disturb the benthic community. Dispersed oils can also rise to the surface and spread, causing sheering and increased biological oxygen demand near the mixing zone .Factors that affect the concentration of dispersed oil in produced water include oil density, interfacial tension between oil and water phases, type and efficiency of chemical treatment, and type, size, and efficiency of the physical separation equipment. Soluble organics and treatment chemicals in produced water decrease the interfacial tension between oil and water.


Inorganic and Organic Components: Deep-water crude has a large polar constituent, which increases the amount of dissolved hydrocarbons in produced water. Temperature and pH can affect the solubility of organic compounds. Hydrocarbons that occur naturally in produced water include organic acids, polycyclic aromatic hydrocarbons (PAHs), phenols, and volatiles. These hydrocarbons are likely contributors to produced water toxicity, and their toxicities are additive, so that although individually the toxicities may be insignificant, when combined, aquatic toxicity can occur

Soluble organics are not easily removed from produced water and therefore are typically discharged to the ocean or reinjected. Generally, the concentration of organic compounds in produced water increases as the molecular weight of the compound decreases. The lighter weight compounds (BTEX and naphthalene) are less influenced by the efficiency of the oil/water separation process than the higher molecular weight PAHs and are not measured by the oil and grease analytical method.

Organic components that are very soluble in produced water consist of low molecular weight (C2-C5) carboxylic acids (fatty acids), ketones, and alcohols. They include acetic and propionic acid, acetone, and methanol. In some produced waters, the concentration of these components is greater than 5,000 ppm. Due to their high solubility, the organic solvent used in oil and grease analysis extracts virtually none of them, and therefore, despite their large concentrations in produced water, they do not contribute significantly to the oil and grease measurements

Treatment Chemicals: Treatment chemicals posing the greatest concerns for aquatic toxicity include biocides, reverse emulsion breakers, and corrosion inhibitors. However, these substances may undergo reactions that reduce their toxicities before they are discharged or injected.

Produced Solids: Produced water can contain precipitated solids, sand and silt, carbonates, clays, proppant, corrosion products, and other suspended solids derived from the producing formation and from well bore operations. Quantities can range from insignificant to a solids slurry, which can cause the well or the produced water treatment system to shut down. The solids can influence produced water fate and effects, and fine-grained solids can reduce the removal efficiency of oil/water separators, leading to excess of oil and grease limits in discharged produced water. Some can form oily sludge’s in production equipment and require periodic removal and disposal.

Scales: Scales can form when ions in supersaturated produced water react to form precipitates when pressures and temperatures are decreased during production. Common scales include calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, and iron sulfate. They can clog flow lines, form oily sludge’s that must be removed, and form emulsions that are difficult to break

Bacteria: Bacteria can clog equipment and pipelines. They can also form difficult-to-break emulsions and hydrogen sulfide, which can be corrosive.

Metals: The concentration of metals in produced water depends on the field, particularly with respect to the age and geology of the formation from which the oil and gas are produced. However, there is no correlation between concentration in the crude and in the water produced with it. Metals typically found in produced waters include zinc, lead, manganese, iron, and barium. Metals concentrations in produced water are often higher than those in seawater.. Besides toxicity, metals can cause production problems.

Naturally Occurring Radioactive Material (NORM): NORM originates in geological formations and can be brought to the surface with produced water. The most abundant NORM compounds in produced water are radium-226 and radium 228, which are derived from the radioactive decay of uranium and thorium associated with certain rocks and clays in the hydrocarbon reservoir. As the water approaches the surface, temperature changes cause radioactive elements to precipitate. The resulting scales and sludge’s may accumulate in water separation systems. [4][5][6][7]

Problems associated with water production

As discussed above lot of organic and inorganic chemical that are present in produced water beside this produced water also having dissolved gases like H2S and carbon di oxide to certain levels. Following are the common problem that may encounter with produced water in oil wells.

Scaling is the precipitation of dense, adherent material on metal surfaces and other materials. Scale formation at oil producing well screens eventually results in lower oil yields and well failure. In addition, the problem of scale in water flooding occurs all the way from the water injection facilities to the producing well. In general, there are six important regions where scaling can occur during and after injection operations:

  • In the injector wellbore
  • Near the injection-well bottomhole
  • In the reservoir between the injector and the producer
  • At the skin of the producer well
  • In the producer wellbore
  • At the surface facilities.

Calcium sulfate (CaSO4), calcium carbonate (CaCO3), barium sulfate (BaSO4), strontium sulfate (SrSO4), iron carbonate (FeCO3) and iron hydroxides are the most common scales in oilfield environments. In addition, there are some scale deposits in oil field environments that are called pseudo scale; that is, the deposit of a reaction product between two or more anthropogenic-introduced chemicals.

Chemical scale inhibitors may be applied to the piping complexes to prevent scales from slowing the oil extraction process.

Sludge is composed of dissolved solids which precipitate from produced water as its temperature and pressure change. Sludge generally consists of oily, loose material often containing silica compounds, but may also contain large amounts of barium. Dried sludge, with low oil content, looks and feels similar to soil.

Oil production processes generate an estimated 230,000 MT or five million ft3 (141 cubic meters) of TENORM sludge each year. API has determined that most sludge settles out of the production stream and remains in the oil stock and water storage tanks. Like contaminated scale, sludge contains more Ra-226 than Ra-228. The average concentration of radium in sludge’s is estimated to be 75 pCi/g. This may vary considerably from site to site. Although the concentration of radiation is lower in sludge’s than in scales, sludge’s are more soluble and therefore more readily released to the environment. As a result they pose a higher risk of exposure.

Corrosion: The corrosivity of produced fluids is most commonly associated with the presence of hydrogen sulfide, carbon dioxide, organic acids, or oxygen. Chemical corrosion is one area where the application of technology, through the use of corrosion resistant metallurgy, can reduce the use, hence the potential discharge, of chemicals.

Carbon dioxide is the most common corrodent, while hydrogen sulfide poses the most significant risk to human health and the environment. Oxygen is not typically found in unaltered produced fluids. Oxygen is usually introduced as the produced fluids are treated. Most corrosion inhibitors work by adsorbing onto exposed metal surfaces. Corrosion inhibitors are very complex compounds that can be sorted into four generic groups: amine imidazolines, amines and amine salts, quaternary ammonium salts, and nitrogen heterocyclic.

Oil soluble corrosion inhibitors are most commonly used since they are usually the most effective at providing a stable, durable film.

Bacteria in injection water and produced water can contribute to corrosion. The main types of aerobic bacteria that cause problems are slime-forming bacteria, iron-oxidizing bacteria, and sulfur-oxidizing bacteria. However, most of the oilfield corrosion problems arise from the activity of anaerobic bacteria such as sulfate-reducing bacteria

Depends on the analysis of produced water, specific inhibitors/treatment programs are to be selected to address the above problems. [8][9]

Produced Water production Minimization


Within a producing formation, water and petroleum hydrocarbons are not fully mixed; they exists as separate adjacent fluid layers, with the hydrocarbon layer typically lying above the water layer by virtue of its lower specific gravity. Operators try their best to design wells to produce from the hydrocarbon layer. As hydrocarbons are removed from the formation, the pressure gradient changes so that the water layer often rises up in the vicinity of the well, creating a coning effect. As production continues, an increasing portion of the produced fluids will be water. It is challenging to minimize the amount of water produced into the well, but there are some strategies that can be used to restrict water from entering the well bore. These involve mechanical blocking devices or chemicals that “shut off” water-bearing channels or fractures within the formation and prevent water from making its way to the well. Although they help to avoid production of water and its associated environmental impacts, they are generally considered to be in the realm of reservoir and production engineering activities rather than environmental management tools. Options: Mechanical Blocking Devices: Poor mechanical integrity of the casing such as holes from corrosion, wear and splits due to flaws, excessive pressure, or formation deformation contribute to casing leaks. Often casing leaks occur where there is no cement behind the casing. Casing leak results in unwanted entry of water and unexpected rise in water production. In addition, the water entry in the wellbore can cause damage to the producing formation due to fluid invasion. Operators have used various mechanical and well construction techniques to block water from entering the well.

  • Straddle packers, Bridge plugs, Tubing patches.
  • Cement, well bore sand plugs, Well abandonment.
  • Infill drilling, Pattern flow control and Horizontal wells.

These have been used for many years, but do not work well in all applications. Operators often do not put forth the time or expense to diagnose the cause of their overabundant water. Consequently, incorrect solutions are not uncommon.

Water Shut-Off Chemicals: Another approach to shutting off water production while allowing continued production of oil involves the use of chemicals that are injected into the formation. In its most basic sense, the process of waste minimization would not generally support introduction of new chemicals into the ground. Most of these products are polymer gels or their pre-gel forms (gelants). Gel solutions selectively enter the cracks and pathways that the water follows and displace the water. When the gels set up in the cracks, they block most of the water movement to the well while allowing oil to flow to the well. Many different types of gels can be prepared, depending o the specific type of water flow that is being targeted.

Dual Completion Wells: Oil production can decline in a well because water forms a cone around the production perforations, limiting the volume of oil that can be produced. This situation can be reversed and controlled by completing the well with two separate tubing strings and pumps. The primary completion is made at a depth corresponding to strong oil production, and a secondary completion is made lower in the interval, at a depth with strong water production. The two completions are separated by a packer. The oil collected above the packer is produced to the surface, and the water collected below the packer is injected into a lower formation. This technology has also been called a downhole water sink.

Downhole Oil/Water Separators: Downhole oil/water separators (DOWS, also referred to as DHOWS) separate oil from water in the well bore itself. DOWS technology reduces the quantity of produced water that is handled at the surface by separating it from the oil downhole and simultaneously injecting it underground. A DOWS system includes many components, but the two primary ones are an oil/water separation system and at least one pump to lift oil to the surface and inject the water. Two basic types of DOWS have been developed—one type using hydro cyclones to mechanically separate oil and water and one relying on gravity separation that takes place in the well bore.[7][10]

Impacts of Produced Water Discharges without treatment

There are many chemical constituents found in produced water. These chemicals, either individually or collectively, when present in high concentrations, can present a threat to aquatic life when they are discharged or to crops when the water is used for irrigation. Produced water can have different potential impacts depending on where it is discharged. Discharges to small streams are likely to have a larger environmental impact than discharges made to the open ocean by virtue of the dilution that takes place following discharge. Numerous variables determine the actual impacts of produced water discharge. These include the physical and chemical properties of the constituents, temperature, content of dissolved organic material, humic acids, presence of other organic contaminants, and internal factors such as metabolism, fat content, reproductive state, and feeding behavior. Impacts are related to the exposure of organisms to concentrations of various chemicals. Factors that affect the amount of produced water constituents and their concentrations in seawater, and therefore their potential for impact on aquatic organisms, include the following

  • Dilution of the discharge into the receiving environment,
  • Instantaneous and long-term precipitation,
  • Volatilization of low molecular weight hydrocarbons,
  • Physical-chemical reactions with other chemical species present in seawater that may affect the concentration of produced water components,
  • Adsorption onto particulate matter, and
  • Biodegradation of organic compounds into other simpler compounds.[11]

Treatment methods of produced water before discharge


Produced water usually represents a waste product in the petroleum industry; it is more often than not only a cost that must be controlled to enhance project economics. Water management and cost control can be done by choosing appropriate water disposal options or by finding an appropriate beneficial use for the water. Waste options and beneficial uses are, however, highly dependent upon water quality and may require water treatment prior to disposal or use. Treatment of produced water may be required in order to meet pre-disposal regulatory limits or to meet beneficial use specifications. If the oil and gas operator wishes to convey his produced water to a secondary user, the operator must be sure that the water falls within the specifications of the user. Specifications might be chemical (e.g., TDS), physical (temperature), or biological. The general objectives for operators treating produced water are: de-oiling (removal of dispersed oil and grease), desalination, removal of suspended particles and sand, removal of soluble organics, removal of dissolved gases, removal of naturally occurring radioactive materials (NORM), disinfection and softening (to remove excess water hardness). To meet up with these objectives, operators have applied many standalone and combined physical, biological and chemical treatment processes for produced water management. Some of these technologies are reviewed in this section.

  • Soluble Organics Removal (Desalination, Disinfection)

Desalination - Removal of dissolved solid, salts or impurities is often the most important part of water treatment systems. TDS in produced water ranges from <2000 ppm to >150,000 ppm. Average TDS content in seawater is approximately 35,000 ppm. The choice of desalination method depends on TDS content and compatibility of the treatment system to work under the presence of extra contaminants present in the produced water. Oil and gas operators have attempted evaporation, distillation, membrane filtration, electric separation and chemical treatments to remove TDS from the produced water.

Disinfection - Removal of bacteria, viruses, microorganisms, algae, etc. from the produced water is necessary to prevent scaling and water contamination. Microorganisms occur naturally in the produced water or may be added during de-oiling treatments. Advanced filtration techniques are one of the effective technologies used to remove microorganisms. UV light treatment, chorine or iodine reaction, ozone treatment and pH reduction are other treatments available to disinfect produced water.[12]

  • Oil and Grease Removal methods (De-oiling)

Oil and grease in produced water includes free oil, dispersed oil (small oil droplets), and emulsified oil. Oil and grease discharge, along with produced water, involves compliance with stringent regulations.

Oil and grease removal methods depend on the end usage of treated water and composition of oil in the produced water. Table 1 shows typical performance for oil removal treatment as expressed by oil particle size.

Table 1 – Oil and grease removal technologies based on size of removable particles.
Oil Removal Technology Minimum size of particles removed
API gravity separator 150
Corrugated plate separator 40
Induced gas floatation (no flocculants) 25
Induced gas floatation (with flocculants) 3 – 5
Hydro cyclone 10 – 15

The performance of API gravity separators depends on retention time, tank design, oil properties, operating conditions and the effects of flocculants or coagulants if added. Gravity separation is ineffective with small oil droplets or emulsified oil. As the oil droplet size diminishes, the required retention time drastically increases in order to obtain efficient performance. Gravity separation of smaller droplets also requires higher capital, maintenance and cleaning costs.

Corrugated plates separators are packed to enhance the performance of gravity separation tanks. The oil droplets coalesce and form larger oil droplets as the corrugated plates provide a longer path for the oil droplets to travel to the top of the tank (showing in following figure). It is a simple operation that allows the compact design of the API separation tank; however, the efficient oil removal limits the oil droplet size of 40 microns and larger. Removal of smaller oil droplets is difficult with corrugated plate separator

Hydro cyclones use physical method to separate solids from liquids based on the density of the solids to be separated. They are made from metals, plastics or ceramic, and usually have a cylindrical top and a conical base with no moving parts .The performance of the hydro cyclone is determined by the angle of its conical section. Hydro cyclones can remove particles in the range of 5–15 µm and have been widely used for the treatment of produced water.

Induced gas floatation creates fine gas bubbles through mechanical, hydraulic or sparging systems. The induced gas bubbles adhere to the oil droplets as they move upward to the surface. It provides high oil removal efficiency at larger throughput or lesser retention time for a given rate. Efficient performance is limited to oil droplet size of greater than 25 microns. To achieve higher efficiency if smaller droplets are present, flocculants and coagulants are added to improve the performance. Produced water treatment systems based on micro-bubble floatation system have been developed which use 5-50 micrometer bubbles through the reactor. Smaller bubbles more effectively separate oil from the produced water which results in low skim volume

  • Ion Exchange

Ion exchange resins are classified as cation exchangers, which exchange positively charged ions and anion exchangers, which exchange negatively, charged ions. The resins are further classified as:

  • Strong Acid Cation (SAC) Resins
  • Weak Acid Cation (WAC) Resins
  • Strong Base Anion Resins
  • Weak Base Anion Resins

Ion exchange has several applications in water treatment processes such as hardness removal, desalination, alkalinity removal, radioactive waste removal, ammonia removal and heavy metal removal. Since divalent ions (Ca, Mg, etc.) are favored over monovalent (Na, etc.) ions by the resin for replacement, secondary treatment Produced water from oil wells is to be treated stepwise within the treatment facility. Settling of suspended sediments and releasing of residual gas will be within the impoundment. Na+, barium and other heavy metals from produced water will be removed using SAC resins. Removal of CO2 produced during the ion exchange process and adjustment of pH will be achieved by adding calcium hydroxide. CO2 can be removed by air-stripping or membrane degasification. The physical law governing this process is the equilibrium between the gas phase and the concentration of the solute gas in the liquid phase.

The schematic is shown in Figure. The Higgins Loop is a vertical cylindrical loop containing a packed bed of strong acid ion exchange resin that is separated into four operating zones by butterfly (loop) valves. These operating zones (Adsorption, Regeneration, Backwashing and Pulsing) function like four separate vessels.

The Higgins Loop treats liquids in the adsorption zone with resin while the ions are being removed from loaded resin in the regeneration zone simultaneously. Intermittently, a small portion of resin is removed from the respective zone and replaced with regenerated or loaded resin at the opposite end of that zone. This is accomplished hydraulically by pulsing of the resin through the loop. The result is continuous and countercurrent contacting of liquid and resin. The cations (Ca+, Na+ etc.) are replaced by hydronium (H+) ions from resin beads. The hydronium ions are released in the treated water, which lowers the pH of the water. Cations are stripped from the resin in the regeneration zone concurrent with ion exchange in the adsorption zone. Dilute hydrochloric acid is injected into the loop and moves counter-current to the resin and the spent brine discharge, leaving the resin restored to the hydronium form. Concentrated brine volumes average approximately 1.0% of the total Loop feed volume, depending on the cation loading that is removed from the treated water. Excess brine that is not recycled to other beneficial uses is proposed to be transported offsite by truck for disposal.[13][7]

  • Electro dialysis (ED) and Electro dialysis Reversal (EDR)

Most salts dissolved in water are ionic, being positively (cationic) or negatively (anionic) charged. These ions are attracted to electrodes with an opposite electric charge. In ED, membranes that allow either cations or anions (but not both) to pass are placed between a pair of electrodes. These membranes are arranged alternately. A spacer sheet that permits feed water to flow along the face of the membrane is placed between each pair of membranes.

Figure shows an ED assembly with feed spacer and ion exchange membrane placed between oppositely charged electrodes. Positively charged ions (Na+ etc) migrate to cathode and negatively charged ions (Cl- etc) migrate to anode.

During migration the charged ions are rejected by similarly charged ion exchange membranes. As a result, water within the alternate compartment gets concentrated leaving desalted water within the next compartment of the ED unit. The concentrate and desalted water are continuously removed from the unit. The basic electro dialysis unit consists of several hundred cell pairs bound together with electrodes on the outside and is referred to as a membrane stack.

Feed water passes simultaneously in parallel paths through all of the cells to provide a continuous flow of desalted water and brine to emerge from the stack. The feed water is circulated through the stack with a low-pressure pump with enough power to overcome the resistance of the water as it passes through the narrow passages. The raw feed water must be pre-treated to remove materials that could harm the membranes or clog the narrow channels in the cells from entering the membrane stack. A rectifier is generally used to transform alternating current (AC) to the direct current (DC) supplied to the electrodes on the outside of the membrane stacks.

Post-treatment consists of stabilizing the water and preparing it for distribution. This post-treatment might consist of removing gases such as hydrogen sulfide and adjusting the pH.

Case study: Basin, Lysite, WY: The produced water from a conventional well in Wind River Basin of Wyoming contains H2S, oil, acid, BTEX, dissolved solids etc. About 93% of total TDS (8,350 to 10,000 ppm) is accounted for as sodium, chloride, calcium and bicarbonates. Oil and grease content was about 65 ppm and BOD value was more than 330 ppm (contributed by acetates and volatile acids). The treatment trailer consists of the following units:

  • De-oiling via induced gas floatation unit.
  • Dissolved organics removal via two fluidized bed reactors. First was the anaerobic and nitrate consuming reactor for reducing large amount of organics. The second was the aerobic reactor ensuring oxidation of dissolved organics.
  • Desalting/Demineralization using an ED unit.

ED provided economical demineralization in this case. The feed water had approximately 9,000 ppm TDS. As usual, the cost of the ED unit operation increases as the required TDS removal increases. Table.1 shows the overall removal of contaminants using different treatment technologies. The ED removed approximately 89% of TDS from the produced water.

Table 1– Produced water treatment performance at Wind River Basin, WY
Parameter Influent, ppm Effluent, ppm Overall Removal, %
Oil and Grease 90 4 95.5
BOD 330 51 84.5
BTEX 11 0.1 99.1
TDS (using ED) 9,100 1,000 88.9
  • Capacitive Deionization Technology (CDT)

Capacitive deionization technology (CDT) is a new technology being developed for the treatment of produced water from oil wells. A constant voltage is applied and soluble salts are collected on the surface of porous carbon electrodes, thus purifying the water for human consumption or industrial processes. In CDT, a brackish water stream flows between pairs of high surface area carbon electrodes that are held at a potential difference of 1.2 V. The ions and other charged particles (such as microorganisms) are attracted to and held on the electrode of opposite charge. The negative electrode attracts positively charged ions (cations) such as calcium (Ca), magnesium (Mg) and sodium (Na), while the positively charged electrode attracts negative ions (anions) such as chloride (Cl) and nitrate (NO3).

Case study: Following table shows the result of the treatment of produced water from a CBNG well in Wyoming using CDT.

Table – Performance of CDT for the CBNG produced water treatment
Constituent Before treatment After treatment
Conductivity (micro s/m) 2,100 < 800
Sodium ions (ppm) 280 84
Bicarbonate ions (ppm) 520 144
  • Membrane filtration technology

Membranes are micro porous films with specific pore ratings, which selectively separate a fluid from its components. There are four established membrane separation processes, including microfiltration (MF), ultra filtration (UF), reverse osmosis (RO) and nanofiltration (NF). RO separates dissolved and ionic components, MF separates suspended particles, UF separates macromolecules and NF is selective for multivalent ions. MF and UF can be used as a standalone technology for treating industrial wastewater, but RO and NF are usually employed in water desalination. Membrane technology operates two types of filtration processes, cross-flow filtration or dead-end filtration that can be a pressure (or vacuum)-driven system.

Microfiltration/ultra filtration MF has the largest pore size (0.1–3 µm) and is typically used for the removal of suspended solids and turbidity reduction. It can operate in either cross-flow or dead-end filtration. UF pore sizes are between 0.01 and 0.1 µm. They are employed in the removal of color, odour, viruses and colloidal organic matter. UF is the most effective method for oil removal from produced water in comparison with traditional separation methods, and it is more efficient than MF for the removal of hydrocarbons, suspended solids and dissolved constituents from oilfield produced water. Both MF and UF operate at low transmembrane pressure (1–30 psi) and can serve as a pre-treatment to desalination but cannot remove salt from water.

Polymeric and ceramic membranes are used for UF/MF treatment of water. Polymeric MF/UF membranes are made from polyacrylonitrile and polyvinylidene and ceramic membranes from clays of nitrides, carbides and oxides of metals Ceramic UF/MF membranes have been used in a full-scale facility for the treatment of produced water]. Product water from this treatment was reported to be free of suspended solids and nearly all non-dissolved organic carbon.

Reverse osmosis and nanofiltration RO and NF are pressure-driven membrane processes. Osmotic pressure of the feed solution is suppressed by applying hydraulic pressure which forces permeate (clean water) to diffuse through a dense, non-porous membrane. Seawater RO can remove contaminants as small as 0.0001 µm, but its major disadvantage is membrane fouling and scaling.

  • Adsorption:

Adsorption is generally utilized as a polishing step in a treatment process rather than as a standalone technology since adsorbents can be easily overloaded with organics. It has been used to remove manganese, iron, total organic carbon (TOC), BTEX, oil and more than 80% of heavy metals present in produced water. There are a variety of adsorbents, such as activated carbon, organ clays, activated alumina and zeolites. Adsorption process is applicable to water treatment irrespective of salinity. It requires a vessel to contain the media and pumps to implement backwashes which happen periodically to remove particulates trapped in the voids of the media. Replacement or regeneration of the media may be required depending on feed water quality and media type.

Depends on the quality of produced water from wells any of the treatment techniques can be adopted on well site prior to disposal. [7][14][15][16]

WEMCO system


During more than thirty five years in the produced water treatment industry, WEMCO has strategically aligned itself with the best equipment manufacturers in today’s world. Today these equipments became an integral part of every oil and gas processing platforms. It’s having the best and most innovative technology with the highest reputation for product performance and value. Wemco equipments are designed with advanced features that ensure high efficiency and lower operating costs for offshore and onshore applications and also address a wide range of challenging water quality treatment issues. WEMCO having variety of equipments to treat and handle produced water having (oil droplets greater than 120-150 microns in size (Bulk oil) to micron level size (0-20 microns in size).

Following are the list of equipments:

1) Bulk oil removal – This removes oil droplets greater than 120-150 microns in size.

UNICEL Vertical Skim Vessel: The vessel design is simple, with a central inlet riser column and a skimming trough. A set of structured coalescing packing can be added at the top of the riser in some applications. Raw water flows vertically up the center riser prior to being released at the surface of the vessel, where an oil pad forms. The water then flows downward around the outside of the central riser before exiting the vessel. This annulus serves as an additional residence for oil separation and for any water treatment chemicals that are added to the system.

The oil pad is removed periodically by a repeat cycle timer that raises the water level and enables the oil layer to spill over into the internal skim trough, from where it can be removed.

Capacities: These systems are available in standard sizes from 1,000 bwpd to 75,000 bwpd.

Benefits and Advantages:

  • Consistent Water Quality Performance Under Varying Process Conditions
  • Less Skim Liquor Volumes to Reprocess
  • 100% Turn Down Capability
  • Gas Tight Design Eliminates Noxious Vapors
  • Small Footprint and Less Weight
  • Low Maintenance - No Moving Parts
  • ASME Code Vessels for Pressurized Operation
  • Easy to Operate – Minimal Controls – Requires Very
  • Little Operator Attention

2) Dispersed Oil Removal - This stage accomplishes removal of smaller oil droplets suspended in the aqueous phase. Oil droplets greater than 3-5 microns in size can be removed. The primary technology used in this stage is induced gas floatation.

WEMCO ISF Systems - Streamlined for simple, efficient operation and maintenance, each ISF machine consists of a cylindrical vessel partitioned into several major components: floating, degassing, optional skim storage compartments, a recirculation pump and piping and a liquid level control system. All equipment is skid mounted for rapid installation and start-up. The ISF is an induced gas flotation system through which a high-velocity stream of recycled clarified water enters the cells containing influent water through educator nozzles in the bottom of the vessel. This induces a recalculating flow of air or gas from the vessel freeboard into the process water, and a unique educator arrangement distributes small gas bubbles uniformly throughout the cell volume. These bubbles lift contaminants to the liquid surface forming a froth layer, which is then skimmed from the liquid surface by a simple collection trough. Gas and a small volume of treated water are continuously recycled from the degassing chamber into the treatment cells. The skim cycles are automatically initiated by a timer and the cycle interval; duration and level set points are all user-selectable and can be changed without interrupting operation or entering the vessel. The power requirements of the ISF are very low with the gas induction and mixing in the flotation cells being provided by a simple reticulating pump.

Benefits and Advantages:

  • Compact, lightweight, horizontal or vertical installation
  • Minimal footprint
  • No internal moving parts, low maintenance
  • Minimal power requirements, minimal controls
  • Modular design, easy to expand, reduced installation costs
  • Motion insensitive vertical UNICEL design is ideal for floating production systems
  • Utilizes process or inherent feed pressure
  • No environmental pollution
  • All hazardous or toxic gases are contained
  • Can be constructed to ASME code for pressurized operation.
  • Separation efficiency up to 95%

Product Range: Individual units for flow rates of 380 m3/day to 20,670 m3/day (2400 BPD to 130,000 BPD)


3) Free Oil Removal - This stage removes oil droplets greater than 40 microns in size for the media coalesces and greater than 10-20 microns in size for the hydro cyclones. This stage includes the removal of small oil droplets suspended in the aqueous phase.

WEMCO Deoiling Hydro cyclones: Deoiling Hydro cyclones are used to separate two liquids of differing densities, e.g. oil from water. Usually driven by process pressure, oily water enters the line through the inlet to the involute chamber and is directed to flow along the liner wall. Forced down the liner, the fluid accelerates in the narrowing cross-section and the forces required to separate the oil droplets are developed. Centrifugal forces acting upon the heavier water phase cause it to migrate to the wall of the tapered section. The lighter oil phase is displaced as a result and forms a central, low-pressure core which is removed via the reject. The outer clean water vortex exits via the underflow.

Benefits and Advantages:

  • Highest density hydro cyclone packing on the market giving the smallest package footprint and lowest weight.
  • Ramped geometry maximizes flow and minimizes erosion.
  • No moving parts, low maintenance, and no external power required minimal controls.
  • Removable involute allows easy disassembly, cleaning, inspection and replacement.
  • Range of material options to suit corrosive and erosive environments.
  • Insensitive to motion, ideal for floating production systems.

Successful Installation and operation:

4) Polishing / Filtration - With removal of very small droplets down to very low concentrations, this is a more time dependent process because it requires sufficient time in order to allow the oil droplets to coalesce. Primary equipment used for removal at this stage includes mesh coalesces and media filter equipment.

Hydromation Nut Shell Filter: These filters are used to remove suspended solids and hydrocarbons from produced water, surface water, sea water, river, lake, and well water. In metal working, power generation, municipal, chemical and petrochemical applications, they treat and remove suspended solids, oily residues, ash, and metallic hydroxides from industrial liquids.

Performance: Under normal operating conditions, they remove 95 to 99% of suspended solids and 90 to 99% of insoluble hydrocarbons, without the use of chemicals.


Benefits and Advantages:

  • Proven reliable experience with many units operating worldwide in a wide variety of applications
  • Media scrubbing cycle prevents filter bed fouling
  • Energy efficient - high mixer efficiency minimizes energy consumption during backwash cycle
  • Reduced operating, maintenance, and downtime costs
  • Media scrubber generates a minimum of 40,000 GPM (9085 m3/h) of pumping shear rate with only a small horsepower motor
  • Feed water is used for backwashing
  • Media is not ground up in a pump, so less than 5% per year of media attrition is guaranteed
  • Back-flush volume is typically 0.5-1% of throughput so waste volume is minimized
  • Greater than 99% annualized online performance
  • Effluent concentrations down to non-detectable limits of suspended oil and solid.

5) Disposal: Skim Piles, often called Disposal Piles and Sump or Disposal Caissons, are large diameter open-ended cylindrical structures, suspended from the platform to a point well below the water surface. They are based on a separation of oil droplets of a particular size (usually 500µm) and a specified residence time. The Skim Pile is the final stage of an open deck drains and/or produced water treatment system.

Skim Pile (Plated Caisson with Oil Risers): The oil and water separation and sand cleaning occurs as intermittent rain and wash down water flows through a series of closely spaced baffle plates. The tight spacing of the baffle plates creates quiescent zones and reduces the distance a given droplet must rise to be separated from the main flow. Once in the quiescent zone there is sufficient time for coalescence of the oil particles. The larger coalesced droplets then migrate up the underside of the baffle into the oil riser. The riser prevents the oil droplets from being swept back into the flow stream and remixing with the incoming water.

Technical Advantages: WEMCO superior designs are capable of separating down to 50 µ droplets — most designs on the market can only separate down to 500 µ droplets. Within designs, there are a number of customizable options available for oil removal

6) Other includes:

Two-Stage Softeners: Two-stage primary and secondary softener scheme to reduce the hardness. One ppm or less, outlet conditions are achievable with TDS in the inlet as high as 5000 ppm. A Sodium Zeolite resin softening process is used in each stage. The advantages of using a Sodium Zeolite-based process are realized in the regeneration capability of the resin. “Salt,” instead of high cost acids or caustics, is used for regeneration. Salt/brine is introduced from the bottom of the secondary softener to regenerate the resin and flows upwards. Salt/brine from the secondary softener then flow to the primary softener to provide a downward flow regeneration of the resin. This scheme ensures that the resin near the bottom of the secondary softener is free from Calcium and Magnesium in order to eliminate possibility of hardness leakage.

Key Features:

  • Cameron reliability and support
  • Choice of Sodium Zeolite versus high cost acidic or caustic agent
  • Efficient salt/brine based resin regeneration scheme
  • Hardness leakage prevention inherent by design
  • Simple parallel array expansion for higher flow capacities


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