IWC-12-21 

OVERVIEW OF PRODUCED WATER AND EOR 

WATER TREATMENT 

AVIJIT DEY, Bechtel Corporation, Houston, TX 77056 

IWC 12-21 

KEYWORDS: BTEX, CBM, CDX, crystallizer, CSG, deoiling, EOR, evaporation pond, evaporator, flowback, FO, 

fracking, Hi-Flow, HLS, IGF, ISF, Liquid/ Liquid coalescer, MBBR, MBF, MFT, , MPPE, , NPD, PACT, PAH, Produced 

water, SAGD, shale gas, skimmer, SRP, UIC, vacuum deaeration, walnut shell filter, water flooding, WLS, ZLD.

ABSTRACT 

Produced water is mainly salty water trapped in the reservoir rock and brought up along with oil or gas during 

production. It can hold very minor amounts of chemicals added down-hole during production. These waters exist under 

high pressures and temperatures, and usually contain oil and metals. The treatment of produced water is a key 

component of the cost of producing oil and gas. The ability to efficiently and economically dispose of this water is vital 

to the success in the oil production business. 

In this article, produced water treatment approach for shale gas, oil sand mining, oil sand steam assisted gravity 

drainage (SAGD), coal bed methane (CBM), coal seam gas (CSG), and offshore oil/ gas development fields shall be 

discussed. In addition, technical options for the enhanced oil recovery (EOR) water treatment shall also be discussed. 

INTRODUCTION 

Water with higher density than oil lays in huge layers 

below hydrocarbons in the reservoir (formation water). 

After oil and gas production for a while, the formation 

water reaches the production wells and water production 

commence. Early in the life of an oil well, oil production 

is high and water production is low. As the production 

age of the well increases, the oil production decreases 

and the water production increases (Figure 1). When the 

cost of managing produced water surpasses the profit 

from selling oil, production is terminated and the well is 

closed. This is contrary to the typical production cycle of 

coal bed methane (CBM) well. To begin with CBM wells 

produce large volumes of water, which drop over time. 

Methane production is low in the beginning, increases 

over time to a peak, and then decreases. 

Every barrel of oil produced, 3 to 6 barrels of water is 

simultaneously produced. Similarly, for every MCF 

(equals to 1,000 cubic feet) of natural gas produced, 0.1 

to 1.0 barrel of oily water is co-produced. For onshore 

produced water, discharge standard into evaporation 

pond necessitates adherence to a “no visible oil sheen” 

standard or < 10 ppm oil content in water. Third party 

haul-off disposal costs are between $ 0.5 and $8 per 

barrel of water depending on the proximity of the 

disposal sites to the production sites. For offshore 

produced water, EPA regulation entails the total oil 

content of overboard discharge < 29 ppm (monthly 

average) and 42 ppm daily maximum. Tight discharge 

standard along with severe water scarcity force oil and 

gas producers to adequately treat and possibly reuse of 

the treated produced water for beneficial use. 

Shale gas will raise to 47% of US natural gas production 

by 2035. Hydraulic fracturing of a horizontal well to 

produce shale gas necessitates up to 4 million gallons of 

water. Many areas with shale gas resources have limited 

supplies of water. Shale gas produced water treatment 

employs either membrane or thermal equipment based 

on TDS of the produced water. 

Oil sand is a major market in Canada. Mining is used 

when the oil is adjacent to the surface. Drilling is used 

when the oil is deeper under the ground. Drilling projects 

don't need tailings ponds and disturb very little land. 

Tailings management in mining based units is a major 

challenge and good success was obtained using 

centrifuge technology. Steam assisted gravity drainage 

(SAGD) based produced water systems in oil sand 

drilling market can be either regular deoiling, warm or hot 

lime softener, after-filtration, and weak acid cation 

exchanger based systems or falling film evaporator 

based systems respectively where treated produced 

water is reclaimed in once through steam generator 

(OTSG) or drum boilers. 

Natural gas produced from coal beds (coal-bed 

methane, CBM) accounts for about 7.5 percent of the 

total natural gas production in the United States. Along 

with this gas, water is also brought to the surface. The 

amount of water produced from most CBM wells is 

comparatively high compared to conventional natural 

gas wells because coal beds include many fractures and 

pores that can contain and transmit large volumes of 

water. When water is removed from a coal seam, it 

reduces the reservoir pressure. Methane that was held in 

place by water pressure tends to follow the water as it is 
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pumped to the surface. Water coproduced with methane 

is not re-injected into the producing formation to enhance 

recovery as it is in many oil fields. Instead it must be 

disposed of or used for beneficial purpose. Reverse 

osmosis based systems with appropriate pretreatment is 

commonly used for the treatment of CBM produced 

water. 

The rapid move towards an LNG industry in Queensland 

(Australia) has created significant interest in developing 

coal seam gas (CSG) in the Surat region. With this 

escalating development comes the responsibility of 

managing the associated water byproduct of CSG 

extraction. CSG produced water systems typically 

include ultrafiltration, weak acid cation exchanger, and 

reverse osmosis units. 

Some offshore produced water includes benzene, 

toluene, ethyl benzene, and xylene (BTEX) which are not 

bio-degradable and requires state-of-the-art technologies 

including macro porous polymer extraction (MPPE) for 

its removal. Due to tight COD discharge standards, 

specialized biological water treatment technologies are 

utilized. Such technologies include but not limited to 

powdered activated carbon treatment (PACT), moving 

bed biofilm reactor (MBBR), and integrated fixed film 

activated sludge (IFAS). 

To maintain the hydraulic pressure in the petroleum 

reservoir, which is diminished as soon as production is 

started, seawater is commonly pumped into the offshore 

reservoir water layer below the hydrocarbons (Figure 2).

This pressure maintenance using water injection is 

termed water flooding and it causes high extensions in 

recoverable hydrocarbons but contributes to increased 

water production. The injected water will sweep or 

displace the oil from the reservoir, pushing it toward the 

production well, stimulating oil recovery. Prior to being 

injected, the seawater must be free of contaminants. 

These are called enhanced oil recovery (EOR) 

processes. Many proprietary processes are available 

e.g. Sulfate removal package (SRP) and LoSal water 

flooding. 

Deep well Injection 

Injection wells, which carry and permanently place fluids 

underground, are a potential ground water contamination 

source if not properly sited, constructed and maintained. 

Injection wells are regulated by the USEPA under the 

authority of the Underground Injection Control (UIC) 

program, as provided by Part C of the safe drinking 

water act. Federal underground injection control 

regulations are located at 40 CFR parts 144-147. There 

are five classifications of injection wells for subsurface 

injection of waste fluids below, into, and above 

underground sources of drinking water (USDW). Class II 

wells inject waste fluids associated with the production of 

oil and natural gas. The approximately 144,000 Class II 

wells in operation in the United States inject over 2 billion 

gallons of salty produced water every day. Most oil and 

gas injection wells are in Texas, California, Oklahoma, 

and Kansas. Any underground injection into a well is 

prohibited unless the well is authorized by the rule or 

authorized by a UIC permit. Injection well owners are 

required by law to submit inventory information to 

USEPA or the state delegated agency. UIC owners must 

not endanger USDW. 

The average injection well is about 5,000 feet deep 

(about 1 mile). Produced water is typically piped or 

trucked to the injection site where the water is 

transferred to holding tanks and pumped down a Class II 

injection well. In the United States, injection well casings 

must provide double containment to compensate for any 

structural failure (Figure 3). Wells are typically tested 

every five years for integrity and monitored continuously 

for possible contamination. 

Evaporation Pond 

A technology that is popular is the evaporation of 

produced water in high density polyethylene (HDPE) 

lined containment ponds after separation and removal of 

hydrocarbon component from the water. The top liner in 

the ponds is black HDPE, which creates a hot surface. 

Produced water can be managed at small onsite 

evaporation ponds or can be sent offsite to commercial 

facilities that employ large evaporation basins. 

Disposition of the salts accumulating in pond facilities is 

a long-term concern. 

As long as evaporation rates exceed inflows including 

precipitation, produced water disposal can be 

sustainable. Evaporation depends on local humidity, 

temperature, and wind. Penman’s original equation can 

be used to calculate evaporation rate as follows (Linacre, 

1993): 

 

[(0.8 40) 2.5  ]

0.015 0.00042 10 6

0

S m D

m

R F u T T

E T z

       

     

F     z 5 1.0 8.7 10

 10.8 153 RS Tm

Produced Water Deoiling 

The presence of emulsified oils and water soluble 

organics (WSO) create challenge in treatment of 

produced water. WSO are class of organic compounds 

that are soluble in water and add to the oil content of 

produced water. WSO include semi-volatile organics, 

gasoline range organics, and semi-volatile organic acids. 

Table–1 lists the various systems employed in produced 

water deoiling. Most commonly used water treating 

equipment depends on the forces of gravity to separate 

the oil droplets from the water continuous phase. When 

the buoyant force and drag force are equal, a constant 

velocity of oil droplets is reached, which can be 

computed from Stokes’ law as follows (Ken and Maurice, 

2008). The larger the size of an oil droplet, the greater 

the vertical velocity will be. Lighter crude is easier to 

treat due to greater difference in density between the oil 

droplet and the water. The higher the temperature, the 
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lower the viscosity of the water and, thus, the greater the 

vertical velocity will be (Ken and Maurice, 2008). 

 

w

m SG d V



7 2

0

5.55610    



Most popular deoiling technology in offshore applications 

is static hydrocyclones utilizing available pressure for 

enhanced speed in separation. In on-shore applications, 

skimmers (Figure 4), induced gas flotation (IGF) (Figure 

5) followed by walnut shell filters (Figure 6) typically 

constitute a step-wise deoiling system. A minimum 

residence time of 10 to 30 minutes should be provided in 

the skimmer to assure that surges do not upset the 

systems. Impellers used in IGF to produce bubbles in the 

mechanical units are typically designed for a tip speed of 

1,200 fps. On the contrary, induced static flotation (ISF) 

uses eductors to produce bubbles. ISF results in less 

emulsification of oil and water when compared with IGF 

which improves the oil removal efficiency of downstream 

units. Micro-bubble flotation (MBF) that creates trillions 

of small bubbles have a high probability of contact to 

even the smallest of emulsified oil droplets and efficiently 

adhere and lift them to the surface for skimming. MBF 

can be easily integrated in the skimmer and IGF/ISF 

units. A gas liquid reactor (GLR) (Figure 7) in the MBF 

system generates 5 – 50 micron bubbles. 

The walnut shell filters use a deep bed of 100 percent 

black walnut shells, which have excellent surface 

characteristics for coalescing and filtration, plus superior 

resilience to attrition. Walnut shell filters are available 

with external or internal scrubber with media scrubber 

pump. Internal scrubbers are preferred as clean media 

can not be trapped in the scrubber vessel and 

associated piping. Another type of walnut shell filter uses 

an internal scrubber and mixer (Figure 8). This design 

incorporates the high intensity of a mixer to vigorously 

agitate the media bed during the scrubbing cycle. The 

mixer is combined with the separating efficiency of a 

rotating backwash scrubber screen to produce the 

optimum separation of the scrubbed media from the 

concentrated backwash fluids. 

Other filters are designed to remove free and dispersed 

hydrocarbons along with WSO by utilizing a combination 

of coalescence and enhanced gravity separation 

mechanisms. Areas of particular interest for for this type 

of filter are the ability to remove hydrocarbons in MEG, 

and methanol. 

Chemical affinity filtration utilizing a patented polymer 

integrated into the filter media is capable of removing 

free and emulsified hydrocarbons along with dissolved 

hydrocarbons in water to between 0 to 10 ppm. 

On line oil and grease analyzer using the principle of UV 

fluorescence is available commercially to detect and 

measure oil in water. Detection limit typically ranges from 

low ppb to high ppm. 

Macro porous polymer extraction (MPPE) technology 

removes dissolved and dispersed hydrocarbons 

including BTEX (benzene, toluene, ethylbenzene, and 

xylenes), PAHs (polycyclic aromatic hydrocarbons), and 

NPD (naphtalenes, phenanthrenes, and 

dibenzothiophenes) with high efficiency. This technology 

protects the downstream secondary biological system 

from compounds that are resistant to biological treatment 

in produced water applications. The MPPE particles are 

porous polymer beads which contain a specific 

extraction liquid. Hydrocarbons which have a high affinity 

for the immobilized extraction liquid are removed. 

Periodic in-situ regeneration of extraction liquid is 

accomplished by stripping the hydrocarbons with low 

pressure steam. The stripped hydrocarbons are 

condensed and then separated from the water phase by 

gravity. The application of two columns in Figure 9 

allows continuous operation with simultaneous extraction 

and regeneration. 

Liquid/Liquid coalescer/separator is becoming a popular 

pretreatment option for MPPE technology. Produced 

water enters the coalescing media and flows inside to 

outside. This is where small oil droplets suspended in 

the continuous aqueous phase come together or 

coalesce. Large droplets of dispersed oil separate by 

gravity in the horizontal housing and are removed 

(Figure 10). 

Produced Water Biological Treatment 

Produced water is a high volume waste stream that is 

frequently with a high TDS and chemical oxygen 

demand (COD) as well as containing water soluble 

aromatic compounds such as phenols. Phenol toxicity 

has an adverse effect on heterotrophs growth rate which 

should be considered in designing biological unit 

process. Biological treatment of produced water is 

problematic due to the high TDS content, which inhibits 

conventional wastewater treatment systems. Produced 

water is nutrient deficient and consequently nutrient 

dosage shall be high due to high BOD5 value of 

numerous produced water streams. 

Powdered activated carbon treatment (PACT) (Figure 

11) better handles recalcitrant COD by adsorbing on the 

carbon and allowing bacteria more time for its 

degradation. Maintaining large quantity of powder 

activated carbon (PAC) provides stability against shock 

and variable organic loading protecting the living biology 

from upstream upsets and toxicity spills. Organics are 

retained in the PACT system about sludge retention time 

(SRT) rather than hydraulic retention time (HRT) in 

conventional biological processes. BOD, COD, phenols, 

and priority organics are removed to a very high degree 

in PACT system. Wet air regeneration (WAR) can be 

employed for recovery of PAC for reuse. 

In Moving bed biofilm reactors (MBBR) a tank is partially 

filled with polypropylene (PP) carriers with a density 

around that of water and high specific biofilm surface 
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area that move along with water in the reactor. Microbes 

are well protected on the carrier and hence process is 

more tolerant towards variations and disturbances 

common in the produced water applications. Carriers are 

being moved upward over the surface of the sieve 

constantly by air which creates a scrubbing action that 

prevents clogging (Figure 12). Inert media in the aeration 

basins supports the growth of biomass on the surface. 

Because the return activated sludge (RAS) is fed 

downstream of the carrier media, the biomass in the first 

section of the aeration basin is mainly attached to the 

carrier media. Treatment capacity in a MBBR system is a 

function of specific surface area (SSA) of the reactor. 

SSA for a reactor is the quotient of the total surface area 

on inert carriers for biofilm establishment and the reactor 

volume. The media has its own characteristics SSA. The 

reactor SSA equals the SSA of the media multiplied by 

the fraction of the total reactor volume that the media 

occupies (Weiss et al, 2005). 

In integrated fixed film activated sludge (IFAS) process, 

both the raw wastewater and return activated sludge 

(RAS) are fed at the head of the aeration basin. Because 

the compartment containing the carrier media is 

receiving return sludge, the MLSS concentration in this 

section is about the same as in the aeration basin 

section. The attached biomass population can more than 

double the effective MLSS concentration. The vigorous 

motion of the media through the basin provides high 

shear maintain a thin biological film that improves the 

bio-kinetics. 

Advanced oxidation Process 

Since 1997, the institute of Marine research (IMR) in 

Bergen, Norway has carried out several long term 

studies on fish in order to better understand the 

biological effects of the chemicals found in produced 

water, especially alkylphenols (APs). Most regulatory 

authorities are tightening the discharge limit of phenols 

beyond what is achievable with biological treatment 

methods. Recent developments in the domain of 

chemical water treatment have led to an improvement in 

oxidative degradation procedures for organic compounds 

dissolved or dispersed in aquatic media, in applying 

catalytic and photochemical methods. They are generally 

referred to as advanced oxidation processes (AOP). 

AOP (O3, O3/H2O2, UV, UV/O3, UV/H2O2, O3/UV/H2O2) 

for degradation of phenols in aqueous solutions have 

been studies extensively (Esplugas et al, 2002). 

Experimental results indicated that both phenol and 

benzoic acid are destroyed more rapidly by ozone at 

higher pH (9-12), while ozonation combined with 

hydrogen peroxide or/and UV is considerably faster at 

low pH (3-7). Fastest kinetics was observed with 

UV+O3+H2O2 (Mokrini, and Esplugas, 1997) as shown in 

Figure 13. 

Softening of High TDS Produced Water 

High levels of sodium in the produced water compete 

with ion exchange sites on the resin so that the efficiency 

of the softening process is adversely diminished at high 

TDS levels (Brown and Sheedy, 2002). Hardness 

leakage is directly proportional to the square of TDS of 

produced water [TDS]pw, and directly proportional to 

hardness concentration in the brine regenerant [TH]Brine

as follows: 

   Leakage  TDS pw  TH Brine

2

This suggests that in order to accomplish low hardness 

leakage levels on high TDS produced waters, it is 

essential to use high purity brine regenerant. Since 

softener leakages increase with increasing TDS, the 

upper limits of strong acid cation (SAC) exchangers is 

generally taken at 5,000 ppm (Michaud, 2001). Above 

5,000 ppm of TDS, customary practice is to use weak 

acid cation (WAC) softeners owing to their much higher 

affinity for hardness ions than conventional SAC resins. 

Produced Water Membrane Treatment 

RO based flowsheets exist for membrane desalination of 

produced water with high concentration of silica, 

organics, hardness, boron, and particulates. These 

flowsheets use multiple treatment processes, involving 

degasification, chemical softening, media filtration, ion 

exchange softening, cartridge filtration and reverse 

osmosis (RO) technologies. The RO process operates at 

an elevated pH, which effectively controls biological, 

organic and particulate fouling, eliminates scaling due to 

silica, and increases the rejection of silica and boron 

(Figure 14). Later versions of this flowsheet use ceramic 

ultrafiltration (UF) membranes (Figure 15). This process 

removes silica via pH controlled reaction with MgO which 

can be useful in SAGD application. 

Forward osmosis (FO) employs a salt “draw” solution on 

the permeate side of the membrane which has a higher 

osmotic potential than the dirty feed water. Higher 

osmotic potential of the “draw” solution is the power 

source nature provides to drive the filtration process. 

Permeate water dilutes the higher concentration “draw” 

solution. In conventional high feed pressure RO system, 

fouling of membrane results from high pressure 

compaction of foulants at the membrane surface which is 

eliminated in the FO systems due to ultra-low operating 

pressure and hence it can handle dirty oilfield produced 

water more effectively. Forward osmosis filtration can be 

used to recycle drilling waste into a high quality 

completion fluid for use in frac jobs. On each well, over 

80% of the drilling waste can be recycled to provide 

approximately 20% of the water required for hydraulic 

fracturing (Figure 16). Pit water contains large amount of 

suspended solids from drilling mud and cutting which is a 

major problem for both conventional RO and evaporative 

systems. In gas wells where fresh sodium chloride or 

potassium chloride (2 – 7%) is used as a clay stabilizer 

during completion stages, the dilute draw solution can be 
IWC-12-21 

utilized directly as completion fluid. Recycle of drilling 

waste into completion fluid not only reduces a significant 

portion of the need for additional fresh water, but also 

greatly reduces the amount of heavy truck traffic 

required to move the waste and source water in and out 

of the well-site, respectively. 

Produced Water Thermal Treatment 

Mechanical vapor recompression (MVR) falling film (FF) 

evaporator is an energy efficient method of evaporation, 

typically to concentrate the water up to the initial 

crystallization point in produced water applications. 

Vapor-compression evaporation is the evaporation 

method by which a compressor is used to compress, and 

thus, increase the pressure of the vapor produced. Since 

the pressure increase of the vapor also generates an 

increase in the condensation temperature, the same 

vapor can serve as the heating medium for its "mother" 

liquid or solution being concentrated, from which the 

vapor was generated to begin with.The resultant brine 

then enters a forced circulation (FC) crystallizer where 

the water concentrates beyond the solubility of the 

contaminants and crystals are formed. The crystal-laden 

brine is dewatered in a filter press or centrifuge and the 

filtrate or Centrate (also called “mother liquor”) is 

returned to crystallizer (Figure 17). 

Shale gas 

Hydraulic fracturing of a horizontal well to produce shale 

gas requires up to 4 million gallons of water (Figure 18). 

Given that many recently posited shale gas reserves 

seem to occur in areas of water scarcity, this raises 

some questions as to how usefully some of these 

resources can be developed. Sand and chemicals like 

friction reducer, oxygen scavenger, corrosion inhibitor, 

scale inhibitor, and biocides are added to the water that 

is pumped downhole for the frac job. As a result, 

components in flowback water include constituents of 

produced water and frac job additives. Millions of gallons 

of flowback (FB) and produced water require handling, 

treatment, and disposal. 

FB water has a murky appearance from high levels of 

suspended particles. Most of the FB occurs in the first 7 

to 10 days while the remaining can takes place over a 3 

to 4 weeks time period. The volume of recovery is 

anywhere between 20 and 40% of the volume that was 

originally injected into the wells. The left behind of the 

fluid remains absorbed in the shale formation. As 

production continues, the water quality varies to imitate 

more and more the formation water which is 

characteristically high in TDS. Produced water 

characteristics from different shale gas focus areas are 

listed in Table–2. Ranges in produced water TDS is from 

8,000 up to 300,000 ppm. Such produced waters 

normally contain some hydrocarbons like BTEX, weak 

organic acids, alcohols, PAH, and hexane extractable 

aliphatics. 

Reverse osmosis technology has been applied to treat 

frac water in San Ardo (California). In some low TDS 

applications, use of MPPE along with membrane 

bioreactor (MBR) system is required to maintain the TOC 

and COD level in the RO feed water within acceptable 

level to avoid membrane organic fouling. Operation of 

RO at elevated pH is desired in many applications to 

solubilize organic acids. 

It is recommended to examine available membrane and 

thermal recycling technologies and evaluate the 

underlying economics to make appropriate decision to 

recycle all produced water or dispose of it. Disposal well 

availability and alternative methods of disposal such as 

surface discharge should also be evaluated both from 

regulatory and technical standpoints. 

The high total dissolved solids (TDS) levels beyond 

40,000 ppm in the produced water require thermal 

process for economic water recovery. Evaporation and 

crystallization remains the major treatment option for 

high TDS shale gas produced water beyond 40,000 ppm 

(Figure 19). 

Aqua-Pure introduced NOMAD MVR evaporators for 

shale gas flow back water applications. These systems 

utilize their ROVER mobile clarifier as primary 

pretreatment. Intevras introduced evaporative reduction 

and solidification (EVRAS) evaporator systems for shale 

gas produced water. The EVRAS technology employs an 

evaporative process similar to a cooling tower that relies 

on water temperature, surface area, and airflow. 

Produced water evaporates into the atmosphere. 

EVRAS crystallizer allows total evaporation, resulting in 

solid residue for disposal. AltelaRain introduced 

evaporation and condensation process to handle 

produced water for a TDS up to 150,000 ppm. 212 

Resources introduced VACOM evaporation system that 

combines MVR with turbulent flow heat exchanger 

technology for the shale gas produced water treatment 

up to a TDS of 110,000 ppm. 

GE RCC uses their seeded slurry evaporators for the 

treatment of shale gas produced water and successful in 

recovering 70% for reuse with only 30% required 

disposal. 

Oil sand – Mining 

Mining is used in oil sand business when the oil is close 

to the surface. About 20% of the oil in the oil sands is 

close enough to the surface that it has to be mined 

(Figure 20). Bitumen is extracted from surface mined oil 

sand using hot water extraction process (HWEP) in 

which caustic is added. 2 barrels of fresh water is 

required to produce each barrel of oil. After gravity 

separation of bitumen, tailings are forwarded to the 

pond. However, this is not the final solution. Energy 

resources conservation board (ERCB) directive 074 

mandated in February 2009 in Canada requires removal 

of solids with particles ≤40 microns by 20% within June 

30, 2011, 30% within June 30, 2012, and 50% within 
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June 30, 2013. Mature fine tailings (MFT) form a distinct 

layer in the pond. Nano particle clays (20 – 300 

nanometers) suspended in salt solution controls the MFT 

behavior. These nano particles are found in all oil sand 

ores. The challenge is that MFT do not settle with in 

reasonable time frame. Most promising technology at 

this point of time is the decanter centrifuge that involves 

putting tailings through vessels where a spinning action 

separates out water. Cake with 60% solids dryness is 

achievable (Figure 21). 

Oil sand – SAGD 

Drilling is used in the oil sand business when the oil is 

deeper under the ground. About 80% of the oil in the oil 

sands is so deep underground that it has to be drilled. 

Steam assisted gravity drainage (SAGD) facilities inject 

steam into geological formations to facilitate the 

production of heavy hydrocarbon. The steam fluidizes 

the heavy oil and allows the oil/water mixture to be 

transported to the surface. The oil is recovered as 

product and the produced water is treated for reuse in 

the steam generators. Limited make up water availability 

and lack of discharge options dictate that the produced 

water is recycled to make more steam. Most plants aim 

to recycle and reuse 90% of the water. 

The two common options for steam generations are 

once through steam generators (OTSGs) as shown in 

Figure 22 and conventional drum boilers. Table–3 

compares the typical feed water specifications for these 

different types of steam generation equipment. The limits 

for OTSGs are based on industrial practice while the 

limits for drum boilers are based on ASME guidelines for 

water tube, drum type boilers operating at 1001 – 1500 

psig. 

SAGD facilities have traditionally used a combination of 

warm or hot lime softening, filtration, and weak acid 

cation (WAC) ion exchange unit to produced water after 

satisfactory deoiling (Figure 23). The treated water is 

directed to OTSG to produce about 80% quality steam. 

The steam-water mixture goes through a series of vaporliquid separators to generate 100% quality steam 

required for injection into the well. OTSG generates a 

blowdown, which is about 20% of boiler feed water 

volume and results in a brine stream, which is about 

fivefold the concentration of the boiler feed. This stream 

must be disposed of by deep well injection or, if there is 

an inadequate or no deep well capacity, by further 

concentrating the blowdown with a zero liquid discharge 

brine concentrator (Figure 23) and crystallizer system, 

generating a dry solid for disposal (Heinz, 2007). 

An alternative method of produced water treatment and 

steam production is mechanical vapor recompression 

evaporator followed by standard drum boilers (Heins et 

al, 2005) as shown in Figure 24. 

The High pH process by GE RCC employs a high 

caustic dosage to raise the pH of the feedwater in order 

to keep the silica in solution. The high pH of evaporator 

brine can also result in hardness scaling in evaporator 

system when using produced or make-up water with high 

hardness. The SAGD produced water typically contains 

silica between 200 and 350 ppm and when concentrated 

by a factor of 30 silica level can be raised to 6,000 to 

10,500 ppm in the concentrated brine stream in 

evaporator sump of the High pH process. The 

concentrated evaporator brine has pH between 11 and 

13. The high pH evaporator blowdown typically needs to 

be neutralized prior to deep well disposal in a Class II 

well which also requires equally high level of acid 

dosage to reduce the pH. Moreover, acid addition to 

concentrated brine stream may release H2S. 

HPD, a division of Veolia Water Solution, employs MgO 

seeded slurry to remove silica in the silica sorption 

evaporator used to treat blowdown from once through 

steam generator (OTSG) in SAGD application (patent 

7905283 - Process For Removing Silica In Heavy Oil 

Recovery). The Silica Sorption Process employs a MgO 

slurry that reacts with the silica in the evaporator feed 

water (generally a mix of produced water and brackish 

make-up water) and reduces the reactive silica below 50 

ppm. Thus it significantly drops the caustic consumption 

and produces slurry suitable for economic on-site or offsite disposal as well as conventional ZLD systems. It is 

important to note that this process is not only used to 

treat the OTSG blowdown in SAGD application, but 

mainly to treat the SAGD produced water that has high 

level of silica. 

A purge stream removes contaminants from the system. 

The purge is typically 2 – 5% of the incoming flow; these 

systems operate at concentration ratios of 20 – 50. This 

stream must be disposed of by deep well injection or, if 

there is an inadequate or no deep well capacity, by 

further concentrating the blowdown with a zero liquid 

discharge brine concentrator and crystallizer system, 

generating a dry solid for disposal. 

Coal-bed methane 

CBM produced water is high in sodium and bicarbonate 

and low in hardness, may include suspended solids, 

iron, silica, and barium. Table-4 provides a typical CBM 

produced water characteristics. Sodium is a closely 

monitored aspect of the treated water quality as it is 

predominantly utilized for irrigation. The influence of 

dissolved sodium on soils is commonly assessed using 

sodium adsorption ration (SAR). SAR is calculated from 

the concentrations of sodium, calcium, and magnesium 

ions in the water as follows: 

2

2 2







Ca Mg

Na SAR

Irrigation water with an SAR>12 is commonly 

categorized as sodic and has the potential to swell and 

disperse clays in the soil, which can result in decreases 

pore size and soil permeability. When concentration of 

sodium sorbed on clay exchange sites increase relative 
IWC-12-21 

to calcium, the attractive forces between clay platelets 

are decreased and platelets begin to swell and disperse. 

Although boron is an essential plant nutrient, excessive 

amounts can be toxic. Boron concentration less than 0.5 

ppm is generally safe, 0.5-1.0 ppm is slight to moderate, 

and greater than 1.0 ppm is considered severely toxic. 

CBM produced water treatment plant design commonly 

incorporates RO and recovery RO (RRO) to maximize 

system recovery (Figure 25). The plants are designed to 

discharge greater than 95% of the influent water into the 

Powder River. An aeration pond is used for evaporating 

and concentrating the RO brine stream. While the silica 

concentration in the produced water is moderate (Table4), high recovery rate of the membrane system leads to 

silica scaling at low pH. On the contrary, scale control for 

hardness ions calls for low pH operation of the RO 

system. Ion exchange softener is included in the RO 

pretreatment to remove polyvalent hardness contributing 

ions. This allows the RO system to operate at a higher 

pH. The higher RO feed water pH increase solubility of 

silica, and organics which translate to lower silica scaling 

and organic fouling. Moreover, boron rejection across 

RO improves at a higher pH (Dey and Thomas, 2003). 

The CBM produced water plant in Powder River Basin 

was designed to discharge to a blended sodium level 

and to meet whole effluent toxicity (WET) test standards. 

Coal seam gas 

Natural gas from coal (NGC) in Canada and coal seam 

gas (CSG) is Australia generates produced water similar 

to CBM in their basic characteristics. Extracting natural 

gas from coal seams deep underground involves 

managing large quantities of water. 

Since October 2008, the Queensland government has 

had a published CSG water management policy, aiming 

to ensure that salt produced through CSG activities does 

not contaminate the environment, and to encourage the 

beneficial use of treated CSG water. There are 

widespread concerns about evaporation ponds, and long 

term legacy associated with salt stored in them. They are 

commonly equipped with leak detection system to keep 

water at controlled levels, and are enclosed by fencing to 

prevent adverse impact on wildlife and the environment. 

One potential problem posed by such ponds stem from 

their attractiveness to migratory waterfowl. If the pond 

contain oil or other hydrocarbons on the surface, birds 

landing in the ponds could become coated with oil and 

suffer harm. Covering pond with netting helps to avoid 

this problem. 

As the CSG industry expands, Government is concerned 

about the groundwater and landscape impacts of CSG 

water disposal methods. Despite this, there is evidence 

that evaporation ponds are still being constructed, and 

remain favored as the cheapest option for CSG 

producers. RO is identified as the best water treatment 

option to facilitate beneficial use of CSG produced water. 

The RO process is sensitive to the feed water quality. 

Hence the correct pretreatment process is essential to 

achieve the desired membrane life of at least three 

years. RO pretreatment system commonly consists of 

self screen strainer, ultrafiltration (UF) membrane, and 

weak acid cation exchanger (WAC) as shown in Figure 

26. CSG produced water treatment design commonly 

incorporates three stage RO process to achieve a 

recovery rate of 90%, leaving only 10% brine. The multistage RO process brine stream can be further 

concentrated by zero liquid discharge brine concentrator 

and crystallizer system, generating a dry solid for 

disposal. Treated produced water is mostly used for 

irrigation. 

Offshore produced water 

Produced water from offshore operations has generally 

been discharged to the sea. The discharge of produced 

water from offshore installations has been a major topic 

of discussion in the framework of Oslo/Paris (OSPAR) 

convention (Table-5) and the preceding Paris 

commission. In a typical process flow, production enters 

a three-phase high pressure separator, from which the 

output is water with a 500-2,000 ppm oil-in-water 

concentration. Use of hydrocyclone or skimmer serves 

as primary treatment option and achieves 50-150 ppm oil 

concentration. IGF is the most common secondary 

treatment option that conditions the produced water for 

overboard discharge or reinjection. Discharge oil 

concentration from IGF is typically below 25 ppm. An 

IGF is often selected over dissolved gas flotation (DGF) 

because of issues of solubility of inert and fuel gas at the 

high temperatures characteristics of produced water 

processes. Coalescing media or chemical affinity 

filtration discussed previously can be additionally used 

as tertiary step on an as needed basis to avoid sheens 

causing platform shutdowns. Most of the measures 

adopted by the commission have focused on dispersed 

oil fraction; however, there has been clear recognition of 

the discharge of hydrocarbon constituents in the 

dissolved phase, most notably the aromatic 

hydrocarbons. 

Subsea flow conditions are conducive to hydrates 

formation due to increased pressure and low 

temperatures at seabed and well flow conditions. 

Hydrates are physical combination of water and other 

small molecules to form a solid material having an “icelike” appearance but with significantly different structure 

and properties than ice. Hydrates in subsea flow 

conditions are issue for flow assurance. As a result, 

continuous hydrate inhibition is mandatory. The use of 

glycol and methanol for hydrate inhibition in gas 

production lines is well established and works effectively 

as long as the salt solubility is not exceeded. Glycol is 

normally recovered and recycled, whereas methanol is 

used in both once-through systems and in some cases 

partially recovered. 
IWC-12-21 

For subsea production systems, separation of produced 

water on the sea floor is not possible and any salt water 

associated with gas will distribute into and be separated 

with the rich glycol phase. During glycol regeneration, 

water is boiled off and salt enters the glycol systems led 

to serious operational problems and repeated fouling 

and plugging of process equipment including filters, heat 

exchangers, reboilers etc .However, recent innovations 

overcome problems experienced with salt contaminated 

glycol regeneration. 

As explained, TDS of the high temperature produced 

water stream generated from glycol regeneration system 

is typically low. However, produced water is generally 

high in organic impurities like BOD, COD, TOC, MEG, 

Methanol, BTEX, and Phenols. Tight discharge 

standards of BOD5 less than 10 ppm, COD less than 100 

ppm, each BTEX component less than 0.05 ppm, and 

phenol less than 0.015 ppm recently set by most 

regulatory authorities needs a comprehensive treatment 

strategy as shown in Figure 27. Role of each unit 

operations involved in the proposed treatment system is 

described previously. It is important to realize that 

phenol toxicity has an adverse effect on heterotrophs 

growth rate, this should be considered in designing 

biological unit process. The toxic effect can be measured 

by following the fraction of Specific Oxygen Uptake Rate 

(SOUR) loss between the sludge with zero phenol 

(SOUR0)and the sludge dosed with phenol 

(SOUR+)(Sorour, 2006) as follows. The results obtained 

from SOUR measurements indicate an increasing of 

toxicity effect from 0.325 at phenol concentration of 100 

mg/l to 0.53 at phenol concentration of 200 mg/l, 

increasing phenol concentration further to 300 mg/l 

resulted in increasing the phenol toxicity effect to 0.63. 

0 1

SOUR

SOUR PT



 

Enhanced oil recovery 

Water injection is mainly used for enhanced oil recovery 

(EOR). As oilfield age, the amount of water injected into 

the reservoir to help maintain reservoir pressure 

increases. Chemically enhanced oil recovery (CEOR) 

incorporates alkali, surfactant, and polymer to further 

improve the efficiency. 

Corrosion control by removal of dissolved oxygen (DO) 

is particularly important in water flooding. The vacuum 

deaeration process to remove DO is based on the 

reduction of solubility of oxygen in water at reduced 

pressure and oxygen content of equilibrium vapor. 

Addition of an inert gas to the contact tower of a vacuum 

deaeration process further reduces the concentration of 

DO in treated water. Alternative processes for the 

removal of DO exist. One system is based on stripping 

oxygen from water with a closed loop circulated nitrogen 

gas. This system includes regeneration of stripping gas 

by exothermic catalytic reaction between oxygen and a 

fuel in a reactor called deoxidizer. Catalyst being 

palladium coated Al2O3 sphere balls and fuel being 

hydrogen, methanol, or ethanol. Another process 

depends on the catalytic de-oxygenation using hydrogen 

gas with palladium doped anion exchange resin as 

catalyst (2H2+O2=2H2O). Membrane deaerators utilize 

hydrophobic hollow-fibre polypropylene micro porous 

membrane. Since the membranes are hydrophobic and 

have small pores, water will not easily pass through the 

pore. Commercial membrane deaerator units involve 

mass transfer in hollow-fibre modules where the vacuum 

and sweep gases are applied inside the fibres, and the 

water flows outside the fibres in cross flow perpendicular 

to the fibre axis. If we reduce the partial pressure of the 

volatile solute, some quantity of dissolved solute 

including oxygen will come out of the aqueous phase 

until the system reaches equilibrium. 

Injection of seawater can cause barium and/or strontium 

sulfate scale to form. They can create scale on the inside 

of pipes and tanks. Upon pressure decreases in and 

around production wells, the supersaturated sulfate 

solution is no longer stable and precipitation occurs. 

Marathon oil developed sulfate removal plant (SRP) 

using nanofiltration (NF) membranes in 1991 (Figure 28). 

British Petroleum developed a process that uses low 

salinity water for injection. Low salinity oil recovery is the 

injection of water with a TDS ranging from 300 ppm to 

4,000 ppm. This system can use RO or a combination of 

NF and RO. 

Conclusions 

Produced water is not a single commodity. The physical 

and chemical properties of produced water vary 

considerably depending on the geographical location of 

the field, the geological host formation, and the type of 

hydrocarbon product being produced. The treatability of 

produced water varies even at a single location over 

time. Consequently, no unified treatment approach exists 

for various produced water streams. It is recommended 

to investigate specific produced water characteristics 

with respect to quality and quantity, and assess the 

technical and economic feasibility of available alternative 

technologies to achieve desired level of treated water 

quality. 

Nomenclature 

dm=Diameter of the oil droplet, micron (μm) 

E0 = Evaporation rate, mm/day 

F=Factor accounts for change in air density with change 

in elevation, dimensionless 

PT=Phenol toxicity, dimensionless 

RS=Solar irradiance, W/m2

SOUR+=SOUR for sludge laden with phenol, 

mgO2/mgMLSS.h 

SOUR0=SOUR for sludge with zero phenol, 

mgO2/mgMLSS.h 

TD=Mean dew point temperature, °C 

Tm=Mean of daily extreme temperatures, °C 

u=Wind velocity at 2m above surface, m/s 
IWC-12-21 

V0=Rising vertical velocity of oil droplet relative to water 

continuous phase, m/s 

z=Elevation above sea level, m 

ΔSG=Difference in specific gravity of oil and water 

relative to water, dimensionless 

μw=Viscosity of water, CP 

References 

1. Brown, C. J., and Sheedy, M. (2002), “A novel ion 

exchange process for softening high TDS 

produced water”, SPE International Thermal 

Operation and Heavy oil Symposium, Calgary. 

2. Center for Environment, Commerce, and Energy, 

(October 20, 2011), “Water Produced with coal 

bed methane”. 

3. Davis, J. A., Harrison, K., and Shields, B. (2009), 

“Compact Technology: Increasing Treatment 

Capacity without building more basins”, Florida 

Water Resources Journal, pp. 24 – 29. 

4. Dey, A, and Thomas, G. (2003), “Electronics 

Grade Water preparation”, Tall Oaks Publishing, 

Colorado., pp. 384 

5. Esplugas, S., Gimenez, J., Contreras, S. 

Pascual, E., and Rodriguez, M. (2002), 

“Comparison of different advanced oxidation 

processes for phenol degradation”, Water 

Research, 36, pp. 1034 – 1042. 

6. Gwak, K. W., and Bae, W., (2010), “A review of 

steam generation for in-situ oil sand projects”, 

Geosystem Engineering, 13(3), pp. 111 – 118. 

7. Heins, W. F., McNeill, R., and Albion, S. “World’s 

first SAGD facility using evaporators, drum 

boilers, and zero discharge crystallizers to treat 

produced water”, Canadian International 

Petroleum Conference, June 7 – 9, Calgary, 

Alberta, Canada. 

8. Heins, W. F., and McNeill, R., (October, 2007), 

“Vertical-tube evaporator system provides SAGD 

facility quality feed water”, World Oil, 228. 

9. Heinz, W. F. (2007),”Is a Paradigm shift in 

produced water treatment technology occurring at 

SAGD facilities?”, Canadian International 

Petroleum Conference, June 12 – 14, Calgary, 

Canada. 

10. Kashaev, S., and Lee, D. W. (January , 2010), 

“Deep bed nutshell filter evolution”, 20th Annual 

Produced Water Seminar 

11. Ken, A., and Maurice, S. (2008), “Surface 

production operations – Design of oil handling 

systems and facilities”, Elsevier, Volume 1 (Third 

edition), pp. 501. 

12. Linacre, E. T. (1993), “Data-sparse estimation of 

lake evaporation, using a simplified Penman 

equation”, Agricultural and Forest Meteorology, 

64(3-4), pp. 237-256. 

13. Michaud, C. F. “Boiler Feed Water: Reducing 

scale and corrosion”, (April, 2001), Water 

Conditioning & Purification, pp. 38-42. 

14. Mokrini, A. D., and Esplugas, O. S., (1997), 

“Oxidation of aromatic compounds with UV 

radiation/ ozone/ hydrogen peroxide”. Water 

Science and Technology, 35 (4), pp. 95 – 102. 

15. Nature Technology Solution, “Introduction to 

Produced Water Treatment”, 

http://www.naturetechsolutions.com/ 

16. Sorour, M. T., Abdelrasoul, F., and Ibrahim, W. A. 

“Phenolic wastewater treatment”, Tenth 

International Water Technology Conference, 

IWTC10, Alexandria, Egypt, 2006. 

17. StateImpact, NPR, (January 23, 2012.), “Could 

Fracking Earthquakes Shake Pennsylvania?”. 

18. Weiss, J. S., Alvarez, M., Tang, C. C., Horvath, 

R. W., and Stahl, J. F. (2005), “Evaluation of 

moving bed biofilm reactor technology for 

enhancing nitrogen removal in a stabilization 

pond treatment plant”, WEFTEC, Washington 

DC. 

19. Welch, J. (August, 2009) “Coal-Bed Methane 

Produced Water: An Evolution in Treatment”, 

White Paper, Siemens Water Technologies. 
IWC-12-21 

Table – 1: Produced water deoiling equipment 

Equipment Type Removal 

Capacity 

By Particle 

Size, 

Microns 

Oil In Water 

Concentration, 

ppm 

Skimmer Tanks 

and Vessels 100 – 150 500 – 10,000 API gravity 

separator 

Parallel plate 

separator 30 – 50 100 – 1,000 Corrugated plate 

separator 

Induced gas 

flotation 20 – 30 20 – 300 

Hydrocyclones 10 – 15 200 – 10,000 

Liquid/Liquid 

coalescer 5 – 10 10 – 10,000 

Centrifuge 5 – 10 200 – 10,000 

Walnut shell filter 2 – 5 1 – 50 

Table – 2: Produced Water Characteristics from 

different shale gas focus areas 

Shale Gas 

Focus 

area 

Geographical Region Produced 

Water TDS, 

ppm 

Barnett Bend Arch-Fort Worth 

Basin, Texas 

40,000 – 

250,000 

Fayetteville Arkansas 8,000 – 

80,000 

Haynesville Southwestern 

Arkansas, northwest 

Louisiana, and East 

Texas 

40,000 – 

250,000 

Marcellus Appalachian Basin of 

eastern North America 

from central New York 

through Pennsylvania 

and West Virginia into 

Virginia and 

Tennessee and as far 

west as Ohio. 

45,000 – 

300,000 

Woodford Oklahoma 12,000 – 

150,000 

Table – 3: Comparison of feed water specification for 

OTSGs and drum boilers 

Parameters OTSG Drum Boilers 

Hardness, mg/l 

as CaCO3

0.2 – 0.5 Not detectable 

TDS or 

Conductivity < 7,000 ppm < 150 μs/cm 

Silica, mg/l as 

SiO2

< 50 ≤ 2.0 

pH 7.0 – 9.5 8.8 – 9.6 

Dissolved 

oxygen, ppm 

0.01 – 0.02 < 0.007 

Oil, ppm < 0.5 < 0.2 

Iron, ppm < 0.1 < 0.01 

Table – 4: Typical CBM produced water characteristics 

Produced water parameter Unit Typical 

Value 

pH 8.2

Sodium + Potassium ppm 915

Total hardness ppm as 

CaCO3 130 

Barium ppm 1.4

Strontium ppm 0.9

Carbonate ppm 37

Bicarbonate ppm 2,416

Chloride ppm 32

Boron ppm 0.2

Silica ppm 12

Total dissolved solids (TDS) ppm 3,460

Table – 5: Offshore discharge regulations 

Agreement Oil in water 

Limit 

Other 

OSPAR (North 

sea countries) 30 ppm (2007) 

Pre-approval of 

chemical 

additives 

Baltic sea 

convention and 

HELCOM 

(Helsinki 

commission) 

15 ppm 

Pre-approval of 

chemical 

additives 

Kuwait 

convention 

(Red sea) 

40 ppm (100 

ppm maximum) 

Barcelona 

convention 

(Mediterranean) 

40 ppm (100 

ppm maximum) 

China 

(GB4914-85) 

30-50 ppm (75 

ppm maximum) 

Australia 30 ppm (50 

ppm maximum) 

USA (40 CFR 

435) 

29 ppm (42 

ppm maximum) 
IWC-12-21 

Figure 1: Typical production profile for an oilfield in the 

North East Atlantic (Source: Nature Technology 

Solution, http://www.naturetechsolutions.com/) 

Figure 2: Water flooding in an offshore installation 

(Source: BJ Services/Baker Hughes) 

Figure 3: Injection well (Source: NPR, January 23, 

2012) 

Figure 4: Oil skimmer (Source: Extol Hydro 

Technologies) 

Figure 5: Induced gas flotation (Source: Veolia Water 

Solutions) 

Figure 6: Walnut shell filter operation (Source: 

Siemens Water Technology) 
IWC-12-21 

Figure 7: Gas Liquid Reactor in micro-bubble flotation 

system (Source: Exterran Water Solutions) 

Figure 8: Walnut shell filter with internal scrubber and 

mixer (Kashaev and Lee, 2010) 

Figure 9: Macro porous polymer extraction (MPPE) 

system (Source: Akzo Nobel/Veolia Water Solution) 

. 

Figure 10: Liquid/Liquid Coalescer/separator (Source: 

Pall PhaseSep Coalescer) 

Figure 11: PACT wastewater treatment system 

(Source: Siemens Water Technologies) 

Figure 12: Moving Bed Biofilm Reactor (MBBR) 

(Source: Davis et al., 2009) 
IWC-12-21 

Figure 13: Profile of phenol with different AOP 

(Mokrini, A. D., and Esplugas, O. S., 1997) 

Figure 14 RO flowsheet for produced water 

desalination (Source: Veolia Water Solutions) 

Figure 15: RO flowsheet for produced water 

desalination (Source: Veolia Water Solutions) 

Figure 16: Forward Osmosis – The Green Machine 

(Source: Emerald Surf Sciences) 

Figure 17: Brine concentrator and crystallizer (Source: 

RCC, GE Water & Process Technologies, “Produced 

and Frac Water Treatment/ Reuse for the Barnet 

Shale Play” Presentation for the STW Resources Inc.) 

Figure 18: Hydraulic fracturing – Shale gas production 

(Source: http://www.squidoo.com/) 
IWC-12-21 

Figure 19: Evaporation and Crystallization for 

Marcellus shale produced water and flowback water 

treatment 

(Source: HPD/Veolia Water Solutions) 

Figure 20: Mining and SAGD methods for oil sands 

(Source: TOTAL, Paris) 

Figure 21: Decanter centrifuge for oil sand tailings 

management (Source: GEA Westfalia) 

Figure 22: Boiler feedwater and steam circuit for 

OTSG SAGD process (Gwak and Bae, 2010) 

Figure 23: SAGD produced water treatment system 

for reuse in OTSGs 

Figure 24: Evaporative SAGD produced water 

treatment and drum boiler (Heins and McNeill, 2007) 

Figure 25: CBM produced water treatment system in 

Powder River Basin (Welch, 2009) 
IWC-12-21 

Figure 26: Coal seam gas produced water treatment 

Figure 27: Glycol regeneration produced water treatment 

Figure 28: Sulfate reduction Plant (Source: NATCO, Kizomba A Case Study in Angola, West Africa)