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# OVERVIEW OF PRODUCED WATER AND EOR

WATER TREATMENT

AVIJIT DEY, Bechtel Corpor ation, Houston, TX 77056

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KEYWORDS: BTEX, CBM, CDX, crystallizer, CSG, deoiling, EO R, evaporation pond, evaporator, flowback, FO, fracking, Hi-Flow, HLS, IGF, ISF, Liquid/ Liquid coale scer, MBBR, MBF, MFT, , MPPE, , NPD, PACT, PAH, Produced water, SAGD, shale gas, skimmer, SRP, UIC, vacuum deaer ation, 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 a dded down-hole during production. These waters exist under high pressures and temperatures, and usually contain oil a nd metals. The treatment of produced water is a key component of the cost of producing oil and gas. The ability to e fficiently and economically dispose of this water is vital to the success in the oil production business. In this article, produced water treatment approach for s hale gas, oil sand mining, oil sand steam assisted gravity drainage (SAGD), coal bed methane (CBM), coal seam gas (CS G), and offshore oil/ gas development fields shall be discussed. In addition, technical options for the enhanced oil re covery (EOR) water treatment shall also be discussed.

INTRODUCTION Water with higher density than oil lays in huge layers below hydrocarbons in the re servoir (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 tr eat 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 r egular 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 stat e-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 diminis hed 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): 

#  
  ] 5

. 2 ) 40 8

. 0 [( 10 00042

. 0 015

. 0 6

0

D m S m T T u F R z T E

    

        

z F  

   5 10 7

. 8 0

. 1

153 8

. 10   
m S T R
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 d SG V
 2 7

0 10 556

. 5    

 

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. Detecti on 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 ar omatic 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 BOD 5 value of numerous produced water streams.

Powdered activated carbon tr eatment (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) provi des stability against shock and variable organic loading protecting the living biology from upstream upsets and toxi city 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 acti vated 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 (O 3 , O 3 /H 2 O 2 , UV, UV/O 3 , UV/H 2 O 2 , O 3 /UV/H 2 O 2 ) 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+O 3 +H 2 O 2 (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: 

#   

Brine pw 

### TH TDS Leakage   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 dr ive 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

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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 circulatio n (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 hydr ocarbons 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 in troduced 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 H 2 S. 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 consumptionand 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   

  Mg Ca 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

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to calcium, the attractive forces between clay platelets are decreased and platelets begi n 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 silicaconcentration 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 characte ristics. 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 arecovery 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 framew ork 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 previous ly 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 othersmall molecules to form a solid material having an “icelike” appearance but with significantly different structure and properties than ice. Hy drates 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.

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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 BOD 5 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 (SOUR 0 )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 Al 2 O 3 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 (2H 2 +O 2 =2H 2 O). Membrane deaerators utilize hydrophobic hollow-fibre pol ypropylene 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

d m =Diameter of the oil droplet, micron ( μ m)

E 0 = Evaporation rate, mm/day F=Factor accounts for change in air density with change in elevation, dimensionless PT=Phenol toxicity, dimensionless

R S =Solar irradiance, W/m 2

SOUR + =SOUR for sludge laden with phenol, mgO 2 /mgMLSS.h

SOUR 0 =SOUR for sludge with zero phenol, mgO 2 /mgMLSS.h

T D =Mean dew point temperature, °C

T m =Mean of daily extreme temperatures, °C u=Wind velocity at 2m above surface, m/s

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V 0 =Rising vertical velocity of oil droplet relative to water continuous phase, m/s z=Elevation above sea level, m

Δ SG=Difference in specific gravity of oil and water relative to water, dimensionless

μ w =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.

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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 CaCO 3 0.2 – 0.5 Not detectable

TDS or Conductivity < 7,000 ppm < 150 μ s/cm

Silica, mg/l as

SiO 2 < 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 CaCO 3 130

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)

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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)

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Figure 7: Gas Liquid Reactor in micro-bubble flotation system (Source: Exterran Water Solutions)

Figure 8: Walnut shell filt er 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)

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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/ )

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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)

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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)