WO2012047210A1 - Système et procédé de recyclage d'eau de champs pétrolifères - Google Patents

Système et procédé de recyclage d'eau de champs pétrolifères Download PDF

Info

Publication number
WO2012047210A1
WO2012047210A1 PCT/US2010/051554 US2010051554W WO2012047210A1 WO 2012047210 A1 WO2012047210 A1 WO 2012047210A1 US 2010051554 W US2010051554 W US 2010051554W WO 2012047210 A1 WO2012047210 A1 WO 2012047210A1
Authority
WO
WIPO (PCT)
Prior art keywords
water
treating
clarifier
tank
contaminated
Prior art date
Application number
PCT/US2010/051554
Other languages
English (en)
Inventor
Thomas S. Evans
Original Assignee
Evans Thomas S
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Evans Thomas S filed Critical Evans Thomas S
Priority to PCT/US2010/051554 priority Critical patent/WO2012047210A1/fr
Publication of WO2012047210A1 publication Critical patent/WO2012047210A1/fr

Links

Classifications

    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D17/00—Separation of liquids, not provided for elsewhere, e.g. by thermal diffusion
    • B01D17/02—Separation of non-miscible liquids
    • B01D17/0202—Separation of non-miscible liquids by ab- or adsorption

Definitions

  • Produced water is typically contaminated with significant concentrations of chemicals and substances requiring that it be disposed of or treated before it can be reused or discharged to the
  • Produced water includes natural contaminants that come from the subsurface environment, such as hydrocarbons from the oil- or gas-bearing strata and inorganic salts.
  • Produced water may also include man-made contaminants, such as drilling mud, "frac flowback water” that includes spent hydraulic fracturing fluids such as polymers and inorganic cross- linking agents, polymer breaking agents, friction reduction chemicals, and artificial lubricants. These contaminants are injected into the wells as part of the drilling and production processes and recovered as contaminants in the produced water.
  • frac flowback water that includes spent hydraulic fracturing fluids such as polymers and inorganic cross- linking agents, polymer breaking agents, friction reduction chemicals, and artificial lubricants.
  • the disclosure describes a novel approach for treating water, such as oilfield production waste.
  • the disclosure describes novel methods for chemically treating contaminated water, such as chemical processes for softening water, demulsifying hydrocarbons, destroying a sequestering effect on divalent cations, destroying any detectable amount or over 99% of aerobic and anaerobic bacteria, and breaking long chain polymers.
  • the disclosure further describes novel methods for clarifying contaminated water to remove suspended solids.
  • this disclosure describes a method of treating contaminated water, the contaminated water containing some amount of polyacrylamides, emulsified hydrocarbons, and sequestered divalent cations.
  • the method includes performing the following steps: a) treating a stream of the contaminated water with an effective amount of phosphoric acid and sodium phosphate;
  • the tight emulsion clarifier comprises a hydrophobic isobutylene backbone and a hydrophilic maleic hydrophilic component
  • Another aspect of this disclosure describes a method of treating water.
  • the method includes performing the following steps:
  • Yet another aspect of this disclosure describes a method of treating water.
  • the method includes performing the following steps:
  • An additional aspect of this disclosure describes a method of treating water. The method includes performing the following steps:
  • FIG. 1 illustrates an embodiment of a process flow diagram of a water treatment system.
  • FIG. 2 illustrates an embodiment of a method for treating water.
  • FIG. 3 illustrates an embodiment of a method for treating water.
  • FIG. 4 illustrates an embodiment of a method for treating water.
  • FIG. 5 illustrates an embodiment of a method for treating water.
  • This disclosure describes embodiments of novel systems and methods for treating water including, specifically, treating oilfield production waste water to such an extent that it can be either reused or discharged.
  • This disclosure describes chemical processes and a system which breaks long chain polymers common in flowback fluids generated by hydraulic fracturing treatments (hereinafter referred to simply as "frac flowback fluids").
  • This disclosure further describes chemical processes for softening water, demulsifying emulsified hydrocarbons contained in water, and eliminating a sequestering effect on divalent cations contained in water. These chemical processes do not require digestion or dissolved air flotation.
  • Produced water is typically contaminated with significant concentrations of chemicals and substances requiring that it be disposed of or treated before it can be reused or discharged to the environment.
  • Produced water includes natural contaminants that come from the subsurface environment, such as hydrocarbons from the oil- or gas-bearing strata and inorganic salts.
  • Produced water may also include man-made contaminants generated by the injection of chemicals to improve production from wells.
  • frac flowback water that includes spent hydraulic fracturing fluids such as polymers and inorganic cross-linking agents, polymer breaking agents, friction reduction chemicals, and artificial lubricants.
  • Hydrofracturing, or "frac-ing” is a process whereby the production rates of wells can be increased by the injection of a solution of chemicals that cause the fracturing of the subsurface strata. Frac-ing is a very water intensive process and requires the use of water that is sufficiently clean to allow the frac chemicals to work properly and
  • acids and caustics such as soda ash, calcium
  • viscosity reducing agents such as polymers of acrylamide.
  • Frac water is a term that refers to water suitable for use in the creation of fracturing (frac) gels which are used in hydraulic fracturing operations. Frac gels are created by combining frac water with a polymer, such as guar gum, and in some applications a cross-linker, typically borate-based, to form a fluid that gels upon hydration of the polymer.
  • Frac flowback waters frequently contain significant amounts of unbroken gels and polyacrylamides because breaker chemistry is ineffective or improperly applied. Additionally, traditional polymer breaking chemistry used in fracturing operations only works downhole where temperatures are high. These breakers do not work at ambient surface temperatures and pressures. Common breakers are oxidizers such as potassium persulfate, sodium persulfate, and hydrogen peroxide and, of the above, only hydrogen peroxide has any effect at room
  • the water treatment processes and systems in this disclosure can be described as performing a chemical breakdown of undesirable polymers followed by a separation operation.
  • the polymer breakdown operation drastically reduces the polymer chain length of the polymers commonly encountered in oilfield waste water which then allows the water to be reused for other industrial purposes, such as for frac water, for which the untreated produced water is unsuitable.
  • the industrial uses contemplated are those in which low salt and dissolved solids content is typically not a requirement.
  • the effluent from the treatment system could be diluted with fresh water until the desired chemistry is obtained.
  • the polymer breakdown operation may be performed in a single stage or in multiple stages.
  • one or more chemicals may be mixed with the produced water to be treated (also referred to as the "raw water”).
  • the mixing may include inline mixing such as through the use of venturi or other mixing valves or flow chambers, mixing in one or more tanks or some combination of the two mixing approaches.
  • the raw water is treated with phosphoric acid and sodium phosphate to perform the chemical breakdown of undesirable polymers.
  • the phosphoric acid and sodium phosphate reduce at least some of the chain length of the undesirable polymers contained in the water. Further, phosphoric acid and sodium phosphate reduce water hardness.
  • the water is treated with a tight emulsion clarifier and/or calcium carbonate powder and potassium hydroxide to assist the phosphoric acid and sodium phosphate in performing the chemical breakdown of undesirable polymers and/or to assist the downstream separation operations.
  • the tight emulsion clarifier demulsifies at least some of the emulsified hydrocarbons and/or fluorosurfactant stabilized hydrocarbons contained in the water.
  • the calcium carbonate powder and potassium hydroxide destroy a sequestering effect on divalent cations found in the water to facilitate removal of suspended solids in downstream separation operations, such as a coagulation operation and/or a flocculation operation. Further, the calcium carbonate powder and potassium hydroxide reduces water hardness.
  • the separation operation may be a single stage operation or be performed in multiple stages.
  • any precipitates or other solids that exist during or result from the polymer breakdown operation may be intentionally carried into the separation operation for removal.
  • easily removable solids that exist during or result from the polymer breakdown operation may be removed as part of the polymer breakdown operation with the following separation operation being used as a final polishing step.
  • sufficient solids removal may be obtained concurrently with the polymer breakdown operation so that no additional and independent separation operation need be performed - in essence the polymer breakdown operation and separation operation being performed simultaneously.
  • the separation operation need not be performed at all, such as where the industrial application allows for and can handle water with entrained solids.
  • the separation operation includes a coagulation operation, a flocculation operation, a clarifying operation, and/or a filtering operation.
  • the water treatment system preferably does not utilize digestion or dissolved air flotation, although depending on the conditions such treatments could be adapted for use with the systems described herein.
  • reference to “a lithium hydroxide” is not to be taken as quantitatively or source limiting, reference to “a step” may include multiple steps, reference to “producing” or “products” of a reaction should not be taken to be all of the products of a reaction, and reference to “reacting” may include reference to one or more of such reaction steps. As such, the step of reacting can include multiple or repeated reaction of similar materials to produce identified reaction products.
  • FIG. 1 illustrates a process flow diagram of a water treatment system 100.
  • the water treatment system 100 includes at least one polymer breaking operation and at least one separation operation.
  • a break operation is utilized to chemically break down undesirable long chain polymers, such as polyacrylamides, in water.
  • a separation operation is utilized to remove any precipitates or other solids that exist during or result from the break operation and are carried into the separation operation for removal.
  • the water treatment system 100 includes a first break operation 102, a second break operation 104, a coagulant addition operation 106, a flocculent addition operation 108, a clarifying operation 110, and a filtering operation 112.
  • the first break operation 102 receives contaminated water.
  • the contaminated water is any water containing any undesirable polymers, such as produced water, frac flowback fluids, and blends thereof.
  • the frac flowback fluids are from both "slick water” and “gel” fracs. They may contain polyacrylamide friction reducers, guar type gels, crosslinkers, and a variety of frac additives.
  • the produced waters are generally 2,000-15,000 TDS brines from producing oil and gas wells. However, the produced water can be as high as 290,000 TDS brines from producing oil and gas wells.
  • Raw produced water also may contain significant quantities of iron oxide, iron sulfides, scales, sulfate reducing bacteria, aerobic bacteria, and hydrocarbons.
  • First break operation 102 treats the contaminated water with a chemical mixture to start the polymeric chain breaking process.
  • the treatment is performed utilizing:
  • This treatment reduces the viscosity of the contaminated water and aids in enhancing water clarity.
  • fluids enter the bottom of the tank and discharge off the opposite top side of tank although other configurations are also suitable.
  • chemical injection is at the incoming point of flow although it could be injected into the tank at any point or into the water stream prior to the point of entry.
  • sample points are maintained at the center of the tank and the discharge of the tank is monitored for the chemistry and the other properties of the water in the first tank.
  • the first break operation 102 mixes the fist tank at a high rate.
  • the average retention time of the contaminated water in the first tank by first break operation 102 is about 5 to 15 minutes.
  • the retention time in the first tank by first break operation 102 is determined based on effluent testing so that effluent is not released from the tank until it reaches some target chemistry.
  • successful treatment by first break operation 102 is indicated by a significant reduction in viscosity (particularly with heavy polymer laden frac flowback fluids) and a significant enhancement of the flocing process.
  • a target reduction of viscosity is less than 50% of input viscosity, with reductions to less than 25% and less than 10% preferred. Without this step, coagulation and flocculation may not happen. In the lab, over- treating at this stage does not seem to have a negative effect on the ultimate suitability for the treated water for industrial reuse.
  • Incoming fluid ratios or other properties such as viscosity may be used to indicate potential treating rates. For example, if the ratio of frac flowback to produced water exceeds 50/50 (as determined based on some analysis of the raw water), the response may be to increase the chemical treatment to provide additional polymer breaking.
  • the contaminated water may be pretreated to remove liquid hydrocarbons.
  • the contaminated water is pretreated with quaternary ammonium chloride compounds to reduce anaerobic and aerobic bacteria levels.
  • batches of contaminated water high in polymer concentrations are pretreated to reduce viscosity, such as with an epi amine (as discussed further below).
  • the water is pretreated with oxidizing chemistry.
  • liquid hydrocarbons are removed during the first break operation via gravity settling, through the use of emulsion breaker chemistry and heat, and/or any other suitable process or system for removing hydrocarbons from water. Hydrocarbon removal need not be complete. In an embodiment, the resulting fluids may still contain up to approximately 150-500 ppm oil when processed by the polymer breakdown operation without inhibiting the treatment process.
  • the flowback fluid now contains free hydrocarbons, highly emulsified hydrocarbons, and very fine fluorosurfactant stabilized hydrocarbon.
  • DBSA dodecylbenzyl sulfonic acid
  • Protreat supplies products that combine all of these chemistries in one custom formulation, such as the products EB-506, EB-507, EB-508, EB-510, and EB-51 1.
  • the treating rate for these products is about 25 to 100 ppm based on total fluid volume treated.
  • application of any of any one of these products or a combination of products is done via chemical injection with static mixer in the standard oil/water separation facilities ahead of the water recycle plant.
  • the tightly emulsified and fluorosurfactant/micro emulsion stabilized hydrocarbons contained in the contaminated water presents a unique and difficult treatment problem. Since the hydrocarbon particles are vey small in size (less than 5 micron diameter) and very stabilized by the surfactant/fluorocarbon chemistry, separation by centrifugation, mechanical filtration, chemical and heat, solvent extraction, and other standard oil/water separation techniques are virtually impossible. Therefore, a new approach for oil/water separation is needed.
  • the first break operation 102 may treat for the tightly emulsified and fluorosurfactant stabilized hydrocarbons utilizing a unique copolymer or tight emulsion clarifier.
  • the chemical structure of the tight emulsion clarifier includes a hydrophobic isobutylene backbone and a hydrophilic maleic component.
  • the tight emulsion clarifier may be an anionic dispersant for aqueous systems.
  • the isobutylene backbone has abundant oil attracting sites and the pentane shaped maleic hydrophilic component of the copolymer or tight emulsion clarifier attracts dispersed water wet constituents in the fluid.
  • the tight emulsion clarifier imparts a strong negative charge on the resultant accumulations which sets up a very favorable scenario for subsequence coagulation and flocculation.
  • the treating rate of the tight emulsion clarifier is about 20 to 250 ppm.
  • Treatment with the tight emulsion clarifier improves clarity (NTU) of the final product by about 50 to 75%.
  • the phrase "final product" refers to the effluent or water produced by system 100 or any performed method described herein.
  • the tight emulsion clarifier is the polycarboxylic acid salt copolymer Rhodoline® 11 1 as sold by Rhodia Corp.
  • the tight emulsion clarifier is the copolymer Rohm and Haas Tamol 731A as sold by Dow.
  • copolymers were designed for and are typically utilized for stabilizing iron oxide pigments in latex paints.
  • the hydrophobic oxides are attracted to the hydrophobic isobutylene backbone and are then carried to the hydrophilic water base by the hydrophilic maleic "head" of the copolymer in latex paints. This results in a stabilized/dispersed suspension of iron oxide in a water based latex paint that resists settling during storage (i.e. the pigments do not readily settle out to allow for mixing and re-mixing of the paint).
  • the isobutylene backbone of the copolymer attracts tightly emulsified oil, demulsifies it, (only the hydrocarbons will stick to the backbone, the water will be released), and then uses the maleic component to carry the captured oil into a water based floe for removal.
  • the tight emulsion clarifier was found to be effective in the water treatment system 100.
  • two particularly effective tight emulsion clarifiers are Rhodoline® 1 11 as sold by Rhodia Corp. and Tamol 731A as sold by Dow. Both of these compounds are carboxyl-functional polymers having a hydrophobic component and a hydrophilic component and it is presumed that any polymer structure with these components would be effective.
  • the water may be treated with silicates to demulsify the emulsified and fluorosurfactant stabilized hydrocarbons instead of utilizing the tight emulsion clarifier.
  • Silicates are very hydrophilic and in this application are effective at drawing water out of emulsion and dispersion allowing the residual hydrocarbons to get caught up in the flocculation process.
  • the silicate chemistry works synergistically with phosphoric acid when phosphoric acid is also added to treat the contaminated water in the first break operation 102. It is further believed that the acid activates the silicate as typified when municipal water treating facilities activate sodium silicate with sulfuric acid prior to application for water clarification. If the silicate is applied with phosphoric acid in the first break operation 102, then the resulting clarity of the final product is improved by about 25 to 50% compared to a final product produced from applying silicate upstream.
  • the silicate utilized is sodium silicate Type N (3.22 weight ratio) as sold by PQ Corporation.
  • the silicate utilized is Kasil 1 Potassium Silicate (2.50 weight ratio) as sold by the PQ Corporation.
  • the silicate utilized in the first break operation 102 is Kasil 6 Potassium Silicate (2.10 weigh ratio) as sold by the PQ Corporation.
  • the water is pretreated with oxidizing chemistry, such as hydrogen peroxide/ammonium persulfate and sodium bisulfite.
  • oxidizing chemistry such as hydrogen peroxide/ammonium persulfate and sodium bisulfite.
  • the pretreatment is performed utilizing:
  • Peroxide and persulfates are strong oxidizers which break down hydrogen bonds and thus destroy long chain polymers.
  • Sodium bisulfite acts as a strong activator for the system and allows it to work at low temperatures (less that 80 degrees Fahrenheit).
  • Oxidizers used for gel/pac breaking traditionally only are effective at high temperatures (over 150 degrees
  • this pretreatment is performed utilizing:
  • this pretreatment is performed utilizing:
  • the effluent from the first tank has a pH that is about 0.5 to 1.0 less than the contaminated water that enters the first tank.
  • the contaminated water that enters the first tank has a pH of about 6.70 and the effluent from the first tank has a pH of about 5.70 to 6.20 depending on incoming water quality and make-up.
  • the effluent from the first tank will have a viscosity that is lower than the contaminated water that enters the first tank.
  • the contaminated water entering the first tank will be dark or opaque with a NTU of about 500-2500. In this
  • the effluent from the first tank has no visual color change.
  • Effluent from first tank generated by first break operation 102 is transferred to and treated in second tank by the second break operation 104.
  • the second break operation 104 treats the effluent with calcium hydroxide and potassium hydroxide to raise the pH to 10- 12.5. It is understood that this step breaks down the remaining polymers and crosslinkers and starts the pin floe process and may be referred to as a pH adjustment operation.
  • calcium hydroxide is fed at a 5% solution but any suitable concentration may used in order to achieve the treatment target.
  • the calcium carbonate formed in situ at this stage provides a nucleation site for solids agglomeration.
  • KOH is fed at a 45% strength.
  • mixing is at a high rate and average retention time is 5-15 minutes or as necessary to meet the treatment targets.
  • the second break operation 104 treats at a specific rate with Ca(OH)2 and then use KOH to increase the pH to 12.0 to start.
  • an effective lime treating rate of 0.1% by weight that is treating a weight of water with 0.1% of that weight in lime
  • Going above 0.2% did not help the polymer breaking or the end result.
  • With produced waters, the process has been observed to work down to a pH of 10.5.
  • Polymer-laden waters have been observed to require the 12.0 pH and higher level. Again, over treating at this stage has not appeared to cause problems in the later stages with the exception of the increased cost to neutralize the effluent treated during the filtration operation 112.
  • the second break operation 104 treats the effluent produced from the first break operation in a second tank with potassium hydroxide (KOH) and powdered calcium carbonate.
  • KOH potassium hydroxide
  • the recent changes in frac fluid make-up include the addition of various chemicals that create sequestration of divalent cations in the water. Some of this sequestration/chelation occurs as a result of using acetic acid in the early stages of the frac to facilitate gel formation. It is frequently added with some sodium acetate. When injected downhole, acetic acid can form sodium acetate, calcium acetate, and/or potassium acetate. Also, copper ion in EDTA is frequently utilized as a catalyst in an attempt to improve gel breaking and acts as a chelation agent for cations. All of these additives set up a condition that seriously negates the lime softening effect of the treating process described below.
  • a combination of potassium hydroxide and powdered calcium carbonate is utilized to treat the effluent produced from the fist break operation 102 in the second break operation 104.
  • the shock treatment of potassium hydroxide in combination with natural calcium in the water results in the formation of calcium carbonate in situ. No calcium hydroxide is required.
  • powdered calcium carbonate is then added to supply ample nucleation sites and facilitate coagulation and flocculation of the suspended solids.
  • Powdered calcium carbonate may be utilized because it provides an extremely high level of surface area available for attraction of particulates. Further, the use of powdered calcium carbonate greatly enhances the "softening" effect of the calcium carbonate formed in situ.
  • Lime softening typically provides from about 55 to 65% reductions in hardness.
  • This new combination process (of KOH and powdered calcium carbonate) provides for more than 95% reduction in water hardness.
  • the KOH and powdered calcium carbonate may be added in amounts to achieve a maximum reduction in hardness but, alternatively the system can be operated to achieve any target hardness reduction such as a 50% reduction, a 75% reduction a 90% reduction a 95% reduction or a maximum achievable reduction.
  • the process is synergistic and requires both chemistries in order to work. Neither chemical (KOH or powdered calcium carbonate) appears as effective by itself as in combination, suggesting the two in combination work sympathetically to enhance treatment.
  • the strength of potassium hydroxide in this process is about 45%.
  • treatment rate is about 200 to about 2000 ppm depending on water quality.
  • extremely high purity calcium carbonate from Missouri deposits is utilized to treat the effluent during the second break operation 104 in the second tank.
  • the calcium carbonate from Missouri deposits has very low levels of aluminum, magnesium, silica, and iron, which is sold by Mississippi Lime as CalCarb R2 200 mesh.
  • the treatment rate of the powdered calcium carbonate is about 100 to 1000 ppm depending on water quality during the second break operation 104 and the desired reduction in water hardness.
  • fluids enter the bottom of the second tank and discharge off the opposite top side of the tank.
  • chemical injection is at the incoming point of flow although it could be injected into the second tank at any point or into the water stream prior to the point of entry.
  • sample points are maintained at the center and discharge of the tank for monitoring the chemistry and other properties of the water in the second tank. Continuous pH monitoring may be performed via Hach instrumentation.
  • Another major observed advantage of treating at a pH of about 12.0 or higher at this stage is that this pH kills all detectable amounts or over 99 % of aerobic and anaerobic bacteria in the contaminated water.
  • Water containing detectable amounts of or 1% or more bacteria compared to the contaminated water fed into the water treatment system 100 cannot be re-used. It is critical that the water be free of any detectable amount of bacteria or contains less than 1% bacteria compared to the contaminated water prior to being shipped to the field.
  • the pH in the second tank is about 12 to 12.2. Additionally, pin floe may begin to appear within the second tank. Further, solid precipitate may begin to appear in the second tank.
  • Effluent generated by second break operation 104 is treated with a coagulant addition operation 106 in a third tank with a coagulant.
  • a coagulant addition operation 106 There are two types of coagulants. In one embodiment, a mixture of both types is used in the coagulant addition operation 106.
  • the first type of coagulant is inorganic.
  • Inorganic coagulants include the aluminum- based and iron-based compounds.
  • Iron-based coagulants include ferric sulfate, ferric chloride and ferrous sulfate.
  • Iron chemistry for coagulation has major drawbacks in the oilfield. While iron-based coagulants are effective at coagulating polymer when used in this process, they typically require large dosages and add dissolved iron to the water. The dissolved iron eventually oxidizes somewhere in the system causing severe scale deposition which operators interpret as major corrosion problem. Iron-based coagulants also results in large sludge volumes. For these reasons, aluminum-based coagulants are preferred over iron-based coagulants in this application.
  • the second type of coagulant is organic, which include polyamines, polydiallyldimethyl ammonium chloride cationic polymers (polyDADMACS), and epi-DMA (see below for a discussion of epi-DMA). While epi-DMA is preferred, polyamines and DADMACS do produce coagulation. Depending on the embodiment various combinations of two or more inorganic coagulants may be used to achieve synergistic effects.
  • an embodiment of the process uses a combination of inorganic and organic coagulants to achieve a synergistic effect that is much believed to be an improvement over using either type of coagulant by itself.
  • Another benefit of using the combination of coagulant types is that additional polymer breaking is provided as an insurance policy in the event polymer remains in the water that reaches the third tank.
  • An example of an embodiment of the coagulant used in coagulant addition operation 106 is the following mixture:
  • epi-DMA refers to epichlorohydrin/dimethyl amine copolymers (sometimes also referred to as epi-DMA amines or epi-amines) and high molecular weight (HMW) refers to a general characterization of the molecular weight of the epi-DMA.
  • HMW refers to molecular weight in the range of 500,000 to 10,000,000
  • Medium molecular weight (MMW) refers to 100,000 to 500,000
  • Low molecular weight (LMW) refers to less than 100,000
  • Very high molecular weight refers to greater than 10,000,000.
  • Epi-DMA are copolymers that vary in molecular weight and cationic charge density and, thus, possess differing abilities to coagulate different suspended solids in various waters. Examples of suitable epi- DMA include:
  • any equivalent or similar epi-DMA now known or later developed, may be used although different compounds may require different treatment amounts to achieve the target chemistry for this step.
  • Aluminum compounds are believed to be the most effective (treating rate and cost) coagulants for the purpose described.
  • ACH aluminum chlorohydrate
  • the metal ion is hydrolyzed and appears to form aluminum hydroxide floe as well as hydrogen ions. It has another benefit in the least effect on alkalinity of any of the aluminum based coagulants. It is believed that these aluminum floe structures are particularly effective at removing color and colloidal matter. Both are adsorbed onto/into the metal hydroxide.
  • ACH also produces much lower volumes of sludge than traditional coagulants and works over a much wider pH range. It has one of the highest basicity and lowest treating rate of all the coagulants. In testing, adequate treatment is observed when the process treats to a target of 50 ppm ACH in the third tank.
  • this step neutralizes the negatively charged suspended particles with a strongly cationic chemical combination and that the epi amine breaks down any residual polymer that has gotten this far in the process and produces a smaller/tighter/stronger floe structure.
  • a significant pin floe is formed at this point and the mixing speed is high to provide high collision rates.
  • the amount of pin floe found in the third tank is greater than the amount found in the second tank. Again, retention time is about 5 to 15 minutes but may be varied to achieve specified results.
  • fluids enter the bottom of the tank and discharge off the opposite top side of the tank.
  • chemical injection is at the incoming point of flow although it could be injected into the tank at any point or into the water stream prior to the point of entry.
  • sample points are maintained at the center and discharge of the tank for monitoring the chemistry and other properties of the water in the third tank.
  • treatment in the coagulant addition operation 106 may be dependent upon results of the flocculent addition operation 108. Poor turbidity and/or poor floe formation may be used to indicate improper treating rates at flocculent addition operation 108 in a fourth tank.
  • the process may include sampling at the discharge of the third tank and quickly performing a bench test to get advanced results. Loose floe may be used to indicate over treating at the coagulant addition operation 106 while high turbidity may be used to indicate under treating at coagulant addition operation 106.
  • the amount of floe in the fourth tank will be greater than the amount of floe found in the third tank. Further, clear water may begin to appear surrounding and/or above the floe in the third tank.
  • DADMACS Various molecular weight and charge density polydiallyldimethyl ammonium chloride cationic polymers
  • Effluent from the third tank generated by coagulant addition operation 106 is treated with a flocculant in a fourth tank during a flocculent addition operation 108.
  • flocculants There are three types of flocculants: Cationic including copolymers of acrylamide and DMAEM (dimethyl-aminoethyl- methacrylate), copolymers of acrylamide and DADMAC, and Mannich amines; Anionic including polyacrylates, copolymers of acrylamide and acrylate; and Non-ionic including polyacrylamides.
  • the preferred flocculant used are anionic copolymers of acrylamide and acrylate however any of the three types may be used.
  • the flocculant is:
  • floe structures sink rapidly and do not float. However, even if the floe structures float the treatment is the same. Again, average retention time is about 5 to 15 minutes but may be varied to achieve specific treatment targets.
  • fluids enter the bottom of the tank and discharge off the opposite top side of the tank.
  • chemical injection is at the incoming point of flow although it could be injected into the tank at any point or into the water stream prior to the point of entry.
  • sample points are maintained at the center and discharge of the tank for monitoring the chemistry and other properties of the water in the fourth tank.
  • Effluent from the fourth tank generated by flocculent addition operation 108 is fed into a fifth tank for a clarifying operation 110.
  • the clarifying operation 110 includes floe settling, separation and removal. Accordingly, within the fifth tank, the floe may settle to the bottom of the clarifier with a large layer of clear water being formed above the floe.
  • any separation system or process could be used instead of a clarifying operation 110 as long as the solids are adequately removed.
  • internal curtains are utilized to contain floes, encourage rapid settling, and minimize floe carryover to the next stage.
  • a sludge rake is employed to enhance sludge removal at the bottom of the vessel.
  • This rake rotates.
  • the rotation has a rate of .25 RPM.
  • Sludge discharge is through a timed valve mechanism to enhance the thickening process prior to entry into the filter box.
  • the average retention time is about 10 to 60 minutes.
  • clear fluids may be gravity fed off the top to the next stage, if any. Accumulated solids are removed from the tank bottom and fed to auxiliary storage for dewatering and any water obtained may be added to the fifth tank effluent or at any earlier stage of the process.
  • fluids enter the fifth tank or clarifier at a point approximately 30% above the tank bottom and exit in the opposite top side of tank. Sample points may be maintained at one or more of the bottom, center, and discharge of the fifth tank.
  • continuous monitoring of turbidity (NTU) is performed with Hach
  • effluent from the top of the clarifier or the fifth tank is fed through a 50 micron filter of a filtration operation 112 and into a sixth tank where the effluent from the fifth tank is treated with HC1 to neutralize the pH (to about 7.0-8.0).
  • the filter of the filtration operation 112 will pick up any residual floe particles.
  • a moderate mixing speed may be used to assist the neutralization treatment.
  • fluids enter the tank at the bottom and exit on the opposite top side of the tank. Chemical injection may be at the point of fluid entry or any other location.
  • continuous pH monitoring is performed via Hach instrumentation and sample points are maintained at the center and discharge of the tank.
  • Turbidity is monitored at the discharge of the tank via Hach instrumentation.
  • a biocide e.g., DBNPA, THPS, Thione, and/or WSKT 10.
  • DBNPA e.g., DBNPA, THPS, Thione, and/or WSKT 10
  • bacteria testing indicates high aerobic or anaerobic bacteria levels exist.
  • the effluent from the sixth tank passes through a filter skid where it flows through two cartridge filters before entering the clean water storage tanks.
  • the filters of the filtration operation 112 are variable in size. In one embodiment, the filters are a 25 micron filter followed by a one micron filter. Any combination of filters and filter sizes may be utilized in the filtration operation 112.
  • the sixth tank only receives clear water with a pH of about 7 to 8.
  • the water within the sixth tank has a turbidity of about 0.5 to 1.0 NTU.
  • the water contained in the sixth tank will have a reduced hardness of about 50 to 95% compared to the contaminated water entering the first tank.
  • the water contained in the sixth tank will be free of any detectable amount of bacteria or contain less than 1% bacteria compared to the contaminated water fed into the water treatment system 100.
  • the final product or effluent from process 100 produces clear neutralized water suitable for reuse in fracs, drilling fluids, workover fluids, kill fluids, plug drilling fluids, and well cleanout fluids.
  • Turbidity quality control goals are less than 5.0 NTU although any treatment level may be targeted and the system adjusted to obtain the targeted treatment level. Due to the inherent TDS levels (4000-15000 mg/1), this water may not be suitable for surface drilling or other uses without further treatment.
  • Continuous monitoring for quality control is done via Hach instrumentation and includes pH at incoming, second tank and the sixth tank. Turbidity is monitored at incoming water and the sixth tank. ORP is monitored at incoming water. All data is fed to a central computer where continuous visual readout and date logging is available. The instrumentation also controls all chemical pumps via a 4 to 20 ma output signal on incoming data.
  • all mixers are 375 revolutions per minute (RPM) gear down type although any suitable type may be used.
  • RPM revolutions per minute
  • the first and second tanks may be operated at about 125 to 150 RPM; the third tank may be operated at about 250 to 275 RPM; the fourth tank may be operated at about 50 to 75 RPM with paddle blades; the fifth tank will not be mixed; and sixth and seventh tank are operated at about 125 to 150 RPM.
  • system 100 will routinely sample at the exit of each tank to verify effectiveness which is compared to a minimum effective treating rate for all fluids at each point in the process.
  • the exact concentration and form of the chemicals being added is not specifically defined.
  • any suitable form selected based on availability, economics and ease of use may be used without changing the ultimate ability of the system to treat the produced water. Different selections may require adjustments in treatment times, sizes of feed tanks or other equipment or use of alternative equipment (for example when a dry form is substituted for an aqueous form).
  • the system and process may be modified, as is known in the art, to utilize such alternative forms and achieve the desired level of treatment without undue experimentation.
  • the system 100 as described above may optionally be followed with other treatment stages.
  • water from filtration operation 112 is fed through nanofiltration equipment to reduce the TDS to less than 1000 mg/1. This would produce higher quality water suitable for applications where low TDS water is required (drilling operations where spent mud is land applied) and where low chlorides are necessary to reduce corrosion potentials.
  • water may be run through a reverse osmosis system to produce dischargeable quality water.
  • Embodiments of the system 100 may be designed to any desired throughput as continuous or batch systems.
  • a system 100 as illustrated in the FIG. 1, is sized to handle flow rates of about 50 to 400 gpm.
  • the footprint will be approximately 80 feet by 60 feet including a 500 bbl frac tank for clean water storage and a filter tank for clarifier bottoms.
  • the tanks are 2500 gal and the clarifier is 6900 gal.
  • all chemical tanks are 275 gal totes. If a Ca(OH)2 tank is utilized, it is 500 gal.
  • the system 100 could be mounted on a 40 foot drop deck trailer with small process tanks (500 gal) and auxiliary storage, but with a decrease in throughput.
  • FIG. 2 illustrates an embodiment of method for treating water 200. As illustrated in FIG. 2
  • method 200 utilizes a treatment operation 202.
  • Treatment operation 202 treats water with an effective amount of a tight emulsion clarifier for aqueous systems.
  • the tight emulsion clarifier includes a hydrophobic isobutylene backbone and a hydrophilic maleic hydrophilic component.
  • the tight emulsion clarifier demulsifies at least some emulsified and fluorosurfactant/micro emulsion stabilized hydrocarbons contained in the water. This allows the hydrocarbon to be removed from the water.
  • method 200 further performs a removal operation 204.
  • the removal operation 204 removes any demulsified hydrocarbons from the water after treating with the tight emulsion clarifier.
  • the tight emulsion clarifier is at least one of Rhodoline® 1 11 and Rohm and Haas Tamol 731 A. In another embodiment, the tight emulsion clarifier increases clarity of the final product by about 50 to 75%. In another embodiment, the water is treated at a rate of about 50 to 250 ppm with the tight emulsion clarifier.
  • FIG. 3 illustrates an embodiment of method for treating water 300. As illustrated in FIG. 3
  • method 300 utilizes a treatment operation 302.
  • Treatment operation 302 treats water with an effective amount of calcium carbonate powder and potassium hydroxide. The treatment reduces the hardness of the water. In one embodiment, treatment operation 302 reduces water hardness by more than 95%. In another embodiment, treatment operation 302 provides for 100% water softening.
  • the treatment operation 302 further destroys a sequestering effect on divalent cations contained in the water to facilitate the removal of at least some suspended solids from the water in downstream separation steps, such as during flocculation and coagulation.
  • method 300 further performs a removal operation 304.
  • the removal operation 304 removes at least some reduced chain length polyacrylamides from the water after treating with the calcium carbonate powder and potassium hydroxide. Further, in yet another embodiment, the strength of the potassium hydroxide is about 45%.
  • FIG. 4 illustrates an embodiment of method for treating water 400. As illustrated in FIG. 4
  • method 400 utilizes a treatment operation 402.
  • Treatment operation 402 treats water with an effective amount phosphoric acid and sodium phosphate.
  • the treatment operation 402 reduces water hardness.
  • the treatment operation 402 further reduces the chain length of at least some
  • method 400 further performs a removal operation 404.
  • the removal operation 404 removes at least some of the reduced chain length polyacrylamides from the water after treating with the phosphoric acid and sodium phosphate.
  • FIG. 5 illustrates an embodiment of method for treating contaminated water 500, the contaminated water containing some amount of polyacrylamides, emulsified hydrocarbons, and sequestered divalent cations.
  • method 500 performs three different and independent treatment operations on contaminated water, such as the treatment operation described above in methods 200, 300, and 400. The treatment operations may be performed in any order or sequence.
  • Method 500 treats contaminated water with sodium phosphate and phosphoric acid 502.
  • the sodium phosphate treatment operation 502 reduces the chain length of at least some of the polyacrylamides contained in the water. Further, the sodium phosphate treatment operation 502 reduced water hardness.
  • Method 500 further treats the contaminated water with calcium carbonate powder and potassium hydroxide 504.
  • the calcium carbonate powder treatment operation 504 reduces hardness of the contaminated water. In one embodiment, calcium carbonate powder treatment operation 504 reduces water hardness by more than 95%. In another embodiment, calcium carbonate powder treatment operation 504 provides for 100% water softening.
  • the calcium carbonate powder treatment operation 504 destroys a sequestering effect on divalent cations contained in the water to facilitate the removal of at least some suspended solids from the water in downstream separation steps, such as during flocculation and coagulation. Further, in yet another embodiment, the strength of the potassium hydroxide is about 45%.
  • Method 500 additionally treats the contaminated water with an effective amount of a tight emulsion clarifier for aqueous systems.
  • the tight emulsion clarifier includes a hydrophobic isobutylene backbone and a hydrophilic maleic hydrophilic component.
  • the tight emulsion clarifier demulsifies at least some emulsified and fluorosurfactant stabilized hydrocarbons contained in the water, which allows these hydrocarbons to be removed from the water.
  • the separation operation 508 separates at least some broken solids containing polyacrylamide from a water stream contaminated after the treating operation are performed by performing one or more of a coagulant addition operation, a flocculent addition operation, a clarifying operation, a filtration operation, and a pH adjustment operation to obtain an effluent water stream and a first waste stream of solids separated from the second intermediate water stream.
  • the coagulant addition operation, flocculent addition operation, clarifying operation, filtration operation, and pH adjustment operations may be any suitable separating operations for a water treatment system.
  • the coagulant addition operation, flocculent addition operation, clarifying operation, filtration operation, and pH adjustment operation are identical the above operations described in FIG. 1.
  • the separation operation 508 further removes the demulsified hydrocarbons from the contaminated water after treating with the tight emulsion clarifier.
  • One benefit of the systems and processes described herein is that they do not require the use of excessive amounts of sodium hydroxide to break down polymers and they do not use expensive mechanical processes to treat the water.
  • contaminated water was ran through a system 100 according to FIG. 1.
  • the system 100 was ran utilizing the following compounds at the listed amounts in the appropriate tanks as described above:
  • Measurements were taken of the contaminated water fed into system 100. Measurements were taken of the water after treatment with system 100. Table 1 below lists the measurements from the contaminated water and from the water after treatment with system 100.
  • Toluene 2500 690 trans- 1 ,2-Dichloroethene ND ND trans- 1 ,3 -Dichloropropene ND ND trans- 1 ,4-Dichloro-2-butene ND ND
  • contaminated water was ran through a system 100 according to FIG. 1.
  • the system 100 was ran utilizing the following compounds at the listed amounts in the appropriate tanks as described above:
  • Table 1 shows a reduction in the suspended solids from 108 to 28 mg/1, water hardness from 687 to 205, oil and grease from 1500 to 1 1, calcium from 236 to 82 mg/1, magnesium from 23 mg/1 to a non-detectable amount, barium from 19 to 1 mg/1, iron from 169 to 0.18 mg/1, benzene from 3000 to 0 ug/1, o-xylene from 180 ug/1 to a non-detectable amount, toluene from 2500 to 690 ug/1, napthalene from 460 ug/1 to a non-detectable amount, and diesel range organics from 4800 to 38 ug/1 after treatment with the water treatment system 100 as outlined in Example 1.
  • Table 2 shows a reduction in the suspended solids from 138 to 13 mg/1, COD from 1600 to 90 mg/1, calcium from 197 to 40, magnesium from 22 to 0.20 mg/1, barium from 3.11 to 0.24 mg/1, iron from 26 to 4 mg/1, benzene from 2400 to 1200 ug/1, xylene from 2800 to 2250 ug/1, turbidity from 214 to 7 NTU, and corrosivity from 0.12 to 0.10 SI after treatment with the water treatment system 100 as outlined in Example 2.
  • the amounts of the above materials as found in the contaminated water causes scaling problems, prevent gel formation, and create formation damage when utilized in frac water.

Landscapes

  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Separation Of Suspended Particles By Flocculating Agents (AREA)

Abstract

L'invention porte sur une nouvelle approche en ce qui concerne le traitement de l'eau, telle que l'eau résiduaire de production en champ pétrolifère. L'invention porte sur de nouveaux procédés, qui permettent de traiter chimiquement l'eau contaminée, tels que des procédés chimiques pour l'adoucissement de l'eau, la rupture d'émulsion des hydrocarbures, la suppression d'un effet de séquestration sur des cations divalents, l'élimination de toute quantité détectable ou de plus de 99 % de bactéries aérobies et anaérobies et la rupture de polymères à longue chaîne. L'invention porte en outre sur de nouveaux procédés qui permettent de clarifier l'eau contaminée pour éliminer les matières solides en suspension.
PCT/US2010/051554 2010-10-06 2010-10-06 Système et procédé de recyclage d'eau de champs pétrolifères WO2012047210A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
PCT/US2010/051554 WO2012047210A1 (fr) 2010-10-06 2010-10-06 Système et procédé de recyclage d'eau de champs pétrolifères

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2010/051554 WO2012047210A1 (fr) 2010-10-06 2010-10-06 Système et procédé de recyclage d'eau de champs pétrolifères

Publications (1)

Publication Number Publication Date
WO2012047210A1 true WO2012047210A1 (fr) 2012-04-12

Family

ID=45927999

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2010/051554 WO2012047210A1 (fr) 2010-10-06 2010-10-06 Système et procédé de recyclage d'eau de champs pétrolifères

Country Status (1)

Country Link
WO (1) WO2012047210A1 (fr)

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN102701347A (zh) * 2012-05-31 2012-10-03 周正坤 油田采出水处理反应、沉降装置
CN105419856A (zh) * 2016-01-12 2016-03-23 扬州大学 一种高含渣含水污油的处理工艺
CN112679020A (zh) * 2020-12-25 2021-04-20 成都硕特环保科技有限公司 一种低成本页岩气压裂返排液处理系统及处理方法

Citations (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3342733A (en) * 1964-10-05 1967-09-19 Exxon Research Engineering Co Preparation of colloidal carbonates in hydrocarbon media
US4179369A (en) * 1975-02-18 1979-12-18 Nalco Chemical Company Polymer to agglomerate resolved emulsions
US4248705A (en) * 1977-05-05 1981-02-03 Exxon Research & Engineering Co. Process for removing oil from oily waste water streams
US5597789A (en) * 1993-04-27 1997-01-28 The Procter & Gamble Company Liquid or granular automatic dishwashing detergent compositions containing silicate and low molecular weight modified polyacrylate coploymers
US5730882A (en) * 1995-03-29 1998-03-24 Union Oil Company Of California Method for remediation of water containing emulsified oils
US20030089668A1 (en) * 2001-07-03 2003-05-15 Moffett Robert Harvey Phosphorus reduction in aqueous streams
US20050038128A1 (en) * 2001-11-16 2005-02-17 Jean-Francois Argillier Reversible stabilized emulsion and method for stabilizing and/or destabilizing an emulsion
US20050118322A1 (en) * 2002-09-19 2005-06-02 Elder Vincent A. Method for enhancing acrylamide decomposition
US7077963B2 (en) * 2000-10-27 2006-07-18 Nauveau Technology Investments Processes for water treatment

Patent Citations (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3342733A (en) * 1964-10-05 1967-09-19 Exxon Research Engineering Co Preparation of colloidal carbonates in hydrocarbon media
US4179369A (en) * 1975-02-18 1979-12-18 Nalco Chemical Company Polymer to agglomerate resolved emulsions
US4248705A (en) * 1977-05-05 1981-02-03 Exxon Research & Engineering Co. Process for removing oil from oily waste water streams
US5597789A (en) * 1993-04-27 1997-01-28 The Procter & Gamble Company Liquid or granular automatic dishwashing detergent compositions containing silicate and low molecular weight modified polyacrylate coploymers
US5730882A (en) * 1995-03-29 1998-03-24 Union Oil Company Of California Method for remediation of water containing emulsified oils
US7077963B2 (en) * 2000-10-27 2006-07-18 Nauveau Technology Investments Processes for water treatment
US20030089668A1 (en) * 2001-07-03 2003-05-15 Moffett Robert Harvey Phosphorus reduction in aqueous streams
US20050038128A1 (en) * 2001-11-16 2005-02-17 Jean-Francois Argillier Reversible stabilized emulsion and method for stabilizing and/or destabilizing an emulsion
US20050118322A1 (en) * 2002-09-19 2005-06-02 Elder Vincent A. Method for enhancing acrylamide decomposition

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN102701347A (zh) * 2012-05-31 2012-10-03 周正坤 油田采出水处理反应、沉降装置
CN105419856A (zh) * 2016-01-12 2016-03-23 扬州大学 一种高含渣含水污油的处理工艺
CN105419856B (zh) * 2016-01-12 2018-04-27 扬州大学 一种高含渣含水污油的处理工艺
CN112679020A (zh) * 2020-12-25 2021-04-20 成都硕特环保科技有限公司 一种低成本页岩气压裂返排液处理系统及处理方法

Similar Documents

Publication Publication Date Title
US20110017677A1 (en) Oil field water recycling system and method
US20120168364A1 (en) Oil field water recycling system and method
US20070102359A1 (en) Treating produced waters
US8790514B2 (en) Waste water treatment method
EP2956222B1 (fr) Ajout de silice colloïdale pour favoriser la séparation d'huile à partir d'eau
US7722770B2 (en) Method for treating produced water
US7510656B2 (en) Waste water treatment method
US20050098504A1 (en) Oil and gas well fracturing (frac) water treatment process
US20150053619A1 (en) Process for Hardness and Boron Removal
CA2858727A1 (fr) Traitement d'eaux residuaires
WO2015106154A1 (fr) Procédé de recyclage des eaux usées de champs pétrolifères et autres
EP3687653B1 (fr) Conservation de l'utilisation d'eau de lavage fraîche dans le dessalage de pétrole brut
US20040112836A1 (en) Oil and gas well fracturing (frac) water treatment process
CA2867496C (fr) Procede et appareil de traitement de fluide de forage
CA2657072C (fr) Methode de traitement des eaux usees
Jabbar et al. Treatment oilfield produced water using coagulation/flocculation process (case study: Alahdab Oilfield)
WO2012047210A1 (fr) Système et procédé de recyclage d'eau de champs pétrolifères
US10934189B2 (en) Methods and compositions for clarifying produced waters for boiler feed waters
Nacheva Water management in the petroleum refining industry
KR19990027620A (ko) 탈염기 배출수 처리 시스템
Jabbar et al. Coagulation/flocculation process for oily wastewater treatment
CA2915917C (fr) Procedes d'elimination de matiere organique et autres contaminants dissous d'eau de dgmv
JP2000185202A (ja) 塩除去装置における泥洗浄水からのエマルジョンの分離
Zarei et al. Oil & Gas Research
Asadov et al. REAGENT FOR CLEANING INDUSTRIAL WASTE WATER FROM PETROLEUM AND PETROLEUM PRODUCTS

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 10858233

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 10858233

Country of ref document: EP

Kind code of ref document: A1