WO2014116646A1 - Procédé de rupture d'émulsions micellaires pétrole-eau - Google Patents

Procédé de rupture d'émulsions micellaires pétrole-eau Download PDF

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Publication number
WO2014116646A1
WO2014116646A1 PCT/US2014/012459 US2014012459W WO2014116646A1 WO 2014116646 A1 WO2014116646 A1 WO 2014116646A1 US 2014012459 W US2014012459 W US 2014012459W WO 2014116646 A1 WO2014116646 A1 WO 2014116646A1
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WO
WIPO (PCT)
Prior art keywords
production fluid
water
oil
chemical compound
salt
Prior art date
Application number
PCT/US2014/012459
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English (en)
Inventor
Fan-Sheng Teddy Tao
Ronald David Hobbs
Varadarajan Dwarakanath
Taimur Malik
Sophany Thach
Original Assignee
Chevron U.S.A. Inc.
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 Chevron U.S.A. Inc. filed Critical Chevron U.S.A. Inc.
Publication of WO2014116646A1 publication Critical patent/WO2014116646A1/fr

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G33/00—Dewatering or demulsification of hydrocarbon oils
    • C10G33/04—Dewatering or demulsification of hydrocarbon oils with chemical means
    • 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
    • B01D17/04—Breaking emulsions
    • B01D17/047—Breaking emulsions with separation aids
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1033—Oil well production fluids

Definitions

  • the present disclosure generally relates to a method for separating production fluids into oil and water phases.
  • the present disclosure concerns a method of using a chemical compound, such as an ionic salt (e.g., sodium chloride, calcium chloride, sodium carbonate, sodium bicarbonate) and/or a high-molecular weight alcohol (e.g., 2-ethyl hexanol, decanol), to separate the tight micellar oil-water emulsions in produced fluids, such as those produced from chemically enhanced oil recovery methods.
  • a chemical compound such as an ionic salt (e.g., sodium chloride, calcium chloride, sodium carbonate, sodium bicarbonate) and/or a high-molecular weight alcohol (e.g., 2-ethyl hexanol, decanol)
  • Reservoir systems such as petroleum reservoirs, typically contain fluids such as water and a mixture of hydrocarbons such as oil and gas.
  • fluids such as water and a mixture of hydrocarbons such as oil and gas.
  • hydrocarbons such as oil and gas.
  • different mechanisms can be utilized such as primary, secondary or tertiary recovery processes.
  • Secondary recovery processes include water or gas well injection, while tertiary methods are based on injecting additional chemical compounds into the well.
  • fluids are injected into the reservoir to maintain reservoir pressure and drive the hydrocarbons to producing wells.
  • An additional 10-50% of OOIP can be produced in addition to that produced during primary recovery.
  • secondary and tertiary methods of oil recovery can further enhance oil production from a reservoir, care must be taken in choosing the right processes and injection fluid for each reservoir, as some methods may cause formation damage or plugging.
  • SP surfactant-polymer
  • Polymers are used to increase the viscosity of a fluid, thereby leading to a reduced mobility ratio and to improved sweep efficiency.
  • the most commonly used polymer for surfactant- polymer flooding is polyacrylamide (PAM) in its anionic form, hydrolyzed polyacrylamide (HP AM).
  • PAM polyacrylamide
  • HP AM hydrolyzed polyacrylamide
  • Surfactants are used to lower the interfacial properties of the reservoir, thereby reducing capillary forces and increasing the efficiency of the displacement of oil.
  • a wide variety of surfactants exist, but the most widely used are petroleum sulfonates.
  • the compositions of chemicals used in enhanced oil recovery (EOR) processes may vary depending on the type, environment, and composition of the reservoir formation.
  • a general embodiment of the disclosure is a method of separating fluids produced from a chemical enhanced oil recovery flooding process, comprising: receiving a production fluid from a chemical enhanced oil recovery flooding processes comprising an oil-water micellar emulsion, b) adding a chemical compound to the production fluid, the chemical compound being selected from the group consisting of an ionic inorganic salt, a C 4 - C 10 alcohol, or a combination thereof, and c) separating the production fluid to produce an oil product and a water product.
  • the oil product has a basic sediment and water content of less than 1%.
  • the water product may have an oil content of less than 1000 ppm, less than 500 ppm, or less than 300 ppm. Additionally, embodiments of the disclosure further include mixing the production fluid and the one or more chemical compounds prior to separating the production fluid. An additional demulsifying agent may also be added to the production fluid. Steps a-c may be performed off-shore or on-shore. In embodiments of the invention, the chemical compound is a solid or is in solution. The method may further comprise heating the production fluid to 100°F, at least about 125°F, at least about 150°F, at least about 175°F, at least about 200°, at least about 225°F, or at least about 250°F, or at least 275°F.
  • the added chemical compound may comprise at least about 0.25%, 0.5%, about 1.0%, about 1.5%, about 2.0%, at least about 3.0%, at least about 4.0%, or at least about 5.0% by weight of the production fluid.
  • the production fluid may be processed to remove a gas product.
  • the production fluid further comprises at least one of a surfactant and a polymer.
  • the chemical compound is an ionic inorganic salt.
  • the ionic inorganic salt may be sodium chloride, calcium chloride, sodium carbonate, sodium bicarbonate, or a mixture thereof.
  • the chemical compound may be sodium chloride provided in the form of seawater or waste brine.
  • the waste brine is water brine from water treatment, waste brine from a boiler blow down, or waste brine from a water softener.
  • the seawater comprises at least 0.5%, at least 0.75%, at least 1.0%, at least 1.25%, at least 1.5%, at least 1.75%, at least 2.0%, at least 2.25%, at least 2.5%, at least 2.75%, at least 3.0%, or at least 3.5% sodium chloride.
  • the chemical compound is a C 4 - Cio alcohol.
  • the C 4 - Cio alcohol may be 2-ethyl hexane, decanol, or a mixture thereof.
  • the production fluid is separated in a wash tank.
  • the production fluid may reside in the wash tank for at least 20 minutes, at least 30 minutes, at least 1 hour, at least 2 hours, at least 3 hours, at least 4 hours, at least 5 hours, at least 6 hours, at least 7 hours, or at least 8 hours.
  • the production fluid is separated in a pressure vessel.
  • Another general embodiment of the disclosure is a method of separating an oil-water micellar emulsion, the method comprising: a) receiving a production fluid comprising an oil- water micellar emulsion, b) adding waste brine or sea water to the production fluid, and c) separating the production fluid to produce an oil product and a water product.
  • the waste brine may be waste brine from a water treatment process, from a boiler blow down, from a water softening process, or combinations thereof.
  • Fig. 1 is a flow diagram of an embodiment of the invention
  • Fig. 2 is an example of a tank based separation system
  • Fig. 3 illustrates a functioning free water knockout tank
  • Fig. 4 illustrates a functioning wash tank
  • Fig. 5 is an example of a pressure vessel based separation system.
  • an embodiment of the invention is separating an oil-water micellar emulsion into separate or distinct oil and water phases.
  • the oil-water micellar emulsion may be in production fluid recovered from an enhanced oil recovery processes.
  • An embodiment of the method includes adding a chemical compound, such as an ionic salt and/or a high-molecular weight alcohol, to the production fluid.
  • ionic salts include, but are not limited to, inorganic ionic salts such as sodium chloride, calcium chloride, sodium carbonate, and sodium bicarbonate.
  • the addition of the ionic salt may be in the form of seawater.
  • High-molecular weight alcohols include C4-C10 alcohols, for example 2-ethyl hexanol and decanol.
  • Another aspect of the disclosure is separating oil and water phases in recovered production fluid by adding sea water or waste brine to the recovered production fluid.
  • the term “equal” refers to equal values or values within the standard of error of measuring such values.
  • high-molecular weight alcohol refers to a C4-C10 alcohol.
  • 2-ethyl hexanol and decanol are both considered high-molecular weight alcohols for the purposes of this disclosure.
  • Ionic salt refers to a neutrally charged ionic compound that comprises a cation and an anion.
  • Salt and “sodium chloride,” are used interchangeably and refer to NaCl.
  • production fluid or “produced fluid” refers to fluid directly recovered from a production well, or to production fluid that has already undergone some sort of processing. For example, production fluid that has been previously processed to remove gas is still considered “production fluid” for the purposes of this disclosure.
  • An embodiment of the disclosure is a method for breaking the microemulsions of produced liquids recovered after a Surfactant Polymer (SP) flood by adding in an additional chemical compound, such as an ionic salt or a high molecular weight alcohol.
  • SP Surfactant Polymer
  • the salinity of produced fluids is built up with the addition of chemical compounds, such as the ionic salt and/or high molecular weight alcohol, thereby promoting the change of phase behavior of the microemulsions from Winsor type I (oil in water microemulsions) to Winsor type II (water in oil microemulsions).
  • Such behavior change induces the partitioning of the surfactant micelles from water phase into the crude oil phase, thereby breaking the microemulsions.
  • these methods have also been found to improve the quality of the water.
  • the methods of the disclosure may be performed on-shore or off-shore, and may be adjusted to make the most efficient use of the location.
  • seawater may be used to provide sodium chloride (the chemical compound) during off-shore oil production, since off-shore production facilities tend to have an abundance of seawater available, limited storage space, and transportation costs to and from off-shore site are typically high.
  • the seawater can be processed prior to addition to the production fluids, such as through water softening, in order to reduce any scale formation that could occur after the separation steps.
  • the ionic salt or high molecular weight alcohol may be added to the production fluid as a solid form or in a solution.
  • solid sodium chloride may be used at an on-shore site to reduce the shipping costs associated with shipping a liquid.
  • Solid forms of the chemical compound such as solid sodium chloride, calcium carbonate, and calcium bicarbonate may be used in on-shore or off-shore applications.
  • the solid forms may be put into solution prior to addition to the production fluid, or the solid form may be directly added to the production fluid.
  • waste brine from drilling operations, water treatment, water softening processes, or boiler blowouts may be used as the chemical compound.
  • This waste brine generally contains sodium chloride, as well as magnesium chloride, strontium chloride, and calcium chloride.
  • the waste stream from a reverse osmosis water treatment process or a boiler blow down may be piped into the production fluid to facilitate breaking the microemulsions.
  • the waste brine or waste salt may be processed prior to addition to the produced fluid.
  • the chemical compound is mixed into the production fluid.
  • the mixing may occur by an active process, such as stirring or vortex, or the mixing may occur passively, such as by the addition of the chemical compound into flowing production fluid.
  • chemical compounds described throughout may also be used in conjunction with other demulsifying chemicals, such as a polyamine or phenol-formaldehyde resins.
  • demulsifying chemicals such as a polyamine or phenol-formaldehyde resins.
  • salt may be added to the water or oil phases that have previously been separated using a chemical demulsifying agent.
  • Separation equipment such as a wash tank or a pressurized vessel, is used to separate the gas, oil, and water phases of the production fluid.
  • Known separation processing systems include atmospheric tank systems, pressurized vessel systems, and combinations thereof. Tanks are mainly used in on-shore processes, while pressurized vessels are used mainly offshore.
  • An example of a tank based dehydration process is shown in Fig. 2.
  • Production fluid from the production well enters a gas boot, which separates gas and vapor from the water and oil.
  • the water and oil production fluid is then passed through a free water knockout (FWKO) tank which removes the low lying water.
  • FWKO free water knockout
  • the oil and remaining water are then passed to the wash tank, which further separates out water from the oil.
  • FIG. 5 An example of a pressurized vessel separation system is illustrated in Fig. 5.
  • the separation system of Fig. 5 comprises two stages of pressurized separators, followed by an electrostatic treater.
  • the oil-water mixture such as production fluid, may be heated (e.g., using a heating element or heat exchanger) to further enhance the effect of the added chemical compound.
  • the oil-water mixture may be heated to at least about 100°F (about 37.8 degrees Celsius), at least about 125°F (about 51.7 degrees Celsius), at least about 150°F (about 65.6 degrees Celsius), at least about 175°F (about 79.4 degrees Celsius), at least about 200°F (about 93.3 degrees Celsius), at least about 225°F (about 107.2 degrees Celsius), or at least about 250°F (about 121.1 degrees Celsius), or at least 275°F (about 135 degrees Celsius).
  • the oil-water mixture to be separated may also stay for a period of time in the separation equipment.
  • the production fluid may have a residence time in the wash tank or pressurized vessel of at least about 20 minutes, at least about 30 minutes, at least about 1 hours, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 6 hours, at least about 7 hours, at least about 8 hours, at least about 9 hours, at least about 10 hours, or at least about 15 hours, or at least about 24 hours.
  • the ionic salt or high molecular weight alcohols described herein may be added to the production fluid at anytime.
  • salt may be added to the production fluid downhole, at the wellhead, at manifold, prior to passing through the gas boot, after passing through the gas boot but before passing through the free water knockout tank, and after passing through the free water knockout tank but before passing through the wash tank, or in the recycled fluids.
  • the salt may be added directly to the downhole location, wellhead, manifold, gas boot, directly to the free water knockout tank, or directly to the wash tank. Salt may also be added multiple times to the process at different points.
  • the ionic salts and high molecular weight alcohols described here, salt for example may be added prior to each separation step in a pressurized separation process, or may be added directly to each of the pressure vessels.
  • the ionic salt or high molecular weight alcohol may be added to the water or oil phases that have been previously separated using a demulsifying agent or separation technique.
  • the chemical compounds herein could be added to the water phase recovered from the separation of an emulsion using a known demulsifying agent.
  • Fig. 1 Production fluid is received from a production well, for example. A chemical compound, such as salt as shown, is added to the production fluid. The production fluid is then separated to produce an oil product and a water product. The oil product may have less than 1% by volume basic sediment and water (BS&W).
  • BS&W basic sediment and water
  • the acceptable shipping oil quality is less than 1% by volume BS&W.
  • Examples of produced crude from surfactant-polymer flooding may only reach approximately 15-40% water-cut after settling for 6 hours at a producing temperature of about 185°F (about 85 degrees Celsius).
  • a inorganic ionic salt such as sodium chloride, calcium chloride, sodium carbonate, sodium bicarbonate, or a high-molecular weight alcohol is able to dehydrate the crude to meet the shipping oil quality of ⁇ 1% BS&W.
  • Examples 1-7 illustrate that crude dehydration using the chemical compounds described here can achieve ⁇ 1% BS&W and also show that the addition of such chemical compounds compete positively with commercially sold chemical demulsifying agents.
  • Examples of commercially available demulsifying agents are amphoteric acrylic acid copolymers, branched polyoxyalkylene copolyesters, and vinyl phenol polymer.
  • An embodiment of the present disclosure is the addition of sodium chloride to production fluids recovered from enhanced oil recovery processes.
  • sodium chloride has been removed from the production fluid, not added.
  • Sodium chloride has been traditionally held to be a detriment to the process of oil recovery, as salt is well known to cause corrosion issues in refining and shipping processes.
  • the addition of sodium chloride not only reduces the BS&W of the oil phase, but it can also increase the quality of the water phase.
  • Example 1 shows an oil-in-water content of 214 ppm at 1.0% salt content.
  • chemical compounds other than sodium chloride may be used for crude oil and water treatment.
  • the chemical compounds includes other ionic salts such as calcium chloride, sodium bicarbonate, and sodium carbonate.
  • the chemical compounds include high molecular weight alcohols such as 2-Ethyl Hexanol, and Decanol. Examples 2 and 3 relate to the testing of these specific compounds. It was found that the addition of inorganic compounds, such as salt, calcium chloride, sodium carbonate, or sodium bicarbonate, breaks the micellar emulsions found in enhanced oil recovery methods, and produces an oil phase with reasonable BS&W and oil content in water. The control (without any salt or the disclosed chemical compounds) had very high BS&W in the crude oil and high oil content in water. Similarly, the addition of organic compounds, such as 2-ethyl hexanol or decanol, broke the micellar emulsions, and produced oil with reasonable BS&W and oil content in water.
  • a microemulsion was made by mixing a light crude oil with equal amount of synthetic water solution containing 0.5% (by weight) of sulfonates surfactants and solvent such as ethylene glycol butyl ether (EGBE), 0.1% of polyacrylamide polymer, and 0.5% sodium carbonate. The amount of these chemicals simulates the expected breakthrough (production) fluids from a surfactant-polymer flood.
  • the microemulsion was made by simulating downhole electric pump production in the oilfields.
  • a reagent grade salt sodium chloride
  • An ASP solution was prepared which contained 0.5% (by weight) of surfactants
  • Synthetic water was prepared according to the chemical composition of the produced water.
  • the above fluid was mixed at a shearing rate that simulates downhole electric submersible pump shearing action during production and produced a tight micellar oil-water emulsion.
  • Steps 4 and 5 were repeated with 1,000 ml (61.0 cubic inches) total oil- water emulsions for the following tests.
  • the salt solution (step 1) was added into the bottles to make the following concentrations: 0 (no salt), 0.1, 0.2, 0.25, 0.35, 0.5, 075, 1.0 and 2.0% by weight based upon the total fluid.
  • Example 2 The same procedure as given in Example 1 was followed, but the salt was replaced with calcium chloride (Table 2), sodium carbonate (Table 3), and sodium bicarbonate (Table 4). As the chemical concentration increased, the water contents in oil and oil content in water generally decreased. This trend shows that the addition of these chemical compounds improve both oil and water qualities.
  • Example 5 The same procedure as given in Example 1 was followed, but the salt was replaced with 2-ethyl hexane (Table 5) and decanol (Table 6). As the chemical concentration increased the water content in oil and oil content in water generally decreased. This trend shows that the addition of these chemical compounds improve both oil and water qualities.
  • Example 1 previously illustrated that sodium chloride can be used as a demulsifying chemical for treating produced emulsions.
  • a larger scale pilot test was conducted with a 75% water-cut crude emulsion at a continuous flow rate of 9.6-12 gpm in a 6-inch diameter and 20 feet high steel column. The crude emulsion entered the column at the 3 feet level, and exited at the 16 feet level. A 20% brine solution was used and injected at a concentration of 3 to 4% by weight into the crude emulsion before entering the column continuously at 185°F (85 degrees Celsius). At the 6 th hour, oil samples were collected at various levels of the 16 foot (4.88 meters) column. Results of the BS&W measurements at 6 hours residence time are shown as follows:
  • Salt treatment was conducted in laboratory simulated tests for water separated from oil in a wash tank using commercially available demulsifying chemicals, Demulsifiers A, B, C, D, E, F and G. This water had relatively high oil content due to the inefficiency of the chemicals used during the crude dehydration treatment. When this water was tested with salt addition, it showed that, in most cases, it would require approximately 0.50-0.75% by weight salt to reduce the oil content to a level below 300 ppm in the production fluid recovered from the same production run at two different time periods.
  • Table 10 Oil water interface quality and top and mix cut BS&W.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Engineering & Computer Science (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Wood Science & Technology (AREA)

Abstract

L'invention concerne un procédé pour améliorer la séparation d'émulsion micellaire pétrole-eau, telle que celles trouvées dans un fluide de production. Plus précisément, un mode de réalisation de l'invention sépare les phases de pétrole et aqueuses dans un fluide de production récupéré par addition d'un sel ionique tel que du chlorure de sodium, du chlorure de calcium, du carbonate de sodium, du bicarbonate de sodium et/ou un alcool de masse moléculaire élevée, tel que le 2-éthyl hexanol ou le décanol, dans le fluide de production. Le fluide de production peut comprendre des fluides produits à partir d'un procédé de récupération de pétrole amélioré.
PCT/US2014/012459 2013-01-24 2014-01-22 Procédé de rupture d'émulsions micellaires pétrole-eau WO2014116646A1 (fr)

Applications Claiming Priority (4)

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US201361756310P 2013-01-24 2013-01-24
US61/756,310 2013-01-24
US13/832,529 2013-03-15
US13/832,529 US20140202927A1 (en) 2013-01-24 2013-03-15 Method of breaking oil-water micellar emulsions

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US10745627B2 (en) * 2013-12-20 2020-08-18 Exxonmobil Research And Engineering Company Desalter operation
CA2911610C (fr) 2014-11-13 2017-12-12 Weatherford Technology Holdings, Llc Separation d'une emulsion petrole/bitume
BR102015017003A2 (pt) * 2015-07-16 2017-07-11 Companhia Estadual De Águas E Esgotos Cedae Integrated process for biodiesel production through the application of the stages of saline deemulsification, distillation and esterification of fatty acids and their derivatives
US10155913B2 (en) 2016-04-20 2018-12-18 Next Alternative Inc. Systems and methods for manufacturing emulsified fuel
KR101926481B1 (ko) * 2016-10-31 2018-12-10 에스케이이노베이션 주식회사 폐가성소다 용액의 층분리 방법
CA3018277A1 (fr) * 2017-09-22 2019-03-22 Chevron U.S.A. Inc. Systeme et methode de systeme de controle d'ecoulement intelligent destines a la production de renvois de cimentation

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