Technical Field
This application relates generally to systems and methods used to remove contaminants from oilfield effluents, and more particularly, to systems and methods used to remove hydrogen sulfide from oilfield effluents.
Background Information
Oilfield effluents, including crude oil, produced water and flowback fracturing water, often contain dissolved hydrogen sulfide. Hydrogen sulfide is highly corrosive and may damage equipment used in oil and gas refining processes. Hydrogen sulfide is also toxic to humans and presents a significant health risk to workers in the oil and gas refining industry. Various transportation rules and guidelines may require that hydrogen sulfide concentrations not exceed certain levels.
Known methods used to remove hydrogen sulfide from oilfield effluents often include adding large amounts of scavenger chemicals or utilizing a stripping gas. These methods are often expensive, complex, time-consuming, unable to be easily transported to and from a site, and ineffective at removing large-scale quantities of hydrogen sulfide from the oilfield effluents. Moreover, utilizing a stripping gas may also remove low boiling point hydrocarbons, such as propane, isobutene, n-butane, isopentane, n-pentane, hexane and the like, which are desirable to retain in oilfield effluents such as crude oil. Thus, there is a continued need in the industry for systems and methods to remove hydrogen sulfide from oilfield effluents that are cheaper, simpler, faster, easily set-up and transported to and from a site, and more effective at removing large-scale quantities of hydrogen sulfide from oilfield effluents.
The systems and methods for removing hydrogen sulfide from oilfield effluents described herein employ a pre-treatment subsystem, a vapor treatment subsystem and a treatment subsystem interconnected by a plurality of piping and valve subsystems. An oilfield effluent, including crude oil, produced water or flowback fracturing water, that is contaminated with hydrogen sulfide is pumped from a site to the pre-treatment subsystem and then to the treatment subsystem whereupon hydrogen sulfide is removed from the oilfield effluent by atomization and vacuum flashing. The vapor treatment subsystem treats the vapor released from the pre-treatment subsystem and the treatment system by removing hydrogen sulfide. The system is not dependent on pH and can operate at temperatures as low as about −20° C. The system is mobile and can be easily transported to and from a site and readily assembled at a site by interconnecting the subsystems.
The embodiments described below refer to the accompanying drawings, of which:
Mobile systems and methods for removing hydrogen sulfide from oilfield effluents are discussed in more detail below with crude oil as an example of an oilfield effluent.
Referring to
The pre-treated oil 130 is pumped by the pre-treatment subsystem 200 to the treatment subsystem 300 where the pre-treated oil 130 is atomized and vacuum flashed to produce a treated solution, treated oil 140. The second vapor 150 contains hydrogen sulfide removed from the pre-treated oil 130 during atomization and vacuum flashing. The second vapor 150 is pulled, or pumped, to the vapor treatment subsystem 400 and treated by removing hydrogen sulfide from the vapor to yield a treated vapor 160. The treated vapor 160 is then vented, or otherwise released, into the atmosphere. The treated oil 140 is pumped by the treatment subsystem 300 to a storage tank 25.
Referring now to
As the first vapor 120 passively vaporizes out of the crude oil 110 in the receiving tank 11, the first vapor 120 is passively vented to a scrubber tank 14 of the vapor treatment subsystem 400 where the first vapor 120 is treated by passing, pumping or the like, the first vapor 120 through liquid triazine in the scrubber tank 14 to remove hydrogen sulfide. The treated vapor 160 is then vented, or otherwise released, into the atmosphere 170 by the scrubber tank 14. When the treated vapor 160 reaches a hydrogen sulfide level of about 10 ppm, or higher, during the process, the liquid triazine in the scrubber tank 14 is replaced with fresh liquid triazine. In other embodiments, liquid ammonia or ferric hydroxide may be used instead of liquid triazine.
In
The atomizer tank 16 is housed or mounted on its own trailer bed and has a volume of about 60 m3. In other embodiments, the size of the atomizer tank(s) may vary between about 20-80 m3. The atomizer tank 16 is maintained at a vacuum of about 3-15 inHg, preferably about 4 inHg. The atomizing spray nozzle 17 consists of a 2″ opening with a blast plate. In other embodiments, the associated pass-through rates or droplet sizes of the pre-treated solution passing through the atomizing spray nozzle may vary according to design. For example, the size of the openings of the atomizing spray nozzle may vary between about 1-3″ or the shape of the atomizing spray nozzle itself may vary, such as a spiral-type atomizing spray nozzle.
In
After the pre-treated oil is atomized and vacuum flashed in the atomizer tank 16, the remaining treated oil condenses and collects in the bottom of the atomizer tank 16. This treated solution is then pumped out of the atomizer tank 16 as treated oil 140 by the pump 18 to the storage tank 25. While the treated oil is collected and stored in the storage tank 25 at atmospheric pressure, the oil may release additional residual vapor contaminated with hydrogen sulfide. This residual vapor is passively vented out, or pumped out, of the top of the storage tank 25 as a vapor 180 to the vapor treatment subsystem 400. The vapor treatment subsystem then removes hydrogen sulfide from this contaminated vapor in the scrubber tank 14 by passing, pumping or the like, the vapor through a liquid triazine solution. This decontaminated vapor is then released into the atmosphere 170 as the treated vapor 160. In other embodiments, the decontaminated vapor may be collected or flared off.
In
Referring to
In
Referring now to
The atomization of the pre-treated oil 130 in the first atomizer tank 16 creates fine droplets of treated oil which collect in the bottom of the first atomizer tank 16 as a first treated oil 132. The first treated oil 132 is then pumped out of the bottom of the first atomizer tank 16 by a pump 18 at a pressure of 1-100 PSI into a second atomizer tank 21 through an atomizer spray nozzle 22, consisting of a 2″ opening with a blast plate. The atomizer spray nozzle 22 atomizes the first treated oil 132 into fine droplets in the second atomizer tank 21. The first treated oil 132 is also vacuum flashed in the second atomizer tank 21, which is maintained at a vacuum of approximately 3-15 inHg, preferably about 4 inHg. In other embodiments, the second atomizer tank 21 may be at a different pressure than the first atomizer tank 16.
Atomization and vacuum flashing of the first treated oil 132 in the second atomizer tank 21 release a contaminated vapor 134 containing additional hydrogen sulfide released from the first treated oil 132. The contaminated vapor 134 is pumped out of the second atomizer tank 21 and treated by the vapor treatment subsystem 400. The fine oil droplets created during atomization in the second atomizer tank 21 collect in the bottom of the second atomizer tank 21 as a second treated oil 135. The second treated oil 135 is pumped out of the second atomizer tank 21 to the storage tank 25 by a pump 23.
Depending on the application, the atomizer tank(s) of the embodiments may also be configured to recycle and re-treat the treated oil collected in the bottom of the atomizer tank(s). For example, in
In other embodiments, the number and setup of the components of the subsystems may vary depending on the particular parameters of the treatment methods and attributes of the oilfield effluent. For example, additional atomizer tanks of differing volume may be employed, depending on various parameters and needs of the systems, including the level of contaminants, such as hydrogen sulfide, in the oilfield effluent. Other embodiments may employ additional atomizer tanks in a series within the treatment subsystem 300 or each additional atomizer tank may simultaneously receive oilfield effluent directly from the pre-treatment subsystem 200. Additional storage tanks of varying volume may also be utilized. Depending on the amount and type of particulate in the oilfield effluent, other embodiments may include a filtration unit with filters and a backwashing subsystem as part of the pre-treatment subsystem 200. This filtration unit may help prevent any downstream clogging or damage to the systems. One or more additional receiving tanks may also be used to pre-treat the oilfield effluent.
The atomizer tank(s) may also be maintained at atmospheric pressure. In such embodiments, “sweet” gas or nitrogen gas is continuously pumped into the atomizer tank(s) to flush out vapor contaminated with hydrogen sulfide that is released during atomization. The “sweet” gas (or nitrogen gas) and flushed-out contaminated vapor is then pumped, or passively vented, to the vapor treatment subsystem 400 for removal of hydrogen sulfide. In other embodiments, “sweet” gas or nitrogen gas is intermittently pumped into the atomizer tank(s) while the atomizer tank(s) is/are under pressure to sweep and flush out contaminated vapor from the atomizer tank(s).
The treatment subsystem 300 may optionally contain one or more interconnected chemical storage units for the addition of chemicals into the systems. For example, the chemical storage units may contain hydrogen sulfide scavenging chemicals such as triazine or triazine-based chemicals, copper carbonate, hydrogen peroxide, zinc carbonates or oxides, ammonium salts, aldehydes (e.g. acrolein), or other amine-based scavengers. These hydrogen sulfide scavengers may be added to the oilfield effluent prior to treatment in the atomizer tank(s), after treatment in the atomizer tank(s) or both. Various chemicals may also be added after atomization in one atomizer tank, but prior to atomization in another atomization tank. One or more mixers may be employed to mix chemicals added to the oilfield effluent in the receiving tank, with the pre-treated solution prior to treatment by the treatment subsystem or with the treated solution prior to storage in the storage tank.
In other embodiments, the vapor treatment subsystem 400 may include one or more vapor recovery subsystems to capture contaminated vapor released, vented or pumped from the pre-treatment subsystem, the treatment subsystem, or the treated oilfield effluent in the storage tank(s). These contaminated vapors may contain various energy-producing light chain hydrocarbons, such as methane, ethane, propane or butane, which may be stored for later use or transportation or may be re-introduced into a natural gas pipeline. The vapor treatment subsystem 400 may also include additional scrubber tanks to treat, for example, the first contaminated vapor from the pre-treatment subsystem separate from the second contaminated vapor from the treatment subsystem.
The systems are mobile and can be readily and easily transported to and assembled at a site. The systems and methods operate effectively at temperatures as low as −20° C. With regard to the treatment of crude oil, the systems and methods reduce the amount of light chain hydrocarbons released from the crude oil at low operational temperatures and a high quality treated oil output is achieved. For example, the system may operate at a temperature below the boiling point of butane, thus preserving butane in the treated oil. The systems and methods are also inexpensive, simple, quick, and extremely effective at removing large-scale quantities of hydrogen sulfide from oilfield effluents.
The foregoing description has been directed to specific embodiments. It will be apparent, however, that other variations and modifications may be made to the described embodiments with the attainment of some or all of their advantages. For instance, it is expressly contemplated that the embodiments described herein may include additional components, such as receiving tanks, atomizer tanks, condenser tanks, scrubber tanks or a combination thereof. Also, while a particular order of particular treatment methods have been shown and described, those skilled in the art will appreciate that other method orders, arrangements, orientations, and the like, may be used to treat oilfield effluents, such as crude oil, produced water or flowback fracturing water, and that the systems and methods described herein are merely illustrative embodiments. Accordingly, this description is to be taken only by way of example and not to otherwise limit the scope of the embodiments herein. Therefore, it is the object of the appended claims to cover all such variations and modifications as come within the true spirit and scope of the embodiments herein.
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Number | Date | Country | |
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20150299582 A1 | Oct 2015 | US |