WO2024073701A1 - Procédé de gestion d'hydrates - Google Patents

Procédé de gestion d'hydrates Download PDF

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Publication number
WO2024073701A1
WO2024073701A1 PCT/US2023/075569 US2023075569W WO2024073701A1 WO 2024073701 A1 WO2024073701 A1 WO 2024073701A1 US 2023075569 W US2023075569 W US 2023075569W WO 2024073701 A1 WO2024073701 A1 WO 2024073701A1
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WO
WIPO (PCT)
Prior art keywords
hydrate inhibitor
meg
thermodynamic
hydrate
kinetic
Prior art date
Application number
PCT/US2023/075569
Other languages
English (en)
Inventor
David John Knight
Brian Edward Messenger
James Alex MCRAE
Simon Hunter
Sijia Hu
Archana Patel
Original Assignee
Cameron International Corporation
Schlumberger Canada Limited
Cameron Technologies Limited
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 Cameron International Corporation, Schlumberger Canada Limited, Cameron Technologies Limited filed Critical Cameron International Corporation
Publication of WO2024073701A1 publication Critical patent/WO2024073701A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B37/00—Methods or apparatus for cleaning boreholes or wells
    • E21B37/06—Methods or apparatus for cleaning boreholes or wells using chemical means for preventing or limiting, e.g. eliminating, the deposition of paraffins or like substances

Definitions

  • the present disclosure generally relates to processes and systems associated with oil and gas extraction. Specifically, this application relates to optimized hydrate management methods and systems.
  • Gas hydrates are crystalline solid compounds consisting of a three-dimensional lattice of hydrogen-bonded water and gas molecules (e.g., methane, carbon dioxide, hydrogen, etc.) formed at high-pressure and low-temperature conditions.
  • gas molecules e.g., methane, carbon dioxide, hydrogen, etc.
  • Typical gas hydrates are classified into three crystal structures: cubic structure I (si), cubic structure II (sll), and hexagonal structure (sH).
  • Gas hydrates provide the possibility of carbon dioxide (CO2) transportation and storage, due to a high storage density of approximately 175 volumes of CO2 per volume of hydrate.
  • CO2 carbon dioxide
  • gas hydrates can be formed in subsea oil and gas wells and flowlines because the operating conditions include high pressure and low temperature at which gas hydrates are thermodynamically stable. The deposition and agglomeration of gas hydrates can subsequently plug the flowlines, resulting in disruption to production, economic losses, and adverse environmental impacts. Hydrate inhibitors were developed to provide prevention and mitigation strategies for potential hydrate issues.
  • Thermodynamic hydrate inhibitors (THIs) are the most commonly used hydrate inhibitors to prevent hydrate formation. THIs can prevent hydrate formation by shifting the operating conditions outside of the hydrate stability zone. Common THIs are methanol and monoethylene glycol (MEG).
  • Certain embodiments of the present disclosure include a method for managing hydrate formation in a hydrocarbon stream comprising injecting in the stream a thermodynamic hydrate inhibitor and a kinetic hydrate inhibitor.
  • thermodynamic hydrate inhibitor comprises monothylene glycol (MEG).
  • the kinetic hydrate inhibitor is used in a closed loop, wherein the closed loop comprises recirculating and reusing the kinetic hydrate inhibitor after its passing within a MEG reclamation unit.
  • Certain embodiments of the present disclosure include a system for managing hydrate formation in a hydrocarbon stream comprising means to inject a thermodynamic hydrate inhibitor and means to inject a kinetic hydrate inhibitor into the hydrocarbon stream.
  • the system further comprises a MEG reclamation unit and means to recirculate and reuse the kinetic hydrate inhibitor after its passing within the MEG reclamation unit.
  • a method of reducing a dose rate of a thermodynamic hydrate inhibitor used for inhibition of hydrate formation in a hydrocarbon stream includes injecting the thermodynamic hydrate inhibitor and a kinetic hydrate inhibitor into the hydrocarbon stream.
  • the thermodynamic hydrate inhibitor can be MEG.
  • the kinetic hydrate inhibitor can have high temperature stability.
  • the method can reduce the dose rate of the thermodynamic hydrate inhibitor by 80%.
  • the kinetic hydrate inhibitor can be injected into the hydrocarbon stream at a dose of less than 2 % vol, for example, 1.5 % vol.
  • the thermodynamic hydrate inhibitor can be injected into the hydrocarbon stream at a dose of approximately 15 % vol.
  • connection As used herein, the terms “connect,” “connection,” “connected,” “in connection with,” and “connecting” are used to mean “in direct connection with” or “in connection with via one or more elements”; and the term “set” is used to mean “one element” or “more than one element.” Further, the terms “couple,” “coupling,” “coupled,” “coupled together,” and “coupled with” are used to mean “directly coupled together” or “coupled together via one or more elements.”
  • the terms “real time,” ’’real-time,” or “substantially real time” may be used interchangeably and are intended to describe operations (e.g., computing operations) that are performed without any human-perceivable interruption between operations.
  • data relating to the systems described herein may be collected, transmitted, and/or used in control computations in “substantially real time” such that data readings, data transfers, and/or data processing steps occur once every second, once every 0.1 second, once every 0.01 second, or even more frequent, during operations of the systems (e.g., while the systems are operating).
  • the terms “automatic” and “automated” are intended to describe operations that are performed or are caused to be performed, for example, by a greenhouse gas emission analysis system (i.e., solely by the greenhouse gas emission analysis system, without human intervention).
  • thermodynamic hydrate inhibitors in oil and gas operations to stop formation of gas hydrates in subsea/deepwater fields.
  • thermodynamic hydrate inhibitors can be used just before or after shutdowns, but also in general production in some cases, depending on the conditions.
  • MEG regeneration is used to reduce the need to continuously add fresh chemical, as the required dose rate of MEG can be as high as 60 wt % based on the overall amount of water.
  • the stream is vaporized to remove excess water and salt, and the rich MEG is regenerated into a lean, high purity and salt-free MEG for recirculation to the wells and flowline.
  • This can require large, expensive equipment with high heat duty and OPEX.
  • MEG reclamation unit design is dependent on the hourly MEG injection rate. A high MEG injection rate requires a larger unit footprint, ultimately increasing the cost and schedule to build units.
  • the MEG regeneration and reclamation units are usually designed for the maximum produced water volume anticipated, which is uncertain and often occurs late in the field life when water production from wells increases.
  • the reclamation unit is therefore designed and sized for a small operating window in the life of the asset, meaning the unit is oversized for the majority of its operational lifetime.
  • the present disclosure advantageously provides methods and apparatus to reduce the usage of THIs for preventing hydrate formation, thereby minimizing or reducing the size of the reclamation units and/or allowing higher water production to be accommodated.
  • KHIs kinetic hydrate inhibitors
  • LDHI low dosage hydrate inhibitor
  • the KHI can be recirculated and reinjected into the hydrate management system after passing through the MEG recovery unit, which enables further reduction of the total chemical cost for the flowline.
  • a rocking cell apparatus allows for testing of the performance of KHI in the presence of THI, such as MEG.
  • THI such as MEG.
  • the system allows the mixing of oil, water, gas and hydrate inhibitors (and/or other production chemicals) at the desired pressure and temperature where hydrates would typically form.
  • an inserted ball moves through the entire length of the testing cell and improves the mixing of all components.
  • the ball movement introduces shear forces and turbulence inside the test cell, which aims to mimic the conditions inside a flowline.
  • the cells are mounted on a movable axle, inside a bath of cooling liquid.
  • the cells are filled with sample fluid (e g., oil/condensate, gas, brine) and the desired dose rates of inhibitor, and then are cooled to the target temperature.
  • sample fluid e g., oil/condensate, gas, brine
  • Each cell can be subsequently individually pressurized up to 2900 psi. All test parameters, such as cooling rate, rocking angle, rocking rate, and test length, can be scheduled via software.
  • a camera can record pictures and videos at any time during the experiment.
  • a pressure of 1350 psi and a temperature of 5°C were used as the final conditions for hydrate testing, which reflects a subcooling (the temperature difference between the operating and hydrate equilibrium temperatures at fixed pressure) of 8°C.
  • the brine included 1 wt.% NaCl and 0.5 wt.% CaC12.
  • the gas composition, which results in si hydrates formation, is shown in Table 1.
  • a minimum protection time of 72 hr was required for any candidate KHI to pass the test.
  • the initial performance evaluation is considered the first phase of the method evaluation process.
  • the high-temperature stability testing aimed to determine if a KHI can maintain optimal performance in delaying hydrate formation onset after severe heating. This testing is considered as the second and third phases of the method evaluation process.
  • the final formulated products were placed in a sealed aging cell at a temperature of 140°C for 3 days. Then the samples were injected into rocking cells for retesting at the desired conditions.
  • the third phase tests the products under even more severe conditions.
  • the raw KHI active alone was placed on a hot plate at 160°C to remove the solvent present in the neat product. This step produces dry solids inside the container. The solids were then re-dissolved with proper solvents. This re-dissolved material subsequently had the same activity compared to the initially formulated product that was tested.
  • systems and methods according to the present disclosure enable reduction of costs of a hydrate management system due to the size reduction of the pipeline and the topside MEG recovery facilities, and associated utility systems. Additionally or alternatively, systems and methods of the present disclosure enable the debottlenecking of MEG reclamation systems to accommodate higher water production. Further, in some configurations, systems and/or methods according to the present disclosure include (1) recycling unrecovered KHI back to the wells (such as subsea wells) and flowline along with lean MEG and/or (2) recovering the KHI active components from the process, re-formulating the KHI, and then injecting the recovered KHI to the wells and flowlines with, or separately from, the lean MEG product from the MEG recovery system.
  • the KHI is added via an umbilical core, and MEG is delivered via a separate larger lean MEG line.
  • a chemical injection valve CIMV
  • CIMV enables addition of KHI in the umbilical.
  • the CIMV can be retrofitted to an existing system using MEG injection.
  • a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. ⁇ 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

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  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • Chemical & Material Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Chemical & Material Sciences (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Organic Low-Molecular-Weight Compounds And Preparation Thereof (AREA)

Abstract

L'invention concerne des procédés et des systèmes de gestion de la formation d'hydrates dans un flux d'hydrocarbures. Les procédés et les systèmes comprennent l'injection dans le flux d'hydrocarbures d'un inhibiteur d'hydrate thermodynamique et d'un inhibiteur d'hydrate cinétique. L'ajout de l'inhibiteur d'hydrate cinétique permet une réduction de la quantité d'inhibiteur d'hydrate thermodynamique nécessaire. L'inhibiteur d'hydrate cinétique présente une stabilité à haute température pour permettre le recyclage et la réutilisation.
PCT/US2023/075569 2022-09-30 2023-09-29 Procédé de gestion d'hydrates WO2024073701A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US202263377774P 2022-09-30 2022-09-30
US63/377,774 2022-09-30

Publications (1)

Publication Number Publication Date
WO2024073701A1 true WO2024073701A1 (fr) 2024-04-04

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Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20100018712A1 (en) * 2008-07-25 2010-01-28 Baker Hugues Incorporated Method of transitioning to kinetic hydrate inhibitors in multiple tie-in well systems
US20100144559A1 (en) * 2006-08-03 2010-06-10 Baker Hughes Incorporated Kinetic Gas Hydrate Inhibitors in Completion Fluids
US20100193194A1 (en) * 2007-09-25 2010-08-05 Stoisits Richard F Method For Managing Hydrates In Subsea Production Line
US20180265647A1 (en) * 2015-05-27 2018-09-20 Commonwealth Scientific And Industrial Research Organisation Hydrate inhibitor carrying hydrogel
US20200317990A1 (en) * 2018-08-01 2020-10-08 Halliburton Energy Services, Inc. Low density gas hydrate inhibitor

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20100144559A1 (en) * 2006-08-03 2010-06-10 Baker Hughes Incorporated Kinetic Gas Hydrate Inhibitors in Completion Fluids
US20100193194A1 (en) * 2007-09-25 2010-08-05 Stoisits Richard F Method For Managing Hydrates In Subsea Production Line
US20100018712A1 (en) * 2008-07-25 2010-01-28 Baker Hugues Incorporated Method of transitioning to kinetic hydrate inhibitors in multiple tie-in well systems
US20180265647A1 (en) * 2015-05-27 2018-09-20 Commonwealth Scientific And Industrial Research Organisation Hydrate inhibitor carrying hydrogel
US20200317990A1 (en) * 2018-08-01 2020-10-08 Halliburton Energy Services, Inc. Low density gas hydrate inhibitor

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