CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] Any and all applications for which a foreign or domestic priority claim is identified in the Application Data Sheet as filed with the present application are hereby incorporated by reference under 37 CFR 1.57. The present application claims priority benefit of U.S. Provisional Application No. 63/377,774, filed September 30, 2022, the entirety of which is incorporated by reference herein and should be considered part of this specification.

BACKGROUND

[0002] 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.

[0003] This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present techniques, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as an admission of any kind.

[0004] 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. Typical gas hydrates are classified into three crystal structures: cubic structure I (si), cubic structure II (sll), and hexagonal structure (sH).

[0005] 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. However, 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).

SUMMARY

[0006] A summary of certain embodiments described herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure.

[0007] 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.

[0008] In embodiments of the disclosure, the thermodynamic hydrate inhibitor comprises monothylene glycol (MEG).

[0009] In embodiments of the disclosure, 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.

[0010] 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.

[0011] In embodiments of the disclosure, 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.

[0012] In some configurations, 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.

[0013] 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.

[0014] Various refinements of the features noted above may be undertaken in relation to various aspects of the present disclosure. Further features may also be incorporated into these various aspects as well. These refinements and additional features may exist individually or in any combination. For instance, various features discussed below in relation to one or more of the illustrated embodiments may be incorporated into any of the above-described aspects of the present disclosure alone or in any combination. The brief summary presented above is intended to familiarize the reader with certain aspects and contexts of embodiments of the present disclosure without limitation to the claimed subject matter.

DETAILED DESCRIPTION

[0015] One or more specific embodiments of the present disclosure will be described below. These described embodiments are only examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0016] When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.

[0017] 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.”

[0018] In addition, as used herein, 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. For example, as used herein, 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). In addition, as used herein, 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).

[0019] Mono Ethylene Glycol (MEG) and Methanol are used as thermodynamic hydrate inhibitors in oil and gas operations to stop formation of gas hydrates in subsea/deepwater fields. Such 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.

[0020] In the reclamation process, 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. In most cases, 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. [0021] 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.

[0022] To reduce the usage of THIs, for example of MEG, thereby minimizing or reducing the size of the reclamation units and/or increasing the reclamation unit capacity for higher water production, the methods and systems of the present disclosure introduce kinetic hydrate inhibitors (KHIs) into the hydrate management system. In some configurations, KHI, classified as a low dosage hydrate inhibitor (LDHI), can be effective at 1-2 vol.% of water. The hydrate management system can be protected kinetically by increasing the hydrate induction and growth times.

[0023] A series of performance tests were undertaken in a high-pressure rocking cell to evaluate the effect of the combination of KHI and MEG on hydrate induction times. Compared to a typical hydrocarbon field, which currently injects over 50 vol.% MEG for hydrate treatment, results demonstrate that the MEG dose rate could be reduced by up to 80% with less than 2 vol.% KHI added into the system. In some configurations, this reduction in the required MEG dose rate could lead to a reduction of up to 40% in the flowrate of rich MEG (including MEG, water, dissolved salts and KHI) to the MEG recovery unit, where the water and salt present in the flowline MEG are removed to yield a lean MEG product suitable for re-injection. Based on a production estimation of 4,000 BPD water, the weight of the top-side equipment is reduced, for example by up to 15%. Requirements for main utilities, as well as rich and lean MEG storage, are also reduced.

[0024] In some configurations, 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.

[0025] The methodology to optimize hydrate management process according to embodiments of the disclosure was supported by the following confirmatory performance steps.

Rocking Cell

[0026] A rocking cell apparatus allows for testing of the performance of KHI in the presence of 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. By tilting, 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.

[0027] The cells are mounted on a movable axle, inside a bath of cooling liquid. For a test, 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. 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.

[0028] In some testing according to the present disclosure, 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.

Table 1: Gas composition used in the evaluation process

High-Temperature Stability Testing

[0029] As most KHIs contain active materials that are polymeric, they can be precipitated when the temperature increases, causing a reduction in performance. Hence, 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. [0030] In the second phase, 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.

[0031] 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.

First phase - Product Performance Evaluation

[0032] To establish a fundamental understanding of the scenario, a series of baseline testing was performed without the addition of KHI to evaluate the required MEG dose rate at the desired pressure and temperature conditions. The MEG dose rate was increased from 0 vol.% to 50 vol.% by total fluid. It was found that at least 25 vol.% MEG was needed to treat the system without any support from the KHI. This result was used in the following phases when determining how much MEG can be reduced with the addition of KHI according to the method of the present disclosure.

[0033] As the performance of any KHI is influenced by many parameters, such as gas composition, salinity, etc., multiple tests were conducted to screen for the optimal product for this particular scenario. A total of 4 products were selected as candidates for rocking cell testing. To ensure a direct comparison, the concentration of the active components in each product remained constant. For comprehensive screening, different combinations of KHI and MEG were tested. As shown in Table 2, two candidates, CHEMI and CHEM2, were selected for the next step due to the long induction time.

Table 2 Testing results of the 4 candidates in rocking cell

[0034] To investigate the performance envelope of CHEMI and CHEM2 on delaying hydrate formation onset, additional rocking cell tests were conducted with the same brine at different pressures, temperatures, gas compositions, and subcoolings. Table 3 shows rocking cell testing results at 1900 psi and 5°C using both CHEMI and CHEM2 candidates with the gas composition shown in Table 1. The

Table 3: Rocking cell test results at 1900 psi and 5°C

[0035] To investigate the effect of hydrate structures, a new gas composition, outlined in Table 4, that leads to structure II hydrate formation in the system was used for testing.

Table 4: Gas composition that forms structure II hydrates

[0036] To maintain a constant subcooling of 10°C, 1020 psi and 5°C were used for structure II hydrate formation. As shown in Table 5, the combination of 15% MEG and 1.5% CHEM2 remains an effective treatment strategy for hydrate formation. Both candidates showed fewer “Pass” results compared to the previous testing results, due to a higher subcooling that can lead to reduction in performance of KHI.

Table 5: Rocking cell results at 1020 psi and 5°C with gas composition of Table 4

Second phase - performance after heating

[0037] To confirm the KHI product remains effective after heating in the processing unit, testing was conducted and duplicated to ensure the performance of the two selected candidates, CHEMI and CHEM2. As shown in Table 6, several combinations of the KHI and MEG concentrations were tested after heating in a 140°C oven for 3 days. Both products were kept in small glass bottles and showed the ability to protect the system from hydrate formation for at least 72 hr. In some configurations, with the addition of a small dosage of KHI, the total required MEG can be reduced from 49 vol.% (currently injected) to 10 vol.%, leading to an 80% saving on MEG usage.

Table 6 Testing results of CHEMI and CHEM2 with heating at 140°C in an oven

[0038] To confirm performance after the heating process, an aging cell was selected to use for heating CHEMI and CHEM2. The products were placed in a capped glass tube and stored in a stainless steel aging cell. The aging cell provides good sealing on the samples so the solvents in the formulations will not be evaporated into the air. The samples were subsequently injected into the rocking cell for performance testing, with the results shown in Table 7. The results showed that the performance of the products did not decline due to thermal aging, especially for the condition of 1.5 vol.% KHI + 15 vol.% MEG.

Table 7 Testing results of CHEMI and CHEM2 with heating at 140°C in an aging cell Third phase - severe temperature stability testing

[0039] To further challenge the stability and performance of KHI, CHEM2 was dried at 160°C for 4 hours in a beaker. Instead of good sealing and keeping all components inside, at this phase, the solvents used in the formulation were all removed so the KHI’s active material became solids. The solid active material generated was then re-formulated with fresh solvents and injected into the rocking cell for performance testing. This updated heating process pushes the KHI material to a more severe condition.

[0040] Based on the results shown in Table 8, no reduction in performance was observed with the addition of the dried and re-reformulated CHEM2. The result of 1.5 vol.% KHI + 15 vol.% MEG remains positive and is consistent with the previous testing. This updated validation method aims to mimic the processes inside a rich MEG reclamation unit as contemplated in embodiments of the disclosure, where MEG and KHI will experience high temperatures. Since KHIs are polymers, the high temperature can lead to solid precipitation and performance reduction. As indicated in the results, it was found that KHIs have the potential to remain effective after being heated, and therefore can be reused or recycled for future chemical injection. The results of the performance tests confirmed that the product may be reused after being heated and filtered in a MEG reclamation system as contemplated in embodiments of the disclosure. The KHI could therefore be used in a closed loop, whereby the KHI is recovered and reused.

Table 8 KHI Performance testing after heating at 160C and reformulation [0041] As outlined above, multiple experimental testing and modeling phases have been performed to successfully demonstrate that the addition of KHIs can significantly reduce the overall usage of THI, such as MEG, and the size of the corresponding MEG reclamation unit, thereby effectively reducing CAPEX and OPEX. In some configurations, the addition of 1.5 vol.% KHI reduces the MEG usage by 80% and also provides a long induction time without hydrate formation. A series of high-temperature testing was conducted to confirm the reusability of the KHI. Results indicated that the product remains effective and is still functional in inhibiting hydrate formation kinetically. Therefore, those performance tests demonstrate that methods and systems according to embodiments of the present disclosure enable (1) using KHI and MEG to treat the hydrate problem; (2) reducing the overall MEG usage by adding KHI; and (3) recirculating and reusing the KHI material after being heated in a MEG reclamation system.

[0042] Methods and systems 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.

[0043] In some configurations, the KHI is added via an umbilical core, and MEG is delivered via a separate larger lean MEG line. In some configurations, a chemical injection valve (CIMV) enables addition of KHI in the umbilical. In some configurations, the CIMV can be retrofitted to an existing system using MEG injection.

[0044] The specific embodiments described above have been illustrated by way of example, and it should be understood that these embodiments may be susceptible to various modifications and alternative forms. It should be further understood that the claims are not intended to be limited to the particular forms disclosed, but rather to cover all modifications, equivalents, and alternatives falling within the spirit and scope of this disclosure. [0045] In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, for example, although 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.