Gas Hydrates and Flow Assurance

The need for a CFD exploratory investigation into the possible effect of hydrogen injection into existing natural gas pipeline network, was the driver for this study. Recent technical feasibility reports on transporting a blend of both gases (JIR, 2019), did not mention if a study was done to rule out the possible effect of natural gas-hydrogen blend on hydrate formation in a hydrate-prone gas pipeline. A CFD model of 0.0508m and 10m length, with a mesh size of 20,000 elements was developed and simulated using ANSYS Fluent version R19.3. Hydrogen concentration by volume of 5%, 10%, 15% and 20% were simulated at velocities of 5m/s and 10m/s. The results indicated that increasing the volume concentration of hydrogen gas in the blend led to a reduction of downstream temperature. Again, the force on the inner wall decreased as the volume of hydrogen injected increased. The inference was that the reduction in temperature could lead to hydrates formation, whereas the reduction in exerted force on the pipe wall by the fluid could suggest a reduction in turbulence. However, this study was exploratory in nature and it is recommended that a detailed experimental study be carried out to clearly define the hydraulic and thermal behavior of a pipeline transporting a natural gas-hydrogen blend under various subcooling temperatures.

This research is focused on the difficulties that gas producers usually face with Hydrates formation during its production, processing and transportation. Hydrates build up in gas production pipeline is one of the major task for gas operators to deal with as it may cease gas flow through the pipeline and associated production facilities. Research efforts to date, have addressed flow assurance issues of oil and gas displacement through the production pipeline and processing facilities but further research is needed to determine the best methods in handling flow assurance problems.
The principal objective of this research is to simulate gas flow through two different wells using hydrocarbon simulation software Aspentech HYSYS 7.1 and PIPESYS to investigate the effect of E-glycol on hydrates in two separate production lines from both wells. Two different scenarios were considered at the operating conditions of the field; before glycol injection and after glycol injection. The phase envelope plots indicates hydrate formation lines moving from right to left after glycol injection.
The simulation results reveal that the current gas production at Eriemu field increased from 75,073.7MMBtu/day to about 127,827.61MMBtu/day, which is about 41.2% of the initial gas production of the field after the injection of low dosage ethylene glycol into the production line. The glycol acts as an inhibitor and aid in dissociating hydrates from the pipe which resulted in an increase in production. This increase in production stand as a good economic indicator for Eriemu Field.

As the world’s appetite for energy continues to grow, oil and gas developments are moving to ever deeper subsea environments, thereby causing hydrates-related issues to become a growing concern for the industry. Hydrates blockages, beyond the safety risk they represent, result in time-consuming and costly mitigation and remediation operations. Most hydrate experiences found in the literature, and the corresponding prevention and remediation strategies, concern subsea pipelines. This work relates a novel technology for hydrate mitigation in subsea pipelines. This is the cold flow technology. A detailed review of the cold flow technology, its main component equipment, the concepts by different organizations on the technology, as well as the advantages and disadvantages of each proposal has been done.
A qualitative research method is used, which is suitable when exploring a new phenomenon.
Six cases of different technologies were chosen which include: chemical inhibition (THIs and LDHIs), direct electrical heating system and three potential emerging cold flow technology concepts for ensuring flow assurance in long pipelines. The technical, environmental and economical evaluations of the different technologies have been done. In order to obtain information on these cases, observation and documental studies (archives) were chosen as research methods. These methods however do not give me all the needed information about the various cases and this is a weakness of the results.
Cold flow technology was compared with the conventional technology currently used for tackling hydrate and wax problems. It was found out that the cold flow technology offers a more robust means of eliminating the problem in a cost and environmentally effective manner especially over long distances greater than 200 kilometers. The lessons learned from this experience are presented here and are currently being used as a basis for improving operation guidelines and hydrates prevention strategies for deepwater transportation pipelines.

In natural gas transmission and processing, gas hydrate formation is a major flow assurance challenge which led scientists towards conducting new and more detailed studies on different aspects of gas hydrates inhibitors. Ionic liquids (IL) recently revealed as novel hydrate inhibitors due to their unique properties like electrostatic charges together with ability to form hydrogen bonding with water molecule lead them viable research area in the field of gas hydrate mitigation. This paper highlighted the experimental evaluation of thermodynamic measurements of tetra methyl ammonium hydroxide (TMAOH) for Methane (CH4) and Carbon Dioxide (CO2) gas hydrates. TMAOH belongs to ammonium based ionic liquids (AILs) which is comparatively economical ILs among the other ILs families. Traditional T-cycle technique with isochoric step heating method was adopted for determining thermodynamic inhibition in this work. Results reveal that TMAOH effectively shift the hydrate equilibrium curve to upper pressure and lesser temperature regions for CH4 + TMAOH + water system and CO2 + TMAOH + water system. The average reduced temperature obtained for CH4 + TMAOH + water system is around 1.06 oC while for CO2 + TMAOH + water system, the inhibition effect found to be around 2.09 oC. Therefore, this study provides road map for superior alternative for the development of novel thermodynamic hydrate inhibitor, which can efficiently control the gas hydrate formation.

Depleted gas reservoirs are appealing targets for carbon dioxide (CO 2) sequestration because of their storage capacity, proven seal, reservoir characterization knowledge, existing infrastructure, and potential for enhanced gas recovery. Low abandonment pressure in the reservoir provides additional voidage-replacement potential for CO 2 and allows for a low surface pump pressure during the early period of injection. However, the injection process poses several challenges. This work aims to raise awareness of key operational challenges related to CO 2 injection in low-pressure reservoirs and to provide a new approach to assessing the phase behavior of CO 2 within the wellbore. When the reservoir pressure is below the CO 2 bubble-point pressure, and CO 2 is injected in its liquid or supercritical state, CO 2 will vaporize and expand within the well-tubing or in the near-wellbore region of the reservoir. This phenomenon is associated with several flow assurance problems. For instance, when CO 2 transitions from the dense-state to the gas-state, CO 2 density drops sharply, affecting the wellhead pressure control and the pressure response at the well bottom-hole. As CO 2 expands with a lower phase viscosity, the flow velocity increases abruptly, possibly causing erosion and cavitation in the flowlines. Furthermore, CO 2 expansion is associated with the Joule-Thomson (IJ) effect, which may result in dry ice or hydrate formation and therefore may reduce CO 2 injectivity. Understanding the transient multiphase phase flow behavior of CO 2 within the wellbore is crucial for appropriate well design and operational risk assessment. The commonly used approach analyzes the flow in the wellbore without taking into consideration the transient pressure response of the reservoir, which predicts an unrealistic pressure gap at the wellhead. This pressure gap is related to the phase transition of CO 2 from its dense state to the gas state. In this work, a new coupled approach is introduced to address the phase behavior of CO 2 within the wellbore under different operational conditions. The proposed approach integrates the flow within both the wellbore and the reservoir at the transient state and therefore resolves the pressure gap issue. Finally, the energy costs associated with a mitigation process that involves CO 2 heating at the wellhead are assessed.

Depleted gas reservoirs are appealing targets for carbon dioxide (CO 2 ) sequestration because of their storage capacity, proven seal, reservoir characterization knowledge, existing infrastructure, and potential for enhanced gas recovery. Low abandonment pressure in the reservoir provides additional voidage-replacement potential for CO 2 and allows for a low surface pump pressure during the early period of injection. However, the injection process poses several challenges. This work aims to raise awareness of key operational challenges related to CO 2 injection in low-pressure reservoirs and to provide a new approach to assessing the phase behavior of CO 2 within the wellbore. When the reservoir pressure is below the CO 2 bubble-point pressure, and CO 2 is injected in its liquid or supercritical state, CO 2 will vaporize and expand within the well-tubing or in the near-wellbore region of the reservoir. This phenomenon is associated with several flow assurance problems. For instance,...

Depleted gas reservoirs are appealing targets for carbon dioxide (CO 2 ) sequestration because of their storage capacity, proven seal, reservoir characterization knowledge, existing infrastructure, and potential for enhanced gas recovery. Low abandonment pressure in the reservoir provides additional voidage-replacement potential for CO 2 and allows for a low surface pump pressure during the early period of injection. However, the injection process poses several challenges. This work aims to raise awareness of key operational challenges related to CO 2 injection in low-pressure reservoirs and to provide a new approach to assessing the phase behavior of CO 2 within the wellbore. When the reservoir pressure is below the CO 2 bubble-point pressure, and CO 2 is injected in its liquid or supercritical state, CO 2 will vaporize and expand within the well-tubing or in the near-wellbore region of the reservoir. This phenomenon is associated with several flow assurance problems. For instance,...