ORCID Profile
0000-0001-9186-3511
Current Organisation
University of Western Australia
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Publisher: Elsevier BV
Date: 09-2022
Publisher: Elsevier BV
Date: 05-2021
Publisher: American Chemical Society (ACS)
Date: 29-07-2021
Publisher: SPE
Date: 12-11-2020
DOI: 10.2118/202447-MS
Abstract: Natural gas hydrate has attracted interest as an energy resource capable of meeting the expected growth in global energy demand. Several key issues remain to be tackled to enable commercial production, one of which is gas hydrate re-association in production lines, where significant volumes of water are co-produced with free gas. To predict this behavior, we introduce a model and simulation tool tailored towards hydrate growth in water-dominant turbulent flow. We have produced a model to predict the growth rate of hydrate in water dominant systems, integrated into an in-house pseudo-steady-state multiphase flow simulator, named HyFAST. This is a mass transfer limited model where the growth rate is limited by the dissolution of guest gas molecules into the water-continuous phase. It considers the effect of interfacial gas-water bubble surface area, the degree of turbulence on mixing, and changes in bulk viscosity caused by hydrate particle formation. The tool is deployed to estimate the hydrate volume formed in production lines during the second offshore methane hydrate production test in Japan. Initially, the model was validated in an experimental study against flowloop data, where, at worst, model predictions showed order of magnitude agreement with experimental growth rates following this the model was integrated into an overall flow simulation tool used for larger scale predictions. The offshore production test was designed to use two separate lines to produce gas and water, however, some gas was entrained into the water production line, posing a risk of re-association. As such, our primary focus was on this water production line, approximately 1 km in length, rather than the gas production line, which generally remained outside the hydrate stability region. Our simulation predictions showed that the hydrate volume in the water production line was less than 5 vol%. Coupled with flowloop data which showed that blockages did not occur in similar systems up to 20 vol% hydrate, this suggests there was not a significant hydrate blockage likelihood in the offshore production test. These initial results suggest that the model may scale well from lab to field, and that such simulation tools can prove useful in discussing the consequences of hydrate re-association. A new model and simulation tool were developed to predict the rate and extent of hydrate growth in water-dominant flow. These were used to predict hydrate formation in both flowloop experiments and actual production lines. The validation results showed that the approach may prove useful in evaluating hydrate blockage propensity in future gas hydrate production.
Publisher: Elsevier BV
Date: 10-2023
Publisher: Society of Petroleum Engineers (SPE)
Date: 03-04-2017
DOI: 10.2118/182230-PA
Abstract: The first offshore methane-hydrate production test was conducted in the Eastern Nankai Trough area of Japan in 2013, subjecting a gas-hydrates reservoir to large drawdowns by reducing bottomhole pressure (BHP) for in-situ dissociation of gas hydrates. This pioneering test has proved the feasibility of the depressurization method through demonstration of gas production from a deepwater gas-hydrates reservoir. Approximately 119 500 std m3 of gas was produced during a continuous flow period of 6 days. However, reservoir response to a range of drawdown conditions was not attainable, which is important for reservoir evaluation, because drawdown became uncontrollable after unintended water production through the gas line occurred. Gas and water released from the dissociation of gas hydrates were separated by use of a downhole gas-separation system. The separated gas and water were produced to surface by means of two dedicated gas and water lines. Drawdown was executed by pumping out water into the water line by use of an electrical submersible pump (ESP). Drawdown control was designed to regulate the liquid level (or hydrostatic pressure) in the gas line by controlling the ESP frequency and the water-line surface backpressure. Analysis of production data supported by flow simulations indicated that continuous water production through the gas line was the main reason for the loss of drawdown control. The trigger of the water production was that the water column in the gas line reached surface because of the rising water level resulting from the produced gas, which also lightened the water column and lowered the BHP. Consequently, the continuous water production made it difficult to regulate the drawdown as intended. The analysis concluded that the risk of water production through the gas line could be significantly lowered if a choke valve was installed at the surface gas line and/or the ESP had high tolerance to the presence of free gas. This first field trial has provided valuable information in understanding the methane-hydrate production system to further improve/develop strategies in controlling large drawdown in the system.
Publisher: OTC
Date: 05-05-2014
DOI: 10.4043/25237-MS
Abstract: The world's first offshore methane hydrate production test was carried out in March 2013 in the Eastern Nankai Trough. The dissociation of methane hydrates in sediments was produced by depressurization. In this situation, flow assurance (FA) and prevention of hydrate re-formation in the wellbore is an important issue because water mixed with methane is transported through the well and seabed facilities, and subject to the well bore flowing pressure while being cooled-down by the surrounding seawater (around 4°C near the seabed). A particular concern results from incomplete downhole gas separation of methane and water: this leads to the methane production line containing a small amount of water, and the water production line containing a small amount of free methane gas. In this water dominant flow line there is then the possibility of flow blockage due to gas hydrate re-formation and accumulation, but knowledge about behavior of hydrates under such water dominant conditions was not well known. To investigate the potential for hydrate re-formation downstream of the downhole separator (including subsea pipes and equipment), Japan Oil, Gas and Metals National Corporation (JOGMEC) and Oilfield Production Technologies (OPT) developed a unique flow loop maintained at low temperature and high pressure. The flow loop was some 20 m in length. Notably, 6 m of the flow loop was constructed in optically clear cast acrylic, which allowed image capture in horizontal and vertical flow lines, and at flow stagnation points, ofmethane/water flows outside the hydrate regionthe formation, development and flow characteristics of hydrate slurries In this paper we describe the flow loop design, show images of flow taken by a high speed camera, and our measurements of temperature and pressure in this water dominant system, and the potential of FA problems caused by hydrate re-association. The results and observations were used in the design of the test plan and test procedures implemented in the East Nankai production testing.
No related grants have been discovered for Shunsuke Sakurai.