Gas Hydrate Management Strategies Using Anti-Agglomerants: Continuous & Transient Large-Scale Flowloop Studies

Abstract

Subsea oil and gas flowlines can provide favorable conditions for gas hydrate formation, which can lead to flow assurance issues as hydrate particles agglomerate and accumulate in the flowline. Shut-in and restart operations are particularly critical for hydrate plug formation. Traditional strategies to mitigate hydrate plugging use total hydrate avoidance with thermodynamic inhibitors; however, thermodynamic inhibition can become cost-prohibitive as oil production moves towards harsher environments associated with deeper drilling. Hydrate management strategies using low dosage hydrate inhibitors (LDHI), such as anti-agglomerants (AA), are an attractive alternative to reduce operational and capital expenditures in offshore oil and gas production. In order to successfully deploy anti-agglomerants to mitigate hydrate plugging, a comprehensive understanding of the variables affecting the performance of these additives, such as oil composition and mixture velocity, is needed. Industrial-scale flowloop studies are valuable to investigate the influence of these variables on hydrate particle transportability when using AAs. These experimental setups could be also useful to assess AA performance during transient operations (i.e. shut-in and restart); however, large-scale flowloop data at these conditions is limited. High pressure industrial-scale flowloop tests were conducted using a non-dispersing oil at 50 vol. % water content and 70 vol. % liquid loading. The aqueous phase is a 3.5 wt. % NaCl solution and the gas phase comprises a natural gas favoring the formation of sII gas hydrates. The AA used in these tests is a quaternary ammonium salt. Both baseline (without AA injection) and AA dosed (2 vol. % AA) tests were conducted in order to compare the influence of mixture velocity on hydrate transportability using AAs with respect to systems without AA injection. Three different mixture velocities (2.3, 3.7 and 5.8 ft s) were employed. The experimental procedure included shut-in and restart operations. A combination of different data, such as temperature and pressure drop profiles, mass flow rate and droplet/particle size evolution was used to analyze the effects of AA injection at the different studied velocities. Additionally, water/oil dispersion tests were carried out in order to investigate the influence of the AA on the properties of the dispersion. Both hydrate growth rate and droplet/particle size were influenced by mixture velocity in baseline tests; however, experiments with 2 vol. % AA showed similar hydrate growth rates and droplet/particle sizes regardless of the mixture velocity. In addition, despite AAs reducing hydrate bedding at all mixture velocities with respect to baseline experiments, a certain velocity was needed to completely suppress any indication of hydrate bedding in these systems. Moreover, AA injection successfully inhibited hydrate particle size increase (agglomeration) under static conditions (shut-in), allowing solid material flow after restarting the system. Finally, dispersion tests showed that this particular AA formulation modifies the surface chemistry properties of the system and favors water-continuous dispersions at room conditions with respect to systems without addition of AA.

Hydrate Risk Management in Gas Transmission Lines

“…Rather, the successive application of the scientific method to a mechanistic model of hydrate blockage formation, particularly when adjustable or tuning parameters are absent, provides three distinct advantages: (i) The approach is scalable to the diversity of expected multiphase flow conditions that can be encountered in complex hydrocarbon transmission networks . (ii) The incorporation of new phenomena in a mechanistic model naturally illuminates new opportunities for exploitative control of at-risk systems . (iii) The approach can be readily coupled with probabilistic input parameters to provide statistically meaningful descriptions of risk to hydrocarbon productivity…”

Correlating Antiagglomerant Performance with Gas Hydrate Cohesion

“…In this context, flow assurance activities are experiencing a remarkable change from “hydrate avoidance” to “hydrate management”, toward reducing capital and operational costs. − Hydrate inhibitors are commonly used to prevent the agglomeration of solid hydrate particles or their deposition on pipe walls. Depending on the expected inhibition mechanism, low-dosage hydrate inhibitors can be categorized as kinetic hydrate inhibitors (KHIs) and/or antiagglomerants (AAs). ,, KHIs and AAs can be effective at dosages in the range of 0.5–2 vol %, while thermodynamic hydrate inhibitors require dosages of as high as 30–40 vol %. − However, the AA performance and their minimum effective dosage in specific applications vary, thereby affecting significantly the production costs.…”

Quantitative Framework for Hydrate Bedding and Transient Particle Agglomeration

“…1 A sound understanding of the physical mechanisms of hydrate bedding is critical in mitigating risks with hydrate plugging. With over a decade of research work from Turner et al, 2 Davies et al, 3 Boxall, 4 Joshi et al, 5 Zerpa et al, 6 Aman et al, 7 Grasso, 8 Warrier et al, 9 Majid et al, 10 Brown et al, 11 Chaudhari et al, 12 Dapena et al, 13 Liu et al, 14 Wang et al, 15 Salmin et al, 16 Charlton et al, 17 and Srivastava et al, 18 a modified conceptual picture (Figure 1) of hydrate plug formation was recently proposed. 19 The conceptual picture was based on the original work by Turner followed by the continued learning from these researchers and from the analysis of recent flow loop data (acquired in 2014−2016).…”