Article pubs.acs.org/EF
Underinhibited Hydrate Formation and Transport Investigated Using a Single-Pass Gas-Dominant Flowloop Mauricio Di Lorenzo,*,†,‡ Zachary M. Aman,‡ Karen Kozielski,† Bruce W. E. Norris,‡ Michael L. Johns,‡ and Eric F. May*,‡ †
CSIRO Earth Science and Resource Engineering, 26 Dick Perry Avenue, Kensington, Western Australia 6151, Australia Centre for Energy, School of Mechanical and Chemical Engineering, University of Western Australia, 35 Stirling Highway, Crawley, Western Australia 6009, Australia
‡
ABSTRACT: There are substantial economic and operational incentives to reduce the volumes of thermodynamic inhibitors (THIs) injected in deepwater oil and gas pipelines to a minimum threshold necessary to achieve a flowable hydrate slurry and prevent hydrate deposition; however, there is uncertainty about whether this underinhibited condition may worsen hydrate transportability and increase plugging potential. In this study, hydrate formation rate and hydrodynamic pressure drop were measured over a range of temperatures and subcoolings using a one-inch single-pass flowloop containing aqueous monoethylene glycol (MEG) solutions (0−40 wt %) at a liquid loading of 5 vol % and a synthetic natural gas at an initial pipeline pressure of 10.3 MPa (1500 psia). Measured average formation rates in this gas dominant flow were within a factor of 2 of the kinetic rate and about 250 times faster than that expected for oil dominant flows. When the system was underinhibited with MEG, the pressure drop behavior over time was consistent with a proposed conceptual description for hydrate plugging in gas-condensate pipelines based on the mechanisms of stenosis (narrowing of the pipeline due to the deposition of a hydrate coat at the pipe wall) and sloughing (shear breaking of the hydrate deposits). The results from experiments performed at constant temperature showed that increasing the MEG dosage reduced hydrate formation rates and improved hydrate transportability. However, at decreasing temperatures, increasing the concentration of MEG to maintain a constant subcooling (and formation rate) appeared to promote hydrate sloughing. In certain experiments, it was possible to estimate the average deposition rate over the entire flowloop in addition to the average formation rate. Although formation rates were correlated with subcooling (rather than MEG concentration), the deposition rates were constant over the subcooling range (3.1 to 5.5 °C) achieved with MEG concentrations of 0 to 20%. Several field cases have been reported in which hydrates form when the amount of inhibitor present in the pipeline is less than required to preclude hydrate nucleation.5,6 In most cases, this underinhibition has been unintentional or due to equipment failures (e.g., with THI injection systems); however, it has not always led to complete pipeline blockages. In the Gulf of Mexico’s Tahoe field, cyclical operation at underinhibited conditions was intentionally implemented due to a lack of injection capacity and extended the field’s life by two years.7 Despite the economic incentive of operating at underinhibited conditions, this practice has not yet been accepted as an operational strategy because the risk of hydrate blockage cannot yet be predicted reliably using current simulation tools or models. Significant effort has been focused at developing a comprehensive model for hydrate formation and plugging in oil and gas flowlines8 that can be implemented in multiphase flow simulators. Although much progress has been made in the ability to describe oil-dominated systems, and computational tools for predicting hydrate plugs in oil-dominated multiphase flows are currently available,9 gas-dominated systems have been investigated to a much lesser extent. Lingelem10 and later Sloan
1. INTRODUCTION Gas hydrates are crystalline inclusion compounds, where hydrogen-bonded cages of water molecules surround light hydrocarbon species (e.g., methane) at high pressure and low temperatures. Hydrates are the chief flow assurance concern in deepwater oil and gas flowlines, as the growth and sloughing of hydrate deposits on the pipe wall as well as the agglomeration and jamming of hydrate particles in flow may result in complete line blockage.1 Antifreeze agents, such as alcohols or glycols, are the most reliable method to avoid hydrate formation altogether in deepwater oil and gas production systems. These thermodynamic hydrate inhibitors (THIs) interfere with the hydrogen bonding between water molecules, disrupting the stability of hydrate cages; THIs have been successfully used by the petroleum industry for the last 60 years.2 Well-established procedures are available to select the proper inhibitor for each particular development and calculate the minimum dosage necessary for complete hydrate suppression.3 To completely avoid hydrate formation at a given pipeline pressure and temperature condition, the amount of THI injected scales linearly with the volume fraction of coproduced water, typically in the range of 15 to 50 wt % of the aqueous phase. Creek4 estimated the cost of methanol for complete hydrate inhibition in an oil field producing 50 000 bbl/day water may reach 50% of the operating revenues, at the current prices of oil and methanol. © XXXX American Chemical Society
Received: July 15, 2014 Revised: September 22, 2014
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dx.doi.org/10.1021/ef501609m | Energy Fuels XXXX, XXX, XXX−XXX
Energy & Fuels
Article
Figure 1. Conceptual model for hydrate plug formation in gas-dominant systems, adapted from Lingelem.10
Figure 2. Simplified layout of the flow loop, with seven pressure and temperature gauges (denoted “P-T”), four viewing windows (denoted “VW”) along the test section, and liquid and gas flow meters (“LFM” and “GFM,” respectively) prior to entering the test section, adapted from Di Lorenzo et al.20
et al.1 have proposed conceptual mechanisms to describe hydrate plug formation in gas-dominant systems (Figure 1) which include: (i) nucleation and growth of a hydrate film at the pipeline wall; (ii) growth of the deposit, which occludes the flow area; (iii) sloughing of the hydrate deposit from increased fluid shear stress; and (iv) settling of collapsed material resulting in severe restriction or blockage of the flowline. Operating at underinhibited conditions will enable limited hydrate formation but it is uncertain whether this hydrate will be transported by the fluid phases as a dispersion or deposit on the pipeline wall as indicated in Figure 1. The rate of hydrate formation at underinhibited conditions has been investigated using high-pressure stirred autoclaves. Yousif11 and Abay and Svartaas12 reported that at low weight fractions of methanol (5−10 wt % of the aqueous phase), underinhibited operation increased hydrate induction times (a positive flow assurance effect) and simultaneously increased hydrate growth rates (a negative flow assurance effect). In recent studies using monoethylene glycol (MEG), Akhfash et al.13 did not observe any effect on the hydrate growth rate when the inhibitor was added at 10 wt % concentration. Cha et al.14 reported an increase of the hydrate induction time and smaller hydrate growth rates with 30 wt % MEG in water but observed no effect at 10 wt % MEG. Similar findings were reported by Hemmingsen et al.15 in their investigation using a flow-wheel apparatus with a gas-condensate system underinhibited with MEG. Shorter induction times were observed at 10 wt % MEG compared with the uninhibited and the higher MEG fraction systems, whereas the uninhibited and the 10 wt % MEG systems showed similar formation rates, which were higher than those found at 20 and 30 wt % MEG. These previous studies together suggest hydrate growth rate in underinhibited systems
may be controlled by competing effects: (i) MEG increases the equilibrium concentration of methane in water,16 which removes diffusional transport limitations for hydrate growth,17 whereas (ii) MEG shifts the hydrate equilibrium curve to higher pressure and lower temperature conditions, which reduces the driving force and diffusion rate. Although they are far from conclusive, the autoclave results above potentially suggest the first of these competing effects may be more significant at low THI concentrations (
