Hydraflow: Avoiding Gas Hydrate Problems

Abstract

Flow Assurance continues to remain a major challenge in offshore production operations. Current methods for avoiding gas hydrate problems are generally based on one or a combination of the following three techniques:injection of thermodynamic inhibitors (e.g. methanol, ethylene glycol) to prevent hydrate formation,use of kinetic hydrate inhibitors (KHIs) to sufficiently delay hydrate nucleation/growth, andmaintaining pipeline operating conditions outside the hydrate stability zone by insulation and/or active heating and/or by controlling pressure.1 However, for many production operations, particularly deepwater fields, those requiring long tiebacks, and mature reservoirs (where water cuts can be very high), the above techniques may not be economical and/or logistically practical. Thus the industry needs novel and improved techniques to tackle flow assurance problems for such challenging conditions. The new approach presented in this paper -HYDRAFLOW- aims to meet this need. HYDRAFLOW is a novel 'cold flow' concept, which breaks from the tradition of straightforward hydrate prevention. Instead, gas hydrate formation in pipelines is intentionally induced and managed, eliminating the need for expensive thermal/chemical inhibition while improving the economics and practicalities of multiphase fluid transport. Experimental analyses of low and high GOR systems for various different production scenarios with and without AA (Anti-agglomerant) have been undertaken as part of HYDRAFLOW concept development. The effect of simulated shut-in on fluid transportability has also been tested. A new experimental set-up for measuring the viscosity of the fluid system under high-pressure conditions has been designed and commissioned in order to evaluate the rheology of the systems under investigation. Results prove that the concept is viable (at least under laboratory conditions), and strongly suggest that HYDRAFLOW technology could offer significant benefits over existing flow assurance strategies, providing a novel low CAPEX/OPEX solution for challenging (e.g. deepwater, long tie-backs, mature fields) operations. Introduction Generally, most of the existing gas hydrate flow assurance techniques are based on avoiding solid hydrate formation. This is normally achieved by either reducing water content, reducing heat loss to the environment (e.g. by insulation and/or active heating) or the injection of thermodynamic and/or kinetic hydrate inhibitors. However, all of these approaches have limitations, particularly in the case of deepwater operations, high water cuts (e.g. mature fields) and/or long tieback systems. As forecasted by ITI Energy, global oil and gas production is increasingly being dominated by exploitation of mature fields, meaning existing techniques - which are more geared to new developments (lower water cuts) - are becoming less practical/economic.2 Thus the requirement for alternative strategies is expected to continue to increase in the future. HYDRAFLOW is a new, patented flow assurance technology, which aims to meet this need. The concept of HYDRAFLOW is to be able to transport oil/gas without any thermal (i.e. insulation or active heating) or high dosage chemical treatment, thus greatly reducing the costs of multiphase hydrocarbon pipeline transport. The absence of thermal and/or major chemical treatment means HYDRAFLOW falls under the umbrella of 'cold flow' technologies.

Preventing and removing wax deposition inside vertical wells: a review

“…While wax deposition may be avoided by eliminating the heat flux, even below the WAT, much work is still needed to develop the technology required for effectively cooling the bulk fluid to this condition and for transporting the resulting cold slurry over long distances. Additionally, Haghighi et al (2007) and Azarinezhad et al 2010proposed a wet cold flow-based concept with the potential benefit of wax inhibition.…”

On liquid phase hydrates formation in pipelines in the course of gas non-stationary flow

“…Therefore, for definition the possible area of hydrate generation first of all it is necessary to find out pressure and temperature distribution in the pipeline. Such kind problem, under the condition of gas stationary flow, have been discussed and examined by a number of investigators [1,[13][14][15][16][17][18][19][20][21][22]. In our study an attempt is made to examine the role of gas non-stationary flow with accounting heat exchange with medium for definition hydrates possible generation point in the pipeline.…”

“…Equations (19), (16) and (17) create system with regards to functions P, ω and T: Equations (21) and (22) of the system represent a system of two-variable equations with regards to functions ) , ( t x P and ) , ( t x…”

“…There are many scientific articles denoted to the problem of prediction of possible points of hydrates origin in the main pipelines [13,15,16]. There are several methods for avoiding gas hydrate problems, but generally modern methods for prevention of hydrate formation are based on the following techniques: injection of thermodynamic inhibitors, use of kinetic hydrate inhibitors to sufficiently delay hydrate nucleation/intensification, and maintain pipeline operating conditions outside the hydrate stability zone by insulation, heating and controlling pressure [17][18][19][20][21]. However, the above techniques may not be economical and practical.…”

Experimental investigation of hydrate formation, plugging and flow properties using a high-pressure viscometer with helical impeller

“…The rheological characterization of complex fluids has been studied using flowloops (Bbosa 2015;Sinquin et al 2004;Haghighi et al 2007;Hald and Nuland 2007;Gudmundsson 1999, 2000;Lv et al 2012;Chen et al 2014) and a high-pressure mixer-viscometer (Bbosa et al 2017;Camargo et al 2000;Eric et al 2013Eric et al , 2012Ahmad et al 2017;Patrick et al 2008). Some of the measurements on these systems assume that the resulting slurries obey the Newtonian rheological model (Haghighi et al 2007; Andersson and Gudmundsson 2000;Camargo et al 2000). However, when the measured viscosity was plotted against shear rate, shear thinning behavior was observed (Bbosa 2015;Sinquin et al 2004;Bbosa et al 2017;Eric et al 2012;Ahmad et al 2017;Patrick et al 2008).…”