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Summary Some crude oils contain naturally occurring surfactants that avoid hydrate agglomeration. Natural hydrate antiagglomeration has been linked to different crude oil fractions, including asphaltenes. Asphaltenes can promote the formation of stable water-in-oil (W/O) emulsions due to their amphiphilic properties. The surfactant-like behavior of asphaltenes is related to their aggregation state. Asphaltenes are strong emulsifying agents when in an aggregated state but weak emulsifying agents when either precipitated or well solubilized in the bulk oil phase. The asphaltene aggregation state may be artificially modified, changing its interfacial activity, by mixing crude oil with heptane–toluene mixtures. This work investigated the influence of the asphaltene aggregation state on gas hydrate agglomeration. Results show that the natural hydrate antiagglomerant properties of crude oils can be highly dependent on the artificially induced asphaltene aggregation state. For instance, if asphaltenes were induced to be solubilized into the bulk oil phase, the natural hydrate antiagglomerant behavior was diminished. However, when asphaltene aggregation was induced, gas hydrate agglomeration was avoided. These new findings could have significant implications for the implementation of novel hydrate management strategies that can reduce or eliminate the need for external interventions and hence minimize capital and operational expenditures by taking advantage of the intrinsic natural antiagglomerant properties of some crude oils.

High-pressure and low-temperature conditions during subsea pipeline transportation favor the formation of gas hydrates and may create challenging flow assurance problems. Once gas hydrates have plugged the pipeline, it is usually difficult and costly to remediate. To prevent hydrate plugging, rigorous hydrate management guidelines need to be formulated and implemented at an affordable cost. Current hydrate management guidelines are mostly based on fluid analysis and benchtop experimental results, which may not represent the actual field conditions. Based on this situation, a simulation tool that can bridge the gap between benchtop experiments and field pipeline transportation conditions is needed. In this paper, a methodology is proposed to combine benchtop ultralow volume (<10 mL) experiments with field simulations to provide insights for field hydrate management. This methodology was applied to a real black oil field to study the blockage risk during shut-ins of varying durations. Simulations were carried out at three representative water cuts. It is indicated that for production shut-ins within 6 h, the flowlines can be directly restarted without hydrate plugging risk. Hydrate slip and accumulation could increase the plug potential, thus for a restart following a planned shut-in longer than 6 h, AA injection might be necessary. Simulations indicate that even after 16 h into a shut-in, the hydrate formation amount would be very low during dead oil displacement. This suggests that dead oiling could be a good strategy to minimize risk during the ensuing restart for unplanned shut-ins longer than 6 h. Based on these simulation results, the envelope for a hydrate risk management approach can be expanded to allow higher water cut operation with minimal blockage risk during extended unplanned shut-ins and restarts. This simulation tool and the proposed methodology may be used to develop competitive field hydrate management guidelines with relatively low capital expense (CAPEX) and operating expense (OPEX) in different fields.

As increasing environmental policies constrains are imposed, the demand for biodegradable products also increases. Although vegetable oils present some properties that favor its use for formulation of a bio-based lubricant, its poor resistance to oxidation hinders its application as such. In this study, the thermo-oxidative stability of bio-based products was compared to petroleum-based lubricants and vegetable oils through the PetroOXY method. Chemical modifications in the ricinoleic acids were carried out using long-chain alcohols in esterification reactions. Acetates were obtained from ricinoleates with and without hydrogenation steps. Additionally, commercial antioxidants and phenolic compounds (saturated and unsaturated cardanol) obtained from cashew nut shell liquid were added to the synthesized samples with higher induction times. The results show that the chemically modified bio-based products exhibited improved oxidative stability (up to 6 times) and depressed pour point (−42°C) when compared to pure castor oil. Overall, the addition of antioxidants increased from 6 to 20 times the oxidative stability of the bio-based products. Propyl gallate and saturated cardanol showed higher efficiency for retarding the oxidative process of bio-based samples than the commercial antioxidants.

Gas hydrate formation in oil and gas flowlines can represent a safety concern and a cause for hindered production, resulting in economic losses. Hydrate risk mitigation can be attained through hydrate avoidance or management strategies. Hydrate avoidance methods aim to keep the flowline outside of the hydrate stability region through, for example, the use of thermodynamic hydrate inhibitors. Thermodynamic hydrate inhibitors (THIs) increasingly shift the hydrate boundary towards higher pressures and lower temperatures as a function of THI concentration in solution. Hydrate management strategies allow the flowline to operate inside the hydrate stability zone, without the risk of forming a plug by using kinetic hydrate inhibitors or commercial hydrate anti-agglomerants. Some crude oils, denoted non-plugging crude oils, have naturally occurring surfactants (e.g., asphaltenes) that can behave as a hydrate anti-agglomerant and allow the formation of a transportable non-agglomerating hydrate slurry. Recent work has suggested that the asphaltene-aggregation state is a parameter that may dictate the natural hydrate anti-agglomeration behavior of non-plugging crude oils. The ability of naturally occurring anti-agglomerants to prevent hydrate plugs is limited by the intrinsic amount found in the non-plugging oils and thus depends on the amount of hydrates formed in the flowline. Therefore, there is an opportunity to use thermodynamic hydrate under-inhibition (i.e., partial thermodynamic inhibition) in non-plugging crude oil systems that can no longer safely avoid a hydrate plug while relying on natural surfactants alone. If THI under-inhibition is used to partially reduce the amount of hydrates formed, the natural anti-agglomerants can prevent hydrate agglomeration of the remaining hydrates formed. The THI volume required for under-inhibition would be lower than that of complete THI inhibition, thereby reducing operational costs. In this work, alcohols with different hydrocarbon chains and mono-ethylene glycol were shown to have a key impact on the asphaltene-aggregation state, inferred through size measurements of solvent-extracted asphaltene particles, correlating with changes in emulsion stability, and the non-plugging potential of a crude oil as assessed by rocking cell tests. The effect of alcohols on the asphaltene-particle size was also shown to be highly sensitive to the presence of a free-water phase, likely due to observed alcohol partitioning into the water phase. Alcohols with intermediate-hydrocarbon chains prevented asphaltene aggregation more effectively and reduced their emulsification tendency compared to alcohols with shorter carbon chain lengths. Furthermore, short-chain alcohols or MEG showed no antagonism when used with the non-plugging oil tested, resulting in a partially inhibited system able to avoid hydrate agglomeration at a higher water cut compared to a non-inhibited system. On the other hand, alcohols with intermediate-chain length were found to be detrimental to the non-plugging potential of the specific crude oil tested, potentially due to its effect of reducing the asphaltene-particle size in solution. More experimental work is required to better understand these phenomena and determine if other non-plugging crude oils show a similar behavior.

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Gas hydrates can form in subsea oil and gas flowlines, where the depths of seawater and ocean conditions provide the thermodynamic environment for hydrate stability. Hydrates present a major flow assurance problem due to the relatively fast timescales at which they can form, grow/agglomerate, and plug a flowline. The common strategy for preventing hydrate formation uses thermodynamic inhibitors (THIs). However, THIs can be cost prohibitive or impractical as the water content in the flowline and its seawater depth increases. Therefore, there is growing interest in the use of alternative hydrate management strategies, such as the injection of low dosage hydrate inhibitors (LDHIs), which are active at considerably lower concentrations than THIs (e.g. 2 vol.% of LDHI versus 50 vol.% of THI). Anti-agglomerants (AAs) are a type of LDHI that prevent agglomeration and allow hydrates to flow as a slurry in oil and gas subsea flowlines. Before field deployment, AAs are screened and selected using laboratory set-ups, mimicking field conditions, in order to evaluate their performance and determine the effective dosage. Current hydrate agglomeration characterization methods implemented in the industry are non-uniform and qualitative, which can lead to conservative recommendations. In this work, the possibility of quantifying hydrate agglomeration in the presence of AAs is investigated, along with studies of the mechanisms via which AAs may operate. One mineral oil and two crude oils were used with a commercial AA in a high pressure stirred autoclave, equipped with particle imaging probes. Motor current input at a fixed RPM was monitored throughout the experiments and serves as an indicator of relative viscosity of the hydrate slurry. This investigation enabled the development of a comprehensive AA performance evaluation. Hydrate agglomeration was detected and quantified by simultaneous increases in the relative motor current and chord length distribution.