Solid deposition during production, transport, and storage of crude oils leads to significant technical problems and economic losses for the oil and gas industry. The thermodynamic equilibrium between high-molecular-weight components of crude oil, such as asphaltenes, resins, and waxes, is an important parameter for the stability of crude oil. Once the equilibrium is disturbed due to variations in temperature, pressure, and oil composition during production, the solubility of high-molecular-weight waxes decreases. This results in a decrease in the wax appearance temperature (WAT) and the deposit of wax onto solid surfaces. On the other hand, under these conditions, asphaltenes do not interact sufficiently with the resins/waxes and tend to flocculate among themselves and form asphaltene nanoaggregates. The role of waxes during the asphaltene aggregation and deposition has not been appropriately explained yet. The objective of this research study is to describe the interaction of asphaltenes and waxes and subsequently address the specific example of an asphaltenic oil commingled with a wax inhibitor-containing oil during the combination of different oil streams. It is a crucial building block for the development of a suitable and cost-effective strategy for the handling of wax/asphaltene associated flow assurance problems. In this work, the quartz crystal microbalance (QCM) technique has been used for the first time to investigate the effect of waxes and related chemicals, which are used to mitigate wax deposition, on asphaltene aggregation and deposition phenomena. Asphaltene onset point and asphaltene deposition rate have been monitored using QCM at high pressure–high temperature (HPHT) conditions. This study confirms that the different wax inhibitor chemistries result in significant differences in the pour point decrease and viscosity profiles in crude oil. Different wax inhibitors also showed different outcomes regarding the asphaltene deposition tendency. A comprehensive modeling study has also been conducted for mechanistic investigation of experimental results. In this regard, the perturbed chain statistical associating fluid theory equation of state (PC-SAFT EoS) was utilized to model the systems.
Evaluation of anti-agglomerate hydrate inhibitor in water-in-crude oil emulsions of different water cutA commercially available anti-agglomerant was evaluated in water-in-crude oil emulsions at different water cut. The injection of an anti-agglomerant to an emulsion affects the induction time and rate of hydrate formation. When the antiagglomerant was injected before emulsification, the anti-agglomerant performed better due to the higher number of anti-agglomerant molecules at the hydrate surface has been increased. The transition from stable a water-in-crude oil emulsion to a stable hydrate-in-crude oil suspension takes place without hydrate agglomeration in the presence of the anti-agglomerant, so the results obtained can be applied for developing deep-water transport technologies of crude oil under pipeline conditions.
An offshore Mid-Norway oil field includes wells on sub-sea templates at a depth of 350m. The formation waters contain up to 300 mgl-1 of barium, giving a sulphate scaling potential on seawater breakthrough. Scale protection on the template and down-hole is provided by squeeze treatments. Deployment possibilities include bull-heading down the methanol injection line (a distance of 10km) and bull-heading directly to the sub-sea template from a boat. In the event of a produced gas leak into the system, the conditions dictate that a water-based squeeze inhibitor will be in the region for hydrate formation. In such an event hydrates would be formed in minutes, blocking the service line before it could be re-flooded with the thermodynamic hydrate inhibitor methanol. Current scale inhibitors (SI) are hydrate-inhibited by formulation in MEG. This paper describes an innovative SI protected from hydrate formation by formulating with kinetic gas hydrate inhibitors (KHI). The field scale squeeze inhibitor was modelled and shown to have the potential for hydrate formation under sub-sea conditions. The concentration of MEG required to avoid this region was also modelled as >50% based on water. This was followed by laboratory autoclave tests when gas hydrates formed as predicted by the model. Using the same SI formulated with a small addition of a KHI the hydrate induction time was extended beyond the SI residence time in the injection line. Further testing of SI efficiency demonstrated an improved efficiency over an equivalent scale inhibitor formulated in MEG. Due to the spiralling costs of installing new oil production facilities the use of sub-sea templates is increasing. Any scale squeeze treatments must be protected against potential gas hydrate formation. This paper describes such a protection by adding a KHI to a water-based product rather than formulating in MEG thereby allowing formulation at higher SI actives, potential lower costs and a lower viscosity product at low temperature. Introduction An offshore Mid-Norway oil field has an extensive history of aqueous scale squeeze treatments, utilising phosphonates, polyaspartates and other polymers. In recent years the emphasis has been on polymeric chemistries due to increasingly stringent environmental legislations. Although progress has been significant, the development of new and ever more environmentally friendly squeeze chemicals will continue in order to cope with further restrictions in the future. A major challenge of this study was the identification of a solution fully compliant with Statens Forurensingstilsyn (SFT - the Norwegian Pollution Authority). The deployment of chemicals in the field is a problem, especially on sub-sea templates where access is limited and often requires a rig or a special intervention boat to connect to the wells on the template. These are costly to rent and also highly dependent on weather, making pumping operation during the winter storms a challenge both for the companies' wallets and patience. This paper is concerned with another option for bull-heading on sub-sea templates, where the squeeze treatment is deployed down methanol injection lines from the production facility. A further application considered is general scale protection on sub-sea templates; as such products have the same requirements for low temperature application, including methanol compatibility.
Kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs) – known as low dosage hydrate inhibitors (LDHIs) – have been used widely for gas hydrate prevention in oil and gas operations. They offer significant advantages over thermodynamic inhibitors (e.g., methanol and glycols). While significant works have been done on KHIs evaluation, AAs suffer from their evaluation in terms of hydrate structural effect, gas composition, water cut, and hydrate amount, which are the main objectives of this work. A Shut-in-Restart procedure was carried out to experimentally evaluate (using a visual rocking cell) various commercial AAs in different gas compositions (from a simple methane system to multicomponent natural gas systems). The kinetics of hydrate growth rate and the amount of hydrate formation in the presence of AAs were also analysed using the recorded pressure-temperature data. The amount of hydrate formation (WCH: percentage of water converted to hydrate) was also calculated by pressure drop and establishing the pressure-temperature hydrate flash. The experimental results from the step heating equilibrium point measurement suggest the formation of multiple hydrate structures or phases in order of thermodynamic stability rather than the formation of simple structure II hydrate in the multicomponent natural gas system. The initial findings of experimental studies show that the performance of AAs is not identical for different gas compositions. This is potentially due to the hydrate structural effect on AAs performance. For example, while a commercially available AA (as tested here) could not prevent hydrate agglomeration/blockage in the methane system (plugging occurred after 2% hydrate formed in the system), it showed a much better performance in the natural gas systems. In addition, while hydrate plugging was not observed in the visual rocking cell in the rich natural gas system with AA (at a high subcooling temperature of ∼15°C), some hydrate agglomeration and hydrate plugging were observed for the lean natural gas system at the same subcooling temperature. It is speculated that methane hydrate structure I is potentially the main reason for hydrate plugging and failure of AAs. Finally, the results indicate that water cut%, gas composition, and AAs concentration have a significant effect on hydrate growth rate and hydrate plugging. In addition to increasing confidence in AAs field use, findings potentially have novel applications with respect to hydrate structural effect on plugging and hydrate plug calculation. A robust pressure-temperature hydrate flash calculation is required to calculate the percent of water converted to hydrate during hydrate growth in the presence of AAs.
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