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This paper describes the change of the chemical flow assurance mitigation strategy for a major deep water waxy crude oil pipeline in SE Asia. The case relates to an application of a Pour Point Depressant (PPD)/Wax Inhibitor (WI) chemical that is critical in maintaining subsea flow assurance due to cooling of a waxy crude oil over the length of the 210 km deep water subsea pipeline. The paper further describes how the injection strategy was successfully changed. New chemical key performance indicators (KPIs) were initially determined based on chemical performance and risk mitigation requirements. Results of the laboratory new chemical formulation, qualification and subsequent successful field trial are presented. Other significant benefits yields are also discussed. KPI targets for the PPD/WI application were first determined based on field application performance and requirements. Candidate PPD/WI chemicals were selected based on the KPI requirements and initially screened to evaluate performance in reducing the crude oil pour point. Product development was then further refined once a definitive correlation between chemical structure and performance for the specific waxy crude oil was identified. Subsequently, more detailed laboratory testings were performed, including rheology measurements, coaxial shearing paraffin deposition and dynamic wax flow loop measurements. Field trial was later conducted to gradually obtain the optimum dosage while closely monitoring both onsite and in the lab to confirm the product effectiveness. Key to the success of the change was the identification of the opportunity to switch the PPD injection from subsea to topsides. This decision enabled a much wider portfolio of PPD chemistries to be evaluated. New topside PPD was identified which was able to reduce the pour point of the crude oil from 18°C to 9°C using a low dose rate of ~100 ppm, which is a ~40% reduction in chemical consumption compared to the previous chemical used. The new chemical was piloted without any disruption to the facilities and/or production. Furthermore, the field trial created significant benefits by reducing OPEX through the reduction in waxy pigging debris and chemical logistics, improving HSE and reducing the risk of chemical non-deliverability due to umbilical blockages. This paper demonstrates the re-evaluation of a field’s flow assurance strategy to realize significant benefits by challenging conventional wisdom regarding the need for subsea PPD/WI injection in waxy deep water fields. Understanding the gel strength of the crude through detailed evaluation and monitoring of the shear force needed to break the gel during a shutdown by using an optimized PPD/WI product/dosage is an important parameter to look at to ensure effective field optimization, rather than relying on the standard method of pour point monitoring.
This paper describes the change of the chemical flow assurance mitigation strategy for a major deep water waxy crude oil pipeline in SE Asia. The case relates to an application of a Pour Point Depressant (PPD)/Wax Inhibitor (WI) chemical that is critical in maintaining subsea flow assurance due to cooling of a waxy crude oil over the length of the 210 km deep water subsea pipeline. The paper further describes how the injection strategy was successfully changed. New chemical key performance indicators (KPIs) were initially determined based on chemical performance and risk mitigation requirements. Results of the laboratory new chemical formulation, qualification and subsequent successful field trial are presented. Other significant benefits yields are also discussed. KPI targets for the PPD/WI application were first determined based on field application performance and requirements. Candidate PPD/WI chemicals were selected based on the KPI requirements and initially screened to evaluate performance in reducing the crude oil pour point. Product development was then further refined once a definitive correlation between chemical structure and performance for the specific waxy crude oil was identified. Subsequently, more detailed laboratory testings were performed, including rheology measurements, coaxial shearing paraffin deposition and dynamic wax flow loop measurements. Field trial was later conducted to gradually obtain the optimum dosage while closely monitoring both onsite and in the lab to confirm the product effectiveness. Key to the success of the change was the identification of the opportunity to switch the PPD injection from subsea to topsides. This decision enabled a much wider portfolio of PPD chemistries to be evaluated. New topside PPD was identified which was able to reduce the pour point of the crude oil from 18°C to 9°C using a low dose rate of ~100 ppm, which is a ~40% reduction in chemical consumption compared to the previous chemical used. The new chemical was piloted without any disruption to the facilities and/or production. Furthermore, the field trial created significant benefits by reducing OPEX through the reduction in waxy pigging debris and chemical logistics, improving HSE and reducing the risk of chemical non-deliverability due to umbilical blockages. This paper demonstrates the re-evaluation of a field’s flow assurance strategy to realize significant benefits by challenging conventional wisdom regarding the need for subsea PPD/WI injection in waxy deep water fields. Understanding the gel strength of the crude through detailed evaluation and monitoring of the shear force needed to break the gel during a shutdown by using an optimized PPD/WI product/dosage is an important parameter to look at to ensure effective field optimization, rather than relying on the standard method of pour point monitoring.
Hydrate blockage had caused impeded flow in offshore pipelines and resulted production stoppage and significant economic loss. Hydrate blockages can occur very rapidly especially during winter conditions. The amount of inhibitor used need to be frequently revisited to ensure sufficient inhibition due to temperature change and other affecting parameters. The objective of this study is to provide an online monitoring of hydrate formation for four offshore pipelines to ensure sufficient mono-ethylene glycol (MEG) inhibition. It also provides an integrated operations monitoring that can be accessed anywhere and anytime. The system can provide early warning of hydrate formation to avoid blockage and production disruption. There are three parts in this study:-Part 1-Hydrate Prediction Model, Part 2-Integration with PETRONAS Integrated Operations platform and Part 3-Hydrate Monitoring and MEG Tracking. In Part 1, fluid composition for each pipeline was used to develop the hydrate curve. The minimum inhibition concentration model was built using mathematical curve fitting at maximum operating pressure under varying temperature. Another computational model was built to determine the MEG injection rates based on various parameters such as water cut, lean MEG concentration and safety margin. The model was then integrated with both real-time and sporadic data and run on predetermined schedule on the Integrated Operations (IO) platform. Part 2 ensures the critical parameters are linked to the hydrate prediction model and provide results such as hydrate operating condition, minimum inhibitor concentration requirement and MEG injection rates. In Part 3, real-time hydrate monitoring has to be readily accessible to everyone via a mobile compatible web interface. Actual MEG concentration vs minimum MEG concentration is analyzed to represent adequacy of current MEG injection rates. Further analysis can be done to predict the MEG recovery plan by tracking MEG inventory. The online hydrate monitoring is frequently used by offshore operations in their daily meetings. The system assists in advising the amount of MEG injection rates and ensure sufficient inhibition for all of the pipelines. From available trending, operator can optimize the MEG rates based on current operating temperature, pressure, watercut and relevant parameters. This online monitoring is useful to avoid re-occurrence of hydrate blockage in the pipelines and to optimize MEG usage. There are many hydrate inhibition technologies in existence, but this is the first in the world of its kind which is simple, innovative and inexpensive method to monitor the pipeline from entering hydrate region in real-time, which can be conveniently accessed anytime and anywhere. Not only the system had prevented production loss in millions of dollars, it also saved operating cost of MEG which may cost operations several million dollars.
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