Gas fields containing contaminants continue to not only challenge new field development projects, but also existing operations worldwide. Unforeseen variables such as increasing levels of contaminants from existing fields paired with increased sales gas demands, justifies the urgent need of identifying limits and pushing boundaries of existing facilities to handle the operation parameter changes. This study focuses on a debottlenecking study done for an existing operational facilities located at the Caspian Sea area, with an original inlet H2S design of 45 ppmv, to be processed down to < 3.5 ppmv. New sales gas demand requires for the existing facilities to process sour gas from reservoir having a maximum level of 580 ppmv H2S, at a higher continuous sales gas volume. Challenges to achieving this also includes uncertainties due to fluctuations of H2S levels from the reservoirs, with some variations going from <10 ppmv to 300 ppmv H2S coming out from the same well. Discussion will elaborate on challenges in meeting the new sales volume with expected increased in H2S levels from existing wells, and how limitations of existing facilities (Acid Gas Removal Unit, Acid Gas Incinerators and materials sour service compatibility) are addressed to produce a feasible operating envelope, with minimal changes to existing operating facilities. Actual operating data from approximately 5 years of operation was analyzed to determine the feasibility of the AGRU and Incinerator to handle higher H2S levels in feed. This is in anticipation of continuous feed gas volume of 500 MMscfd, at blended H2S levels of between 45 ppm to 162 ppm (worst case scenario). Existing facilities sour materials compatibility analysis are also done to determine the feasibility of the operating envelope. In the analysis, data from actual operating history and new production profiles are plotted against a feasible operating curve developed for the AGRU. The resultant graph gives an indication of the existing AGRU capability to manage incoming increase in gas volume and H2S levels. The analysis also evaluates the impact to the Incinerators, with new emission dispersion simulations done, to ensure operating curve complies with local environmental regulations on emission dispersion. The analyses conclude that the existing facilities is deemed adequate to handle new gas demand, with some curtailment on blended H2S levels to ensure only minimum changes and upgrades are required to existing facilities. The curves developed are hereby used as a reference for operations of the facilities in the future, whilst the methods applied here can be used as a reference for future sour facilities debottlenecking.

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.