Should Deep Water Well Tubing be Dosed with Hydrate Inhibitor Post Shutdown?

Abstract Preservation of the subsea system and well tubing following a shutdown where the system is expected to cooldown to hydrate formation conditions is one of the activities that the Operations team carry out along with other troubleshooting activities when it comes to deep and medium-depth water developments. Such preservation usually includes injecting a thermodynamic hydrate inhibitor (THI) (e.g. methanol) to the areas where gas and water are both present together and the system has less heat content to stay outside hydrate zone until the next restart. Whilst preservation of the subsea production system such as jumpers and manifolds has been better defined the project development team in terms of No Touch Time (NTT) and Cooldown Time (CDT) definitions, preservation of the production and injection trees and tubings have been less defined in project phases, and hence the requirements such as inhibitor injection volume and timing are more often conservatively defined to avoid hydrate blockages. The well operating conditions, particularly GOR and WC, which may vary from design phase to operation and also over the life of the field is another reason for the design phase engineers not being able to fully specify the requirement for well tubing preservation post shutdown. Hence, in majority of developments, it is the Operations Support Team who will need to re-define the preservations requirement for each production and injection wellbore. This work has investigated the necessity of well tubing preservation for a large number of wells in a few deep water oil-producing assets which had been recommended by the design phase to be preserved with methanol within 48h of shutdown. The initial trigger for this study was the analytics of the KPI records which led to an investigation of the historical success rates of methanol injection into the well tubing within 48h of shutdown and lack of any field evidence for hydrate formation. The records were analyzed for the past 5 years of operation, and they showed that despite a poor success rate, none of the wells had any hydrate blockage issues upon restart. A commercial software with numerical engine was then used to model several wells under shutdown condition, the outcome of which showed that the 48h time limit for wellbore preservation was significantly conservative. The modelling work also revealed that not all production wellbores require preservation following a shutdown as phase segregation occurs inside the tubing causing free water phase to drain down into a warm section of the production tubing, which in majority of cases, is outside hydrate formation region (HFR). The phase segregation and location of the water-hydrocarbon interface was proven to be a strong function of GOR and WC. The well models were then run for a wide range of GORs and WCs to further determine this relationship. A GOR vs. WC graph was later devised for the Operations team to work out which well tubing would require treatment with methanol for a long-term shutdown. The strategy used for generating such graph and guidelines for Operations can be adopted for similar deep water production assets to avoid unnecessary methanol injections to production wells in the event of a shutdown. The water injection wells were also studied to identify the reasons and mechanism for hydrate blockage so that a new strategy could be developed for preservation of injection well tubing. The mechanism for potential hydrate in water injection wells was concluded to be due to gas (or hydrocarbon) migration into injection zone and then up the tubing when the well was shut in long enough for the water injection bottom-hole pressure to dissipate into the reservoir and hence allow the hydrocarbon migration to occur. It is noted that only injection wells that were completed in the reservoir formation were at the risk of hydrocarbon migration and needed preservation against hydrate blockage. Migration of hydrocarbon into a water injection tubing also depends on how close the water injection well is to a gas injector (if any) as gas can migrate and create a cross-communication channel to the water injection tubing if the water injector is left shut-in long-term compared to the nearby gas injector. Surely, such cross communication depends on the reservoir structure and the driving force for gas migration. Nonetheless, in the absence of a 4D seismic which can determine whether the nearby water and gas injectors are at the risk of hydrate blockage during a long-term shutdown, it is recommended to treat the water injection well tubing with hydrate inhibitors within a period specified based on BHP decay trends over time.