An acid stimulation was performed in an ultra-deepwater pre-salt Brazil well to improve its productivity. The formation of hydrate plugs was a critical concern, as the stimulation requires water injection to neutralize the acid, and this well has a high GOR. Even with a risk of hydrate formation, acid stimulation is proven to be effective in recovering the production potential. However, experience with gas wells is still in the learning process with low best practices reported in the literature. The intention of this paper is to present a case history and the lessons learned during an acid stimulation in a high GOR well, in which the gas production was greater than anticipated leading to the formation of a massive hydrate plug, noted while the coiled tubing was being pulled and became stuck.
The hydrate risk analysis and the steps taken to release the coiled tubing will be presented, and the discussion will include the following:
Hydrate risk analysis from the acid stimulation program: as the subsea valves remain locked open during the rig operation, gas continuously migrates from the reservoir into the well leading to a high risk of hydrate formation during the water injection steps, requiring a bullhead with base oil to mitigate this risk. Also, a detailed evaluation of the risk of hydrate formation during the well startup will be discussed, as the high volume of water injected to neutralize the acid requires artificial lift to produce this effluent, in the case the only option was gas lift, the combination of high BSW% effluent and gas lift leads to a high risk of hydrate formation.
Troubleshooting to dissociate the hydrate: After the hydrate identification some attempts to dissociate were taken, the effective one being a gas flush from the FPSO to the Rig, injecting gas to the well through the service line to lift the drilling fluid from the work over riser to the Rig, therefore reducing the pressure until being outside of the hydrate stable zone, making possible to pull the coil tubing in an inhibited liquid environment, in the case MEG 50%, to avoid hydrate reassociation.
The figure below illustrates the steps of hydrate risk assessment during well startup: i) above 10% BSW the fluid temperature puts the subsea system inside the hydrate formation zone; ii) the evaluation of the best suitable thermodynamic hydrate inhibitor available to avoid hydrate reassociation and to move the system to outside the hydrate formation zone; iii) the gas flush to move outside of the stable hydrate formation zone at sea level depth, showing that the option was valid to dissociate a hydrate formed at this depth.
This case history discusses an acid stimulation in a high GOR well, in ultra-deep water, offshore Brazil. The lessons learned in this operation will be discussed to propose a structured guideline for hydrate mitigation during acid stimulation jobs in high GOR wells, from the risk analysis before the operation until the well restart, including hydrate dissociation options.