The first known multi-stage hydraulic fracture stimulation of a well utilizing equipment completely self-contained on a floating drilling rig was successfully performed in the Angsi field approximately 170 km off the east coast of Peninsular Malaysia. Three low permeability gas sands were fractured on Esso's Angsi-4 appraisal well to obtain quantitative productivity improvement data required for development planning.
Four multi-stage frac treatments of 37,000 pounds of proppant in approximately 14,000 gallons of fluid were pumped from the deck of the semi submersible rig Hunter utilizing a batch mixing configuration. Overall results of the fracture stimulations were very positive, yielding a fourfold increase in productivity over pre-frac production rates. While well performance was better than anticipated, several technical, logistical and "first time" operational challenges were confronted. Through detailed planning, equipment modification, and enhanced operating procedures, these challenges were overcome.
Relatively small propped fracture stimulations performed during exploration/appraisal from a floating drilling rig are a technically viable and economic way to obtain critical information required to fully evaluate marginal or uncertain development scenarios in the presence of tight reservoirs. This case study focuses on the operational aspects of the frac jobs while emphasizing technical and operational planning, execution and limitations experienced.
The Angsi field is a northwest-southeast trending compressional anticline located approximately 170 km ENE of Kerteh, Malaysia (Fig. 1) in a water depth of 70 m. The Angsi-1 discovery well was drilled in 1974 with three additional delineation/appraisal wells drilled during 1995. Wells have encountered up to 32 hydrocarbon bearing zones in the Groups I, J, K, L and M reservoirs.
Production tests performed on Angsi-2 revealed very low permeability (<0.01-3.0 md) in the Groups K, L and M gas reservoirs. Gas production rates ranged from <40 KSCFD in Groups L and M to 3.4 MSCFD in Group K with as high as 3,000 psi drawdown at the wellbore, and a skin factor of 13.9 was observed. The large skin factor is believed to be primarily the result of near wellbore retrograde gas condensation, due to the high pressure drop at the wellbore. The accumulation of condensate in the near wellbore region of the reservoir reduces relative permeability and gas mobility.
Low productivity and high skin observed during Angsi-2 well tests led to a series of propped hydraulic fracture treatments on Angsi-4 to evaluate productivity improvement.
The objectives of the fracture stimulations were threefold. First, there was a need to more clearly define productivity improvement potential from a fracture stimulation. This data would be used for calibration of reservoir simulation models used in the evaluation of various development scenarios. Second, low permeability had limited the radius of investigation on previous well tests. A fracture would allow greater depth of investigation to better evaluate bulk reservoir properties. The final objective was to perform the frac treatments at the minimum cost possible while providing the required information and ensuring data integrity.