The basal clastic sand (BCS) unit is derived from a granitic basement and forms the lower part of the Mumbai High field. Oil indicators in unconventional reservoirs, such as basement and BCS, were explored here before 1987; however, these reservoirs were not targeted for more than two decades after drilling the first exploratory well in 1989. Huge potential in BCS resources remained untapped, and monetizing these resources became possible because of extensive hydraulic fracturing design optimization for these layers.
Previously, acid stimulation treatment failed to provide any improvement in the BCS reservoir. Because BCS is derived from a granitic basement and contains clay minerals (kaolinite and chlorite), heavy minerals, siderite, pyrite, hematite, etc., it is difficult to obtain gains using acid stimulation because of poor leakoff and associated reaction kinetics. However, stimulation using hydraulic fracturing with proppants proves to be the ultimate productivity enhancement tool and is the prudent alternative.
The first hydraulic fracturing attempt in BCS was performed at Well B in 2013 and was unsuccessful because proppant placement and admittance are extremely difficult in these layers. High net pressure and complex branch growth were identified to be the core causes of premature screenout in this layer. Post-treatment pressure evaluation indicated propagation of short fissures and fractures leading to a complex fracture plane that reduced overall fracture conductivity.
Subsequently, Well A was diverted from the original location, completed in the BCS reservoir, and selected as a candidate for proppant fracturing. The stimulation strategy was designed to meet stimulation challenges of the BCS formation. Perforation designs were revised to reduce near-wellbore tortuosity and perforation friction. After perforating, the well was treated with an acetic acid cushion against the target zone. A new fracturing treatment design based on slug and sweep, where the slug stages were increased, was used to control excessive near-wellbore complex fracture growth. Aggressive pumping rates and high conductivity proppant size and concentration were designed to help increase stimulation efficiency. These unconventional modifications aided successful placement of the fracture plane in the BCS reservoir in Well A.
Well A initially produced 202 BOPD; however, production declined because of the tight nature of the BCS reservoir. Later, the well produced 100 BOPD with gas lift. After hydraulic fracturing treatment for this well was successfully performed, as per the modified design, the production increased to 1,580 BLPD with 100% oil and no artificial lift using a 1/2-in. choke. This paper highlights design considerations, execution results, and post-treatment evaluation of this extremely challenging BCS volcanic rock and can be viewed as a best practice for addressing stimulation challenges in similar volcanic reservoirs in other fields.