Lesson Learned: Fracturing Story Continues in Completely New Telisa Formation in B Structure South Sumatera

Abstrak

Telisa is a formation in South Sumatera Basin that was famous for its hydraulic fracturing success. In Pertamina, Telisa is found in TL Structure and was successfully treated with hydraulic fracturing. This year, Pertamina found Telisa as a new formation in B-Structure. It has the lowest net pressure yet highest fluid efficiency among other Telisas. Adding low permeability, low young modulus, and nonideal reservoir behavior to that list, fracturing this formation becomes quite challenging.

The first Telisa formation in B Structure was found in well B-62. The well can only produce intermittently in a space of two months. However, its water cut was as low as 50%. In order to produce the well continuously and increase its productivity, hydraulic fracturing treatment was planned. Since Telisa is considered soft rock with young modulus around 1 million psi, the treatment was designed to use 20/40 proppant to minimize embedment effect. According to petrophysical analysis this formation has 40 mD permeability, therefore treatment design was designed to be aggressive with fracture width as priority instead of halflength.

After performing breakdown, step rate test, and data frac, treatment was redesigned. It turned out that reservoir permeability is not as high as previously estimated. Transmissibility that was acquired from breakdown test data showed that permeability is less than 10 mD,  herefore the treatment was switched from aggressive to conservative with half-length as priority. Step down test, and was later confirmed by data frac, it can be inferred that this well has high entry friction at 1300 psi. Data frac also showed presence of fissures from decline curve with concave up shape. Fluid efficiency and pad ratio calculation was adjusted accordingly to handle this non-ideal reservoir behavior. Final design for fracturing treatment was with total of 65,000 lbs 20/40 proppant to target minimum 1.2 FCD, 0.3 inch fracture width, and 2 lbs/ft2 average proppant concentration. Pre-treatment of hundred mesh sand slug was pumped ahead of proppant slurry to reduce entry friction. During main frac job, sand slug failed to reduce entry friction Job was carried out to 6 ppg proppant concentration before loss prime on one of the frac pumps occurred and eventually screen out at the last proppant stage (7 ppg). Total proppant pumped into formation was 44,701 lbs.

Pumping 70% from designed proppant mass was not too bad, however opportunity for improvements was wide opened. There are three things to be considered for next treatments: perforate formation with highest entry hole size available and increase gel viscosity to handle excessive entry friction, pump more sand slug to deal with fissures, and improve pumping system reliability by installing filter to prevent unwanted solid during pumping and  erforming horse power test to the frac pumps.