Excessive fluid loss in productive zones

Pemex’s Samaria 6117 well in southern Mexico is in a naturally fractured reservoir with an average temperature of 279 degF [137 degC). It was drilled to 15,150 ft [4,618 m] with oil-base mud as the drilling fluid.

Excessive drilling fluid losses were reported to be 70 m3 [440 bbl] in the productive zones. This fluid loss could cause formation damage from solids bridging and emulsions due to fluid incompatibilities. Pemex expected oil production in this area to be 800 bbl/d [127 m3] based on offset well production and petrophysical property analysis.

Matrix stimulation proposal for well optimization

Schlumberger used the PowerSTIM well optimization service to generate a stimulation proposal that considered reservoir knowledge, fluid selection, treatment design, execution, and evaluation. The model predicted that the lost drilling fluid had invaded the critical matrix and plugged the fracture system, reducing well productivity. This prediction was supported by a laboratory compatibility test for the drilling cuttings, oil sample, and stimulation fluids.

The proposal outlined two stages:

1. Nonreactive fluid CLEAN SWEEP solvent systems for damage removal to disperse emulsions and clean drilling mud from the rock
2. Reactive fluids including

• retarded SXE acid to achieve greater penetration into the formation and to bypass the damage
• MSR 100 mud and silt remover (15%) to complement the retarded system
• two SDA self-diverting acid slugs to improve fluid placement along the entire perforated interval

SXE acid is a viscous, highly retarded, concentrated acid system (70% HCl, 30% oil), stabilized with an emulsifier. Because it can penetrate farther into the formation than any live acid, SXE acid was used for deep penetration. The dissolving power of the HCl-base SXE acid system, coupled with slower carbonate reaction time, creates deeper wormholes and makes the emulsion less corrosive to steel casing and tubing.

Production increased by 162%

The SXE acid treatment delivered a 162% production increase over expected production (2,100 bbl/d versus 800 bbl/d [334 m3/d versus 127 m3/d]) of oil. Pemex will use this treatment in wells with similar temperature conditions.