Water-based fluids are used for drilling most of vertical and horizontal wells in carbonate reservoirs in Saudi Arabia. Even in moderate and lower permeability formations, drilling solids can invade the formation and cause fines plugging. An XC-polymer based drilling fluid, containing sized calcium carbonate particles (marble), is used to limit the amount of fluids lost to the formation during the drilling operations. However, near wellbore damage was evident from field tests conducted on several vertical wells. High skin factors (+2 to +4) following drilling indicated severe well damage and decreased production potential. The only solutions are drilling additional wells to increase production capacity, or stimulation of existing damaged wells. A stimulation procedure was needed to mitigate the problem.
Traditional stimulation efforts in carbonate reservoirs are conducted using regular HCl acid. Rock mechanical studies have indicated wellbore stability after drilling, and rock strength are concerns in the subject formations. It was suspected that an attempt at normal HCl acid matrix stimulation would result in surface washout and enlargement of the wellbore. This is especially true in low permeability (less than 30 mD), fine grain carbonates. This could exacerbate borehole stability problems.
Emulsified acids have been shown to induce deep wormholes in carbonates. These wormholes will serve the same function as perforations to by-pass the drilling damage, yet maintain the integrity of the formation. An emulsified 15 wt. percent HCl - diesel mixture (at 70:30 volume ratio) was evaluated as a portion of an ongoing study of the effects of acid stimulation in carbonate reservoirs.
Currently, there are few accurate methods of laboratory evaluation of this type of stimulation fluid, and scale up-factors are nebulous at best. Traditional tables for matrix type stimulation are inaccurate, and result in excessive acid volumes. Acidizing with large acid volumes is not recommended because of the weak nature of the rock in some fields.
This paper demonstrates a new laboratory core test procedure and provides a novel interpretation of scale-up equations developed for the study. The resulting laboratory data are compared to field results, and show:
1. The test procedure accurately simulates the damaged seen in the formation.
2. The acid can effectively stimulate the formation, while preserving the formation integrity.
3. The acid penetration and “worm-hole wander” can be controlled by monitoring acid injection rate and volume.
4. The scale-up volume equations to be accurate for emulsified acid treatments.