Fracture Stimulation Increases Production in Challenging North African Completions

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215705, “Increasing Production and Reserves Through Fracture Stimulation in Challenging, Multizone, Vertical Well Completions,” by Andrew Boucher, SPE, Josef R. Shaoul, SPE, and Inna Tkachuk, SPE, Fenix Consulting Delft, et al. The paper has not been peer reviewed. The complete paper presents a case study of a North African oil field scattered with wells that did not initially require fracture stimulation for economic production but now could benefit from hydraulic fracturing. Many of these wells are producing from multiple perforated intervals through completions with production tubing that were not designed for fracturing and cannot be worked over. The field is producing from two Ordovician sands, one with a higher permeability (5 md) and one with a much lower permeability (0.5 md). Significant benefit was achieved by fracture stimulating one or both intervals in two wells, despite completion and operational limitations. For the field of interest, the operator drilled and completed two exploration wells on its concession in 2015, targeting multiple reservoir layers. Both wells successfully flowed hydrocarbons from the Ordovician Atchane and Jeffara intervals. Initial petrophysical analysis results indicated that Well 2 had more net height and better reservoir quality than Well 1 and that the Atchane reservoir is of better quality than the Jeffara reservoir because it contains approximately 80% of the permeability thickness (kh). Atchane holds more of the total reserves. A field-development plan and reservoir model were prepared. The reservoir model indicated that the two drilled wells were located adequately to allow good recovery of the field reserves, so these wells were temporarily suspended by loading with heavy calcium bromide (CaBr2) brine while tie-in to surface production facilities could be completed. The reservoir contains very light, volatile oil with a high gas/oil ratio. The reservoir was initially overpressured, with an initial reservoir pressure of 8,800 psi, which is a reservoir pressure gradient of 0.725 psi/ft. However, significant and uneven depletion was experienced before any fracturing operations. Once the two wells were tied in and brought back online, production was lower than expected. One or more of the open intervals in both wells were identified as being damaged or poorly connected to the wellbore. Hydraulic fracturing was identified as a technique that could improve well productivity. The operator did not have significant experience with fracturing, so a qualified team was assembled to evaluate the situation while considering strict regulatory criteria. First, the current completions could not be changed. In general, both wells had two long perforation intervals producing in a large, cemented liner with an upper completion consisting of small tubing and at least one packer. Standard approaches to multistage fracturing and zonal isolation were limited. Second, the maximum pressure limitation while pumping was limited by the completion. Finally, the domestic Ministry of Oil and Gas originally had placed very strict criteria on any fracturing treatments, stating that these had to stay completely contained within a single defined reservoir section and that only one treatment, or injection sequence, could be executed on each well. The complete paper provides detailed case studies for each well. In this synopsis, the case study for Well 1 is summarized.