Production Strategy of a Tight Gas Carbonate Reservoir in Pakistan

Abstract

Appraisal and development of tight gas discoveries in Pakistan is a longstanding yet unsettled challenge to local oil and gas E&P industry. Major challenges include but not limited to marginal gas in-place volumes, sustainability of production rates, lengthy cleanup period, significantly higher capital costs due to imported technologies and services, less volume of work, lower competition among the service providers, lower quality gas, lower recovery factors due to tightness and water production, complex reservoir geology and petrophyics. Several such technical discoveries are being made by local and multinational E&P companies time to time but due to one or the other mentioned challenges such discoveries are presumed to be non-commercial and left unexploited. This paper shares a case study of a real tight gas carbonate reservoir located in Middle Indus Basin of Pakistan which may help the E&P professionals’ kick-off the thought process to understand such discoveries and adopt new strategies to bring them on production. The well Naushahro Feroze X-1 (NF X-1) was drilled as an exploratory well to target Chiltan Carbonate Reservoir in the Naushahro Feroz block in Sindh, Pakistan. A tight gas discovery was made in the Chiltan formation based on the well logs and testing results. It was concluded as naturally fractured carbonate reservoir (NFR) and classified as Type-II NFR, Nelson (2001)1 i.e., mainly fractures provide essential flow capacity. Reservoir evaluation indicated reservoir is over pressured and its permeability is in micro Darcies. Subsequent horizontal appraisal well i.e., NF Hor-1(RE) drilled with a lateral section of ~1300 meters. The well was completed with an open-hole-multistage string and ten stages were selectively acid stimulated, acid fractured and hydraulically fractured to establish the sustainable commercial gas rates. The performance of both the exploration and appraisal wells exhibited typical production behavior of tight gas wells with continuous decline in gas rate and wellhead flowing pressures, however, the appraisal well proved to be better in terms of production due to better drilling, completion and stimulation strategy. Sustainable production rate in the appraisal well could not be established due to extremely tight nature of the matrix and water production from the deeper intervals. Surface separator multirate test was performed followed by an extended buildup period and the surface data was recorded. The data was then used to understand the reservoir behavior on short term and long-term basis using various analytical and numerical analysis techniques. A 3D Black Oil dual porosity model was developed for reservoir simulation and understanding the reservoir behavior. In the static model, the natural fractures were characterized using the seismic attributes across the Chiltan formation. The model was then initialized, and history matched using the available rock and fluid properties, multirate test and extended buildup data. After completing the analysis, an understanding was developed about the production strategies and well wise range of gas recoveries in such tight gas discoveries which has been shared in this paper.

Optimization of hydraulic fracturing treatment in tight sand reservoir of lower indus basin: an integrated approach

“…Tight reservoirs are usually developed using horizontal well and hydraulic fracturing techniques but have very low recoveries (Wang et al 2018). Sustainability of production rates is the key challenge among the various other challenges in developing a tight reservoir (Dahraj et al 2018). Following parameters are considered in designing a hydraulic fracture treatment: wellbore configuration, reservoir parameters, rock strength, reservoir stress distributions, porosity and permeability, injection rate and pump schedule and other critical operational parameters including size, number and location, phasing angle of perforations, fluid and proppant type (Salman 2015;Sharma et al 2019;Kolawole et al 2019).…”