Hydraulic Fracture Optimization Maintains Original Production Rates in New Wells in a Mature Gas/Condensate Reservoir in Oman.

Abstract

Abstract Hydraulic fracturing has been an integral part of the development of two gas/condensate fields in central Oman. These fields supply an LNG plant on the coast at Sur. The producing reservoir is 160–190 meters thick and highly laminated, so fracture height growth and vertical coverage are key issues. There are significant variations in permeability and depletion (following several years of production) between the individual reservoir units. There has been an evolution in the fracturing strategy in terms of the number of treatments pumped per well (going initially from 1 to 5 fractures), the size of proppant used (12/20, 16/30, 20/40) and the size of the pad volume (75 – 350 m3) [Ref. 1]. A new initiative was taken recently to further optimize the fracturing procedures, following up on the results of a comprehensive analysis of several years of treatments [Ref. 2]. In order to mitigate fracture complexity resulting in very high net pressures, pumping rates were lowered from 8 m3/min, down to as low as 2 m3/min. in some cases. To reduce screenouts in the most difficult reservoir zones, 40/70 ceramic proppant was pumped ahead of 20/40 mesh as a proppant slug in most of the jobs. Because of the significant fracture height containment due to the heterolith layers, the practice of trying to stimulate multiple geological units with one fracture treatment was abandoned in favor of stimulating each individual unit separately. This has led to as many as 11 fracture treatments per well. Based on the previous study, which showed that screenouts were not related to pad size and that the initial slurry stages would also create sufficient fracture dimensions, the pad volumes were decreased, leading to improved fracture conductivity. Using smaller pad volumes and a lower pumping rate have reduced complex fracture growth, reducing the number of near-wellbore screenouts as well as net fracturing pressures. Since the fracture stays contained within the reservoir sub-unit, good fracture half-lengths are produced with small pad volumes. All of these measures have had a positive impact on the post-frac productivity of the newly treated wells, obtaining production rates equal to some of the best initial wells, despite the large amount of depletion in the field. In addition, many of the changes in fracturing strategy have also reduced the cost of fracturing operations, leading to a significant increase in Return On Investment for fracturing expenditures. These results are of interest to anyone working with a thick, laminated formation needing hydraulic fracture stimulation. Introduction Reservoir Description The Barik sandstone reservoir is a thick (160–190 meters) and highly laminated formation, which is at a depth of 4300 meters in the Saih Rawl field. The reservoir has been divided up into 8 units, based on the location of the heteroliths, which are more shaly, have a higher closure stress, and tend to increase in thickness with depth in the reservoir. Thus, the thickest heteroliths are those surrounding the deepest unit (8). The heteroliths are correlated over the entire field and act as flow barriers between the different units. The reservoir is being produced from two fields, Saih Rawl and Barik. In the Saih Rawl field, where all the study wells are located, the reservoir is thicker and deeper. The initial reservoir pressure in the Saih Rawl field was 513 bar, with a reservoir temperature of 135 deg C. The dew point pressure is 424 bar, and the initial condensate to gas ratio (CGR) was approximately 450 sm3/million Sm3 [Ref. 3]. The Barik reservoir lies above another deeper sandstone reservoir called Miqrat. During the last few years the Miqrat reservoir has been produced commingled with the Barik reservoir. The Miqrat sandstone reservoir, 200 m thick lies at an average depth of 5100m, and has thinner shaly layers that do not constitute strong stress barriers as in the Barik. The Miqrat reservoir has a progressive deterioration of reservoir quality with increasing depth.