From the Backyard Dune to Fracturing a Highly Tectonically Complex Formation in Saudi Arabia

Abstract

Sand in Saudi Arabia is easily accessible through surface mining or excavating large dunes that are API approved, but like many sands around the world, lacks the necessary strength for fracturing high stress formations. To exploit the sand, a novel engineered workflow, enabled by the flow channel fracturing technique was established for qualifying and implementing Saudi Arabian sand to fracture stimulate the tectonically complex ultra-tight "T" carbonate formation. Channel fracturing does not depend on the proppant pack to provide conductivity, rather on the creation of stable, open flow channels. Therefore, carefully selected sand that can keep the channel structure open under stress can be a viable material to replace up to 80% of the ceramic proppant materials. The local sand used was qualified through unique lab testing procedures to understand the pack behavior under stress, the pillar erosion under stress, and the effects of stress on long-term conductivity. Once qualified, a design methodology was applied to optimize the fracture geometry and pillar placement for the initial field test in Well-A, a horizontal lateral where high strength proppant (HSP) is traditionally used. A total of six channel fracturing stages with local sand — 40% of the total stages — were placed as per design in two sections of the 15-stage lateral along with four conventional and five channel fracture stages using HSP. A multi-month cleanup and well test period resulted in Well-A being one of the best producing wells in the basin — 26% higher initial production than the next best well. A production log showed sand stages to be producing an average of 15% higher total production than HSP stages. An oil tracer analysis revealed sand stages produced an average of 62% more condensate than HSP stages. This initial production response confirms at least par production with no detrimental effects for channel fracturing with local sand compared to techniques using HSP, with the potential for improved production. This qualified and field tested completion methodology allows for the potential replacement of a significant portion of imported ceramic proppant with locally sourced sand, an abundant and accessible resource inside the Kingdom of Saudi Arabia and beyond. The benefits of this technology include cost reduction, placement improvement, at least par production and the maximizing of in-country content and value.

The Effect of Hydraulic Fracture Geometry on Well Productivity in Shale Oil Plays with High Pore Pressure

“…Horizontal bedding planes, mechanically weak owing to little cohesion, may be stimulated in shale plays in transitional strike-slip to reverse faulting stress regimes, in which S v and S hmin are close in magnitudes and similar to the least principal stress (i.e., S hmin ∼S v ∼S 3 ). Such stress conditions have been reported in some unconventional source rock plays (e.g., the Marcellus Shale in southern West Virginia and the Tuwaiq Mountain formation in the Jafurah Basin, Saudi Arabia [27,38,39]).…”

“…Some mudrock plays are further characterized by high pore pressure and a small difference between the principal stresses. For example, the Jafurah basin exhibits pore pressure gradients between 0.016 and 0.020 MPa/m (∼0.7-0.88 psi/ft) [38,44], and strike-slip faulting stress regime (S hmin ∼0.96 psi/ft < S v ∼ 1.1 psi/ft < S Hmax ∼1.2 psi/ft) [38,44,82]. These environments combined with large fluid volume injection foster interactions between vertical hydraulic fractures and pre-existing discontinuities (e.g., natural fractures and bedding planes).…”

“…This last scenario may occur in shale plays characterized by severe overpressure and small differential stresses or by transitional strike-slip to reverse faulting stress regimes in which the least principal stress (S 3 ) is very close to the overburden (S v ). Such conditions are reported to exist, for example, in the Marcellus shale in southern West Virginia [27], and the Tuwaiq Mountain formation in the Jafurah Basin in Saudi Arabia [38,39]. The unique reservoir simulations discussed here enable us to understand the impact of varied hydraulic fracture and stimulated natural fracture geometries and bedding planes on hydrocarbon production.…”

“…Thus, the bubble point pressure is below the reservoir pressure. The shale reservoirs in the U.S. and Saudi Arabia report pore pressure gradients between 0.014 MPa/m and 0.020 MPa/m (∼0.6 psi/ft-0.9 psi/ft) [38,44,46]. Thus, our study considers an overpressured reservoir with a reservoir fluid pressure gradient of 0.0195 MPa/m (∼0.85 psi/ft).…”