From the Backyard Dune to Fracturing a Highly Tectonically Complex Formation in Saudi Arabia
- K. M. Bartko (Saudi Aramco) | I. H Arnaout (Saudi Aramco) | K. S. Asiri (Saudi Aramco) | K. M. McClelland (Saudi Aramco) | N. I. Mulhim (Saudi Aramco) | R. Tineo (Schlumberger Saudi Arabia) | M. N. Gurmen (Schlumberger Saudi Arabia) | Z. Al-Jalal (Schlumberger Saudi Arabia) | D. Pantsurkin (NTC Schlumberger) | D. Y. Emelyanov (NTC Schlumberger)
- Document ID
- Society of Petroleum Engineers
- SPE Hydraulic Fracturing Technology Conference and Exhibition, 24–26 January, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2017. Society of Petroleum Engineers
- 3.1.3 Hydraulic and Jet Pumps, 1.6 Drilling Operations, 2.5.2 Fracturing Materials (Fluids, Proppant), 2 Well completion, 5.6.4 Drillstem/Well Testing, 2.4 Hydraulic Fracturing, 5.6.5 Tracers, 3.3.1 Production Logging, 5 Reservoir Desciption & Dynamics, 3.3 Well & Reservoir Surveillance and Monitoring, 3.1 Artificial Lift Systems, 5.6 Formation Evaluation & Management, 3 Production and Well Operations, 1.6.6 Directional Drilling
- Proppant, Production enhancement, Conductivity, Fracturing
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- 489 since 2007
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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.
|File Size||2 MB||Number of Pages||18|
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