Gas Flow Blockage Treatment in Shale Gas: Case Study of Qusaiba Hot Shale, Saudi Arabia

Abdulrahman A. AlQuraishi, Abdullah O. AlMansour (), Khalid A. AlAwfi, Faisal A. Alonaizi, Hamdan Q. AlYami and Ali M. AlGhamdi Ali
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Abdulrahman A. AlQuraishi: Mining and Hydrocarbon Technology Institute, King Abdulaziz City for Science and Technology, Riyadh 11442, Saudi Arabia
Abdullah O. AlMansour: Mining and Hydrocarbon Technology Institute, King Abdulaziz City for Science and Technology, Riyadh 11442, Saudi Arabia
Khalid A. AlAwfi: Department of Petroleum and Natural Gas Engineering, College of Engineering, King Saud University, Riyadh 11362, Saudi Arabia
Faisal A. Alonaizi: Mining and Hydrocarbon Technology Institute, King Abdulaziz City for Science and Technology, Riyadh 11442, Saudi Arabia
Hamdan Q. AlYami: Mining and Hydrocarbon Technology Institute, King Abdulaziz City for Science and Technology, Riyadh 11442, Saudi Arabia
Ali M. AlGhamdi Ali: Department of Petroleum and Natural Gas Engineering, College of Engineering, King Saud University, Riyadh 11362, Saudi Arabia

Energies, 2024, vol. 17, issue 20, 1-13

Abstract: Organic-rich hot Qusaiba shale is the primary source rock of most of the Paleozoic hydrocarbon reservoirs of eastern and central Arabia. Representative near-surface Qusaiba shale samples were collected and characterized from one of its outcrop sections at the Tayma quadrangle in northwest Saudi Arabia. The petrophysical and geochemical characterization indicated porosity and permeability of 8.2% and 2.05 nD, respectively, with good total organic carbon (TOC) of 2.2 mg/g and mature kerogen of gas-prone type III. The tight characteristics of the formation can lead to high capillary pressure and extensive post-fracking water retention, leading to flow blockage and a reduction in gas productivity. Three different surfactants and one ionic liquid, namely, Triton X-100, Triton X-405 and Zonyle FSO surfactants and Ammoeng 102 ionic liquid, were tested as additives to fracking fluid to investigate their effectiveness in optimizing its performance. The chemical solutions exhibited no sign of instability when exposed to solution salinity and temperatures up to 70 °C. The investigated chemicals’ performance was examined by measuring methane/chemical solutions’ surface tension and their ability to alter shale’s wettability. The results indicate that Zonyl FSO is the most effective chemical, as it is able to significantly reduce surface tension and, hence, capillary pressure by 66% when added at critical micelle concentration (CMC). Using Zonyl FSO surfactant at a maximum tested concentration of 0.2% induced a relatively smaller capillary pressure drop (54%) due to the drastic drop in the contact angle rendering shale very strongly water-wet. Such a drop in capillary pressure can lower the fracking fluid invasion depth and therefore ease the liquid blockage removal during the flowback stage, enhancing gas recovery during the extended production stage. Triton X-100 at CMC was the second most effective surfactant and was able to induce a quite significant 47% drop in capillary pressure when added at the maximum tested concentration of 0.05%. This was sufficient to remove any liquid blockage but was less likely to alter the wettability of the shale. Based on the findings obtained, it is suggested to reduce the blockage tendency during the fracking process and elevate any existing blockage during the flowback stage by using Zonyl FSO at CMC where IFT is at its minimum with a higher contact angle.

Keywords: surfactant; gas flow blockage; shale gas; wettability; capillary pressure (search for similar items in EconPapers)
JEL-codes: Q Q0 Q4 Q40 Q41 Q42 Q43 Q47 Q48 Q49 (search for similar items in EconPapers)
Date: 2024
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