Drilling Fluid Impact on Injectivity During Multistage Fracturing in Horizontal Wells
- Sultan Asel (Saudi Aramco) | Abdullah Al Moajil (Saudi Aramco) | Bader Al-Harbi (Saudi Aramco) | Sajjad Al Darweesh (Saudi Aramco)
- Document ID
- Society of Petroleum Engineers
- SPE Western Regional Meeting, 23-26 April, San Jose, California, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- impaired injectivity, Multistage Fracturing Completions, Barite, acid fracturing, Drilling fluid
- 15 in the last 30 days
- 104 since 2007
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Multistage Fracturing (MSF) completions have been extensively used as an economical intervention means to handle extreme downhole environment. To have adequate Injectivity during hydraulic fracturing (HF), sand face permeability should be exposed to minimum formation damage. Impaired injectivity is caused by a mechanical obstruction across wellbore, tight formations (low permeability) and high heterogeneity or invaded particulates by Drill-In-Fluid (DIF) that damaged the formation. Many causes were suspected such as formation heterogeneity, false indication of completion port opening, and damage to the sand face due to drilling filter cake. Solvent treatments, acid wash and tubular slotting are the most reasonable remedies to this issue, adding more cost to the operating company. The objective of this study is to present technical procedures and methodologies followed to investigate impaired injectivity associated with MSF completions. Results and recommendations provide remedial recipes and optimized drilling and production operating procedures. Therefore, realizing a significant cost saving for operating companies.
X-Ray Diffraction (XRD), X-Ray Fluorescence (XRF), and Environmental Scanning Electron Microscope (ESEM) techniques were used to analyze solid samples. HP/HT aging cells were used to conduct solubility testing of filter cake and typical barite/oil-based sludge sample. HP/HT filter press was used to study the effect of time on filter cake build-up at 300°F.
HCl acid showed low solubility for typical oil-based drilling fluid sludge at 310°F. Mutual solvents dissolved the sludge partially at 300°F (e.g. ~40wt% solubility). DTPA and EDTA-based chelating agents showed higher dissolution power compared to the HCl solutions. The addition of mutual solvent to the tested chemicals increased the solubility of the sludge. Among tested chemicals, 90 % DTPA and 5 % mutual solvent provided the higher solubility. High filtration rate was noticed during HP/HT filtration test. The thickness of the filter cake increased significantly as a consequence of filtration/soaking time (e.g., up to a week). Therefore, to avoid filter cake build up and the problems associated with that, the filter cake should be removed immediately after the drilling operations.
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