Reservoir Drill-In Fluid Minimizes Fluid Invasion and Mitigates Differential Stuck Pipe with Improved Production Test Results
- Adel Al-Ansari (Saudi Aramco) | Carlos Parra (Saudi Aramco) | Abdullah Abahussain (Saudi Aramco) | Amr M. Abuhamed (Saudi Aramco) | Rafael Pino (Saudi Aramco) | Moustafa El Bialy (Halliburton) | HadjSadok Mohamed (Halliburton) | Carlos Lopez (Halliburton)
- Document ID
- Society of Petroleum Engineers
- SPE Middle East Oil & Gas Show and Conference, 6-9 March, Manama, Kingdom of Bahrain
- Publication Date
- Document Type
- Conference Paper
- 2017. Society of Petroleum Engineers
- 2.1.3 Completion Equipment, 5.1 Reservoir Characterisation, 3.2 Well Operations and Optimization, 5.1 Reservoir Characterisation, 2 Well completion, 1.8 Formation Damage, 1.11 Drilling Fluids and Materials, 3.2.7 Lifecycle Management and Planning, 2.2.3 Fluid Loss Control, 3 Production and Well Operations, 3 Production and Well Operations, 2.2 Installation and Completion Operations, 1.6 Drilling Operations, 3 Production and Well Operations
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A properly designed reservoir drilling fluid and precise control of its properties are essential to prevent formation damage issues that hamper production. An essential prerequisite for a reservoir drilling fluid are nondamaging specialty products and reduced fines and fluids invasion. This paper describes the case history of two deep gas wells in Saudi Arabia, one well showed impaired production due to screens plugging and was put on workover drilling operations whereas the other well was a regular development well. The offset data showed differential sticking, partial losses and tight spots while drilling the 8⅜ and 5⅞ in. hole sections.
The well reservoir data including the bottom hole-temperature – 300°F, permeability – roughly 10 to 20 micron pore throats and lithology – sandstone intercalated with shale, for the reservoir section were determined from offset analysis. Extensive lab testing was performed with nondamaging specialty and optimized PSD for minimized fine and fluids invasion. This engineered fluid was used to drill a 5⅞ in. vertical side track of ± 300 ft for the workover well whereas on the regular development well about ± 400 ft of the 5⅞ in. section was drilled. The fluid was continuously monitored for PSD at the rig along with the particle plugging test for fluid loss control. The hole cleaning and equivalent circulating density was monitored and programmed with a proprietary hydraulics software. All the fluid properties were determined to be within planned range. The wells were drilled without any of the offset problems as discussed above followed by running the 41/2 in. conventional sand screens to the bottom without any issue. Initial flowback production testing was performed on the workover well, which took 8 hours as compared to the usual 48 hours in the offset wells. The BS&W (basic sediment and water) from day 1 of production was 9% as compared to the 25% observed in the offset wells. The gas production rate was 200% more than was expected as per the offset information.
This paper shows the successful use of reservoir drill-in fluid on two gas wells: one was a workover well and another a regular well. The abstract presents a mutual approach between Halliburton and Saudi Aramco to address the issue of minimizing formation damage and mitigating differential sticking. Offset well data learnings, optimized PSD design, monitoring at the rig site, and the use of nondamaging specialty products delivered production optimization.
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El Bialy, M. 2011. Utilization of Non-Damaging Drilling Fluid Composed of Potassium Formate Brine and Manganese Tetra Oxide to Drill Sandstone Formation in Tight Gas Reservoir. Paper SPE/IADC 147983 presented at SPE/IADC Middle East Drilling Technology Conference and Exhibition, Muscat, Oman, 24–26 October.