Design Criteria and Application of High-Density Brine-Based Fracturing Fluid for Deepwater Frac Packs
- Xiaoping Qiu (Shell Oil Co.) | William Edward Martch | Lee N. Morgenthaler (Shell Exploration & Production) | Jerry Adams | Hiep Sy Vu (Shell Intl. E&P Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 4-7 October, New Orleans, Louisiana
- Publication Date
- Document Type
- Conference Paper
- 2009. Society of Petroleum Engineers
- 4.3.1 Hydrates, 5.4.10 Microbial Methods, 4.5 Offshore Facilities and Subsea Systems, 2.4.6 Frac and Pack, 2.2.2 Perforating, 1.6.1 Drilling Operation Management, 1.8 Formation Damage, 4.6 Natural Gas, 2.7.1 Completion Fluids, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.3.4 Scale, 4.1.2 Separation and Treating, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.2 Pipelines, Flowlines and Risers
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Completing deepwater Gulf of Mexico (GOM) wells with depths greater than 20,000 ft and high geopressure may require the use of higher-density fracturing fluids to reduce high wellhead treating pressures. In Shell's Deimos field, frac fluid density of up to 12.5 ppg was required. Although the industry has pumped 11.5 ppg NaBr-based borate cross-linked fracturing fluids, a 12.5 ppg NaBr-based borate cross-linked fracturing fluid has not been used until now. There are many challenges when applying a 12.5 ppg NaBr-based borate cross-linked fracturing fluid.
The 12.5 ppg NaBr high-density, brine-based fluid has significantly different rheological behaviors than typical fracturing fluids made with freshwater or low salt concentrations. The high-density, borate cross-linked fluid responds very differently to shear history and recovers much more slowly than does freshwater-based fluid. Breaker efficiency is also very different. The highdensity, brine-based fracturing fluid is potentially incompatible with formation crude. Base brine quality
was also critical to final fluid quality and quality control procedures had to be better defined.
Shell developed lab and field QA/QC protocols to ensure the fluid met the frac & pack job requirements. With rigorous fluid testing and optimizations, three wells
in the Deimos field were successfully completed in 2007.
This paper summarizes the extensive rheology, fluid compatibility, fluid optimization, and fluid QA/QC processes. It also summarizes important aspects in the application of 12.5 ppg NaBr-based fracturing fluids.
This paper will also discuss friction pressure, treatment pressure, actual frac & pack job performance, and postjob production data. The fracturing fluid design and test
methodology applied in these three Deimos wells are also very beneficial to design and optimization of other kinds of fracturing applications.
Deimos is a subsalt field located principally in Mississippi Canyon Blocks 806/807/762 in the Gulf of Mexico in 3,000 ft of water, approximately 1 mile west of the Mars
TLP. Deimos is located predominantly on the Mars operating unit (Shell 71.5%, BP 28.5%) as shown in Figure 1.
The bottomhole static temperature (BHST) ranges from 205°F to 220°F at perforation depths from about 22,000 ft to 26,000 ft MD. The pore pressure is greater than 16,000 psi, and the frac gradient was estimated to be greater than 0.88 psi/ft. The high pore pressure and long MD presented a challenge to pumping traditional frac & pack fluids. For a traditional frac fluid used in the GOM made of 3-7% KCl- or NaCl-based borate cross-linked fluid, the frictional pressure resulting from the long work string and the high pore pressure could result in high surface treating pressure exceeding the 15,000 psi pressure ratings of surface treating equipment and some wellhead components. In addition, high surface treating pressure may also cause the collapse of the bottomhole assembly (BHA).
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