Extreme Multistage Fracturing Improves Vertical Coverage and Well Performance in the Lost Hills Field
- Kieth A. Hejl (Chevron North America Exploration and Production Co.) | Angela M. Madding (Chevron North America Exploration and Production Co.) | Micheal Morea (Chevron North America Exploration and Production Co.) | Carl W. Glatz (Halliburton Energy Services Group) | Jose B. Luna (Halliburton Energy Services Group) | William A. Minner (Pinnacle Technologies) | Gregory R. Stanley (Pinnacle Technologies) | Tony Singh (Pinnacle Technologies)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- December 2007
- Document Type
- Journal Paper
- 326 - 333
- 2007. Society of Petroleum Engineers
- 1.6 Drilling Operations, 3.3 Well & Reservoir Surveillance and Monitoring, 2.2.2 Perforating, 2.5.2 Fracturing Materials (Fluids, Proppant), 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.5.1 Fracture design and containment, 3 Production and Well Operations, 2.4.3 Sand/Solids Control, 2.5.4 Multistage Fracturing, 5.2.1 Phase Behavior and PVT Measurements, 5.4.1 Waterflooding, 4.1.2 Separation and Treating
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In an attempt to improve production response, fracturing designs in the Lost Hills field went from a standard three- to six-stage design to an extreme 15- to 18-stage design to stimulate approximately 1,000 ft of net pay. The previous standard designs were becoming borderline economic, and if development was to continue, then either production response had to improve or costs had to be reduced. Previous emphasis was placed on reducing fracture-treatment costs by pumping fewer stages and lower proppant volumes, but the cumulative production response decreased as a result. Previous tests using an increased number of fracture stages did not improve economics because of the increased fracturing costs and minimal production increases. When a new coiled-tubing fracturing technique was implemented to perform multistage jobs at reduced costs and the stage count per well was increased, production response and economics improved. This paper will discuss the differences in job execution, analysis of vertical fracture coverage using surface and downhole tiltmeter data, and cumulative production response from the different designs tested. Both treatment and stage design with this fracturing technique are being refined further as the performance and statistical analysis of previous design changes are completed.
A large part of California's oil production occurs in several San Joaquin Valley giant fields that have heavy oil or low permeability. These fields remain highly oil saturated (several have more than 1 billion bbl of remaining oil in place), even though they were discovered and initially developed in the early 1900s. Thermal enhanced oil recovery (EOR), waterflooding, and/or hydraulic-fracturing techniques are now applied to these fields.
Lost Hills is one such field; it was discovered in 1910, remains largely undepleted, and is currently near all-time high production rates because of a combination of hydraulic fracturing and waterflooding. Beginning in the late 1980s, improvements in hydraulic-fracturing design and implementation yielded results that justified an aggressive diatomite primary-development-well program on 2½-acre producer spacing (Wilt and Morea 2004). Waterflooding began in the early 1990s to reduce well failures caused by subsidence and to improve recovery. The 2½-acre development program was completed in 1997, drilling approximately 60 wells per year. Beginning in 1998, infilling began to reduce production well spacing to 1¼ acres in the waterflooded area, and this program continued until it was completed in 2004. In 2001, a 5/8-acre infill pilot was installed, with the pilot being expanded in 2004 because of the encouraging initial results. In 2003, a large waterflood expansion began northward at an accelerated pace, with more than 100 wells being drilled each year until 2005, when more than 200 wells were drilled to complete the north waterflood expansion at 1¼-acre producer spacing.
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