Northern California Gas Sands: Hydraulic Fracture Stimulation Opportunities and Challenges
- Nabil Abdalla El Shaari (BJ Services Company) | William Alan Minner (Pinnacle Technologies)
- Document ID
- Society of Petroleum Engineers
- SPE Western Regional and Pacific Section AAPG Joint Meeting, 29 March-4 April, Bakersfield, California, USA
- Publication Date
- Document Type
- Conference Paper
- 2008. Society of Petroleum Engineers
- 5.4.10 Microbial Methods, 1.6 Drilling Operations, 3 Production and Well Operations, 5.9.2 Geothermal Resources, 5.5.8 History Matching, 2 Well Completion, 4.6 Natural Gas, 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 1.2 Wellbore Design, 5.1.1 Exploration, Development, Structural Geology, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.4.2 Gas Injection Methods, 1.8 Formation Damage, 1.2.3 Rock properties, 2.2.2 Perforating, 5.6.8 Well Performance Monitoring, Inflow Performance, 4.3.4 Scale, 2.5.1 Fracture design and containment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.6.1 Open hole/cased hole log analysis, 5.3.2 Multiphase Flow, 2.4.3 Sand/Solids Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.1.5 Processing Equipment
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Hydraulic fracturing is a stimulation technique successfully applied in formations throughout the world to increase production rates and enhance hydrocarbon recovery. The process involves creating a crack by pumping fluids at pressures above formation fracturing pressures, and then filling the crack with proppant to create a high conductivity connection to a large formation area. Hydraulic fracturing stimulates production by overcoming restrictions imposed by formation permeability, drilling and completion damage, production-induced damage and, an incomplete reservoir connection across laminated intervals. The process has been applied to a large scale in many Central and Southern California fields to enable economic development and reasonable hydrocarbon recovery. Example formations include the Belridge Diatomite, Stevens Sands, Etchegoin, Antelope shale, McLure shale, McDonald shale, Point of Rocks sands, Kreyenhagen shale, Ranger sands, the UP Ford shale, and the Monterey shale. Despite the routine application of fracturing in many fields, there has been very little fracturing experience in the gas-producing formations of Northern California. Example formations such as the Martinez, Forbes, Winters, and the K-1 are generally laminated sand intervals with low to moderate permeability (less than 1 mD and up to 10 mD), that are easily damaged by completion and production operations. Despite the hydraulic fracturing potential for stimulating production rates, improving gas recovery, and increasing reserves by extending the economic development area, it has been only sparingly employed. General formation properties are reviewed - what are the implications for hydraulic fracture potential, treatment design and placement challenges? Several treatments are reviewed to provide examples of fracture treatment behavior and response. Based on the initial experience and formation properties, it is believed that hydraulic fracturing has a significant potential in many Northern California gas reservoirs.
Conventional development of Northern California gas fields has been for the most part limited to non-stimulated vertical well drilling of intervals with low to moderate permeability and highly laminated beds. The nature of the formations and the geology of the basin lend itself to realizing greater recovery potential with the use of fracturing stimulation technique. Hydraulic fracturing is believed to have a significant positive impact potential - it can provide production acceleration from conventional reservoirs, and add new reserves from unconventional or problematic intervals. It would also provide similar benefits from interval damage by drilling, completion, and production operations.
The flow and reservoir deliverability potential as described by Darcy's law (shown below for radial gas flow using average reservoir pressure) is directly proportional to reservoir properties such as formation permeability, zone height, reservoir pressure and pressure drawdown. On the inverse side, production rates and reserve recovery can be limited due to the presence of skin acting as a choke to the full production potential and limited reservoir drainage area.
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