Case Studies: Optimizing Hydraulic Fracturing Performance in Northeastern Fractured Shale Formations
- Javad Paktinat (Universal Well Services Inc.) | Joseph Allen Pinkhouse (Universal Well Services Inc.) | Nicholas James Johnson (Universal Well Services Inc.) | Curtis Williams (Universal Well Services Inc.) | Gary G. Lash (Stony Brook U) | Glenn S. Penny (CESI Chemical) | David A. Goff (CESI Chemical)
- Document ID
- Society of Petroleum Engineers
- SPE Eastern Regional Meeting, 11-13 October, Canton, Ohio, USA
- Publication Date
- Document Type
- Conference Paper
- 2006. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 5.1.1 Exploration, Development, Structural Geology, 2 Well Completion, 2.7.1 Completion Fluids, 4.6 Natural Gas, 5.8.1 Tight Gas, 2.2.2 Perforating, 2.4.3 Sand/Solids Control, 2.4.6 Frac and Pack, 1.6 Drilling Operations, 5.1.5 Geologic Modeling, 3 Production and Well Operations, 1.6.9 Coring, Fishing, 5.1.2 Faults and Fracture Characterisation, 5.8.2 Shale Gas, 2.2.3 Fluid Loss Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.8 Formation Damage, 5.6.4 Drillstem/Well Testing, 1.8.5 Phase Trapping
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The primary purpose of stimulating fractured shale formations is to extend the drainage radius by creating a long fracture sand pack that connects natural fractures and increases flow channels to the wellbore. However, most of the fracturing pad fluid leaks off into natural fractures resulting in shorter effective fracture lengths and a significant damage zone surrounding the fracture. This is due in part to inadequate fluid loss control properties of the injected fluid and high capillary forces that retain fluid in the formation. Surfactants are used to lower high capillary forces and help well cleanup of the injected fluids. However, many of these additives adsorb rapidly within the first few inches of the shale formation, reducing their effectiveness and resulting in phase trapping of the injected fluid.
In this work, laboratory data is presented for various fracturing fluids with different surface activity pumped into the Rhinestreet Shale. Recent fracture treatments have been successful utilizing a slick water treatment consisting of water and dry polyacrylamide polymer with and without surfactants. Commonly used surfactants as well as a microemulsion system are evaluated in this study.
Laboratory data is presented illustrating how a microemulsion accelerates post fracturing fluid cleanup in tight shale cores. Addition of microemulsion to the fracturing fluid also results in lowering pressure to displace injected fluids from low permeability core samples and proppant packs. When microemulsion is incorporated at 2 gpt within the fracturing fluid; the relative permeability to gas is increased substantially while water saturation is decreased. This alteration of the fracturing fluid effectively lowers the capillary pressure and capillary end effect associated with fractures in low permeability reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the fracture, hence longer effective fracture lengths.
Organic-rich, low permeability shale deposits are becoming increasingly vital to the production of natural gas. This burgeoning interest is driven largely by increased natural gas prices and improved completion technologies. There is probably no better example of the role of technology in natural gas recovery than the Late Mississippian Barnett Shale of the Forth Worth Basin, which is providing an analog for exploration of similar unconventional reservoirs throughout North America. Nevertheless, there is no universal production model applicable to each and every unconventional reservoir. Indeed, most vary in terms of basic stratigraphic facies distribution, mineralogy (i.e., quartz content, clay type and content), natural fracture parameters (length, orthogonal spacing, connectivity, anisotropy), porosity and permeability, and rock mechanical properties.
Among the tight, organic-rich shale deposits beginning to generate interest among explorationists are the Upper Devonian Rhinestreet shale and Middle Devonian Marcellus shale of the Appalachian Basin. Several recently drilled wells targeting the Rhinestreet and Marcellus shale in southwestern Pennsylvania have been fractured. This paper describes the laboratory experiments and field case studies comparing various conventional surfactants (CS) including an aliphatic ethoxylate (AE), cationic (CAT), and a microemulsion (ME) fluid system to determine their leakoff and adsorption properties when injected into a 6 foot laboratory shale packed column. Unless otherwise noted, AE was the surfactant used in the CS examples. A laboratory comparison study of these systems was used to select additive combinations to apply within the fracturing fluid to restore pad leakoff efficiencies and improve flowback of injected fluid from fractured shale gas wells.
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