Post-Fracturing Fluid Recovery Enhancement with Microemulsion
- Daniel Miles Agee (Oklahoma State U.) | Agustinus Yudho Wirajati (Schlumberger) | Laura Schafer (Schlumberger) | Graham Grant (Total - Indonesie) | Adeline Garnier (Total CSTJF) | Etienne Thouvenin (PTT Exploration & Production PLC) | Andre Wijanarko (VICO Indonesia)
- Document ID
- Society of Petroleum Engineers
- SPE International Symposium and Exhibiton on Formation Damage Control, 10-12 February, Lafayette, Louisiana, USA
- Publication Date
- Document Type
- Conference Paper
- 2010. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 4.6 Natural Gas, 5.2 Reservoir Fluid Dynamics, 2.2.2 Perforating, 1.6.9 Coring, Fishing, 2.4.3 Sand/Solids Control, 1.8 Formation Damage, 3 Production and Well Operations, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 3.3.1 Production Logging, 1.6 Drilling Operations, 4.1.2 Separation and Treating
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The fields of East Kalimantan, Indonesia contain several depleted gas zones of medium permeability (0.1 to 300 mD). Though the permeability is quite good for gas bearing formations, the majority of the wells targeting these sands have failed to produce at expected rates. In the 1980s, hydraulic fracturing was introduced to the area in an attempt to increase production. The treatments yielded limited success with many wells actually producing less after being fractured. This led operators in the area to believe that the formations could be water sensitive with damage from the injected fluids causing the poor results after fracturing. As laboratory testing has ruled out water-sensitive mineralogy, the suspected cause of damage has been attributed to a decrease in relative permeability to gas after the fracturing fluid has penetrated the pore throats (water block). The water block conclusion is supported by the low percentage of injected fluids that are returned after the treatment.
In 2007, VICO performed four fracturing treatments using a conventional surfactant to aid in post-frac cleanup. Only 2 of the 4 wells that were fractured produced after the treatment. Again, a common problem between the wells was the poor return of treatment fluids during cleanout. The limited success of these treatments indicated the water block issue had not been resolved. After reviewing the results of the first four wells, three additional fracturing treatments were placed in similar reservoirs using a microemulsion additive instead of the surfactant. Though laboratory testing in cores between 1 and 8.5mD failed to show a significant difference between the microemulsion and surfactant, the wells fractured with the microemulsion additive consistently outperformed those fractured previously in terms of returned treatment fluids and incremental production. Paktinat et al. (2006) wrote that the use of fracturing fluids with microemulsion in unconventional tight gas reservoirs can help increase production by increasing the relative permeability to gas in the area surrounding the fracture. Our study shows that similar benefits can also be achieved in depleted gas reservoirs with permeabilities greater than 1 mD, even if the benefits can not be clearly demonstrated under laboratory conditions.
Hydraulic fracturing is a common practice used to increase production from under-producing reservoirs. This process involves injecting large volumes of water or oil-based fluids laden with sand or ceramic propping agents into the target formation. This base fluid leaks off into the pore spaces of the surrounding rock during the treatment and as the fracture closes. The treatment fluid required to create the fracture and place the proppant is now fully saturating the pores of the rock surrounding the newly created fracture. This fluid must be removed in order to reopen the pore throats for hydrocarbon production. It is easy to infer that by removing more of the injected fluids after the treatment, the water saturation of the near fracture area will be reduced. According to Desroches and Bratton (2000), reducing the water saturation in a reservoir will increase the relative permeability to gas. This in turn will increase the productivity of the newly placed fracture. In high permeability or overpressured reservoirs, this is not typically a concern as the fluid can be easily forced back out of the pores and carried to the wellbore by the fracture. As was observed by Paktinat et al. (2005), this return of treatment fluid becomes more difficult as permeability and reservoir pressure decline.
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