Modeling of wastewater volume from unconventional oil and gas fields in Wattenberg field, and evaluation of low salinity waterflood enhanced oil recovery on shale wells
Date
2016
Authors
Bai, Bing, author
Carlson, Kenneth, advisor
Catton, Kimberly, committee member
Stright, Lisa, committee member
Omur-Ozbek, Pinar, committee member
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Volume Title
Abstract
Reuse of wastewater from hydraulic fracturing (flowback and produced water) is a sustainable option for wastewater management practice in unconventional oil and gas fields. Reuse reduces fresh water demand but also lowers the environmental footprint by reducing the storage and transportation of both fresh and wastewater. A successful reuse practice requires a thorough understanding of both the quantity and quality of the wastewater, and more importantly, its potential impacts on well performance. In the first part of this study, wastewater production models were developed for horizontal shale wells in Wattenberg field .In addition, a solid characterization and distribution analysis on wells fractured with fresh and recycled water was performed to understand their impacts on wastewater quality. The second part of this study focuses on understanding the mechanisms of low salinity waterflood (LSF) in unconventional shale wells, and how oil recovery is impacted by the total dissolved solids (TDS) of the recycled brine. Results from the studies above are summarized in Chapter 4 through Chapter 7. A framework for water production prediction was developed in Chapter 4. Water production models were developed with Arps equation for horizontal wells from five fields in Wattenberg field. For a better data fitting and modeling, three time periods were defined: Frac flowback, transition period and produced water. The frac flowback period is the first one month after production starts, followed with 5 months of the transition period and, thereafter, produced water period. A correlation was found between water production volume and locations of wells,; thus, location is very important for estimating water production. Additionally, wells with low gas-oil-ratio (GOR) tend to have higher water recovery. In Chapter 5, sources of variability in flowback and produced water volumes from horizontal oil and gas wells were identified from external factors (time, location, type of frac fluids, wellbore length, and water source).. Horizontal wells in the Denver-Julesburg basin operated by Noble Energy were studied and results show that water production varies with time, location and wellbore length.. Additionally, production volume variation with fracturing fluid type and water source (fresh versus recycled) was explored. Results indicate that both of these variables should also be considered when developing a general model for water production. A guar-based frac fluid resulted in greater water production when compared to a cellulose derivative-based fluid. Finally, wells fractured with a fresh water based fluid had significantly greater produced water volume than geospatially-paired wells with a 1/7-recycled/fresh blend based fluid. Chapter 6 provides a qualitative and quantitative characterization of solids in frac flowback and produced water from five horizontal wells at two separate sites in the Wattenberg field of Northern Colorado. The difference in solids from wells fractured with fresh water and recycled water is compared, and their distribution and characterization are identified by particle size distribution measurement and X-ray photoelectron spectroscopy (XPS). Results show that particle were smaller and more uniform in produced water samples collected during the first week of production from the wells fractured with recycled water, suggesting that the recycled water was more compatible with the shale formation and wells fractured with recycled water tend to clean out faster. Chapter 7 investigates two of the fundamental mechanisms of LSF, clay swelling and diffused double layer (DDL) expansion. Both mechanisms are impacted by the salinity/total dissolved solids (TDS) concentration of the injection water. To test these mechanisms, clay swelling tests and real-time contact angle measurements were performed in this study. Spontaneous imbibition was also conducted, with Niobrara shale core plugs from Denver-Julesburg Basin, to compare oil recovery from low salinity and high salinity brine. Results show an increase in oil recovery when the TDS of brine falls between 400 and 10,000 mg/L. These results also indicate that LSF improves oil recovery from unconventional shale formation, and therefore, an optimal TDS concentration exists for highest oil recovery.
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Subject
frac flowback
produced water
unconventional oil and gas
low salinity waterflood
enhanced oil recovery
spontaneous imbibition