Inorganic scale management during shale gas production
Hydraulic fracturing for shale gas production involves pumping large volumes of water; as a consequence of this, produced water management is an important topic to address in order to sustainably produce shale gas. It has been well documented that only approximately 10-40% of the pumped fluids will be produced back to the surface, and that there will be increased concentrations of various ions in the flowback water during this process. This flowback water, with high total dissolved solids and/or high concentrations of certain ions, presents a significant risk of mineral scaling. Analysis of geochemical data is performed to address the question of whether the increase in salt concentration in the flowback water is due to the dissolution of minerals into the injected fracture fluid, or whether it is due to the interaction/reaction between fracture fluid and the in situ formation water. Data from both industry sources and the public domain have been used. Additionally, to understand better the fluid transport mechanisms within shale systems, and to match the volume of flowback water observed in field cases, models of fractured shale gas systems have been developed and the results are discussed. Analysis of produced water compositional data has been performed – not only to calculate the scaling risk during shale gas production, but also to identify the in situ formation water composition. In general, it can be very challenging to identify the in situ formation water composition in shale reservoirs since samples of the formation water can be difficult to obtain. They may have been contaminated during the drilling process, reactions may have taken place due to fluid mixing between the injected fluid and the formation water, or simply they may not have been preserved appropriately. Some calculations of formation water compositions are presented based on the observed compositional data; thereafter, the predicted formation water compositions are validated by comparison with the observed total dissolved solids (TDS) data. A mineral dissolution model was developed using PHREEQC to understand better the cause of high ion concentrations in the flowback water. Additionally, a series of singlephase 1D reactive transport models (including certain primary minerals) were developed to further analyse and validate the identification of the in situ water composition. In addressing the first question posed in this thesis, we conclude that the main reason for the high salinity of the flowback water is the occurrence of fluid mixing between the fracture fluid and the high salinity formation water; it is not primarily the result of dissolution of minerals into the fracture fluid. A two-phase 3D numerical flow model has been developed that includes a hydraulic fracture and is populated with shale reservoir properties. (This model assumes the hydraulic fracture is already established – i.e. the calculations include coupled flow and component transport, but the geomechanics are not considered). It is used to simulate fluid transport mechanisms within the shale system and to address the second question – what causes the significant retention of fracture fluid in shale reservoirs. A series of simulations was performed to achieve a history match with observed flowback water data in a western Canadian basin (the Horn River Basin). Meanwhile, given that extremely low matrix permeabilities (order nD) are measured in actual field systems, these calculations suggest that the injected fluid must propagate through secondary induced fractures or even a natural fracture network within the shale system, in order to propagate far enough from the main propped hydraulic fracture not to flow back immediately. In order to perform more representative modelling, the conductivity of the grid cells adjacent to the main hydraulic fracture must be increased, thus simulating a secondary induced fracture region. Additionally, the impact of gravity segregation and secondary fracture closure were also included to achieve a history match with field data (total volume of flowback water and the fraction of injected fracture fluid in produced water). A further two-phase 3D flow model was developed to examine the scaling tendency due to the evolving produced brine composition over the lifetime of the well. It is based on the previously history matched model and includes the fracture fluid and formation water compositions to predict precipitation of minerals. The simulation results demonstrate that the worst scaling risk occurs during the initial period of shale gas production: this is an important consideration when designing scale control strategies. Finally, scale inhibitor injection was simulated to examine the impact of inhibitor retention on well protection. The model demonstrates that there is the potential to design a satisfactory scale inhibitor treatment as part of the pumping process. This body of work develops a methodology for systematically analysing flowback water data and predicting in situ formation water compositions in shale reservoirs. It also uses modelling tools to identify scaling risks and address the causes of high salinity in the flowback water. It then introduces a simplified 3D fluid flow model that nevertheless offers a good history match of observed data from a shale system. Further modelling studies based on this history-matched model demonstrate that the scaling tendency can be predicted and that an appropriate scale management programme can be designed.