Simulation Study for Scale Management During Shale Gas Production
- Xu Wang (Heriot-Watt University) | Eric J. Mackay (Heriot-Watt University)
- Document ID
- Society of Petroleum Engineers
- SPE International Oilfield Scale Conference and Exhibition, 20-21 June, Aberdeen, Scotland, UK
- Publication Date
- Document Type
- Conference Paper
- 2018. Society of Petroleum Engineers
- 4.3.4 Scale, 0.2 Wellbore Design, 5.2 Reservoir Fluid Dynamics, 5.2 Reservoir Fluid Dynamics, 2 Well completion, 3.2 Well Operations and Optimization, 3.2.6 Produced Water Management, 7.2.1 Risk, Uncertainty and Risk Assessment, 0.2.2 Geomechanics, 5.5 Reservoir Simulation, 2.4 Hydraulic Fracturing, 5.8 Unconventional and Complex Reservoirs, 7 Management and Information, 3 Production and Well Operations, 5 Reservoir Desciption & Dynamics, 7.2 Risk Management and Decision-Making, 3 Production and Well Operations, 1.6 Drilling Operations, 5.8.2 Shale Gas, 5.5.8 History Matching
- Case study, History match, Simulation, Shale gas, Scaling risk
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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 high concentrations of certain ions, presents a significant risk of mineral scaling (Blauch, 2009).
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 (Pan, 2017). Some calculations of formation water compositions require to be preceded 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 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 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).
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. Finally, scale inhibitor injection was simulated to examine the impact of inhibitor retention on well protection.
|File Size||2 MB||Number of Pages||20|
Fan, L.,Thompson, J.W. and Robinson, J.R., 2010. Understanding Gas Production Mechanism and Effectiveness of Well Stimulation in the Haynesville Shale through Reservoir Simulation. SPE 136696, Canadian Unconventional Resources and International Petroleum Conference, Calgary, Alberta, Canada, 19-21 October.