Recent advancements in Reservoir Modelling have provided a springboard for Oil and Gas Operators in the UK North Sea to focus on modelling Thermal Induced Fractures caused by cold water injection. In this study, we used a Finite Difference method in a Reservoir Simulation software to simulate heat transfer within the reservoir, due to cold water injection. Then, we modelled the stress changes induced by the temperature changes, using a Finite Element Method in a Geomechanical modelling software. The results from this study clearly show the formation of thermally-induced fractures at the injector wells due to tensile stresses, a direct consequence of cold water injection. Results also show how the deformation increases when the reservoir formation temperature is further lowered as more cold water is being injected. Using the coupled simulations, North Sea Operators can now understand the interaction between pressures, stresses and fracture propagation away from their injectors. Knowledge of the fracture propagation gives the operator an idea of the optimum well spacing between the producers and injectors, and limits on the maximum injection rate and pressure. This avoids channeling of injected water at the injectors through the thermally-induced fractures directly to the producer thus, protecting multi-million dollar investments.
Thermal induced fracturing has been an area of interest for many years and this has substantially increased in the past decade with sustained high oil prices. A large percentage of producing oil fields around the world are applying some form of secondary injection with a good chunk of that percentage injecting water for secondary recovery and pressure maintenance. Many offshore operators directly inject sea water into their reservoirs which could potentially lead to shrinkage of the near wellbore rocks. The degree of shrinkage is particularly important in temperate regions where there is a higher temperature differential between the reservoir and the injected sea water. This shrinkage results in tensile stresses being induced in the formation and may lead to thermal induced fracturing.
In every formation, we have the 3 principal stresses which are the Minimum Horizontal Stress (σhmin), the Maximum Horizontal Stress (σhmax) and the Vertical Stress (σv). In conventional fracturing due to pressure induced stresses, for fracturing to occur, σhmin has to be exceeded. But in the case of thermal induced fracturing, the reservoir could fracture at a pressure substantially lower than the minimum horizontal stress. At failure, this stress value is closer to the tensile stress cut-off of the formation.