###### Abstract  
In this study distributed fiber optic sensing has been used to measure strain along a vertical well of a depth of 300 m during a pumping test. The observed strain data has been used in geomechanical simulation, in which a combined analytical and numerical approach was applied in providing scaled-up formation properties. The outcomes of the field test have demonstrated the practical use of distributed fiber optic strain sensing for monitoring reservoir formation responses at different regions of sandstone-mudstone alternations along a continuous trajectory. It also demonstrated that sensitive and scaled rock properties, including the equivalent permeability and pore compressibility, can be well constrained by the combined use of water head and distributed strain data. In comparison with the conventional methods, fiber optic strain monitoring enables a lower number of short-term tests to be designed to calibrate the parameters used to model the rock properties. The obtained parameters can be directly used in long-term geomechanical simulation of deformation of reservoir rocks due to fluid injection or production at the CO: storage and oil and gas fields. pumping test; fiber optic strain sensing; deformation; sandstone-mudstone alternation; geomechanical modeling +
Footnote †: journal: Applied Soft  
gas, and wastewater disposal, injection-induced earthquakes and other risks related to injection-induced surface deformation and fault reactivation have attracted increased attention from scientists and the public alike [5; 6; 7; 8; 9; 10]. Geomechanical effects induced by reservoir production can be particularly pronounced in stress-sensitive reservoirs, such as poorly compacted or fractured reservoirs [11]. For both monitoring and risk assessment purposes, it is important to assess the influence of injection operations so that the geomechanical implications, particularly in terms of the potential for fault reactivation, can be adequately assessed [12]. How to predict and control the risks associated with fault reactivation, including fluid leakage and damaging earthquakes, are key issues to allow fluid injections to be carried out safely and accepted by the public. In these regards, geomechanics plays a role in bridging the gap from geophysics to engineering and is also a key issue in site selection, injection operation, and post-injection management in CO\({}_{2}\) storage and other applications. Given that changes of deformation in a reservoir-caprock system are directly linked to changes in pore pressure and stress state, coupled fluid flow and geomechanical modeling is potentially a powerful tool to understand and predict the mechanical behaviors of the reservoir-caprock system. It can contribute to the characterization, prediction, and optimization of injection operations. In recent years, significant progresses in numerical modeling of reservoir scale have been made for a number of purposes such as quantification of challenge in geothermal development [13], analysis of induced seismicity by shale fracking [5], stimulation of heavy oil reservoir [14], and CO\({}_{2}\) geological storage [15]. In order to make accurate predictions, a geomechanical model needs to be first calibrated against geophysical and geomechanical data obtained from monitoring. As a new technology, continuous and distributed fiber optic sensing (DFOS) technology based on Brillouin and/or Rayleigh scattering has great potential in geotechnical monitoring at both laboratory and field scales [16; 17; 18; 19; 20]. Optical fiber sensors have advantages such as their immunity against electromagnetic interference, low weight, small size, high sensitivity, and large bandwidth. By grouting fiber optic cables into multiple boreholes, a large amount of accurate, spatially resolved data can be obtained. [PERSON] et al.