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Shale reservoirs retain significant natural gas reserves, which are more challenging to recover than in conventional reservoirs. Production from these unconventional resources became economically feasible as a result of advances in both horizontal drilling and hydraulic fracturing technologies. Stimulation technologies continue to improve through the combining of advanced logging, geomechanics, microseismic and frac fluids. This has led to further optimization of hydraulic fracture treatments and higher recovered unconventional reserves.Petrophysical and geomechanical models are built using advanced well logging, special core analysis (SCAL), and rock mechanical properties. Within the petrophysical evaluation, special care must be taken when transferring the dynamic values of Poisson's ratio and Young modulus, obtained from acoustic data, to static values, to reduce the uncertainty of stress and fracture width estimations. Additionally, one of the key parameters in improving hydrocarbon production is choosing a suitable fluid type and associated chemicals to be used in reducing damage to the formation. Geomechanically, utilizing "Drilling-Induced Tensile Fractures" (DITFs) analysis is crucial to estimate fracture half-length, number of fracture stages, closure pressure of the frac and designing the appropriate pump rates.This paper presents a case study from a Saudi Arabian shale formation. The described workflow is designed to help optimize both reservoir characterization and design of hydraulic stimulation treatments.It will be shown that engineered completions are more effective and yield higher ultimate recoveries than

Hydraulic fracturing is widely implemented in stimulation of unconventional reservoirs to unlock the hydrocarbon potential in ultra-low permeability formations. Fracture height growth is a critical parameter in unconventional reservoir to maximize the hydrocarbon productivity. The integrated vertical well interpretations from a case study of the pilot well demonstrates the effect of the vertical stress distribution which impacts fracture height growth. Geomechanical model of a pilot hole was constructed to provide vertical variation of mechanical properties and in-situ stresses. The calibrated geomechanical model has shown that Jubaila source rock has less stiff rock and lower stress than bounding formations. The geomechanical model of the vertical pilot well has shown the overlapping between the minimum horizontal stress and vertical stress in particular, depths restricts the fracture height growth and creates longer horizontal fracture. Pre-frac injection test was performed, analyzed, and integrated into the geomechanical model. Temperature log was performed to identify the fracture height growth and the results of the temperature log were proportional with the geomechanical model. 3D fracture simulation software was utilized to determine the hydraulic fracture properties. The created fracture simulation model was calibrated to the geomechanical model and temperature log interpretations. Furthermore, improving hydraulic fracture design depends on understanding the key parameters and lessons learned from the stimulated vertical well and the integrated process. This will help in selecting the landing point, redesign the completion strategy, and optimize the production in the future horizontal wells.

Condensate banking is a major issue in the production operations of gas condensate reservoirs. Increase in liquid saturation in the near-wellbore zone due to pressure decline below dew point, decreases well deliverability and the produced condensate-gas ratio (CGR). This paper investigates the effects of condensate banking on the deliverability of hydraulically fractured wells producing from ultralow permeability (0.001 to 0.1 mD) gas condensate reservoirs. Cases where condensate dropout occurs over a large volume of the reservoir, not only near the fracture face, were examined by a detailed numerical reservoir simulation. A commercial compositional simulator with local grid refinement (LGR) around the fracture was used to quantify condensate dropout as a result of reservoir pressure decline and its impact on well productivity index (PI). The effects of gas production rate and reservoir permeability were investigated. Numerical simulation results showed a significant change in fluid compositions and relative permeability to gas over a large reservoir volume due to pressure decline during reservoir depletion. Results further illustrated the complications in understanding the PI evolution of hydraulically fractured wells in "unconventional" gas condensate reservoirs and illustrate how to correctly evaluate fracture performance in such a situation. The findings of our study and novel approach help to more accurately predict post-fracture performance. They provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs. The optimization of both fracture spacing in horizontal wells and well spacing for vertical well developments can be achieved by improving the ability of production engineers to generate more realistic predictions of gas and condensate production over time.