Primary production mechanism of a clean sandstone reservoir in a brownfield for oil production has been recently changed from natural depletion to waterflooding. Despite the apparently moderate petro-physical properties of the formation, injector wells performances were observed to be extremely poor, mainly due to: high drilling-induced formation damage and Fluids interaction within the reservoir (injection across the oil rim section). Several stimulation technologies have been applied to improve wells injection capability for pressure support optimization. Re-perforation via abrasive jetting, perforations wash through coiled tubing and various acid formulations via bullheading were attempted without achieving any significant increase in injectivity. Considering the modest rock permeability, the need to access a wider formation area to improve oil sweep efficiency and the crucial requirement to re-pressurize the reservoir, an additional card was played as last resort: hydraulic fracturing. This technique was not new to the area and already experimented by different operators. Several producer wells in different layers were hydraulic fracturing stimulated with proppant and/or acid in the past with a good rate of success. Why not to try then? Given the past experience on the same field with hydraulic fracturing in oil producers and accounting for well integrity and potential injectivity, one was chosen as suitable candidate. Offset wells hystorical data were used to build a hydraulic fracturing reservoir model and plan for the activity in details; operator and service providers engaged in a Frac Well On Paper activity in order to reduce any margin of error during field operations. An approach that proved successful. From there, the first trial well was planned and performed successfully. 4 other hydraulic fracturing jobs on 4 wells followed at close distance in time with different, but steadily comforting, results. Injection was improved from negligible initial values up to 2000 mc/day for the post-stimulation condition, exceeding the preliminary expectations. This paper introduces the steps taken to start the hydraulic fracturing campaign, the decision process that led to the design of the treatment, an overview of the execution phases, results well by well and lessons learned to optimize future campaigns.

Hydraulic fracturing has been an industry standard for the past decades; however, most recent applications are performed in extreme down-hole conditions: complex stresses regime, extended reach sections, abnormal pressure and temperature gradients proved to be strenuous challenges, especially with limited time and budgets. This paper explores the challenges of designing, completing and fracturing High Temperature (HT) tight reservoirs. A novel approach to the problem was mandatory to account for thermal effects on stress regime to increase overall chances of success of stimulation treatments. This multi-disciplinary method interconnects petro-physics, rock mechanics, fluid dynamics and operations by combining data from literature and from the field with the purpose of providing a tailored solution to the new challenges ahead. Hydraulic fracturing in High Temperature reservoirs is indeed a demanding task, for which specialized products have been developed throughout time, such as for example, HT fracturing fluids. However, despite accounting for HT gradients, sometimes the outcomes of hydraulic fracturing activity were surprising or inexplicable; sometimes, even disappointing. Therefore, "post-mortem" reviews are often a must-do: data coming from the field and post-treatments results are analysed from scratch, wiping out any known-fact about the specific well and revising all the possible root causes for the anomalous behaviours. Petro-physical data, tectonic regime, stresses, hydraulic fracturing geometry and diagnostics were entirely accounted for to provide an explanation of the final well results, ultimately resulting in more questions than answers, as it so often happens with science. In drilling operations, the thermal effect of cold fluids on fracture gradients and its influence on losses has been deeply investigated, becoming an industry best practice. However, the effect of cool-down due to fluid injection at high rates with hydraulic fracturing applications are not captured by dedicated literature and, even less, by modelling softwares. As a result, a non-conventional approach to the creation of a geo-mechanical model that could take into account the thermal effect of cold frac fluids injection was elaborated and several sensitivities to understand fracture propagation mechanism were performed, highlighting a wide range of variability which is attributable to the influence of temperature on stress regime. High temperature reservoirs proved easier to frac than expected due to the decrease in terms of pressure required to initialize a fracture. However, this phenomenon could hide potential dangers when it is required to contain such fracture in the targeted interval. The correct modelling of such effect is of extreme importance to forecast fracture geometry, proppant placement and final conductivity requiring to re-adapt and re-adjust field-proven, industry-standardized hydraulic fracturing models and practices to match results with expectations.