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Abstract:Hydraulic fracture initiation and near wellbore propagation is governed by complex failure mechanisms, especially in cased perforated wellbores. Various parameters affect such mechanisms, including fracturing fluid viscosity and injection rate. In this study, three different fracturing fluids with viscosities ranging from 20 to 600 Pa.s were used to investigate the effects of varying fracturing fluid viscosities and fluid injection rates on the fracturing mechanisms. Hydraulic fracturing tests were conducted in cased perforated boreholes made in tight 150 mm synthetic cubic samples. A true tri-axial stress cell was used to simulate real far field stress conditions. In addition, dimensional analyses were performed to correspond the results of lab experiments to field-scale operations. The results indicated that by increasing the fracturing fluid viscosity and injection rate, the fracturing energy increased, and consequently, higher fracturing pressures were observed. However, when the fracturing energy was transferred to a borehole at a faster rate, the fracture initiation angle also increased. This resulted in more curved fracture planes. Accordingly, a new parameter, called fracturing power, was introduced to relate fracture geometry to fluid viscosity and injection rate. Furthermore, it was observed that the presence of casing in the wellbore impacted the stress distribution around the casing in such a way that the fracture propagation deviated from the wellbore vicinity.

Hydraulic fracturing technique has been widely used in many cases to enhance well production performance. In particular, this technology is proven to be the most viable technique for the oil and gas production from unconventional reservoirs. Accurate prediction of fracture initiation and breakdown pressure is vital for successful design of Hydraulic Fracturing operation. Methods of predicting these pressures include Analytical analysis, Field experiments, laboratory experiments and numerical simulations. Despite great achievements in the area of analytical analysis, they often failed to represent the true reservoir case, and consequently are found to be erroneous. Field tests such as mini-frac test are the best method for prediction of initiation and breakdown pressure. However, these tests are very limited due to their costs and are not very suitable for sensitivity analysis. Controlled laboratory tests seem to be the best option for predicting initiation and breakdown pressures. Test parameters such as fracturing fluid properties and principal stresses can be controlled with great precision to achieve accurate results. However, same as field tests, laboratory experiments are expensive. Core samples are limited and are expensive. Coring operation can take 4 to 5 days of rig time to take a 90 ft core. Geomechanical tests can take up to three days of a laboratory technician time per sample. Consequently, this will limit the number of tests to be done, and as a result it causes limitations on the conclusions that can be drawn from these tests. Simulation studies on the other hand do not have these limitations and can be used for as many times as desired to perform sensitivity analysis. This paper presents a simulation model that is based on distinct element method. It is used to study the fracture initiation and breakdown pressure during hydraulic fracturing tests. The accuracy of the model was justified through comparison between laboratory experiments and numerical simulation. Four sandstone samples from two different sandstone types and a synthetic cement sample were used in the experimental studies. The tests were performed in True Tri-axial Stress Cell (TTC) with the capability to inject fluid into the samples. Simulation results demonstrate good agreement with experimental results. Fracture propagation path was found to be very similar. Fractures propagated in the direction of maximum horizontal stress.

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Creating a mechanical earth model (MEM) during planning the well and real-time revision has proven to be extremely valuable to reach the total depth of well safely with least instability problems. One of the major components of MEM is determining horizontal stresses with reasonable accuracy. Leak-off and minifrac tests are commonly used for calibrating horizontal stresses. However, these tests are not performed in many oil and gas wellbores since the execution of such tests is expensive, time-consuming and may adversely impact the integrity of the wellbore. In this study, we presented a methodology to accurately estimate the magnitudes and directions of horizontal stresses without using any leak-off test data. In this methodology, full waveform acoustic data is acquired after drilling and utilized in order to calibrate maximum horizontal stress. The presented methodology was applied to develop an MEM in a wellbore with no leakoff test data. Processing of full waveform acoustic data resulted in three far-field shear moduli. Then based on the acoustoelastic effect maximum horizontal stress was calibrated. Moreover, maximum horizontal stress direction was detected using this methodology through the whole wellbore path. The application of this methodology resulted in constraining the MEM and increasing the accuracy of the calculated horizontal stresses, accordingly a more reliable safe mud weight window was predicted. This demonstrates that the presented methodology is a reliable approach to analyze wellbore stability in the absence of leak-off test.