GEOMECHANICAL MODELLING FOR EFFECTIVE MANAGEMENT OF HYDROCARBON RESERVOIR

Abstract

Stress estimation is an essential requirement for geomechanical characterization of a reservoir. A robust geomechanical model incorporating pressure production information is an effective tool for well failure analysis, sand production, hydro-fracture treatment optimization etc. It also helps in proper well placement based on stress directions. Pre drill analysis is necessary to mitigate drilling related challenges such as inflow, loss circulation, and stuck pipe to reduce non-productive time while drilling a well. For formations prone to sand production, information of pressure drawdown coupled with geomechanical analysis could not only locate the culprit zone but can also provide limiting values of production rates leading to well failure resulting in sand production. Brief of the studies is provided below: Stress assessment of Basement reservoir: Study has been carried out for a giant oil field situated in western offshore India at shallow water depths. The Lower Miocene Burdigalian carbonate reservoir is the major pay of the field. Basement is stratigraphically the deepest established reservoir. Basement is composed of granite and basalt and has fractures as primary fluid mobility conduits. Challenges have been encountered during drilling, resulting in non-productive time leading to financial losses. Since production is from Basement is through interconnected fractures, quantifying stresses leading to fractures and their orientation becomes important for production optimization. The relative magnitude of the stresses and direction play an important role in well placement and productivity. For model building, pore pressure is estimated through standard correlations using wireline log data and calibrated with available field pressure measurements. The estimated fracture pressure is calibrated with leak off test data wherever available. Vertical stress is estimated as integral of density log. For shallower part where density log is not available, extrapolation density from mudline is used. Minimum and maximum horizontal stress values are estimated through poro-elastic approach. For estimating rock mechanical parameters, standard correlations based sonic velocity are used. Minimum horizontal stress is calibrated with fracture pressure, whereas maximum horizontal stress is limited using a stress polygon under normal faulting regime. For Basement, the estimated overburden stress ranges from 40 MPa to 46 MPa, whereas the minimum horizontal stress ranges from about 28 MPa to 38 MPa, and maximum horizontal stress ranges from about 30 MPa to 42 MPa. Maximum horizontal stress orientation is deciphered from the observed drilling-induced tensile fractures in the available micro resistivity image log and is found to be along 154-334 (±15) degrees north. Once the three principal stresses were estimated a stress magnitude map was generated for all three principal stresses. Since the wells chosen for the study cover nearly the whole reservoir, a map with linear interpolation could be generated to quantitatively provide first-hand information for the possible magnitude of the stress acting at that point. Assessment of tensile failures: Drilling induced tensile fracture (DITF) occur when the tangential stress acting on the formation enter into extensional regime. These fractures affect drilling and completion activities. Designing optimum mud weight, therefore, is crucial for restricting the occurrence of these fractures. Higher the mud weight, higher is the possibility of induced fractures. Drilling-induced fractures can be further classified based on their orientation relative to the borehole. Radial fractures are oriented perpendicular to the borehole, while tangential fractures are oriented along the direction of the borehole. Hybrid fractures are a combination of radial and tangential fractures. If the subsurface stress is such that the maximum principal stress is perpendicular to the borehole, higher probability of radial fractures exists, however, if maximum principal stress is parallel to the borehole, tangential fractures are more probable. Since DITFs can lead to potential mud loss, restricting usage of high density mud or high mud weight is one of the possible solutions as it prevents high differential pressure between well and formation. Also drilling in stages is relevant as at each stage the hitherto drilled formation is cased ensuring safety of borehole. For the study well, minimum and maximum horizontals stress values were estimated along with vertical stress. The estimated Cartesian stresses were converted to borehole stresses in cylindrical coordinate system using proper coordinate transformation. At certain depths in the study range the estimated tangential stress along direction of maximum horizontal stress attains nearly zero values especially for the shallower part of Basement. At this point tensile (extensional) forces cause the formation to fail under tension.The findings corroborate with the image log recorded in the well. For the deeper part, tangential stress remains well above zero, leading to compressional regime. Study was further extended to deeper part of the formation where image log do not show any DITFs. In azimuthal stress variation plot, value of tangential stress along maximum horizontal stress is well above the zero value for rock to be in tensile regime. Hence negligible possibility for well to fail under tension which is also justified by the image log where no DITF is observed. Further an attempt was made to estimate the threshold well pressure required to avoid the formation failure under tension. Results were then compared with the mud weight used during drilling of the well. It was observed that for the depth interval where DITF are observed, actual mud weight used for drilling the well was higher than the threshold value predicted using Griffiths or Murrel failure criterion. Thereby causing the well to fail under tension. For the depth ranges where DITF are not observed, the value of predicted mud weight is higher than actual mud weight used for drilling, which implies that rock is still in compressive state and will not fail under tension. Prediction of Sand failure: Sand production is an area of concern for development of fields having pay zones as unconsolidated or moderately hard formation. Such reservoirs are very sensitive to production rates and hence must be studied thoroughly before field development plan is implemented. Failure of sand is caused by a combination of factors viz. geology of the reservoir, properties of sand and production conditions of the well. For wells producing with high gas rate, sand failure is more pronounced due to stronger shear force acting on the grains. Sand production is categorized as transient, continuous or catastrophic depending on the rate of sand production, depending on which different methods are used to control sand production from the well. Identification of sand prone zones and quantification of drawdown causing sand failure is critical for managing sand failures. Gas bearing Daman sandstone reservoir is one such reservoir situated in the western offshore India where sand production is observed during production. In the study well, stable gas production without sand incursion was observed at lower rate, whereas at higher rates, sand production was observed. Since multiple zones were perforated and tested, observations on sand production was different for different zone. In one of the tested zones, sand production was observed from beginning whereas in the other zone no sand production was observed at surface. Study was therefore carried out to quantify the drawdown at which sand failure initiates. Core studied indicated porosity variation form 12-26% with permeability ranging up to 238mD. Micro Computed Tomogram (mCT) showed average grain size of the order of 140microns with unimodal distribution indicating well sorted grains. Unconfined compressive strength of the rock was estimated using standard correlations and calibrated with lab observed data available for Daman formation in the nearby field. Mohr Coulomb failure criteria was used for failure prediction. From the estimated values of normal and shear stress, a limiting value of formation strength was calculated. It was observed that under given stresses, sand failure occurs when the applied drawdown exceeds a certain value depending on the difference between unconfined compressive strength of the rock and the calculated formation strength which is regarded as critical drawdown pressure (CDP). Results of the study are also substantiated with field observations where sand production is observed in zones having estimated CDP less than the applied pressure drawdown due to production. The predicted critical drawdown pressure is vital to control sand production and mitigate hazards associated with sand failure. The study is important for preparation of field development plan to mitigate economic losses arising out of potential sand failures.