Petroleum geomechanics is defined as the interaction between the evolving earth stresses and the overburden and reservoir rock mechanical properties. A comprehensive understanding of rock mechanical behaviour is key to successful field appraisal and development. For example, 70% of the world’s oil and gas reserves are contained in reservoirs where rock failure and sand production will become a problem at some point. Wellbore stability issues have been estimated to cost the industry USD 8 billion annually. Around 80%–90% of data comes from “traditional” core and log petrophysics, but the importance of data quality control and a rigorous and consistent petrophysical interpretation is often overlooked by well construction and production engineers.
The course addresses the holistic sand management strategy implementation from geomechanics perspectives, through evaluation and implementation of appropriate solutions for minimisation of well costs and maximisation of reservoir productivity. It will look at the inter-relationships between geomechanics and operations, application of geomechanics in relation to sand production and completions, and show how geomechanics can be best applied to provide maximum value in sand management and life-of-well and field operations. The course comprehensively covers geomechanics and operational-related sand production mechanisms, laboratory simulations of sand production to provide measurement data for model calibration and validation, state-of-the-art analytical and 4-D numerical sanding predictive methodologies for life-of-well and field including scale effect, rock strength properties reduction associated with water-cut and estimation of cumulative sand volume and rate of sand production, and optimal mitigation and management of sand production taking into consideration the feasibility of deferment or elimination of sand control installation. The course is illustrated with field examples. Application of geomechanics in relation to sand production and completions in order to provide maximum value in sand management and life-of-well and field operations.
Simplified analytical methods are used in 1D geomechanics workflows to predict the rock's behavior during drilling, completion and production operations. These methods are simplistic in their approach and enable us in getting a time-efficient solution, however it does lose out on accuracy. In addition, by simplifying equations, we limit our ability to predict behavior of the borehole wall only i.e. near wellbore solutions. Using 1D analytical methods, we are unable to predict full field behavior in response to drilling and production activities. For example, when developing a field wide drilling plan or preparing a field development plan for a complex subsurface setting, a simplified approach may not be accurate enough and on the contrary, can be quite misleading. A 3D numerical solution on the other hand, honours subsurface features of a field and simulates for their effect on stresses. It generates solutions which are more akin to reality.
In this paper, difference between a simplified semi-quantitative well-centric approach (1D) and a full field numerical solution (3D) has been presented and discussed. The subsurface setting considered in this paper is quite complex - high dipping beds with pinch outs and low angled faults in a thrust regime. Wellbore stability and fault stability models have been constructed using well-centric approach and using a full field-wide 3D numerical solution and compared to understand the differences.
In this study, it was clearly observed that field-based approach provided us with more accurate estimation of overburden stresses, variation of pore pressure across the field, changes in stress magnitudes and captured its rotation due to pinch-outs and formation dips. For example, due to variation in topography, the well-centric overburden estimates at the toe of deviated well at reservoir level is lower by 0.21gm/cc as compared to the 3D model. It is also observed that within the field itself stress regime changes from normal to strike slip laterally across the reservoir. In comparison to 1D model, considerable differences in stable mud weight window of upto 1.5ppg is observed in wells located close to faults. This is due to effect of fault on stress magnitude and azimuth. Stress state of 4 faults were assessed and all are estimated to be critically stressed with elevated risk of damaging three wells cutting through. However, a simple 1D assessment of stress state of faults at wells cutting through them, show them to be stable.
Moreover, the 3D geomechanical properties that are input into the numerical simulation also play an important role on the results. The algorithms and data used to populate the properties away from the well, need to be validated and calibrated with the well data, to predict reliable results. As the subsurface was quite complex, and well data was not sampled optimally, both horizontally and vertically, the selection and optimum usage of 3D trends also became crucial.
By comparing the differences between 1D and 3D solutions, importance of 3D numerical modelling over 1D models is highlighted.
The key objective of this study was to develop a high resolution wellbore stability model for planned highly inclined development wells of an ultra-deepwater field through integrating geological, geophysical, petrophysical and drilling data to design optimized drilling mud weight window.
This study describes a customized high resolution wellbore stability modelling process for development wells in ultra-deepwater setting, where shale and sandstone have different pore pressure and stress magnitudes. Un-calibrated and calibrated seismic velocities along with offset well data were used to generate the high resolution pore pressure model for the overburden shale section. Laboratory based geo-mechanical tests, petrophysical logs and offset well events were integrated for the estimation of sub surface stresses and rock mechanical properties for overburden shale and sandstone. Subsequently, separate wellbore stability model was built to estimate the shear failure gradient for overburden shale and sandstone.
This study suggests that the mud weight (MW) window in the overburden is primarily governed by two parameters – (i) sand-shale pressure equilibrium state, and (ii) stress anisotropy. The intervals where the sand and shale are not in pressure equilibrium state (i.e. shale pressure > sand pressure), the minimum MW requirement is defined by either pore pressure or shear failure gradient (SFG) of shale formation. Whereas, maximum limit is marked by fracture gradient of relatively less pressured sand formation. Therefore, in such intervals mud weight window becomes much narrower (~1 ppg) than those intervals where sand and shale is in pressure equilibrium (~1.6 ppg). This study also highlights the increase of minimum MW requirement (SFG) in some intervals having relatively higher stress anisotropy. The minimum MW requirement within the main reservoir section having thin intra-reservoir shale is controlled by the SFG of the sand formation, as strength is lower in the reservoir sand than intra-reservoir shale. Results show the importance of high resolution modelling in order to capture pressure uncertainty, thin sands, sand/shale pressure equilibrium state, stress anisotropy and its effects in defining the optimum mud weight window. Based on analysis, further risk zonation was done to highlights intervals prone to wellbore collapse and mud loss.
This paper illustrates how the integrated high resolution wellbore stability modeling would help in optimum mud weight planning for highly deviated / horizontal wells to minimize the drilling risks and non-productive time (NPT), especially for challenging field development settings (deepwater, ultra-deepwater, high stress, High pressure High temperature).
Bhardwaj, Nitin (Reliance Industries Limited, Mumbai, India) | Gunasekaran, Karthikeyan (Reliance Industries Limited, Mumbai, India) | Kumar, Ashutosh (Reliance Industries Limited, Mumbai, India) | Dutta, Jayanta (Reliance Industries Limited, Mumbai, India)
In 3D Pore Pressure Modelling workflow, establishing appropriate Normal Compaction Trend (NCT) is not only critical but also requires the maximum extent of human interpretation and geological understanding. If not established appropriately, it can introduce substantial uncertainty in the final pore pressure prediction. Though, statistical algorithm techniques are available to establish it, the authors of this paper have demonstrated that establishing NCT manually based on geological logic and regional pressure understanding is much more reliable technique than pure statistical based approach.
In this paper, authors utilizes two different approaches in establishing Normal Compaction Trend (NCT) for the study area. First, based on pure statistical technique and second, a manual one based on combination of 3D velocity trends and regional geological pressure understanding. The 3D pore pressure volumes generated from the above two separate NCT’s are then checked for their conformance and agreement with the regional pressure data and understanding, including validation with post drill measured pressure data in the study area.
The results and analysis in the study area shows that, establishment of NCT based purely on statistical approach results in higher uncertainty in the 3D pore pressure estimation process. Whereas, manual NCT based on logic results in much more robust, reliable, and regionally consistent 3D pore pressure model with lower uncertainty. In our case study, the average uncertainty in the statistical NCT based 3D Pressures was ranging between 0.8 – 2.3 PPG when compared with actual pressures, while in the case of logic based manual NCT the average uncertainty was less than 1.0 PPG.
This case study indicates that in the offshore areas, particularly in areas where there is transition from shelf to slope to deepwater, it is advisable to use all the regional pressure knowledge and geological understanding in establishing the NCT, rather than adopting only the pure statistical methods.
Saha, Sankhajit (Baker Hughes, a GE company) | Gariya, Bhuwan Chandra (Hindustan Oil Exploration Company Ltd) | Panda, Debabrata (Hindustan Oil Exploration Company Ltd) | Perumalla, Satya (Baker Hughes, a GE company) | Podder, Tuhin (Baker Hughes, a GE company) | Thanvi, Shrikant (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company)
Drilling through the thick shale sequence (Oligocene to Paleocene age) of Cauvery offshore showed severe wellbore instability in the past due to incompatible mud program that increased overall operational cost. While new high-angle sidetrack development wells had been planned, three major challenges need to be addressed. First, proper mud weight recommendation for preventing mechanical instability; second, introduction of a cost-effective mud system preventing time-sensitive failure; and finally, mitigating the environmental impact factor of the mud system.
Geomechanical modelling and Hole Stability analysis had been performed based on available dataset. An optimized mud weight (MW) program was developed based on the analysis. Considering the time-dependent failure characteristics of the shale and overall cost effectiveness, just modifying the mud weight does not address all of the challenges delineated above. Consequently, special "high-performance water-based mud system (HPWBM)" was designed instead of oil-based mud (OBM). This HPWBM was formulated based on the nature of shales encountered. While drilling, real-time geomechanics further facilitated controlled drilling conditions and optimized the mud program.
The well-based geomechanical model indicated a hydrostatic pore pressure gradient in the region. The relative magnitude of three principle stresses showed a normal fault stress regime and maximum horizontal stress (SHmax) azimuth appeared to be nearly aligned to the N-S direction. Hole Stability analysis showed that a minimum of 12 ppg mud weight was required to drill the 8½" section. The sidetrack holes had a maximum inclination of 75 to 77 degrees. Different polymers and bridging agents were added to prepare the customized HPWBM in order to address shale instability and formation damage due to overbalance. Real-time monitoring during drilling operation utilized logging while drilling (LWD) log data, drilling parameters and mud logging data to promote smooth drilling operations. Through systematic planning and execution, the high-angle sidetrack holes had been drilled with zero non-productive time (NPT) in terms of well bore stability. More than 50% cost reduction was achieved on the mud system.
An integrated solution that includes pre-drill geomechanics, HPWBM system design and real-time well monitoring helped to reduce the risks due to model uncertainties while drilling high angle wells through the thick shale section. This approach helped to reduce significant operational cost with an improved success rate.
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
Massive hydraulic fracturing requires an enormous consumption of water and introduces many potential environmental issues. In addition, water-based fluid tends to be trapped in formations, reducing oil/gas-phase relative permeability, and causes clay-mineral swelling, which lowers absolute permeability. Carbon dioxide (CO2) is seen as a promising alternative working fluid that poses no formation-damage risk, and it can stimulate more-complex and extensive fracture networks. However, very little, if any, extant research has quantitatively analyzed the effectiveness of CO2 fracturing, except for some qualitative fracturing experiments that are based on acoustic emissions. In this study, we systematically examine water and CO2 fracturing, and compare their performance on the basis of a rigorously coupled geomechanics and a fluid-heat-flow model. Parameters investigated include fluid viscosity, compressibility, in-situ stress, and rock permeability, illustrating how they affect breakdown pressure (BP) and leakoff, as well as fracturing effectiveness. It is found that (1) CO2 has the potential to lower BP, benefiting the propagation of fractures; (2) water fracturing tends to create wider and longer tensile fractures compared with CO2 fracturing, thereby facilitating proppant transport and placement; (3) CO2 fracturing could dramatically enhance the complexity of artificial fracture networks even under high-stress-anisotropy conditions; (4) thickened CO2 tends to generate simpler fracture networks than does supercritical CO2 (SC-CO2), but still more-complex fracture networks than fresh water; and (5) the alternative fracturing scheme (i.e., SC-CO2 fracturing followed by thickened-CO2 fracturing) can readily create complex fracture networks and carry proppant to keep hydraulic fractures open. This study reveals that, for intact reservoirs, water-based fracturing can achieve better fracturing performance than CO2 fracturing; however, for naturally fractured reservoirs, CO2 fracturing can constitute an effective way to stimulate tight/shale oil/gas reservoirs, thereby improving oil/gas production.
Controlled laboratory experiments and some field studies have shown that the onset of sand production in gas wells differs from that in oil wells. Results from a general 3D sand-production numerical model are presented to explain the differences in the onset of sanding and sand-production volume for different fluids and under different flow and in-situ stress conditions. The sand-production model accounts for multiphase-fluid flow and is fully coupled with an elasto-plastic geomechanical model. The sanding criterion considers both mechanical failure and sand erosion by fluid flow. Non-Darcy flow is implemented to account for the high flow rates. The drag forces on the sand grains are computed on the basis of the in-situ Reynolds number. Both the intact rock strength and the residual rock strength depend on water saturation. Water evaporation (drying) resulting from gas flow is modeled using phase equilibrium calculations.
The onset of sand production is compared for different fluid types (oil and gas). Model results are shown to be consistent with experimental observations reported in the literature. For example, the onset of sanding is observed at higher compressive stresses for gas wells as compared with oil wells. The primary mechanism for this is for the first time shown to be sand strengthening induced by evaporation of water. This effect is not observed in oil wells. The sand-production rate when non-Darcy effects are considered is lower than for Darcy flow. The reason for this is the lower fluid velocity (for the same drawdown) and, consequently, smaller drag forces on the failed sand grains. The effect of water breakthrough and water cut on sand production is studied from both mechanical and erosion perspectives. The model is shown to be capable of accurately predicting the onset of sanding and sand production induced by multiphase- and compressible-fluid flows, helping us to predict sanding issues in both oil and gas wells.
Previous experimental observations have shown the formation of distinct failure patterns and cavity shapes under different stress and flow conditions. With isotropic stress, spiral failure patterns with localized shear bands are likely to form. On the other hand, under anisotropic stress, V-shaped cavities, dog-ear cavities, or slit-mode cavities are usually observed. However, the mechanisms for the development of these sanding cavities have not been fully articulated. In addition, to accurately predict the onset of sanding and to predict the sand-production rate, it is crucial to capture the physics of the formation of these cavities during sand production.
This paper presents a fully coupled poro-elasto-plastic, 3D sand-production model for sand-production prediction around openhole and perforated wellbores in a weakly consolidated formation. Sanding criteria are based on a combination of shear failure, tensile failure, and compressive failure from the Mohr-Coulomb theory and strain-hardening/softening. After the failure criteria are met, an algorithm for the entrainment of the sand based on the calculation of hydrodynamic forces is implemented to predict sand erosion and transport. Dynamic mesh refinement has been implemented to effectively capture the strain-localization regions.
The model has been validated with multiple analytical solutions. In addition, it is applied to compare with previous sand-production experiments that have explored the different cavity shapes formed under different conditions. The model is capable of not only explaining the mechanisms responsible for each type of cavity shape but also predicting the cavity shape that will be formed under a specific set of conditions. Parametric studies for these cases provide an additional insight into the important role that the post-yield, poro-elastoplastic properties of the sand play in controlling the sanding mechanisms and cavity development. This allows us to predict, much more accurately, the onset of sanding and the sanding rate.