Modeling Time-Dependent Pore Pressure Due to Capillary and Chemical Potential Effects and Resulting Wellbore Stability in Shales

2003 ◽  
Vol 125 (3) ◽  
pp. 169-176 ◽  
Author(s):  
M. K. Rahman ◽  
Zhixi Chen ◽  
Sheik S. Rahman
Keyword(s):  
Pore Pressure ◽  
Chemical Potential ◽  
Normal Fault ◽  
Wellbore Stability ◽  
Time Dependent ◽  
Analytical Models ◽  
Analysis Model ◽  
Stress Regime ◽  
Dependent Change ◽  
Drilling Operations

During drilling operations, the mud filtrate interacts with the pore fluid around the wellbore and changes pore pressure by capillary and chemical potential effects. Thus the change in pore pressure around borehole becomes time-dependent, particularly in extremely low permeability shaley formations. In this paper, the change in pore pressure due to capillary and chemical potential effects are investigated experimentally. Analytical models are also developed based on the experimental results. A wellbore stability analysis model incorporating the time-dependent change in pore pressure is applied to a vertical well in a shale formation under normal fault stress regime.

The Effects of Filter-Cake Buildup and Time-Dependent Properties on the Stability of Inclined Wellbores

SPE Journal ◽  
2011 ◽  
Vol 16 (04) ◽  
pp. 1010-1028 ◽  
Author(s):  
Minh H. Tran ◽  
Younane N. Abousleiman ◽  
Vinh X. Nguyen
Keyword(s):  
Pore Pressure ◽  
Filter Cake ◽  
Wellbore Stability ◽  
Time Dependent ◽  
Transient Effects ◽  
Drilling Mud ◽  
Property Variation ◽  
Lost Circulation ◽  
Wellbore Strengthening ◽  
Formation Pore Pressure

Summary The effects of filter-cake buildup and/or filter-cake-property variation with time on wellbore stability have been plaguing the industry. The increasing use of lost-circulation materials (LCMs) in recent years for wellbore strengthening in weak and/or depleted formations necessitates models that can predict these effects. However, the complexities of effective-stress and pore-pressure evolution around the borehole while drilling, coupled with the transient variation of mud-filtration properties, have delayed such modeling efforts. In this paper, the analytical solutions for the time-dependent effects of mudcake buildup and mudcake properties on the wellbore stresses and formation pore pressure, and thus the safe-drilling-mud-weight window, are derived. The transient effects of mudcake buildup and mudcake buildup coupled with its permeability reduction during filtration on the safe-drilling-mudweight window are illustrated through numerical examples. The results showed that the safe-mudweight windows were greatly affected by the buildup of filter cake and its permeability variation. For example, the analysis for filter-cake buildup with cake permeability of 10–2 md showed that the safe-mudweight window was widened by 0.5 g/cc after 2.5 hours post-excavation when compared to the case of a wellbore without mudcake. On the other hand, a lower mudcake permeability of 10–3 md widened the mudweight window by as much as 1 g/cc. Last but not least, the analyses revealed that even for mudcake permeability as low as 10–3 md, neglecting the permeable nature of the mudcake can result in overestimation of the safe-drilling-mudweight window.

The Essence of Horizontal Drilling Challenges in Depleted Reservoirs

2021 ◽  
Author(s):  
Rida Mohamed Elgaddafi ◽  
Victor Soriano ◽  
Ramadan Ahmed ◽  
Samuel Osisanya
Keyword(s):  
Pore Pressure ◽  
Horizontal Well ◽  
New Technology ◽  
Horizontal Wells ◽  
Stability Loss ◽  
Wellbore Stability ◽  
Planning Stage ◽  
Horizontal Drilling ◽  
Infill Drilling ◽  
Drilling Operations

Abstract Horizontal well technology is one of the major improvements in reservoir stimulation. Planning and execution are the key elements to drill horizontal wells successfully, especially through depleted formations. As the reservoir has been producing for a long time, pore pressure declines, resulting in weakening hydrocarbon-bearing rocks. Drilling issues such as wellbore stability, loss circulation, differential sticking, formation damage remarkably influenced by the pore pressure decline, increasing the risk of losing part or even all the horizontal interval. This paper presents an extensive review of the potential issues and solutions associated with drilling horizontal wells in depleted reservoirs. After giving an overview of the depleted reservoir characteristics, the paper systematically addresses the major challenges that influence drilling operations in depleted reservoirs and suggests solutions to avoid uncontrolled risks. Then, the paper evaluates several real infill drilling operations through depleted reservoirs, which were drilled in different oilfields. The economic aspect associated with potential risks for drilling a horizontal well in depleted reservoirs is also discussed. The most updated research and development findings for infill drilling are summarized in the article. It is recommended to use wellbore strengthening techniques while drilling a horizontal well through highly depleted formations. This will allow using higher mud weight to control unstable shales while drilling through the production zone. Managed Pressure Drilling should be considered as the last option for highly depleted formations because it will require a greater level of investment which is not going to have a superior rate of return due to the lack of high deliverability of the reservoir. Using rotary steerable systems is favored to reduce risks related to drilling through depleted formations. Precise analysis of different drilling programs allows the drilling team to introduce new technology to reduce cost, improve drilling efficiency and maximize profit. It is the responsibility of the drilling engineer to evaluate different scenarios with all the precautions needed during the planning stage to avoid unexpected issues. The present market conditions and the advancement in technologies for drilling horizontal wells increase the feasibility of producing the depleted reservoirs economically. This paper highlights the challenges in drilling horizontal wells in highly depleted reservoirs and provides means for successfully drilling those wells to reduce risks while drilling

scholarly journals Incorporating electrokinetic effects in the porochemoelastic inclined wellbore formulation and solution

2010 ◽  
Vol 82 (1) ◽  
pp. 195-222 ◽  
Author(s):  
Vinh X. Nguyen ◽  
Youname N. Abousleiman
Keyword(s):  
Pore Pressure ◽  
Chemical Potential ◽  
Electrical Potential ◽  
Three Dimensional ◽  
Biological Tissues ◽  
Exchange Capacity ◽  
Analytical Models ◽  
Pressure Distributions ◽  
Pressure Chemical ◽  
Benchmark Solutions

The porochemoelectroelastic analytical models and solutions have been used to describe the response of chemically active and electrically charged saturated porous media such as clays, shales, and biological tissues. However, these attempts have been restricted to one-dimensional consolidation problems, which are very limited in practice and not general enough to serve as benchmark solutions for numerical validation. This work summarizes the general linear porochemoelectroelastic formulation and presents the solution of an inclined wellbore drilled in a fluid-saturated chemically active and ionized formation, such as shale, and subjected to a three-dimensional in-situ state of stress. The analytical solution to this geometry incorporates the coupled solid deformation and simultaneous fluid/ion flows induced by the combined influences of pore pressure, chemical potential, and electrical potential gradients under isothermal conditions. The formation pore fluid is modeled as an electrolyte solution comprised of a solvent and one type of dissolved cation and anion. The analytical approach also integrates into the solution the quantitative use of the cation exchange capacity (CEC) commonly obtained from laboratory measurements on shale samples. The results for stresses and pore pressure distributions due to the coupled electrochemical effects are illustrated and plotted in the vicinity of the inclined wellbore and compared with the classical porochemoelastic and poroelastic solutions.

scholarly journals Anisotropic Wellbore Stability Analysis: Impact on Failure Prediction

2020 ◽  
Author(s):  
Michinori Asaka ◽  
Rune Martin Holt
Keyword(s):  
Stability Analysis ◽  
Pore Pressure ◽  
Elastic Anisotropy ◽  
Wellbore Stability ◽  
Practical Implementation ◽  
Borehole Stability ◽  
Gas Field ◽  
Drilling Operations ◽  
Failure Predictions ◽  
The Impact

Abstract Shale formations are the main source of borehole stability problems during drilling operations. Suboptimal predictions of borehole failure may partly be caused by neglecting the anisotropic nature of shales: Conventional wellbore stability analysis is based on borehole stresses computed from isotropic linear elasticity (Kirsch solution) with the assumption of no induced pore pressure. This is very convenient for a practical implementation but does not always work for shales. Here, anisotropic wellbore stability analysis was performed targeting an offshore gas field to investigate in particular the impact of elastic anisotropy on borehole failure predictions. Stress concentration around a circular borehole in anisotropic shale was calculated by the Amadei solutions, and induced pore pressure was obtained from the Skempton parameters based on anisotropic poroelasticity. Borehole failure regions and modes were then predicted using the effective stresses and those are apparently consistent with observations. A comparison with the conventional approach suggests the importance of accounting for elastic anisotropy: Predicted failure regions, modes, and also the associated mud weight limits can be completely different. This observation may have significant implications for other fields since shale often show strong elastic anisotropy.

Wellbore-Stability Analysis by Integrating a Modified Hoek-Brown Failure Criterion With Dual-Porochemoelectroelastic Theory (includes associated erratum)

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 1957-1981 ◽  
Author(s):  
Chao Liu ◽  
Yanhui Han ◽  
Hui–Hai Liu ◽  
Younane N. Abousleiman
Keyword(s):  
Stability Analysis ◽  
Pore Pressure ◽  
Failure Criterion ◽  
Rock Strength ◽  
Chemical Potential ◽  
Wellbore Stability ◽  
Natural Fracture ◽  
Analysis Tool ◽  
Drilling Mud

Summary When drilling through naturally fractured formations, the existence of natural fractures affects the fluid diffusion and stress distribution around the wellbore and induces degradation of rock strength. For chemically active formations, such as shale, the chemical–potential difference between the drilling mud and the shale–clay matrix further complicates the nonmonotonic coupled pore–pressure processes in and around the wellbore. In this work, we apply a recently formulated theory of dual–porosity/permeability porochemoelectroelasticity to predict the time evolution of mud–weight windows, while calculating stresses and pore pressure around an inclined wellbore drilled in a fractured shale formation. The effects of natural–fracture geometric and spatial distributions coupled with the chemical activity are considered in the wellbore–stability analysis. To account for the degrading effect of the fractured shale matrix on the bulk rock strength, a modified Hoek–Brown (MHB) criterion is developed to more closely describe the in–situ state of stress effects on the compressive shearing strength at great depth. Compared with the original Hoek–Brown (HB) failure criterion, the MHB criterion considers the influence of the intermediate principal stress and thus shows better agreement with true–triaxial data for various rocks at varying stress levels. The MHB criterion converges to the original HB criterion when the confining in–situ stresses are equal. Two field case studies indicate that this novel integrative methodology is capable of predicting the operational drilling–mud–weight windows used in these two cases. Another advantage of this newly developed technique is that it can be used as a back–analysis tool to estimate the fracture–matrix permeability from field operational data.

scholarly journals Geomechanical Analysis for Deep Shale Gas Exploration Wells in the NDNR Blocks, Sichuan Basin, Southwest China

Energies ◽  
2020 ◽  
Vol 13 (5) ◽  
pp. 1117 ◽  
Author(s):  
Majia Zheng ◽  
Hongming Tang ◽  
Hu Li ◽  
Jian Zheng ◽  
Cui Jing
Keyword(s):  
Pore Pressure ◽  
Shale Gas ◽  
Sichuan Basin ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Geomechanical Model ◽  
Stress Regime ◽  
Xujiahe Formation ◽  
Geomechanical Analysis

The abundant reserve of shale gas in Sichuan Basin has become a significant natural gas component in China. To achieve efficient development of shale gas, it is necessary to analyze the stress state, pore pressure, and reservoir mechanical properties such that an accurate geomechanical model can be established. In this paper, Six wells of Neijiang-Dazu and North Rongchang (NDNR) Block were thoroughly investigated to establish the geomechanical model for the study area. The well log analysis was performed to derive the in-situ stresses and pore pressure while the stress polygon was applied to constrain the value of the maximum horizontal principal stress. Image and caliper data, mini-frac test and laboratory rock mechanics test results were used to calibrate the geomechanical model. The model was further validated by comparing the model prediction against the actual wellbore failure observed in the field. It was found that it is associated with the strike-slip (SS) stress regime; the orientation of SHmax was inferred to be 106–130° N. The pore pressure appears to be approximately hydrostatic from the surface to 1000 m true vertical depth (TVD), but then becomes over-pressured from the Xujiahe formation. The geomechanical model can provide guidance for the subsequent drilling and completion in this area and be used to effectively avoid complex drilling events such as collapse, kick, and lost circulation (mud losses) along the entire well. Also, the in-situ stress and pore pressure database can be used to analyze wellbore stability issues as well as help design hydraulic fracturing operations.

Application of Artificial Intelligence To Predict Time-DependentMud-Weight Windows in Real Time

SPE Journal ◽  
2021 ◽  
pp. 1-21
Author(s):  
Dung T. Phan ◽  
Chao Liu ◽  
Murtadha J. AlTammar ◽  
Yanhui Han ◽  
Younane N. Abousleiman
Keyword(s):  
Artificial Intelligence ◽  
Neural Networks ◽  
Analytical Solution ◽  
Real Time ◽  
Analytical Solutions ◽  
Wellbore Stability ◽  
Time Dependent ◽  
Processing Unit ◽  
Inference System ◽  
Drilling Operations

Summary Selection of a safe mud weight is crucial in drilling operations to reduce costly wellbore-instability problems. Advanced physics models and their analytical solutions for mud-weight-window computation are available but still demanding in terms of central-processing-unit (CPU) time. This paper presents an artificial-intelligence (AI) solution for predicting time-dependent safe mud-weight windows and very refined polar charts in real time. The AI agents are trained and tested on data generated from a time-dependent coupled analytical solution (poroelastic) because numerical solutions are prohibitively slow. Different AI techniques, including linear regression, decision tree, random forest, extra trees, adaptive neuro fuzzy inference system (ANFIS), and neural networks are evaluated to select the most suitable one. The results show that neural networks have the best performances and are capable of predicting time-dependentmud-weight windows and polar charts as accurately as the analytical solution, with 1/1,000 of the computer time needed, making them very applicable to real-time drilling operations. The trained neural networks achieve a mean squared error (MSE) of 0.0352 and a coefficient of determination (R2) of 0.9984 for collapse mud weights, and an MSE of 0.0072 and an R2 of 0.9998 for fracturing mud weights on test data sets. The neural networks are statistically guaranteed to predict mud weights that are within 5% and 10% of the analytical solutions with probability up to 0.986 and 0.997, respectively, for collapse mud weights, and up to 0.9992 and 0.9998, respectively, for fracturing mud weights. Their time performances are significantly faster and less demanding in computing capacity than the analytical solution, consistently showing three-orders-of-magnitude speedups in computational speed tests. The AI solution is integrated into a deployed wellbore-stability analyzer, which is used to demonstrate the AI’s performances and advantages through three case studies.

Coupled Thermal-Hydro-Mechanical-Chemical Modeling for Time-Dependent Anisotropic Wellbore Stability Analysis

2021 ◽  
Author(s):  
Jingyou Xue ◽  
Kenji Furui
Keyword(s):  
Stability Analysis ◽  
Chemical Potential ◽  
Bedding Plane ◽  
Wellbore Stability ◽  
Time Dependent ◽  
Drilling Fluids ◽  
Shale Formations ◽  
Wellbore Instability ◽  
Bedding Planes ◽  
Stress Changes

<p>Wellbore instability is one of the most serious drilling problems increasing well cost in well construction processes. It is widely known that many wellbore instability problems are reported in shale formations where water sensitive clay mineral exist. The problems become further complicated when the shale exhibits variation in strength properties along and across bedding planes. In this study, a coupled thermal-hydro-mechanical-chemical (THMC) model was developed for time-dependent anisotropic wellbore stability analysis considering chemical interactions between swelling shale and drilling fluids, thermal effects, and poro-elastoplastic stress-strain behaviors.</p><p>The THMC simulator developed in this work assumes that the shale formation behaves as an ion exchange membrane where swelling depends on chemical potential of drilling fluids invading from the wellbore to the pore spaces. The time-dependent chemical potential changes of water within the shale are evaluated using an analytical diffusion equation resulting in the evolution of swelling strain around the wellbore. On the other hand, the thermal and pressure diffusion equations are evaluated numerically by finite differences. The stress changes associated with thermal, hydro, and chemical effects are coupled to the 3D poroelastoplastic finite element model. The effects of bedding planes are also taken into account in the FEM model through the crack tensor method in which the normal and tangential stiffnesses of the bedding planes have stress dependency. The failure of the formation rock is judged based on the critical plastic strain limit.</p><p>The numerical analysis results indicate that the rock strength anisotropy induced by the existence of bedding planes is the most important factor influencing the stability of the wellbore among various THMC process parameters investigated in this work. The numerical results also reveal that an established theory to orient the wellbore in the direction of the minimum principal stress is not always a favorable option when the effect of the anisotropy of in-situ stresses and the distribution angle of bedding planes cancel out each other. Depending on both the distribution angle of bedding plane and ratio of the vertical to the horizontal stress, the trend of minimum mud pressure showed a great variation as predicted by the yield and failure criterion implemented in the model. Furthermore, the analysis results reveal that the distribution and evolution of plastic strains caused by the THMC processes have the time dependency, which can be controlled by the temperature and salinity of the drilling fluids.</p><p>The numerical wellbore stability analysis model considering shale swelling and bedding plane effects provides an effective tool for designing optimum well trajectories and determining safe mud weight windows for drilling complex shale formations. The time-dependent margins of safe mud weight window of drilling can be fine-tuned when the interaction among various parameters is fully considered as the THMC processes.</p>

Role of Geomechanics in Identification of Possible Mechanisms for Non-productive Times NPT and Improving Drilling Operations in a Mature Field in Offshore Sarawak, Malaysia

2021 ◽  
Author(s):  
Avirup Chatterjee ◽  
Amitava Ghosh ◽  
Priveen Raj Santha Moorthy
Keyword(s):  
Wellbore Stability ◽  
Time Dependent ◽  
Geomechanical Model ◽  
Weak Rocks ◽  
Dependent Failures ◽  
Drilling Operations ◽  
Mature Field ◽  
Productive Time ◽  
Numerous Time

Abstract This paper presents a case study on the role of geomechanics to identify possible failure mechanisms for non-productive time (NPT), avoid drilling risks and minimize costs in a field development drilling campaign, Offshore Sarawak Malaysia. Drilling optimization and reducing NPT for the drilling campaign was one of the key focus for maintaining the drilling time and costs. Drilling of moderately to highly deviated wells in this field has proven to be extremely challenging. Numerous lost-time incidents due to tight hole, stuck pipe, pack-off, casing held up were experienced, particularly when drilling through the shallow overburden shales and deeper reservoirs interbedded with shales and coals. Faced with continually increased NPTs, a geomechanical model was developed using regional offset wells to understand the mechanism of failures. A geomechanical model was developed to quantify the minimum recommended mud weights and optimize the wellbore trajectories. The outcome of this study was used as key input for casing and mud design. The in-situ stress state derived from field wide geomechanical model indicates the field is associated with a normal faulting stress regime, i.e., Shmin < SHmax < SV. The presence of relatively weak rocks means the field is potentially subject to stress-induced wellbore instability problems. However, observations of numerous time-dependent failures imply secondary influences must also be considered to arrive at possible remediation strategies. It was observed that the combination of weak rocks and numerous time-dependent failures using different types of mud system have contributed to wellbore stability problems. The wellbore stability is due to reactive shale, which is time sensitive as majority of the drilling problems are observed after drilling. The major contributor to the time-dependent deterioration process is mechanical and chemical imbalances between shale and drilling fluids compounded by large open-hole exposure area and contact time resulting in rising pore pressure caused by the invasion of drilling fluid into the formations, and then exacerbated by less-than-optimal drilling practices. This finding, together with improved geomechanical understanding of the field helped to evaluate the safe mud weight windows, formulate the mud designs and optimize drilling practices. All the planned wells were drilled successfully without any loss time incidents and non-productive time. This paper presents an integrated approach and workflow that combines the drilling data and formation response to identify the most likely causative mechanisms of the time-delayed wellbore instabilities in a mature field. This knowledge was then used to develop strategies for optimizing future drilling operations in the field.

Integrated Mechanical Earth Modeling for Predicting Sand Production: A Case Study

2021 ◽  
pp. 1-19
Author(s):  
Aymen Al-Ameri
Keyword(s):  
Pore Pressure ◽  
Shear Failure ◽  
Normal Fault ◽  
Horizontal Stress ◽  
Reservoir Pressure ◽  
Sand Production ◽  
Stress Regime ◽  
Sand Control ◽  
Formation Pore Pressure ◽  
Minimum Horizontal Stress

Summary Sand production is a serious problem in oil and gas wells, and one of the main concerns of production engineers. This problem can damage downhole equipment and surface production facilities. This study presents a sand production case and quantifies sanding risks for an oil field in Iraq. The study applies an integrated workflow of constructing 1D Mechanical Earth Modeling (MEM) and predicting the sand production with multiple criteria such as shear failure during drilling, B index, and critical bottomhole pressure (CBHP) or critical drawdown pressure (CDDP). Wireline log data were used to estimate the mechanical properties of the formations in the field. The predicted sand production propensity was validated based on the sand production history in the field. The interpretation results of some wells anticipated in this study showed that when a shear failure occurs during drilling, the B index is around 2 × 104 MPa or less and the CBHP is equal to the formation pore pressure. For this case, sand control shall be carried out in the initial stage of production. On the other hand, when the shear failure does not exist, the B index is always greater than 2 × 104 MPa, and the CBHP is mostly less than the formation pore pressure. In this case, implementing sand control methods could be postponed as the reservoir pressure undergoes depletion. However, for the anticipated field, sand control is recommended to be carried out in the initial stage of well production even when the CBHP is less than the formation pore pressure since sanding will be inevitable when the reservoir pressure depletes to values close to the initial reservoir pressure. The tentative evaluation of the stress regime showed that a normal fault could be the stress regime for the formations. For a normal fault stress regime, the study explained that when the reservoir permeability is isotropic, an openhole vertical wellbore has less propensity for sand production than a horizontal wellbore. Moreover, when the wellbore azimuth is in the direction of the minimum horizontal stress, the CBHP will be lower than in any other azimuth, and sanding will take place at higher wellbore inclination angles. For the anticipated field, because of the casedhole well completion and the anisotropic reservoir permeability, a horizontal well drilled in the direction of minimum horizontal stress with oriented perforation in the direction of maximum horizontal stress is an alternative method for controlling sand production.

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