Transient Coupling of Swab/Surge Pressure and In-Situ Stress for Wellbore-Stability Evaluation During Tripping

SPE Journal ◽  
2018 ◽  
Vol 23 (04) ◽  
pp. 1019-1038 ◽  
Author(s):  
Feifei Zhang ◽  
Yongfeng Kang ◽  
Zhaoyang Wang ◽  
Stefan Miska ◽  
Mengjiao Yu ◽  
...  
Keyword(s):  
Stability Analysis ◽  
Pore Pressure ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Pressure Oscillations ◽  
Deepwater Drilling ◽  
Wellbore Pressure ◽  
Operating Window ◽  
Safe Operating

Summary This paper identifies wellbore-stability concerns caused by transient swab/surge pressures during deepwater-drilling tripping and reaming operations. Wellbore-stability analysis that couples transient swab/surge wellbore-pressure oscillations and in-situ-stress field oscillations in the near-wellbore (NWB) zone in deepwater drilling is presented. A transient swab/surge model is developed by considering drillstring components, wellbore structure, formation elasticity, pipe elasticity, fluid compressibility, fluid rheology, and the flow between wellbore and formation. Real-time pressure oscillations during tripping/reaming are obtained. On the basis of geomechanical principles, in-situ stress around the wellbore is calculated by coupling transient wellbore pressure with swab/surge pressure, pore pressure, and original formation-stress status to perform wellbore-stability analysis. By applying the breakout failure and wellbore-fracture failure in the analysis, a work flow is proposed to obtain the safe-operating window for tripping and reaming processes. On the basis of this study, it is determined that the safe drilling-operation window for wellbore stability consists of more than just fluid density. The oscillation magnitude of transient wellbore pressure can be larger than the frictional pressure loss during the normal-circulation process. With the effect of swab/surge pressure, the safe-operating window can become narrower than expected. The induced pore pressure decreases monotonically as the radial distance increases, and it is limited only to the NWB region and dissipates within one to two hole diameters away from the wellbore. This study provides insight into the integration of wellbore-stability analysis and transient swab/surge-pressure analysis, which is discussed rarely in the literature. It indicates that tripping-induced transient-stress and pore-pressure changes can place important impacts on the effective-stress clouds for the NWB region, which affect the wellbore-stability status significantly.

APPLICATION OF GUIDELINE CHARTS IN DECISIONMAKING ON WELL TRAJECTORY AND MUD WEIGHT PROGRAM

2001 ◽  
Vol 41 (1) ◽  
pp. 609
Author(s):  
X. Chen ◽  
C.P. Tan ◽  
C.M. Haberfield
Keyword(s):  
Stability Analysis ◽  
Case Studies ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Material Strength ◽  
Stress Regime ◽  
Wellbore Instability ◽  
Well Trajectory

To prevent or minimise wellbore instability problems, it is critical to determine the optimum wellbore profile and to design an appropriate mud weight program based on wellbore stability analysis. It is a complex and iterative decisionmaking procedure since various factors, such as in-situ stress regime, material strength and poroelastic properties, strength and poroelastic anisotropies, initial and induced pore pressures, must be considered in the assessment and determination.This paper describes the methodology and procedure for determination of optimum wellbore profile and mud weight program based on rock mechanics consideration. The methodology is presented in the form of guideline charts and the procedure of applying the methodology is described. The application of the methodology and procedure is demonstrated through two field case studies with different in-situ stress regimes in Australia and Indonesia.

Numerical Modeling of Sand Production Potential Estimation and Passive Control Optimization: A Case Study

2018 ◽  
Author(s):  
Eva Lopez-Puiggene ◽  
Nubia Aurora Gonzalez-Molano ◽  
Jose Alvarellos-Iglesias ◽  
Jose M. Segura ◽  
M. R. Lakshmikantha
Keyword(s):  
Stress State ◽  
High Resolution ◽  
Plastic Strain ◽  
Pore Pressure ◽  
In Situ Stress ◽  
Point Of View ◽  
Wellbore Stability ◽  
Sand Production ◽  
Production Stress

Solids/sand production is an unintended byproduct of the hydrocarbon production that, from an operational point of view, might potentially lead to undesirable consequences. This paper focuses on a study centered in the geomechanical perspective for solids production. An integrated workflow is presented to analyze the combined effect of reservoir pore-pressure, drawdown, in-situ stress, rock properties and well/perforations orientation on the onset of solid production. This workflow incorporates analyses at multiple scales: rock constitutive modeling at lab scale, 1D geomechanical models at wellbore scale along well trajectories, a 3D geomechanical model at the reservoir scale and 3D/4D high resolution reservoir - geomechanical coupled models at the well and perforation scale. 1D geomechanical models were built using log and field data, drilling experience and laboratory tests in order to characterize in situ stresses, pore pressure and rock mechanics properties (stiffness and strength) profiles for several wells. Rock shear failure mechanism was also analyzed in order to build a pre-drill model and evaluate the wellbore stability from a geomechanical point of view. Pre-production stress modeling was simulated to obtain a representative initial stress state integrating 1D geomechanics well results, 3D dynamic model and seismic interpretations. Mechanical properties were distributed considering properties calculated in the 1D geomechanical models as input. 3D stress field was validated with in-situ stress profiles from 1D modeling results. This simulated pre-production stress state was then used as an initial condition for the reservoir - geomechanical coupled simulations. Effective stress changes and deformations associated to pore pressure changes were calculated including the coupling between reservoir and geomechanical modeling. Finally, a 3D/4D high resolution well scale reservoir - geomechanical coupled numerical model was built in order to determine the threshold of sand production. A limit of plastic strain was obtained based on numerical simulations of available production data, DST and ATWC tests. This critical plastic strain limit was used as a criterion (strain-based) for rock failure to define the onset of sand production as a function of pore pressure, perforation orientation and rock strength. Conclusions regarding the perforation orientations related to the possibility of producing solids can support operational decisions in order to avoid undesirable solid production and therefore optimize the production facilities capacity and design to handle large amounts of solids and/or the clogging of the well.

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.

scholarly journals Wellbore stability analysis based on the stress model around boreholes

2018 ◽  
Vol 1 (T5) ◽  
pp. 290-301
Author(s):  
Khanh Quang Do ◽  
Nam Nguyen Hai Le ◽  
Quang Trong Hoang ◽  
Huy Xuan Nguyen
Keyword(s):  
Stability Analysis ◽  
Oil And Gas ◽  
Wellbore Stability ◽  
Rock Properties ◽  
Stress Model ◽  
Gas Drilling ◽  
Wellbore Pressure ◽  
Tensile Fractures ◽  
Matlab Programming

Wellbore stability analysis plays an important role in the oil and gas drilling. Instability problems during the drilling phase are often the results of a combination of both mechanical and chemical effects. This study aims to assess the mechanical wellbore stability based on the stress model around boreholes. The development of the stress model around boreholes, which is associated with the in-situ stresses, rock properties as well as the wellbore pressure and configuration, are presented. It could visualize the stress distribution around an arbitratily orientated wellbore. Next, lower hemisphere diagrams are presented to demonstrate the wellbore pressure required to initiate borehole tensile and compressive failures. A program for the risk analysis of wellbore (RAoWB) is designed and developed by the Matlab programming language to describe and analyse the risk diagrams of the drilling induced tensile fractures (DITFs) and breakouts (BOs). They help to choice the optimum wellbore trajectories for well planning, as well as to predict the wellbore instabilities caused by inappropriate wellbore pressures.

A Novel Method to Determine the Drilling Fluid Density for Gypsum-Salt Layer

2021 ◽  
Author(s):  
Jitong Liu ◽  
Wanjun Li ◽  
Haiqiu Zhou ◽  
Yixin Gu ◽  
Fuhua Jiang ◽  
...  
Keyword(s):  
Drilling Fluid ◽  
In Situ Stress ◽  
Wellbore Stability ◽  
Shrinkage Rate ◽  
Fluid Density ◽  
Salt Layer ◽  
Rock Creep ◽  
Key Factor ◽  
Well Abandonment

Abstract The reservoir underneath the salt bed usually has high formation pressure and large production rate. However, downhole complexities such as wellbore shrinkage, stuck pipe, casing deformation and brine crystallization prone to occur in the drilling and completion of the salt bed. The drilling safety is affected and may lead to the failure of drilling to the target reservoir. The drilling fluid density is the key factor to maintain the salt bed’s wellbore stability. The in-situ stress of the composite salt bed (gypsum-salt -gypsum-salt-gypsum) is usually uneven distributed. Creep deformation and wellbore shrinkage affect each other within layers. The wellbore stability is difficult to maintain. Limited theorical reference existed for drilling fluid density selection to mitigate the borehole shrinkage in the composite gypsum-salt layers. This paper established a composite gypsum-salt model based on the rock mechanism and experiments, and a safe-drilling density selection layout is formed to solve the borehole shrinkage problem. This study provides fundamental basis for drilling fluid density selection for gypsum-salt layers. The experiment results show that, with the same drilling fluid density, the borehole shrinkage rate of the minimum horizontal in-situ stress azimuth is higher than that of the maximum horizontal in-situ stress azimuth. However, the borehole shrinkage rate of the gypsum layer is higher than salt layer. The hydration expansion of the gypsum is the dominant reason for the shrinkage of the composite salt-gypsum layer. In order to mitigate the borehole diameter reduction, the drilling fluid density is determined that can lower the creep rate less than 0.001, as a result, the borehole shrinkage of salt-gypsum layer is slowed. At the same time, it is necessary to improve the salinity, filter loss and plugging ability of the drilling fluid to inhibit the creep of the soft shale formation. The research results provide technical support for the safe drilling of composite salt-gypsum layers. This achievement has been applied to 135 wells in the Amu Darya, which completely solved the of wellbore shrinkage problem caused by salt rock creep. Complexities such as stuck string and well abandonment due to high-pressure brine crystallization are eliminated. The drilling cycle is shortened by 21% and the drilling costs is reduced by 15%.

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