Borehole stability issues are always a spotlight in drilling activities because of their costly consequences, including borehole collapse, lost circulation, stuck pipe etc. Wellbore instability is primarily a function of how rocks respond to the induced stress concentration around the wellbore during various drilling activities. By considering different failure mechanisms between the formation and drilling fluid interaction, several major wellbore models have been presented over the last seventy years. Those models take into account the mechanical, chemical, hydraulic, or thermal effects between the drilling fluid and the formation, or couple two or more effects in a model. The time effect is also taken into account in some of the models. In most of the models,the rock is treated as a continuous materialborehole failure is normally based on single initial failure point. However, rocks are discontinuous materials formed under an environment of complex stresses. Also, it is likely an overstatement to say that instability occurs when only one point fails. Even if a small group of grains disconnects from wellbore, the well can still be stable. While somewhat irregular (noncircular) the wellbore can still accommodate casing and installation of down-hole equipment. Therefore, this paper also introduces a new approach based on grain-scale discrete element modeling (DEM) to mimic the realistic rock condition. The rock is modeled as an assembly of numerous grains bonded by cement-like materials, and pore spaces are formed between the small grains. The dynamics of rock grains is simulated and tracked on a computer. Micro cracks (because of tensile or shear failure) occurring at stress-concentrated zones and their coalescence to form macro fractures are tracked. The borehole shape and size are tracked with time. This paper is useful to those who wish to understand the main limitations of the conventional models and the potential usefulness of a new approach based on a discrete element method (DEM). The approach presented in this paper can also help engineers understand how wellbore instability (post-initial failure) develops with time. Introduction Subsurface rocks are under a balanced stress condition before a well is drilled. Such equilibrium will be disturbed when a well is drilled. Although drilling fluid can partially support the wellbore surface, the presence of a wellbore can cause the redistribution of stresses around the borehole. If the stress concentration exceeds the strength of the rock, failure in the nearwellbore region occurs. Wellbore stability is a major concern in drilling operations. It is the major cause of nonproductive time during drilling operation and costs the oil and gas industry more than $6 billion USD worldwide annually (SPE review, SPE-UK, 2005). With the increasing demand of energy (oil and gas), drilling operations move to the direction where more and more harsh environments are encountered. With more wells to be drilled under high pressure and high temperature conditions, the industry expects more severe wellbore stability problems to occur. Although wellbore stability has been studied (experimentally and theoretically) for many years, it remains one of the major challenges for the oil and gas industry due to the complex nature of the drilled formations. Therefore a better understanding of wellbore stability is of imperative importance for the oil and gas industry. In this paper, the discrete element method (DEM) is adopted in this study to get a better understanding of time-dependent transient wellbore instability that takes place in a realistic rock condition.

Wellbore heat transfer induces wellbore temperature redistribution and can impact wellbore integrity and the ability of the well to perform its required functions effectively as the design intended. Vacuuminsulated-tubing (VIT) is purposed to reduce wellbore tubing fluid heat loss to protect the tubing fluid or the outside components. Accurate prediction of the wellbore operating temperature during the design phase is essential especially for a VIT well because of its natural difference from the regular pipe.VIT pipe consists of a vacuum section and connector section. The vacuum section has a much better insulation effect than that of the connector, inducing ЉnonuniformЉ heat transfer. This generates significant annulus temperature spikes along the axial direction; up to 50°F in half VIT unit length, 20 ft in field observation ). Conventionally, axial temperature gradient is ignored with regular pipe because it is negligible compared with radial temperature gradient. This is no longer applicable for VIT because these temperature spikes enhance free convection significantly. This paper presents a novel wellbore heat transfer model to provide accurate temperature prediction for a VIT well.Operators use a higher averaged overall thermal conductivity values over VIT because it yields acceptable conservative incremental pressure in annular pressure buildup (APB) calculation, which matches their field observations. There is still uncertainty about modeling with different thermal conductivity values for the VIT vacuum section and connector in conventional commercial simulators that produce high-temperature spikes and relative unreasonable low incremental pressure. Field case study results with this new model show that compared with conventional simulator results the wellbore average temperature increases and the spikes amplitude in the temperature distribution decreases. In addition, whether the connection is insulated or non-insulated plays a critical role in the overall VIT performance. Good connection insulation will increase the overall insulation effect significantly.Literature surveys show few studies on modeling wellbore heat transfer with the enhanced free convection effect inherent to VIT. A conventional wellbore temperature simulator ignores this effect and underestimates the overall wellbore temperature. This paper provides a novel solution model for VIT wellbore temperature prediction, which will be integrated into a commercial advanced casing and tubing design software platform.

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.

Tubular fatigue failures have been commonly reported in geothermal and heavy oil wells with cyclic steam injection operations. Recently, possible fatigue failures in casing connections during multistage fracturing operations have also been reported in the literature. These occurrences raised the question of whether casing fatigue is a real problem, even for shale plays. This paper describes fatigue modeling and analysis of the casing connections during fracturing operations to provide additional information about this issue. The varying casing temperature and temperature-dependent casing loads were obtained using numerical simulations of cyclic hydraulic fracturing operations, such as end of cementing → shut-in → plug and perforation → stimulation (stage 1) → shut-in → plug and perforation → stimulation (stage 2) etc. These simulations were accomplished using commercial software, including a thermal flow simulator and stress analyzer. The previously simulated casing loads were then used to calculate localized stress amplitude, strain amplitude, and maximum stress. Finally, the localized strain and stress values were used as input parameters of fatigue models to estimate the lifetime (cycles) of selected casing sections. The fatigue model was implemented in a computer program and integrated with the thermal flow and stress analysis commercial software, and a field case (shale oil/gas well) was studied with the integrated fatigue simulation. The predicted casing connection fatigue behavior closely correlates with failure field data, and the casing failure location was analyzed and explained in terms of environmental and cyclic stress/strain conditions. The corrosion fatigue appears important for the acidic environment during hydraulic fracturing. The field case study indicates that the fatigue analysis, coupled with numerical thermal-flow analysis and multistring stress analysis, can provide more insight into the failure of casing connections during fracturing operations. Consequently, it is valuable to include fatigue analysis during the wellbore tubular design when multistage fracturing and/or refracturing operations are involved.

Annular pressure buildup (APB) in high-pressure/high-temperature (HP/HT) deepwater wells can result in wellbore failure, even during drill-ahead operations. Manufactured to collapse at a specific pressure and installed on the external casing wall, syntactic foam is an economical solution to mitigate APB and protect casing strings in offshore HP/HT wells. This paper focuses on the modeling and simulation of the effects of syntactic foam deformation on APB in casing/tubing annuli. Syntactic foam is a composite material synthesized by filling a polymer, metal, or ceramic matrix with hollow glass microspheres (HGMSs). Under increasing hydrostatic pressure (HCP), the behavior of the foam material can be described using a HCP-strain curve typically consisting of three regions: linear elastic, plateau, and densification. A multisection linear model was established to express the volumetric strain vs. HCP relationship, which significantly simplifies the APB calculation while still ensuring sufficient accuracy. Analytical correlations were developed for the elastic compressibility and collapse pressure vs. temperature, which can generate feed-in data for the multisection linear model when only limited datasets are available. A workflow was developed for the simulation of syntactic foam effects on APB in HP/HT wells. The syntactic foam models were implemented and integrated into a commercial casing and tubing design software platform. In a simplified example well, numerical simulation results were found to be consistent with the results from analytical calculation. In a case study of an offshore HP/HT well, numerical simulation demonstrates that syntactic foam is a viable and effective option for APB management. Combined with thermal flow and APB simulators, the implementation of the syntactic foam models enables more accurate casing/tubing load analyses. APB simulation including the effects of syntactic foam can provide valuable information to assist well design engineers in the design of HP/HT deepwater wells with long-term well integrity.