Shale is identified as one of the main factors strongly impacting the distribution of stress in the casing and cement sheath system. The risk of radial cracking induced by thermal stress should not be overemphasized, and it highly depends on fluid
temperature in the wellbore and fluid circulation time. Long-term casing and cement integrity is fundamental to the successful and economical development of high-pressure, high-temperature (HPHT) hydrocarbon reservoirs. Casing failure and cement debonding as a result of extreme downhole conditions have been recorded worldwide. Research on casing and cement sheath failure in the past few years has been conducted assuming either plain strain or axisymmetric strain in a
homogeneous formation. It usually underestimates casing deformation and cement sheath failure caused by the effect of a nonhomogeneous formation.
We present a three-dimensional (3D) finite element model consisting of five formation layers to simulate casing and cement sheath mechanical response in interbedded, nonhomogeneous formations. The radial stress of cement sheath is found to be
highly variable and affected by the contrast in Young's moduli in the different formation layers. Maximum stress concentration is predicted in the casing-cement sheath confined by sandstone. Application of this research is useful for casing design, as well as evaluation of downhole failures.
Casing integrity is extremely important to downhole zonal isolation and preventing well instability. The reduction of casing strength not only occurs in directional drilling, but is also observed in vertical drilling with a slight deviation angle. Deteriorated casing in most hydrocarbon wells is reported from the onset of casing wear by the presence of friction force during the rotation of drillpipe. The friction on the casing wall causes the reduction of casing strength. Furthermore, the combination of corrosive drilling fluids with the rotation of drillpipe could dramatically degrade the casing strength. Although casing burst and collapse strength have been emphasized by many researchers, little research has presented the mechanical response of the worn casing. The studies that do exist on casing wear are not relevant for field applications because they do not consider the effects of high temperature and the surrounding formation. Therefore, it is urgent to obtain a proper stress profile of worn casing in order to reveal the true downhole information.
Based on the boundary superposition principle, we propose an analytical solution for the worn casing model that accounts for the contribution of thermal stress. We focus on the stress evolution in worn casing from the effects of high temperature and the confining formation. The predicted results show that the higher thermal loads largely increase the stress concentration of the worn casing, subsequently weakening the casing strength. The finite element solutions indicate that the radial stress in worn casing is not impacted as much as the hoop stress. The remaining part of the worn casing is subject to compression failure, along with an increase of the burst pressure or the elevated temperature.
Multiphase flow in pipe has been intensively investigated since the oneset of oil and gas transportation by pipelines. As flow assurance problems keep arising in recent years, pipeline design solutions are desired for multi-phase flow system. The algorithms have widely guided the design of stream transportation from offshore well head to onshore terminal or platform. Operators would always seek cutting platform number or shut-in producing marginal field whose reserves cannot justify the construction cost. An accurate design of multiphase flow pipeline system is by all means demanded.
Traditional studies focus on gas-oil two-phase flow by deriving empirical or semi-empirical correlations that fit the experimental data. This study investigates a gas-oil-water three-phase pipe flow system. Starting from the momentum and mass conservation equations, force balance, and interaction relationships between different phases, we developed analytical solutions to estimate the pressure drop for stratified flow regime. This general approach can be applied to any gas-oil-water flowing systems. It provides a solid base for nodal analysis, pressure drop calculation for multiphase flow, artificial lift evaluation, etc. to help design and optimize production system. This work can be particularly useful for steady-state distance transportation.
In the boom of unconventional resource exploration, horizontal completion has been widely used. Horizontal well has the advantages of increasing productivity index, preventing gas or water coning, avoiding sanding out, enhancing drainage area, reducing drilling pad and footprint, and accelerating recovery. Although these advantages have been well recognized over vertical completion, the quantitative contribution is not yet to be investigated. The current design of horizontal well is primarily derived from field experience. This consists of more or less arbitrary contents. To fill this gap, this paper presents a model to incorporate production from different lengths of horizontal well, cost of the drilling and completion, discount of revenue, and cost by different timing. The achieved optimum horizontal well design leads to a maximized net present value (NPV) for operators.
For oil reservoir with bottom water and/or gas cap, gas and water conings impose serious problems during the oil production. Coning leads to the premature gas and water breakthrough thus results in high water cut and gas oil ratio, which require a higher surface facility capacity to process excessively produced water and larger three-phase separators to separate gas, oil, and water. Consequences of early breakthrough are large footprint due to large facility, more energy to operate field, and low oil recovery. Even though numerous studies had been focused on solving the critical oil rate for gas and water coning problems, to our knowledge none of them considers the effect of capillary pressure on critical oil rate. The ignorance of capillary pressure caused the error of calculated critical rate to rise to 300%, according to the real field case study.
The errors caused by neglecting capillary pressure are severe in low permeability reservoirs. For the purpose of good production design, we investigated the effect of capillary pressure on critical rate estimation. Our study showed that the calculated critical rates are close to real field critical rates. The existing methods underestimate the critical rate by not taking capillary pressure into account. Therefore, more accurate critical rates can be obtained using our method. With more accurate result more reliable production plan can be designed to maximize the ultimate recovery.