Yang, Xinxiang (University of Alberta) | Kuru, Ergun (University of Alberta) | Gingras, Murray (University of Alberta) | Iremonger, Simon (Sanjel Energy Services Inc) | Taylor, Jared (Sanjel Energy Services Inc) | Lin, Zichao (University of Alberta)
Stress-induced fractures in wellbore cement can form high-risk pathways for methane or carbon dioxide leakage yet little to no quantitative information on the impact of these fractures has been reported. To investigate this, scanning electron microscopy (SEM) and micro computed tomography (micro-CT) techniques were utilized to quantify the 2D and 3D geometrical parameters of cement fractures in mature thermal thixotropic cement samples that were subjected to pre-and post-peak compressive stress. A novel simulation method was also proposed to quantify the impact of the stress-induced realistic 3D fractures on the cement permeability. Results show that: i-) For pre-peak samples, 90% of the 2D fractures have length and width smaller than 100 μm and 5 μm, respectively. Although higher compressive stress reshaped the 3D fractures and increased the fracture length and width, no well-propagated fractures were observed; ii-) For post-peak samples, distinctly visible ( 0.1 mm) well-propagated fractures were generated but failed to penetrate the entire sample, therefore the effect of stress-induced fractures (up to 1.0% strain) on cement sample's permeability is limited; and iii-) CTbased 3D visualization and simulation both show that inclusion of a correctly engineered fiber additive is able to blunt the fracture propagation in cement samples. We conclude that up to the uniaxial compressive strength, the monotonic compressive stress is not likely to create leakage pathways in wellbore cement since the 2D fractures observed in SEM images are in limited dimensions and the large 3D fractures characterized in CT images have poor connectivity. Inclusion of a fiber additive is expected to enhance cement integrity by limiting the fracture propagation.
Rock deformation and fracturing is an important causal mechanism that can compromise well integrity. Geomechanical simulation is a valuable tool to investigate this mechanism and connect well tubular designs with reservoir development strategies. Utilizing relevant field examples, this paper describes a work flow in these regards.
Two example simulation approaches are described. One is to use a composite casing/cement/rock model in a reservoir of complex geology to compute maximum strain, dogleg severity, and ovality/restriction in the casing along the well trajectory. Different well design parameters, such as casing size, grade, and cement thickness, can be iterated against different reservoir production strategies. All these efforts are to arrive at an optimized design. The other approach is to calculate localized shear displacement along a weak plane that will be imposed on well tubulars during reservoir activities. The resulting design is optimized by altering well placement and stimulation/production schedules.
The above workflow has been proven in various field applications. Experience is shared in this paper. It is hoped this work can demonstrate that the optimal management of well integrity can be achieved by an integrated approach that designs appropriate tubulars and adjusts reservoir activities. Placing well tubulars in the context of rock deformation, geomechanical simulation is the best tool to connect the reservoir activities with the well tubular designs and therefore, can potentially offer a cost-effective well integrity management program.
The goal of this paper is to present the philosophies for the qualification and flow loop testing of FCD nozzles as well as the macroscopic implementation and operations of FCDs in SAGD producer wells. A quantitative methodology to evaluate FCD nozzles to choke back steam will be presented. Flow loop testing data will be shown to illustrate the qualification process. We will also discuss if sand control screens should be put on the tubing deployed inflow control devices. Some modeling and field examples will be shown. In the end, field data of the SAGD producer wells installed with the FCDs will be presented. Experience to manage and operate the wells will be shared.
Wang, Dongying (China University of Petroleum, East China) | Yao, Jun (University of Calgary) | Chen, Zhangxin (China University of Petroleum, East China) | Song, Wenhui (University of Calgary) | Sun, Hai (China University of Petroleum, East China) | Cai, Mingyu (China University of Petroleum, East China) | Yuan, Bin (China University of Petroleum, East China)
Multiphase fluid flow in shale is known to be affected by micro-scale pore structure, wettability and complex fluid transport mechanisms. Investigation on the gas-water two-phase transport property during hydraulic fracturing, flowback and online production has practical implications in estimating hydraulic fracturing effect and development of shale gas. In this study, an upscaling method is proposed to derive core-scale gas-water two-phase relative permeability from the perspective of multiphase pore-scale simulation results and experimental data. First, inorganic matter (IOM)/organic matter (OM) pore netwok models are established in use of SEM images from Sichuan Basin, China. Gas/water absolute permeability on IOM/OM pore network model is calculated and gas-water two-phase imbibition (hydraulic fracturing) and drainage process (flowback-to-production) in IOM pore network model is simulated through invasion percolation theory. The comprehensive pore-scale gas-water relative permeability is modeled integrating, 1) real gas effect, critical property change, bulk gas flow demarcated by Knudsen number (Kn) in both IOM and OM, gas adsorption and surface diffusion in OM for gas phase; 2) boundary slip length and spatially varying viscosity for water phase; 3) a piston-like displacement during hydraulic fracturing, and a non-piston displacement during flowback-to-production in IOM incorporating corner flow for water and gas flow in the pore center. A core-scale model is generated by stochastically distributing IOM/OM patches and is proved by using our pressure pulse decay experiment data. A novel upscaling method is then proposed to calculate core-scale gas-water relative permeability by assembling pore-scale simulated permeabilities/relative permeability of IOM/OM patches over the 2D core-scale model during hydraulic fracturing and flowback-to-produciton. Next, the upscaling results are compared with analytical model, which exhibits a consistant pattern. Furthermore, the critical value of TOC content and intrinsic permeability ratio of OM to IOM on the variation of upscaled relative permeability is determined during different flow processes.
With today's current technologies it is possible to answer the question, "What is my most profitable mode of operation for the next few hours, for the rest of today, tomorrow and beyond?" With'lower for longer' oil prices the need for enterprise wide optimization in the upstream and midstream oil & gas industry is greater than ever. The terms Digital Oil Field / Digital Gas Field / Digital Twin are being utilized to extol the virtue and value of big data analytics, model based asset optimization and supply chain optimization. These provide optimization solutions in ways not previously possible with multiple unintegrated systems, processes and procedures. Ad-hoc deployment of applications across multiple sites become difficult to integrate horizontally for management of safe and optimized operations and vertically up to Business ERP (enterprise resource planning) level to give useful and timely business insights.
A detailed understanding of wellbore flow is essential for production engineers in both the design of site equipment and optimisation of operation conditions. With the depletion of conventional resources, the need for unconventional extraction techniques to leverage untapped reserves has seen the generation of new downhole flow conditions. In particular, the extraction of natural gas from coal seams has led to scenarios where liquid removal from the reservoir can cause the development of a counter-current multiphase flow in the well annulus in pumped wells. In this work, high-fidelity computational fluid dynamics is used to capture the momentum interaction between gas and liquid phases in such a flow configuration, allowing for the evaluation and modification of closure relations used in upscaled models.
The computational fluid dynamics model is based on a recently proposed formulation developed using phase-field theory in the lattice Boltzmann (LB) framework. It has been previously applied to the analysis of Taylor bubbles in tubular and annular pipes at a range of inclinations and flow directions. The robustness of the numerical formulation has been proven with a range of benchmark scenarios that extend upon previously reported results in the LB literature. Future investigations will look to apply the developed closure relations into the
Using the multiphase lattice Boltzmann model, the drag force closure relations are investigated for bubbles covering a range of parameters. This assesses the accuracy of existing closures and provides confidence in the developed computational tool. Following on from this, the size of the liquid slug behind a Taylor bubble is analysed. Comparison of the results with pre-existing relations provides a means to modify current large-scale simulators to accurately capture the momentum exchange between gas and liquid phases in a wellbore. With the improved understanding of phase interactions developed in this study, upscaling work is to be conducted through the implementation of closure models within a two-fluid-type model, not unlike OLGA, as well as in a recent mechanistic model.
The novelty of the high-fidelity computational model is in its ability to resolve high density ratio (liquid-gas) flows under complex, dynamic conditions within the lattice Boltzmann framework. Additionally, the development and validation of novel closure relations for mechanistic and
Ren, Long (Xi'an Shiyou University) | Zhan, Shiyuan (Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Zhou, Desheng (University of Alberta) | Su, Yuliang (China University of Petroleum, East China) | Wang, Wendong (Xi'an Shiyou University) | Chen, Mingqiang (Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Jing, Cheng (China University of Petroleum, East China) | Sun, Jian (China University of Petroleum, East China) | Tang, Kang (Xi'an Shiyou University)
Multiple hydraulic fractures in naturally fractured unconventional oil reservoirs have often induced complex fracture network growth, as revealed by microseismic monitoring data by Maxwell et al. (2002), Fisher et al. (2005) and Daniels et al. (2007). History matching and production forecasting from an unconventional oil reservoir is possible only if a complex fracture network can be clearly described through the engineering parameters. However, currently, the integration technology of propagation simulation and structural characterization of the complex fracture network is still an extreme challenge. A new propagation modeling and characterization technique has been developed for these complex fracture network expansion that combines improved displacement discontinuity method (DDM) and pseudo-3D fracture propagation model to simulate the propagation process of complex fracture network and improve stimulation accuracy. This is very important for modeling and simulation of multi-fracture propagation in a unconventional oil reservoir with natural fractures. The theoretical model include the calculation model of combined stress field, the mechanical model of fracture propagation patterns and the corresponding propagation criteria, the injection fluid distribution model, and the mathematical model for structural description and morphological characterization as a post-processing program. The propagation simulation results of complex fracture network are implicitly and directly entered into the post-processing program and characterized by some engineering parameters as well. Simulation results show that the different propagation patterns of fracture network are produced, which is governed by the in-situ stress anisotropy, hydraulic fracture density, and distribution modes of preexisting natural fracture as well as fractures interaction angle.
Khaleghi, Keivan (University of Alberta) | Talman, Stephen (University of Alberta) | Rangriz Shokri, Alireza (University of Alberta) | Primkulov, Bauyrzhan K. (Massachusetts Institute of Technology) | Juncal, Abel S. (University of Alberta) | Chalaturnyk, Rick J. (University of Alberta)
After a critical review of available pore-scale analytical and numerical approaches to estimate permeability of porous media, this paper presents a practical framework to examine and quantify the impact of variation of confining stress during the production lifecycle of a reservoir on the pore space deformation and absolute permeability of rocks formed by spherical grains.
Comparable to commonly used thin sections in CAT scan, spatial and geometrical information of sphere packings, generated using an advanced 3D distinct element method, were embedded into multiple binary images. We then constructed the corresponding pore network, employing an updated pore geometry extraction algorithm, and performed pore-scale fluid flow simulation to evaluate pore connectivity of packings of spherical grains, as imperfect-yet-effective analogues for porous rocks. The variations of pore deformation and computed permeability, with a change in confining stress applied to the packed material, were carefully tracked and systematically analyzed.
Aiming for a better pore-scale understanding of deformation effects on macro-scale transport properties, we initially identified the REV (Representative Elementary Volume) requirements for adequate representation of generated throat and body structure of pores. To obtain accurate porosity values, guidelines to process binary images with optimal resolution were provided. The workflow was then applied to simple cubic geometry and random packings of mono-dispersed particles to compute their permeabilities. The capability and limitations of developed workflow to predict the macroscopic hydraulic properties of porous media were summarized. The evolution of permeability and porosity in a contracting simple cube system under various levels of confining stress were quantitatively tracked. Lastly, the differences in behaviour between our simulation results and available analytical/numerical solutions and experimental studies in current literature were demonstrated.
Extending our modeling approach into a virtual laboratory technique helps to quantify stress-dependent variations of pore space and permeability of spherical grain packings. Given grain size distribution and stress path, modeling environment can be calibrated as a predictive tool to evaluate the behavior of porosity and permeability, hence transport qualities, of rock analogues under varying conditions of reservoir stress. Our analysis provides valuable insights in upscaling such properties for processes where dynamic geomechanical changes are significant.
Zeng, Wenting (PetroChina Coalbed Methane Company) | Sun, Qian (Petroleum Engineering, Texas A&M University at Qatar) | Zhou, Linlang (PetroChina Southwest Oil and Gasfield Company) | Wang, Yuhe (Petroleum Engineering, Texas A&M University at Qatar)
The unique composition and structure of shale kerogen, which bear considerable amount of absorbed gas, greatly complicate the recovery mechanisms of natural gas and challenge the energy industry for efficient and environmentally friendly energy exploitation. In this study, the adsorption and diffusion characteristics of CH4, CO2 and their mixtures in kerogen matrix are investigated using GCGM (Grant Canonical Monte Carlo) and MD (Molecular Dynamics) simulations. The results verify that pressure has a positive effect on CH4 and CO2 adsorption capacity, while the effect of temperature is negative. It is found the isosteric heat of CO2 is larger than CH4, indicating a higher affinity of CO2 to kerogen. The greater interaction between CO2 and kerogen matrix causes the self-diffusion coefficient of CH4 being larger than CO2 at the same conditions. The competitive adsorption of CO2 over CH4 is higher at lower CO2 model fraction, suggesting less amount of CO2 is required to recover the same amount of CH4 at the early stage of CO2 injection. Due to the energetically heterogeneous characteristics of kerogen surface, with increasing pressure the adsorption selectivity goes up first and then declines. We hope that this work may server as a reference for the development of shale reservoirs by injecting CO2.
A digital twin is an enhanced digital representation of a real system. Digital twins are able to mimic the operation of physical systems and use data captured from their sensors to detect abnormal conditions and diagnose the cause of the problem. This paper discusses digital twin concept in general and describes the process of developing a digital twin for electric submersible pump (ESP) systems. It includes a description of the different subsystems interacting with the ESP equipment and the physics governing dynamics of each subsystem and the implementation of the digital versions. The ESP digital twin considered in this paper encompasses the ESP lifted well and includes digital versions of the ESP string, well completion, well fluids, and near wellbore reservoir, among others. The document also describes the implementation of the physics models into a simulator capable to represent diverse operating conditions of the system, including failures and transients.