Yang Gou

Simulation of CO2 plume movement in multilayered saline formations through multilayer injection technology in the Ordos Basin, China

Deep saline aquifers still remain a significant option for the disposal of large amounts of CO2 from the atmosphere as a means of mitigating global climate change. The small scale Carbon Capture and Sequestration demonstration project in Ordos Basin, China, operated by the Shenhua Group, is the only one of its kind in Asia, to put the multilayer injection technology into practice. This paper aims at studying the influence of temperature, injection rate and horizontal boundary effects on CO2 plume transport in saline formation layers at different depths and thicknesses, focusing on the variations in CO2 gas saturation and mass fraction of dissolved CO2 in the formation of brine in the plume’s radial three-dimensional field around the injection point, and interlayer communication between the aquifer and its confining beds of relatively lower permeability. The study uses the ECO2N module of TOUGH2 to simulate flow and pressure configurations in response to small-scale CO2 injection into multilayer saline aquifers. The modelling domain involves a complex multilayer reservoir–caprock system, comprising of a sequence of sandstone aquifers and sealing units of mudstone and siltstone layers extending from the Permian Shanxi to the Upper Triassic Liujiagou formation systems in the Ordos Basin. Simulation results indicate that CO2 injected for storage into deep saline aquifers cause a significant pressure perturbation in the geological system that may require a long duration in the post-injection period to establish new pressure equilibrium. The multilayer simultaneous injection scheme exhibits mutual interference with the intervening sealing layers, especially when the injection layers are very close to each other and the corresponding sealing layers are thin. The study further reveals that injection rate and temperature are the most significant factors for determining the lateral and vertical extent that the CO2 plume reaches and which phase and amount will exist at a particular time during and after the injection. In general, a large number of factors may influence the CO2–water fluid flow system considering the complexity in the real geologic sequence and structural configurations. Therefore, optimization of a CO2 injection scheme still requires pursuance of further studies.

Simulation of CO2-Water-Rock Interaction Processes-Mineral Scaling Problems in Saline Formations

Many problems may occur in the process of CO2 injection which usually lasts for many years. Injection efficiency depends on many factors, such as temperature (T), well bottomhole pressure (P), well heading pressure, injection rate, reservoir properties (porosity, permeability, wettability) and scales of some minerals. The scaling problem in the wellbore and near-well region in reservoir (usually a few meters away from the borehole), may have a large negative effect on the reservoir properties such as a decrease in porosity and permeability near the well borehole region. As a result, the amount of CO2 injected will be restricted. The purpose of this study is to predict mineral scales formation and distribution that happen in near-well reservoir using the simulation method. In this paper, TOUGH2 and TOUGHREACT software are used, and a 1D model has been set up. In this benchmark simulation of scaling problems, T and P are chosen to be at 100°C and 4MPa respectively. Simulation results show that pressure and gas saturation of the reservoir had been changed greatly after CO2 injection. Illite and calcite may be the main mineral scales in the near-well region. At different time after the injection of CO2, there are different changes of mineral types and mineral volume, illustrating that at the beginning of the injection period, the precipitated minerals are illite, oligoclase and calcite, with time, ankerite, smectite-Ca and dawsonite will precipitate. In order to control the scale problems and alleviate destruction of the reservoir and petroleum equipment, chelants (such as EDTA, DTPA) should be used.

Worldwide Status of CCUS Technologies and Their Development and Challenges in China

Carbon capture, utilization, and storage (CCUS) is a gas injection technology that enables the storage of CO2 underground. The aims are twofold, on one hand to reduce the emissions of CO2 into the atmosphere and on the other hand to increase oil/gas/heat recovery. Different types of CCUS technologies and related engineering projects have a long history of research and operation in the USA. However, in China they have a short development period ca. 10 years. Unlike CO2 capture and CO2-EOR technologies that are already operating on a commercial scale in China, research into other CCUS technologies is still in its infancy or at the pilot-scale. This paper first reviews the status and development of the different types of CCUS technologies and related engineering projects worldwide. Then it focuses on their developments in China in the last decade. The main research projects, international cooperation, and pilot-scale engineering projects in China are summarized and compared. Finally, the paper examines the challenges and prospects to be experienced through the industrialization of CCUS engineering projects in China. It can be concluded that the CCUS technologies have still large potential in China. It can only be unlocked by overcoming the technical and social challenges.

Development of a semi-analytical method to calculate depth-dependent temperature and stress changes: investigation of micro-seismicity at Unterhaching Uha GT-2 geothermal well

Since October 2007 when the hydrothermal production of geothermal energy from the deep underground started at Unterhaching, near Munich (Germany), several micro-seismic events have been observed. Three of the five strongest events, with local magnitudes (ML) ranging from 2.0 to 2.4, occurred in 2008 and were partially felt by the residents. The reasons for these events are not clear. These micro-seismic events could have been induced by a variety of factors. The strongest micro-seismic event was observed soon after the injection of cold water, pointing to an intrinsic relationship between micro-seismic event and cold water injection. One of the possible reasons for the observed micro-seismic events could be the reinjection of cooled thermal water into the hotter underground inducing stress redistribution and shear failures in the reservoir formations around the injection wellbore Uha GT-2. To justify this reason, further investigation will be carried out in another simulation study to verify whether the shear failures induced by cold water injection were the major cause for the occurrence of these micro-seismic events. Nevertheless, before the simulation of shear failures, temperature profiles in both the wellbore and surrounding rocks as well as their corresponding thermal stresses during cold water injection should be established in this study. In this paper, a new semi-analytical simulation method has been developed to calculate simultaneously the temperature profiles in the wellbore and the surrounding rock formations and also determine the corresponding thermal stresses in the surroundings near wellbore field and subsequently verified by analytical solution. Results show that great tensile thermal stresses in the reservoir were initiated by the injection of the cooled thermal water in the injection wellbore Uha GT-2. The results of the simulated thermal stresses indicate a great potential for the ensuing shear failures to affect an extensive area and could be used as input data for the planned shear failure simulations in the future.

Evaluation of Geo-processes

A holistic understanding of the physicochemical processes induced by CO2 injection and storage in a reservoir is based on a geoscientific characterisation of the overall geological system consisting of reservoir rocks and cap rocks. It requires in a first step a comprehensive baseline characterisation (sedimentological, mineralogical, geochemical, mechanical, etc.) of pertinent parameters and conditions. To properly handle the large amount of different geoscientific information a Data Management System (DMS) was developed, which proved indispensable to conduct such a multi-disciplinary project. The DMS provides a tool for scientific process management, data analysis, integration and visualisation, data transfer and scheduling through specialised database systems and retrieval techniques, storage technology, and efficient data access.

Numerical investigation of the hydromechanical response of a natural fracture during fluid injection using an efficient sequential coupling model

Hydraulic fracturing is a complicated hydromechanical coupled process, especially in shale gas and deep geothermal reservoirs, in which natural fractures exist. Due to the geological complexity caused by invisibility, and the challenge and high cost in field investigations, numerical modeling becomes an alternative. In this paper, an integrated numerical model is developed to investigate the hydromechanical behavior of a natural fracture during the fluid injection. In the developed model, the mechanical behavior of the fracture including fracture opening, closure, shear dilation, and shear failure is described by proposed constitutive equations; meanwhile, the hydraulic process is simplified as the fluid flows through two parallel planes. The coupled mechanical and hydraulic equations are sequentially formulated in an implicit schema by combining the finite different method and the finite volume method. The advantage of this numerical schema is that the two coupled processes are solved separately and only one sub-iteration is needed. Thus, the solution is efficient and stable than that formulated in a monolithic coupling. Besides, the implicit formulation of the flow equation makes it possible to set a relative large time step. The developed model is verified through three numerical examples. Then, it is used to investigate the hydromechanical behavior of a natural fracture during the fluid injection with a fictive reservoir. Sensitivity studies with variations in the stress state, the fluid injection rate, the fluid viscosity, and the injection form are conducted. The simulation results show that the mechanism in the far field is mainly dominated by shear dilation in contact condition, whereas the mechanism near the injection could be mixed shear–tension in either the contact or the separation conditions. With the increase in the shear stress and the injection length, decrease in the injection rate and the fluid viscosity, the fracture state near the injection will change from separation to contact, the injection pressure will decline below the primary normal stress, and the dominated mechanism is shear dilation. The findings in this study give a better understanding of the mechanical mechanism and the pressure response of a natural fracture during the fluid injection.

Determination of shale osmotic pressure using spontaneous potential log

Wellbore instability in shale results in annual expenditure for petroleum industry especially for shale gas/oil development. Osmotic pressure is one of the most significant effects, which affect wellbore stability during drilling in shale formation using water-based mud. Until now, methods to calculate osmotic were only undertaken in the pre-drilling or post-drilling phase. This paper presents a new developed method to estimate shale osmotic pressure using an spontaneous potential (SP) log, which makes it possible to calculate osmotic pressure during drilling. The relationship between shale osmotic pressure and SP log was investigated. It was found that osmotic pressure and SP value both depend on the shale cation exchange capacity, which was used to bridge the SP log and osmotic pressure. An empirical equation relating the SP value and osmotic pressure was developed, which can compute osmotic pressure using the SP value. Moreover, the depth-dependent earth temperature was considered in the osmotic pressure calculation. A case study was undertaken using the SP log of a wellbore section located in Shengli Oil Field, China.