Pressure Buildup During Supercritical Carbon Dioxide Injection From a Partially Penetrating Borehole into Gas Reservoirs (original) (raw)
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Numerical simulation of supercritical CO2 injection into subsurface rock masses
Energy Conversion and Management, 2008
Carbon dioxide (CO 2) is considered to be one of the greenhouse gases that may contribute most to global warming on the earth. Disposal of CO 2 from stationary sources into subsurface structures has been suggested as a possible means for reducing CO 2 emissions into the atmosphere. However, much remains to be done in the issues regarding the safety and reliability of CO 2 geological sequestration. In this study, we have developed a simulation code by using the mathematical model of two phase flow in porous media to analyze the flow dynamics in the subsurface. The equation of state for CO 2 covering the fluid region from the triple point to the supercritical region is employed to model the states of CO 2 gas, liquid and supercritical state. The correct understanding of the CO 2 state under the geological formation condition is an important factor to predict the injection pressure and CO 2 fluid permeation because the fluid density has a great effect on the injection behavior. The numerical simulation was implemented under several geological conditions including gas, liquid and supercritical states to examine the optimal injection condition. Comparing the numerical results obtained using the equation of state for CO 2 with those obtained using the ideal gas equation, it has been shown that the difference in the injection pressure appears to be significant near the condition of the critical point of CO 2 and the phase equilibrium curves between the gas and liquid states. The numerical simulation has been implemented to examine the effect of the reservoir condition on the injection behavior. The injection pressure is decreased at the lower reservoir temperature and higher hydrostatic pressure condition. The CO 2 permeation is also strongly affected by the reservoir condition, and the spatial CO 2 saturation becomes higher with increasing reservoir temperature. It has been demonstrated that the simulation code developed in this study may be useful to provide knowledge required to select the reservoir condition for CO 2 geological sequestration.
Energy conversion and …, 2007
A project of geological CO 2 storage in the deep Dogger aquifer in the Paris Basin (France) is under development. Before effective containment can be assured, investigations need to be carried out on reservoir behavior when subjected to physical, chemical and mechanical perturbations induced by CO 2 injections. The aim of this study is to present the numerical results of two CO 2 injection scenarios, firstly with CO 2-saturated water and secondly with pure supercritical CO 2. The simulation results confirm the high reactivity of CO 2-saturated water, which can dramatically damage the reservoir structure. On the other hand, supercritical CO 2 injection appears to be weakly reactive, with a limited modification of well injectivity. Supercritical CO 2 reacts differently to CO 2-saturated solution: firstly, it dissolves into aqueous solution and it increases both water acidity and mineral dissolution potential, favoring augmented porosity. Following this step, numerical simulations demonstrate that hydraulic processes induced by supercritical CO 2 injection are accompanied by a desiccation phenomenon of the porous medium. Irreducible water, entrapped in pores, sustains the increase in CO 2 pressure. When the pressure is sufficiently high and under a continuous dry (without water vapor) CO 2 flux, an evaporation process starts leading to the precipitation of salts and possibly other secondary minerals. Although there has been little focus on this desiccation process in the literature until now, it nevertheless must constitute an important risk of both a modification in porosity and well injectivity.
The injectivity of coalbed CO2 injection wells
Energy, 2004
Though it may be possible to enhance methane production from coal by injecting CO 2 , because coal is poorly permeable it is usually necessary to inject under fracturing conditions to achieve acceptable injectivity. Concomitantly, the process of replacing the methane by the injected the CO 2 causes the matrix to swell. These two processes-the fracturing of the coal and the swelling-have opposite effect on the injectivity. TNO-NITG have pressure data from a CO 2 injection test in a coalbed methane field. We used the SIMED II coalbed methane simulator to history match the test behaviour and to find the most sensitive parameters affecting the injectivity of the CO 2 injection well. An analysis of the pressure records revealed both the occurrence of fracturing and the reduction in permeability that swelling induced. When applied to an extended injection simulation, the simulator showed that the most sensitive parameters influencing the injectivity were the permeability, the fracture conductivity, and the cleat system porosity. Unfortunately, due to the adsorption of the CO 2 and the fluctuations in pressure during injection tests, all these vary over time.
A new flow pump permeability test applied on supercritical CO2 injection to low permeable rocks
2011
This study aims to investigate the permeability and storativity characteristics of sedimentary rocks injected with supercritical CO2. Recent development of CO2 storage in sedimentary rocks requires knowledge of CO2 behavior in deep underground characterized as geological layers with low hydraulic gradient, high pressure and high temperature. Therefore, we developed a new flow pump permeability test, so that the test will be able to reproduce similar physical condition of deep underground where CO2 behaves in supercritical state. The injection of supercritical CO2 was conducted on a cored Ainoura sandstone saturated with water. A numerical simulation based on the theoretical analysis of flow pump permeability test incorporating Darcy’s law for two phases flow was also undertaken in order to interpret the experimental results especially to examine the relative permeability and saturation of the saturated water and supercritical CO2 including the specific storage of the sandstone durin...
Experimental study of CO2 injection in a simulated injection well: The MIRAGES experiment
2014
The MIRAGES experiment mimics an injection well at the lab scale (1/20). This experiment allows the injection of supercritical CO 2 under geological conditions of pressure and temperature. The injection fl ow rate, confi nement and injection pressures and temperatures are recorded during the 30 days of the experiment. Chemical parameters (pH, major element contents) are also monitored. The reservoir is represented by a core sampled in the formation of Lavoux limestone. The core is drilled to form an injection well in which an injection tube (made of stainless steel) is sealed with class G Portland cement together with two discs of Callovo-Oxfordian clay representing the caprock. After the experiment, the core sample is studied to follow the petrophysical changes of the well materials and rocks. The interfaces between the reservoir, caprock, cement, and steel are investigated using scanning electron microscopy, cathodoluminescence, and Raman spectrometry. The main results suggest (i) good cohesion of the different interfaces despite the carbonation of the cement, (ii) the precipitation of different carbonate phases relating the changes in the chemistry of solution as a function of time, (iii) the enrichment in silica of the cement phase subjected to the action of CO 2 providing evidence of new mechanisms of in situ silica re-condensation, and (iv) the very good mechanical and chemical behavior of the caprock clay despite the alkaline fl ux from the cement and the acidic attack from the dissolved CO 2 .
The role of supercritical CO2 in gas well health issue – liquid loading
The APPEA Journal, 2020
Liquid load or condensate banking is a common well health issue in gas/gas-condensate reservoirs that decreases well productivity by a factor of two to four. Due to the depletion of bottom-hole pressure, the produced liquid accumulates around the wellbore and creates a static column of liquid that reduces gas production until well production ceases. Enhancing gas recovery by CO2 injection is a promising technology because it reduces greenhouse gas emissions and improves CO2 storage. More investigation needs to be conducted to understand the role of supercritical CO2 (SCCO2) in minimising liquid loading. The aim of this research is to examine the impact of SCCO2 in surface tension, condensate viscosity and well productivity. This study consists of simulation and laboratory experiments. Eclipse 300 was used to develop a model that examines the effect of SCCO2 injection on reducing liquid loading issues by varying the well parameters. We found that injecting SCCO2 improved the microsco...
Investigation of Properties Alternation during Super-Critical CO2 Injection in Shale
Applied Sciences
The low recovery of oil from tight liquid-rich formations is still a major challenge for a tight reservoir. Thus, supercritical CO2 flooding was proposed as an immense potential recovery method for production improvement. While up to date, there have been few studies to account for the formation properties’ variation during the CO2 Enhanced Oil Recovery (EOR) process, especially investigation at the micro-scale. This work conducted a series of measurements to evaluate the rock mechanical change, mineral alteration and the pore structure properties’ variation through the supercritical CO2 (Sc-CO2) injection process. Corresponding to the time variation (0 days, 10 days, 20 days, 30 days and 40 days), the rock mechanical properties were analyzed properly through the nano-indentation test, and the mineralogical alterations were quantified through X-ray diffraction (XRD). In addition, pore structures of the samples were measured through the low-temperature N2 adsorption tests. The result...
International Journal of Greenhouse Gas Control, 2013
Large-scale pressure build-up due to a CO 2 injection is investigated in the vertical and horizontal direction to determine locations and strategies suitable for pressure monitoring of the injection operation, cap rock integrity and large-scale geological setting. A realistic site-scale multi-layered model within the North German Basin is used, which explicitly accounts for a heterogeneous vertical structure including semipermeable layers above the storage formation and below the cap rock. Results show that characteristic trends of the pressure signal are found for specific monitoring locations, depending on the horizontal and vertical distance to the injection well. Pressure signals and thus maximum pressures may be strongly delayed in the vertical direction, with a time shift larger than the injection period. This demonstrates that the maximum leakage risk in the cap rock may occur significantly after the injection period, not at the end of the injection. Vertical permeability contrasts between the cap rock and the storage formation as well as spatial heterogeneities cause variations in the shape and time evolution of the pressure signals and could thus be used to evaluate the vertical connectivity and the leakage risk. Boundary conditions and formation compressibilities control the pressure signal far from the injection well. It is shown that buoyant rise of CO 2 into overlying formations cannot be detected by pressure monitoring.