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Nygaard, Runar (Missouri University of Science and Technology) | Salehi, Saeed (University of Louisiana at Lafayette) | Weideman, Benjamin (Missouri University of Science and Technology) | Lavoie, Robert Guy (RPS Energy Canada)
The most viable options for permanent removal of carbon dioxide (CO2) from the atmosphere include large-scale injection of CO2 from stationary sources, such as coal-fired power plants and heavy-oil production, into brine-filled formations. One of the main risks identified with storing CO2 in the subsurface is the potential for leakage through existing wells penetrating the caprock. The wellbore system has several components that can fail and create leakage pathways, including type and placement of wellbore casing and cements, completion method, abandonment, and wellbore expansion or contraction by changes in temperature and pressure. Of the 1,000 wells in the study area near Wabamun Lake, Alberta, 95 wells penetrated the immediate caprock above the proposed Nisku injection formation and were identified as potential leakage pathways. The leakage risk of these wells was evaluated on the basis of knowledge of the well design, current well status, and historical regulations in the area. Only four wells, for the subset of 27 wells studied, were identified as requiring workover, which was less of a problem than anticipated. To evaluate the risk of creating leakage pathways by thermal and pressure changes caused by CO2 injection, a 3D finite-element model was built by use of poroelastoplastic material models for cement and formation. Multistage simulations for casing/cement and cement/ formation interactions with temperature-enabled elements were conducted. A parametric study of cement properties was conducted to investigate cement design and its mechanical properties for injection wells. The simulation results indicated that thermal cooling might reduce near-wellbore stresses, which would increase the risk of integrity loss in casing/cement and cement/formation. The parametric study revealed that the risk of debonding and tensile failure would increase with increasing Young’s modulus and Poisson’s ratio of the cement under dynamic-loading conditions. In addition, low mechanical cement strength would increase the risk of shear failure in the cement.
The selection of depleted oil and gas fields as potential CO2 geological storage sites has both positive and negative aspects that need to be considered. The positives are that the storage capacity or pore volume can be reliably estimated from field’s production history, and reservoir characterization can be performed with more readily available well, log or seismic data without additional expenses. The main drawback is the presence of wells in the field, as each well may provide a leakage pathway for injected CO2. The leakage potential of a well is a function of its proximity to injection wells, cement coverage in the potential storage zone, well abandonment conditions including cementing of the annular space, and the nature of any barriers to prevent CO2 leakage to the surface. Qualitative and quantitative risk-based approaches can be used to identify the wells that have comparatively higher leakage probabilities in comparison to other wells. The objective of this study is to use a risk-based approach to identify and categorize wells based on their leakage potential in depleted oil and gas fields. This will not only help in planning injection strategies but may also help in selection of remediation strategies. The model may be presented well by using the Fault Tree Analysis (FTA) technique. It implements screening criteria and a tier-based approach in which wells are screened and categorized into different tiers based on different well characteristics. The well characteristics include the physical distance from injection wells, the quality and portion of cement coverage of wells in the target zone, the regulations at the time of well completion, the leakage potential of sealing barriers for the targeted zone, the number of overlying shale and sand intervals and leakage of either CO2 or brine to shallower wells, the nature and quality of permanent or temporary well abandonment procedures, and the quality and length of annular space covered with cement for shallower well casings or sections. Existing models for well leakage are used to quantitatively estimate the leakage rate. The risk of leakage is presented qualitatively and quantitatively in the form of leaked CO2 volume to shallow aquifers or to the atmosphere. The approach is used for a representative depleted oil and gas field in southern Louisiana to show an example application of the process. The developed model provides a means to systemically identify the wells that are more likely to leak and have high consequences. Due to the reduced order nature of the tool, it should prove to be a useful tool in the planning and execution phase of the CO2 sequestration process.
Bai, Mingxing (Northeast Petroleum University) | Song, Kaoping (Northeast Petroleum University) | Li, Yang (Northeast Petroleum University) | Sun, Jianpeng (Northeast Petroleum University) | Reinicke, Kurt M. (Clausthal University of Technology)
Summary A safe and ecologic underground storage of carbon dioxide (CO2) requires long-term integrity of the wells affected by the injected CO2, including both active wells and abandoned wells. In line with other investigators, technical integrity is assumed if there is no significant leak in the subsurface system from the storage reservoir. The evaluation of integrity of abandoned wells over a long time frame during CO2 underground storage can only be performed indirectly and requires a comprehensive understanding of relevant thermal/hydraulic/mechanical/chemical processes affecting well integrity. This paper presents an integrated approach coupling qualitative features, events, and processes (FEPs) and scenario analysis with quantitative-model development and consequence analysis. The qualitative analysis provides a solid and comprehensive study on all the FEPs that affect well integrity. The mechanical model presents the stress distribution of the casing/cement/rock composite system and provides a quantification of the defect dimension caused by different load conditions. The defect dimension can be used to compute equivalent permeability of the cement sheath by use of empirical correlations, which is an important input parameter for the following CO2-leakage simulation, provided it is considered that CO2 can only migrate through the defects instead of the cement matrix. When integrity is compromised, the storage reservoir will leak CO2. For this leakage, a numerical model is presented to simulate the flow of CO2 along abandoned wellbores during the storage period, such as 1,000 years. It is found from the FEP analysis that the most-critical system components are caprock, casing/cement/rock composite system, and abandonment elements. By building a geomechanical model and a leakage model, it is also found that in the simulated scenarios the CO2-leakage rate is very small except for when using cement sheaths of very poor quality, which can lead to a leakage rate exceeding the maximum-allowable value. The sensitivity analysis shows that the vertical permeability of the cement sheath plays the most critical role. In comparison with previous studies, this method is comprehensive and easy to implement.
Abstract Large-scale geological storage of CO2 is likely to bring CO2 plumes into contact with a large number of existing wellbores. The flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. The leakage pathway in wells that exhibit sustained casing pressure (SCP) is analogous to the rate-limiting part of the pathway in existing wellbores along which CO2 may leak. Thus field observations of SCP can be used to estimate transport properties of a CO2 leakage pathway. We develop a more robust optimization algorithm to get the best data fit in the SCP model. Constraints from well construction geometry and from physical considerations reduce the range of estimated permeability. We then describe a simple CO2 leakage model. The model accounts for variation in CO2 properties along the leakage path and allows the path to terminate in an unconfined (constant pressure) exit. The latter assumption provides a worst-case leakage flux. Using pathway permeabilities consistent with observations in SCP wells, we obtain a range of CO2 fluxes for various boundary conditions. In leakage pathways corresponding to the slow but nonnegligible buildup of casing pressure, the CO2 fluxes are comparable to naturally occurring background fluxes observed at ground surface. In pathways corresponding to rapid buildup of casing pressure, the fluxes are comparable to measurements at Crystal Geyser (Utah), a natural CO2 seep. Uncertainty in pathway permeability has a first-order effect on uncertainty of CO2 flux. Uncertainty in the length of the pathway has a comparatively minor effect. Increasing the CO2 at the base of the pathway does not dramatically increase the CO2 flux above the purely buoyancy-driven value.
This paper was prepared for the Midwest Oil and Gas Industry Symposium of the of the Society of Petroleum Engineers of AIME, to be held in Chicago, Ill., April 1-2, 1971. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Monitoring procedures used in underground gas storage operations are reviewed. Besides bringing together the many techniques now used, methods are presented for systematizing the monitoring process.
The underground storage of natural gas is a relatively young industry. In some 20 years of major growth, storage facilities deliver to market annually some 1.5 trillion cubic feet of natural gas. Major gas systems deliver from storage as much as one-third to one-half of their total send-out on a cold winter day. Further indication of the industry's maturity is the effort to improve safety of operation and control of gas reservoirs. This paper reviews the monitoring procedures of gas storage reservoirs and suggests ways of systematizing the alerting process so that appropriate action can be taken, should any imperfection in the system appear.
The storage operator is expected to know where his inventory of stored gas resides. He is charged with sending to market large quantities of gas in a short period at planned rates of delivery. Monitoring is the taking of observations which will insure the satisfactory operation of the storage facility. The primary concern is that no unknown gas migration underground is taking place. Early detection of unexpected gas movement -- penetration of caprock--movement behind the production pipe -- or loss from surface equipment -- pipe -- or loss from surface equipment -- can initiate remedies to minimize any effects on the environment.
Monitoring is interpreted as not only sensing the basic information but also transmitting it to the proper decision center for action. People are a vital part of any monitoring system and must be included in its consideration.