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Leakage through new or existing wellbores is considered a major risk for carbon dioxide (CO 2 ) geological storage. Long-term effective containment of CO 2 is required, and the presence of millions of suspended or abandoned wells exacerbates the potential risk in mature hydrocarbon provinces. Accurate estimates of risk profiles can support the acceptance of geological storage and the adoption of economically effective risk-prevention and -mitigation measures.Reliable data about long-term containment of CO 2 are almost nonexistent, so wells that exhibit a similar risk profile (such as gas storage, gas production, and steam injection) should be used as a proxy to assess failure rates and consequences for cemented wellbores.Statistical data about occurrence of leaks and their consequences are analyzed to determine the risk profile of CO 2 leaks. A smaller sample of data about leak rates is also analyzed to provide their statistical distribution. Rates and consequences are then compared to try to assess the order of magnitude of major and catastrophic leaks.Hydrothermal CO 2 leaks in natural analogs are also reviewed to compare the distribution of leak rates and the consequences upon health, safety, and environment of CO 2 releases to soil and atmosphere.Analysis of existing data will show that major leaks are likely to occur in less than two wells per 1,000, with the overwhelming majority of CO 2 leaks being small and with limited or negligible consequences.Given their risk profile, CO 2 wellbore leaks should be addressed through a routine risk-management approach. Their frequent occurrence requires effective prevention measures, such as understanding leaks and adapting and deploying practices to minimize their occurrence. On the other hand, their low impact ensures maximum effectiveness of mitigation measures, such as monitoring. Because leaks can be detected long before damage ensues, they can be observed to predict their long-term consequences and to plan the most effective intervention without unnecessary immediate operation shutdowns.In conclusion, the recommended course of action is to focus on risk prevention and early detection. This implies the evolution from a "no-leaks" attitude (even for negligible leak consequences) to one that seeks no damage and relies on tight surveillance.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe analysis of deep-reading electromagnetic measurements is critical to the evaluation of hydrocarbon reserves. However, in thin bed formations, poor tool vertical resolution and corresponding low sensitivity to hydrocarbon presence make interpretation in the virgin zone difficult. A priori knowledge such as the formation geometry or auxiliary petrophysical information is necessary to overcome these difficulties. This paper presents a prototype code developed by Schlumberger S-RPC in collaboration with AGIP. Using this code, wireline or LWD, laterolog and induction measurements can be more correctly analyzed in thinly bedded environments (2-D geometry, fluid invaded layers perpendicular to the borehole).This code has been implemented in a software framework that provides a common environment specifically designed for electrical tool interpretation. Processing modules have a common interface and share common functionalities. Their organization reflects an implicit processing methodology, with progressive refinements that provides the interpreter with a robust and simple to use product, to better quantify reserves.A preliminary step is to determine the formation geometry, which is carried out by detecting bed boundaries and representing the formation as a vertical sequence of layers. Petrophysical analysis can be invoked to characterize certain formation properties such as shale volume and porosity. These steps are performed prior to resistivity log measurement analysis and serve as a form of a priori knowledge.Once the formation is described as a sequence of layers, wireline l ogging or logging while drilling (LWD) tool response can be computed using fast 2D simulators. The estimation of resistivity and the subsequent estimation of saturation will correspond to the minimization of a cost function, defined as the weighted squared difference between the measurement and the simulated response. Confidence outputs can be related to the local shape of the cost function at the end of the processing.Two important advantages of the new code must be emphasized: (1) the possibility to choose among several petrophysical models to better describe the environment and determine directly parameters such as hydrocarbon saturation, and (2) the possibility to group together beds which are too thin or too close to each other to be analyzed independently, into a so called single optimization interval described by a reduced set of parameters.This paper presents results obtained on selected benchmarks extracted from real data and compares them with those obtained through more traditional approaches.

Two main types of reservoirs are considered for geological storage of CO 2 : deep saline formations and depleted oil and gas reservoirs. The former offer very large potential capacity and a more even distribution, at the expense of high uncertainty due to the very poor characterization of their properties, including their sealing capacity; the latter offer smaller overall capacity, but with a reduced risk due to better reservoir knowledge. Gas reservoirs have also provided a proven seal to pressurized gas.However, reusing depleted O&G reservoirs presents challenges that must be considered in the evaluation of performance factors and the risks associated Depletion can cause pore collapse in the reservoir -with an associated loss of capacity and injectivity -weaken caprock and bounding faults, or even well completions, leading to possible containment losses due to mechanical failure. O&G reservoirs are also intersected by many wells and it is likely that stricter regulatory requirements on well integrity and the quality of zonal isolation will force operators to recomplete or work over wells which will be exposed to CO 2 , with an obvious impact on cost.Low reservoir pressure may also mean that injection of CO 2 in a dense phase would result in reservoir fracturing and very strong thermal effects that may lead to injectivity problems. In the reservoir, chemical and physical differences in behavior between CO 2 and methane may adversely affect geological containment and injectivity.Economics and financing present another set of constraints: use of injected CO 2 for EOR/EGR vs. storage may lead to difficulties in obtaining emission credits. Infrastructure decommissioning and conflict with resource exploitation may reduce the attractiveness of depleted reservoirs.The benefits and challenges of depleted O&G reservoirs will be analyzed with respect to all performance factors (capacity, injectivity, containment) and the major drivers of costs and risks will be identified. Fixed costs and risks, associated to uncertain capacity for deep saline formations or uncertain containment for depleted reservoirs, will then be used to compare the two candidates for CO 2 geological storage and the paper will propose criteria to aid in the selection of possible storage sites.