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Recent measurements of methane emissions from abandoned oil/gas wells show that these wells can be a substantial source of methane to the atmosphere, particularly from a small proportion of high-emitting wells. However, identifying high emitters remains a challenge. We couple 163 well measurements of methane flow rates; ethane, propane, and n-butane concentrations; isotopes of methane; and noble gas concentrations from 88 wells in Pennsylvania with synthesized data from historical documents, field investigations, and state databases. Using our databases, we (i) improve estimates of the number of abandoned wells in Pennsylvania; (ii) characterize key attributes that accompany high emitters, including depth, type, plugging status, and coal area designation; and (iii) estimate attribute-specific and overall methane emissions from abandoned wells. High emitters are best predicted as unplugged gas wells and plugged/vented gas wells in coal areas and appear to be unrelated to the presence of underground natural gas storage areas or unconventional oil/gas production. Repeat measurements over 2 years show that flow rates of high emitters are sustained through time. Our attribute-based methane emission data and our comprehensive estimate of 470,000-750,000 abandoned wells in Pennsylvania result in estimated state-wide emissions of 0.04-0.07 Mt (1012 g) CH4 per year. This estimate represents 5-8% of annual anthropogenic methane emissions in Pennsylvania. Our methodology combining new field measurements with data mining of previously unavailable well attributes and numbers of wells can be used to improve methane emission estimates and prioritize cost-effective mitigation strategies for Pennsylvania and beyond.

• The viability of carbon capture and storage depends in part on storage security in the subsurface. • Recently, new field data have become available on the permeability of abandoned wellbores. • We present simulations of CO 2 leakage as a function of spatial density and permeability of leaky wells. • We assess the results based on ranges of leaky well permeability and spatial density that are realistic. • Our results indicate that leakage through abandoned wells unlikely to be a major limitation for CCS. The viability of carbon capture and geological storage (CCS) projects depends in part on the risk that injected CO 2 or displaced pore fluid will leak out of the target formation into surrounding formations or to the surface. Abandoned oil and gas wells, of which millions exist both throughout the United States and globally, form a potential conduit for this leakage. Recently, specific field measurements have been made to quantify the range of effective permeabilities that can be expected in abandoned wells, enabling us to, for the first time, combine field-scale numerical simulations of CO 2 sequestration in deep saline aquifers with real data on effective permeabilities of leaky wells. Using a previously developed semi-analytical reservoir simulator that can accommodate an arbitrary sequence of alternating aquifers and aquicludes, as well as an arbitrary number of leaky wells, we investigated how the amount of CO 2 that leaks out of the target formation depends on the spatial density of nearby abandoned wells and their effective permeability. Furthermore, we assess the influence that variations in pressure and temperature found between geological targets have on this dependency. We find that the observed differences in leakage between geological targets are controlled almost exclusively by differences in density of CO 2 at the local subsurface conditions, causing the CO 2 plume to contact a different number of wells when injecting at the same constant mass rate. We quantitatively assess the results obtained from our numerical experiments by combining them with the permeability data that have recently become available, typical spatial densities of abandoned wells, and performance requirements put forward in the literature. Our results indicate that leakage of CO 2 through abandoned wells is unlikely to be a major limitation in storage security of CCS projects. [ABSTRACT FROM AUTHOR]

Abandoned oil and gas wells provide a potential pathway for subsurface migration and emissions of methane and other fluids to the atmosphere. Little is known about methane fluxes from the millions of abandoned wells that exist in the United States. Here, we report direct measurements of methane fluxes from abandoned oil and gas wells in Pennsylvania, using static flux chambers. A total of 42 and 52 direct measurements were made at wells and at locations near the wells ("controls") in forested, wetland, grassland, and river areas in July, August, October 2013 and January 2014, respectively. The mean methane flow rates at these well locations were 0.27 kg/d/well, and the mean methane flow rate at the control locations was 4.5 × 10-6 kg/d/location. Three out of the 19 measured wells were high emitters that had methane flow rates that were three orders of magnitude larger than the median flow rate of 1.3 × -3 kg/d/well. Assuming the mean flow rate found here is representative of all abandoned wells in Pennsylvania, we scaled the methane emissions to be 4-7% of estimated total anthropogenic methane emissions in Pennsylvania. The presence of ethane, propane, and n-butane, along with the methane isotopic composition, indicate that the emitted methane is predominantly of thermogenic origin. These measurements show that methane emissions from abandoned oil and gas wells can be significant. The research required to quantify these emissions nationally should be undertaken so they can be accurately described and included in greenhouse gas emissions inventories. [ABSTRACT FROM AUTHOR]

Abstract: For risk assessment, policy design and GHG emission accounting it is extremely important to know if any CO2 or brine has leaked from a geological sequestration (GS) operation. As such, it is important to understand if it is possible to use certain technologies to detect it. This detection of leakage is one of the most challenging problems associated with GS due to the high uncertainty in the nature and location of leakage pathways. In North America for example millions of legacy oil and gas wells present the possibility of CO2 and brine to leak out of the injection formation. The available information for these potential leaky wells is very limited and the main parameters that control leakage, like permeability of the sealing material are not known. Here we propose to explore the possibility of detecting such leakage by the use of pressure-monitoring wells located in a formation overlying the injection formation. The detection analysis is based on a system of equations that solve for the propagation of a pressure pulse using the superposition principle and an approximation to the well function. We explore the questions of what can be gained by using pressure-monitoring wells and what are the limitations given a specific accuracy threshold of the measuring device. We also try to answer the question of where these monitoring wells should be placed to optimize the objective of a monitoring scheme. We believe these results can ultimately lead to practical design strategies for monitoring schemes, including quantitative estimation of increased probability of leak detection per added observation well. [Copyright &y& Elsevier]

Abstract: Carbon capture and geological storage (CCS) operations will require an environmental risk analysis to determine, among other things, the risk that injected CO2 or displaced brine will leak from the injection formation into other parts of the subsurface or surface environments. Such an analysis requires site characterization including identification of potential leakage pathways. In North America, the century-long legacy of oil and gas exploration and production has left millions of oil and gas wells, many of which are co-located with otherwise good geological storage sites. Potential leakage along existing wells, coupled with layered stratigraphic sequences and highly uncertain parameters, makes quantitative analysis of leakage risk a significant computational challenge. However, new approaches to modeling CO2 injection, migration, and leakage allow for realistic scenarios to be simulated within a probabilistic framework. Using a specific field site in Alberta, Canada, we perform a range of computational studies aimed at risk analysis with a focus on CO2 and brine leakage along old wells. The specific calculations focus on the injection period, when risk of leakage is expected to be largest. Specifically, we simulate 50 years of injection of supercritical CO2 and use a Monte Carlo framework to analyze the overall system behavior. The simulations involve injection, migration, and leakage over the 50-year time horizon for domains of several thousand square kilometers having multiple layers in the sedimentary succession and several thousand old wells within the domain. Because we can perform each simulation in a few minutes of computer time, we can run tens of thousands of simulations and analyze the outputs in a probabilistic framework. We use these kinds of simulations to demonstrate the importance of residual brine saturations, the range of current options to quantify leaky well properties, and the impact of depth of injection and how it relates to leakage risk. [Copyright &y& Elsevier]

Disposal of waste fluids via injection into deep saline aquifers is practiced in a variety of industries. Injection takes place in sedimentary basins that often have a history of oil and gas exploration and production, which means that wells other than those used for waste disposal may exist in the vicinity of the injection site. These existing wells provide possible pathways for leakage of waste fluids toward the shallow subsurface and the land surface. For single-phase flows of liquids with essentially constant properties, the equations governing the system are linear, and solutions may be written using the superposition principle. Because leakage through existing wells produces a time-varying flux rate, the solution of the governing equations involves convolution integrals. Previous solutions have addressed the problem of one injection well, one existing (passive) well, and a simple geometry of two aquifers separated by an aquitard by use of Laplace transforms. Even for this simple case, inversion of the transform is difficult. Solutions involving more than one passive well have not been developed. Nor have solutions been developed for more than two aquifers and one aquitard. Realistic injection cases often involve layered systems with multiple aquifers and aquitards, as well as multiple passive wells, sometimes numbering in the hundreds. Solutions for the general case of multiple aquifers and wells may be developed through introduction of approximations to the well function and appropriate simplification of the convolution integral. Such a solution is computationally simple. Comparison to solutions using the full (Laplace transform) solution indicates that the new solution procedure produces excellent results. Application of the new solution to a case of multiple passive wells shows that the cumulative leakage flux in the passive wells is not a simple sum of the single-well case, owing to leakage-induced drawdown around the passive wells. In addition, application to the case of multiple aquifers and aquitards demonstrates the importance of leakage into intervening aquifers as a mechanism to mitigate leakage into shallow zones, a process referred to as the 'elevator model.' The new analytical solution provides a tool to analyze practical injection problems and forms a foundation on which more complex solutions, such as those involving injection of a nonaqueous fluid into a deep brine formation, may be based. [ABSTRACT FROM AUTHOR]

• Methane emissions from abandoned wells are measured continuously over 24 -hs • Repeat 24 -h measurements are made at a site over the course of a year • 24 h emissions from all wells were non-constant, average varied by a factor of 8 • No statistical significance between the size of emissions and variability in emissions • High emission events are short-lived, so short-term sampling is likely to miss them Recent studies have reported methane (CH 4) emissions from abandoned oil and gas wells across the United States and the United Kingdom. These emissions can reach hundreds of kg CH 4 per year per well and are important to include in greenhouse gas emission inventories and mitigation strategies. Emission estimates are generally based on single, short-term measurements that assume constant emission rates over both short (hours) and longer (months/years) time periods. To investigate this assumption, we measure CH 4 emissions from 18 abandoned oil and gas wells in the USA and the UK continuously over 24 h and then make repeat 24 -h measurements at a single site over 12 months. While the lack of historical records for these wells makes it impossible to determine the underlying leakage-pathways, we observed that CH 4 emissions at all wells varied over 24 h (range 0.2-81,000 mg CH 4 hr−1) with average emissions varying by a factor of 18 and ranging from factors of 1.1–142. We did not find a statistically significant relationship between the magnitude of emissions and variability or that variability is correlated with temperature, relative humidity or atmospheric pressure. The results presented here suggest high CH 4 emission events tend to be short-lived, so short-term (< 1 h) sampling is likely to miss them. Our findings present the dynamic nature of CH 4 emissions from abandoned oil and gas wells which should be considered when planning measurement methodologies and developing greenhouse gas inventories/mitigation strategies. Incorporation of these temporal dynamics could improve national greenhouse gas emissions inventories. [ABSTRACT FROM AUTHOR]