Legacy Wells Research Articles

On parameters affecting the propagation of hydraulic fractures from infill wells

In this article, several parameters that affect the propagation of hydraulic fractures initiated from a horizontal infill well are investigated. Infill wells are horizontal wells that are commonly drilled parallel to current producing (legacy) wells to ensure production from intact parts of the unconventional reservoirs. Production from legacy wells reduces the magnitude and changes the direction of the principal stresses in the depleted zone because of the poroelastic relationship between pore pressure and stress. The local stress redistribution has a significant impact on the topology of the hydraulic fracture that is created in infill wells. As a result of this redistribution, the child fracture asymmetrically propagates toward the depleted side of the infill well and might intersect the pre-existing hydraulic fractures or the legacy well. Each of these scenarios may negatively affect the performance of both wells. Therefore, several parameters should be considered while designing the drilling and stimulation processes of both legacy and infill wells. These parameters include production rate from legacy wells, timing of the infill drilling, legacy-infill well spacing, hydraulic fracture spacing in the legacy wells, rock permeability, fluid viscosity, etc. In this study, we investigate effects of some of these parameters on the propagation of an infill hydraulic fracture in the vicinity of a legacy well where the rock is partially depleted. A transient fully-coupled poroelastic displacement discontinuity model is developed for this purpose, and the maximum principal stress criterion (σ-criterion) is used to account for mixed mode (I & II) fracture propagation. The novelty of our model is that it can account for depletion of the legacy well and out of plane propagation of the child fracture in one run. This approach eliminates the routine exporting the pore pressure depletion and stress profile to a separate model. The parameters that we consider in this study are injection pressure, well spacing, legacy fracture spacing, and the difference between maximum and minimum horizontal stresses. It is observed that as the distance between the legacy hydraulic fractures reduces, the child fracture’s tendency to deviate away from their spacing area increases. Also, in the cases where the difference between the maximum and minimum horizontal stresses is large, refracturing can be postponed. We also provide suggestions for the optimum infill stimulation design for the studied impacting parameters.

Managing well leakage risks at a geologic carbon storage site with many wells

Potential geologic carbon storage (GCS) sites with a history of oil and gas production have well-characterized injectivity and storage capacity, but the presence of legacy wells increases leakage risk. Thus, the success of GCS operations at sites with many wells will require a thorough leakage risk assessment and a robust strategy for managing well leakage risk over the lifetime of the project. In this study, we demonstrate a workflow that uses the National Risk Assessment Partnership’s open-source Integrated Assessment Model to quantify well leakage risks and test the performance of various leakage risk management strategies at a heavily drilled GCS site. Our model simulates a 50-year basin-scale injection of CO2 at a hypothetical site based on the Kimberlina Project Site in the Southern San Joaquin Valley of California. Brine and CO2 leakage through 1000 legacy wells into a USDW are stochastically simulated as a proxy for risk. We consider multiple scenarios that explore the efficacy of various well leakage risk management strategies with changes in well leakage behavior, reservoir behavior, and post-injection site care (PISC) length. Predicted leakage at the site after 100 years was small with a maximum CO2 leakage of 102.1 tonnes (4.08 × 10−5% of the 250 Mt injected) and a maximum brine leakage of 2.4 tonnes. Leakage risk management strategies based on accurate prior information about well leak probability reduced leakage risks more effectively at the modeled site and were more robust with respect to reservoir uncertainty than strategies based on the distance of the legacy well from the injector. The importance of the PISC period length was not clear as it had a negligible impact on CO2 leakage risk but a sizable impact on brine leakage risk in our model.

Integration of wellbore pressure measurement and groundwater quality monitoring to enhance detectability of brine and CO2 leakage

Leakage detectability is a key consideration in evaluating the effectiveness of a measurement, monitoring and verification (MMV) plan for a geologic carbon storage (GCS) project. While studies have shown that surface-based, geophysical monitoring methods may be sensitive enough to detect CO2 leakage, these methods are an indirect indicator of leakage. A drawback to relying on direct geochemical monitoring is that by the time a significant leak is confirmed, it may be too late to mitigate or remediate the environmental impacts. In this study, we combine information from geophysical and geochemical monitoring methods to provide an integrated diagnosis of leakage events. The detectability for various monitoring parameters (pH, TDS, alkalinity, Ca, Cl, Na, and pressure) collected from monitoring wells are evaluated by leakage detection probability, using simulated wellbore-leakage/plume-migration events and monitoring scenarios for a hypothetical GCS operation at the Kimberlina site in California, USA. The NUFT code is used to model these events, by coupling wellbore-leakage simulations to 3-dimensional reactive, multi-phase, flow and transport simulations of brine and CO2 leakage-plume migration in aquifers overlying the GCS reservoir. Wellbore leakage in legacy wells located 1.4, 3.4 and 6.8 km from the CO2 injector is evaluated for a range of (1) wellbore bottom-hole pressure and CO2 saturation determined by GCS simulations, (2) regional groundwater gradient in the aquifers, and (3) wellbore permeability. Simulated leakage-induced changes in seven monitoring parameters at different depths are used to calculate the corresponding detection probabilities, based on the background distribution data and selected monitoring-technology detection thresholds. The responses for these monitoring parameters are tested and combined to enhance the overall detectability. The results indicate the leakage signals are more easily detected at shallower depths where buoyant CO2 has migrated and flashed from supercritical to gas phase, causing a large increase in CO2 volume. While the results suggest pH monitoring is more responsive to the simulated leakage events than TDS monitoring at shallower depths, TDS changes may be more readily observed at greater depths. The addition of carbonate alkalinity can confirm CO2 leakage detection and help distinguish CO2 leakage from other contamination sources. Direct pressure change measurements are very sensitive to leakage, but the rapid and broad propagation of the pressure response hinders using such measurements to easily locate the origin of leakage. Combining measurements could greatly improve the confidence of leakage diagnosis. High bottom-hole CO2 saturation, such as that for a leaky well close to the injector (˜1.4 km), high regional groundwater gradient, and high wellbore permeabilities all increase the leakage plume size, and thus the leakage detectability. Our analysis suggests pressure monitoring is a valuable indicator of leakage events at early stages, while pH, TDS and carbonate alkalinity monitoring can directly diagnose leakage impacts by providing more detailed information in the groundwater receptor. Finally, an example Bayesian belief network model is presented for evaluating the effect of risk reduction options in terms of joint monitoring detection probability using the associated simulation scenarios. This framework is demonstrated to inform how pressure and groundwater quality information can be integrated into site MMV and risk management plans.

Practical Leakage Risk Assessment for CO2 Assisted Enhanced Oil Recovery and Geologic Storage in Ohio's Depleted Oil Fields

A method for estimating the expected liability (risk) associated with wellbore leakage during and after geologic storage operations is presented using three of Ohio’s oil fields as case studies. The risk framework described in this study uses the bowtie method with features, events, and processes (FEPs) descriptors to identify and assess risk posed by legacy wells. The bow-tie framework allows simple visualization of top risk events (hazards). The probability of triggering the hazard is quantified based on estimation of the wellbore’s integrity while the consequences are modeled based on low- and high-cost outcome scenarios. This method builds upon previous work. It estimates current wellbore integrity using characteristic categories to develop a proxy for leakage likelihood. Proxy categories were: Spud Date, Treatment, Well Status, Plugging and Abandonment (P&A) Date, Well Type, Plug, Surface Cement, and Primary Cement. Separate risks were developed for each well and each scenario. The consequence of a leakage event was estimated based on costs to businesses and property owners for each leakage scenario. Using the likelihood of leakage calculated for each field and the cost of potential consequences, the risks for each field were estimated to be between $10 million to $63 million for the three fields of interest. Overall, the identification of threats, hazards, and consequences and the identification of barriers to lessen the likelihood of occurrence or minimize consequences aids in the development of a targeted CCUS strategies.

Orphaned wells, oil assets, and debt: the competing ethics of value creation and care within petrocapitalist projects of return

AbstractThis essay explores the phenomenon known as ‘orphaned wells’, meaning unprofitable oil and gas wells (‘legacy wells’) that have become disentangled from their corporate owners owing to insolvency, or owing to a failure to comply with local regulations. Drawing from an ethnographic example of a near‐insolvent oil and gas corporation in Alberta, Canada, and its strategies of refinancing, the essay explores how value creation and the moral force of the obligation to create a financial return give rise to a ‘durational ethics’ that shapes corporate and financial performativities and prolongs the ‘life’ of legacy oil and gas assets. Legacy assets, understood as potential orphans, are thus caught up in a lively corporate practice of asset circulation and recombination often deployed by producers for the moral work of ‘cleaning balance sheets’. This essay calls for ‘thinking with orphans’ to recognize the competing ethical registers which produce them in addition to the growing need for responsibility and corporate care for legacy oil and gas assets.

Evaluation of Practicable Subsurface CO2 Storage Capacity and Potential CO2 Transportation Networks, Onshore North America

Carbon Capture, Utilization and Storage (CCUS) is considered to be a potentially important technology for reducing the amount of carbon dioxide (CO2) released into the atmosphere from anthropogenic emission sources. With recent progress on capture technologies, attention is increasingly turning to the identification of key challenges associated with CO2 transportation and storage at the scale being considered for the CCUS industry. Decades of oil and gas production have provided experience in application of technologies required for CO2 transportation and storage, but the challenges unique to CO2 storage still need to be evaluated. This paper describes a scoping-level assessment of practicable subsurface geologic CO2 storage capacity and a potential Carbon Capture, Utilization, and Storage (CCUS) industry in the US and Canada, leveraging publically available data/information, publications, and methodologies. Likely subsurface CO2 storage sites and distribution of storage capacity relative to major anthropogenic sources are first characterized using a probabilistic methodology previously developed by the US Geologic Survey (USGS), which was modified to account for several practical factors affecting storage capacity. Major factors considered include 1) subsurface lateral accessibility restrictions imposed by faulting and/or stratigraphic pinch-outs, 2) the proportion of net storage-quality sand comprised of thin sands unlikely to be good injection candidates, 3) surface access restrictions, and 4) dynamic injectivity/storage efficiency considerations. Potential regional CCUS networks are then modeled using a transportation cost framework to map CO2 sources to storage sinks. The USGS assessment and most other existing assessments of storage capacity are based on the premise that all engineering approaches and hardware required to achieve the highest possible storage efficiency would be employed, and that injection rate and timeframe are not issues, with perhaps hundreds to thousands of years of injection permitted to achieve full storage efficiency. We explore the impact of dynamic injectivity considerations on practical storage efficiency by using reservoir simulation models to account for subsurface pressure limitations and the impact of permeability differences and lateral accessibility on CO2 injectability, and then use the results of the modeling to derive a debiting function that reduces the range of static storage capacity estimated by the USGS. Debiting functions accounting for lateral accessibility, thin sands, and surface access restrictions were also applied to obtain practicable storage estimates. Key conclusions from the study include: 1) Although the modified storage capacity estimates are lower than previously published estimates, the estimated subsurface storage capacity in the US onshore is sufficient to sustain a large-scale CO2 storage industry. We estimate that about 500 Gt of potential US subsurface storage capacity is potentially available (excluding federal offshore capacity) even after accounting for dynamic injectibility considerations, thin sands, surface and lateral access issues. Dynamic injectability factors had the largest impact on the reduction in estimated storage capacity. 2) Significant geographic misalignment exists between current high-volume CO2 emission sources and storage availability in North America. This could affect evolution of CO2 transportation networks with time. Detailed site-specific assessments of subsurface storage capacity are required for site selection and actual project implementation. These efforts could change some of the conclusions of this study. In particular, consideration of legacy wells and geomechanical factors such as induced seismicity, ground surface deformation, and fault activation may further reduce storage capacity relative to the estimates presented here. Nevertheless, the methodology described in this paper may be useful for initial assessment of CO2 storage capacity and matching of CO2 emission sources to storage sinks in geographic locations other than those considered in this study.

Quantifying Geological CO2 Storage Security to Deliver on Climate Mitigation

The Storage Security Calculator (SSC) is a tool to simulate the long-term (10kyr) security of CO2 storage at a basin scale. Simulations show that CO2 storage in regions with moderate abandoned well densities and that are regulated using current best practice will retain 96% of the injected CO2 over 10,000 years in more than half of cases, with maximum leakage of 9.6% in fewer than 5% of cases. Poorly unregulated storage is less secure, but over 10,000 years, less than 27% of injected CO2 leaks in half of the simulations; up to 34% leaks in just 5% of cases. This leakage is primarily through undetected and poorly abandoned legacy wells, and could be reduced through effective leak identification and prompt remediation of leakage. Natural subsurface immobilisation means that this leakage will not continue indefinitely. Regulators can most effectively improve CO2 storage security by identifying and monitoring abandoned wells, and perform reactive remediation should they leak. Geological storage of CO2 is a secure, resilient and feasible option for climate mitigation even in overly pessimistic poorly regulated storage scenarios and thus CO2 storage can effectively contribute to meeting the Paris 2015 target.

Integration of Wellbore Pressure Measurement and Groundwater Quality Monitoring to Enhance Detectability of Brine and CO2 Leakage

Abstract Leakage detectability is a key consideration in evaluating the effectiveness of a measurement, monitoring and verification (MMV) plan for a geologic carbon storage (GCS) project. While studies have shown that surface-based, geophysical monitoring methods may be sensitive enough to detect CO2 leakage, these methods are an indirect indicator of leakage. A drawback to relying on direct geochemical monitoring is that by the time a significant leak is confirmed, it may be too late to mitigate or remediate the environmental impacts. In this study, we combine information from geophysical and geochemical monitoring methods to provide an integrated diagnosis of leakage events. The detectability for various monitoring parameters (pH, TDS, alkalinity, Ca, Cl, Na, and pressure) collected from monitoring wells are evaluated by leakage detection probability, using simulated wellbore-leakage/plume-migration events and monitoring scenarios for a hypothetical GCS operation at the Kimberlina site in California, USA. The NUFT code is used to model these events, by coupling wellbore-leakage simulations to 3-dimensional reactive, multi-phase, flow and transport simulations of brine and CO2 leakage-plume migration in aquifers overlying the GCS reservoir. Wellbore leakage in legacy wells located 1.4, 3.4 and 6.8 km from the CO2 injector is evaluated for a range of (1) wellbore bottom-hole pressure and CO2 saturation determined by GCS simulations, (2) regional groundwater gradient in the aquifers, and (3) wellbore permeability. Simulated leakage-induced changes in seven monitoring parameters at different depths are used to calculate the corresponding detection probabilities, based on the background distribution data and selected monitoring-technology detection thresholds. The responses for these monitoring parameters are tested and combined to enhance the overall detectability. The results indicate the leakage signals are more easily detected at shallower depths where buoyant CO2 has migrated and flashed from supercritical to gas phase, causing a large increase in CO2 volume. While the results suggest pH monitoring is more responsive to the simulated leakage events than TDS monitoring at shallower depths, TDS changes may be more readily observed at greater depths. The addition of carbonate alkalinity can confirm CO2 leakage detection and help distinguish CO2 leakage from other contamination sources. Direct pressure change measurements are very sensitive to leakage, but the rapid and broad propagation of the pressure response hinders using such measurements to easily locate the origin of leakage. Combining measurements could greatly improve the confidence of leakage diagnosis. High bottom-hole CO2 saturation, such as that for a leaky well close to the injector (˜1.4 km), high regional groundwater gradient, and high wellbore permeabilities all increase the leakage plume size, and thus the leakage detectability. Our analysis suggests pressure monitoring is a valuable indicator of leakage events at early stages, while pH, TDS and carbonate alkalinity monitoring can directly diagnose leakage impacts by providing more detailed information in the groundwater receptor. Finally, an example Bayesian belief network model is presented for evaluating the effect of risk reduction options in terms of joint monitoring detection probability using the associated simulation scenarios. This framework is demonstrated to inform how pressure and groundwater quality information can be integrated into site MMV and risk management plans.

Geological Model of a Storage Complex for a CO2 Storage Operation in a Naturally-Fractured Carbonate Formation

Investigation into geological storage of CO2 is underway at Hontomín (Spain). The storage reservoir is a deep saline aquifer formed by naturally fractured carbonates with low matrix permeability. Understanding the processes that are involved in CO2 migration within these formations is key to ensure safe operation and reliable plume prediction. A geological model encompassing the whole storage complex was established based upon newly-drilled and legacy wells. The matrix characteristics were mainly obtained from the newly drilled wells with a complete suite of log acquisitions, laboratory works and hydraulic tests. The model major improvement is the integration of the natural fractures. Following a methodology that was developed for naturally fractured hydrocarbon reservoirs, the advanced characterization workflow identified the main sets of fractures and their main characteristics, such as apertures, orientations, and dips. Two main sets of fracture are identified based upon their mean orientation: North-South and East-West with different fracture density for each the facies. The flow capacity of the fracture sets are calibrated on interpreted injection tests by matching their permeability and aperture at the Discrete Fracture Network scale and are subsequently upscaled to the geological model scale. A key new feature of the model is estimated permeability anisotropy induced by the fracture sets.

Geophysical data processing, rock property inversion, and geomechanical model building in a Midland Basin development project, Midland/Ector counties, Texas

The current state of the art for development of unconventional projects integrates geology, geophysics, and engineering into a comprehensive reservoir description. To that end, we have designed a comprehensive geophysical workflow to define the structure, stratigraphy, and rock mechanics of a stacked reservoir sequence in the west-central Midland Basin. The purpose of this paper is to describe the workflow. Portions of three seismic data sets were merged and processed anisotropically, preserving the full range of azimuths. Well control consisted of 35 compressional sonic logs, eight shear sonic logs, three sonic scanners, two lateral formation microimaging tools, and three cores. Nine newly drilled laterals are on production along with a large number of vertical legacy wells. Prestack inversion produced acoustic impedance, shear impedance, and density with good accuracy, although the compressional-to-shear-velocity ratio (VP/VS) was not stable. This volume was successfully recreated via neural net, which was also used to calculate total porosity and total water saturation volumes. Poisson's ratio, Young's modulus, and brittleness were created using standard equations and the neural net VP/VS volume. Structural attributes consisted of ant track, coherence, semblance, fault probability, and Kmin and Kmax curvature. The final step in this portion of the workflow was to create a high-resolution depth conversion velocity volume. A geocellular grid was built and populated with petrophysical volumes, lithology facies, and structural attributes. Principal stresses were incorporated by first establishing 1D mechanical earth models (MEMs) where appropriate log suites were available. These 1D MEMs were extended to a 3D MEM, although confidence in this volume is not high due to known pore pressure and closure stress reductions as a result of legacy vertical well production. Calibration incorporating new data as it becomes available is an ongoing task. An informative simulation using the MEM is frac models, which define the most optimal landing points for laterals. This MEM and the simulations it can perform have easily demonstrated the value of this integrated workflow.

Influence of Chemical, Mechanical, and Transport Processes on Wellbore Leakage from Geologic CO2 Storage Reservoirs.

Wells are considered to be high-risk pathways for fluid leakage from geologic CO2 storage reservoirs, because breaches in this engineered system have the potential to connect the reservoir to groundwater resources and the atmosphere. Given these concerns, a few studies have assessed leakage risk by evaluating regulatory records, often self-reported, documenting leakage in gas fields. Leakage is thought to be governed largely by initial well-construction quality and the method of well abandonment. The geologic carbon storage community has raised further concerns because acidic fluids in the CO2 storage reservoir, alkaline cement meant to isolate the reservoir fluids from the overlying strata, and steel casings in wells are inherently reactive systems. This is of particular concern for storage of CO2 in depleted oil and gas reservoirs with numerous legacy wells engineered to variable standards. Research suggests that leakage risks are not as great as initially perceived because chemical and mechanical alteration of cement has the capacity to seal damaged zones. Our work centers on defining the coupled chemical and mechanical processes governing flow in damaged zones in wells. We have developed process-based models, constrained by experiments, to better understand and forecast leakage risk. Leakage pathways can be sealed by precipitation of carbonate minerals in the fractures and deformation of the reacted cement. High reactivity of cement hydroxides releases excess calcium that can precipitate as carbonate solids in the fracture network under low brine flow rates. If the flow is fast, then the brine remains undersaturated with respect to the solubility of calcium carbonate minerals, and zones depleted in calcium hydroxides, enriched in calcium carbonate precipitates, and made of amorphous silicates leached of original cement minerals are formed. Under confining pressure, the reacted cement is compressed, which reduces permeability and lowers leakage risks. The broader context of this paper is to use our experimentally calibrated chemical, mechanical, and transport model to illustrate when, where, and in what conditions fracture pathways seal in CO2 storage wells, to reduce their risk to groundwater resources. We do this by defining the amount of cement and the time required to effectively seal the leakage pathways associated with peak and postinjection overpressures, within the context of oil and gas industry standards for leak detection, mitigation, and repairs. Our simulations suggest that for many damage scenarios chemical and mechanical processes lower leakage risk by reducing or sealing fracture pathways. Leakage risk would remain high in wells with a large amount of damage, modeled here as wide fracture apertures, where fast flowing fluids are too dilute for carbonate precipitation and subsurface stress does not compress the altered cement. Fracture sealing is more likely as reservoir pressures decrease during the postinjection phase where lower fluxes aid chemical alteration and mechanical deformation of cement. Our results hold promise for the development of mitigation framework to avoid impacting groundwater resources above any geologic CO2 storage reservoir by correlating operational pressures and barrier lengths.

Corrosion and Failure Assessment for CO2 EOR and Associated Storage in the Weyburn Field

Many depleted oil and gas reservoirs are targets for commercial CO2 enhanced oil recovery, resulting in associated CO2 storage which occurs as part of the process. These oil fields have legacy wellbores that may contain a leakage pathway. Corrosion or degradation can occur anywhere along the wellbore through or along the cement, casing, tubing, or plugs and is a challenging issue facing the oil and gas industry. Two case studies presented here are legacy wells in the Weyburn oil field with substantially different CO2 injection rates. These case studies aim to help understand casing corrosion in CO2-rich environments.

Methods and challenges to locating legacy wells in western Pennsylvania: Case study at Hillman State Park

This study demonstrates the application of aeromagnetic surveys for locating late 1800s-era oil and gas wells in Hillman State Park. The study area in southwestern Pennsylvania offered several unique challenges to locating legacy wells. Location records for many of Pennsylvania’s legacy wells do not exist. Those that do exist are often incomplete and inaccurate, and old wells were commonly abandoned without effective plugging. Now, unplugged legacy wells may serve as vertical migration pathways for fluids and gas associated with modern oil and gas operations. Wells in Hillman State Park were abandoned in the early 1900s, leaving little evidence of a well site. However, the steel well casing commonly remained at the site. Between 1940 and 1960, 50% of the land area at Hillman State Park was surface mined for coal. The removal of coal overburden also removed the upper well casings in surface-mined areas to the depth of the coal. The wells were then buried under mine spoil during regrading operations. Today, much of Hillman State Park is covered in trees and dense vegetation, and locating wells with ground-level searches is difficult, time consuming, and often futile. The airborne magnetic survey used in this study identified well locations, including buried wells in mined areas, based on the unique magnetic signature of vertical, steel well casing. The results of the aeromagnetic survey were combined with aerial photography, historic maps, and high-resolution topographic data in a geographic information system to refine well locations prior to verification with a ground search.

Subsea ice‐bearing permafrost on the U.S. Beaufort Margin: 2. Borehole constraints

AbstractBorehole logging data from legacy wells directly constrain the contemporary distribution of subsea permafrost in the sedimentary section at discrete locations on the U.S. Beaufort Margin and complement recent regional analyses of exploration seismic data to delineate the permafrost's offshore extent. Most usable borehole data were acquired on a ∼500 km stretch of the margin and within 30 km of the contemporary coastline from north of Lake Teshekpuk to nearly the U.S.‐Canada border. Relying primarily on deep resistivity logs that should be largely unaffected by drilling fluids and hole conditions, the analysis reveals the persistence of several hundred vertical meters of ice‐bonded permafrost in nearshore wells near Prudhoe Bay and Foggy Island Bay, with less permafrost detected to the east and west. Permafrost is inferred beneath many barrier islands and in some nearshore and lagoonal (back‐barrier) wells. The analysis of borehole logs confirms the offshore pattern of ice‐bearing subsea permafrost distribution determined based on regional seismic analyses and reveals that ice content generally diminishes with distance from the coastline. Lacking better well distribution, it is not possible to determine the absolute seaward extent of ice‐bearing permafrost, nor the distribution of permafrost beneath the present‐day continental shelf at the end of the Pleistocene. However, the recovery of gas hydrate from an outer shelf well (Belcher) and previous delineation of a log signature possibly indicating gas hydrate in an inner shelf well (Hammerhead 2) imply that permafrost may once have extended across much of the shelf offshore Camden Bay.

Wellbore corrosion and failure assessment for CO2 EOR and storage: Two case studies in the Weyburn field

Many depleted oil and gas reservoirs are targets for CO2 enhanced oil recovery, resulting in CO2 storage as part of the commercial enhanced oil recovery process. These oil fields have legacy wellbores that may contain a leakage pathway. Corrosion or degradation can occur anywhere along the wellbore through or along the cement, casing, tubing, or plugs and is a challenging issue facing the oil and gas industry. Two case studies presented here evaluate legacy wells in the Weyburn oil field. One well has injected over 263 million cubic meters of CO2, and the second well has not been exposed to CO2. These case studies aim to help understand casing corrosion in CO2-rich environments.Both wellbores exhibited signs of corrosion, with corrosion ranging from small pits to complete penetration through the casing. Contributing factors to corrosion in these wells range from exposure to injected fluids, injected CO2, packer placements, formation fluid exposure, and the corrosive environment that is present in the perforated area of the well.

Spatial and Temporal Characteristics of Historical Oil and Gas Wells in Pennsylvania: Implications for New Shale Gas Resources.

Recent large-scale development of oil and gas from low-permeability unconventional formations (e.g., shales, tight sands, and coal seams) has raised concern about potential environmental impacts. If left improperly sealed, legacy oil and gas wells colocated with that new development represent a potential pathway for unwanted migration of fluids (brine, drilling and stimulation fluids, oil, and gas). Uncertainty in the number, location, and abandonment state of legacy wells hinders environmental assessment of exploration and production activity. The objective of this study is to apply publicly available information on Pennsylvania oil and gas wells to better understand their potential to serve as pathways for unwanted fluid migration. This study presents a synthesis of historical reports and digital well records to provide insights into spatial and temporal trends in oil and gas development. Areas with a higher density of wells abandoned prior to the mid-20th century, when more modern well-sealing requirements took effect in Pennsylvania, and areas where conventional oil and gas production penetrated to or through intervals that may be affected by new Marcellus shale development are identified. This information may help to address questions of environmental risk related to new extraction activities.

Quantifying the benefit of wellbore leakage potential estimates for prioritizing long-term MVA well sampling at a CO2 storage site.

This work uses probabilistic methods to simulate a hypothetical geologic CO2 storage site in a depleted oil and gas field, where the large number of legacy wells would make it cost-prohibitive to sample all wells for all measurements as part of the postinjection site care. Deep well leakage potential scores were assigned to the wells using a random subsample of 100 wells from a detailed study of 826 legacy wells that penetrate the basal Cambrian formation on the U.S. side of the U.S./Canadian border. Analytical solutions and Monte Carlo simulations were used to quantify the statistical power of selecting a leaking well. Power curves were developed as a function of (1) the number of leaking wells within the Area of Review; (2) the sampling design (random or judgmental, choosing first the wells with the highest deep leakage potential scores); (3) the number of wells included in the monitoring sampling plan; and (4) the relationship between a well’s leakage potential score and its relative probability of leakage. Cases where the deep well leakage potential scores are fully or partially informative of the relative leakage probability are compared to a noninformative base case in which leakage is equiprobable across all wells in the Area of Review. The results show that accurate prior knowledge about the probability of well leakage adds measurable value to the ability to detect a leaking well during the monitoring program, and that the loss in detection ability due to imperfect knowledge of the leakage probability can be quantified. This work underscores the importance of a data-driven, risk-based monitoring program that incorporates uncertainty quantification into long-term monitoring sampling plans at geologic CO2 storage sites.

Key factors for determining groundwater impacts due to leakage from geologic carbon sequestration reservoirs

In this paper we describe potential impacts to groundwater quality due to CO2 and brine leakage, discuss an approach to calculate thresholds under which “no impact” to groundwater occurs, describe the time scale for impact on groundwater, and discuss the probability of detecting a groundwater plume should leakage occur. To facilitate this, multi-phase flow and reactive transport simulations and reduced-order models were developed for two classes of aquifers, considering uncertainty in leakage source terms and aquifer hydrogeology. We targeted an unconfined fractured carbonate aquifer based on the Edwards Aquifer in Texas and a confined alluvium aquifer based on the High Plains Aquifer in Kansas, which share characteristics typical of many drinking water aquifers in the United States. The hypothetical leakage scenarios centered on the notion that wellbores are the most likely conduits for brine and CO2 leaks. Leakage uncertainty was based on hypothetical injection of CO2 for 50 years at a rate of 5 million tons per year into a depleted oil/gas reservoir with high permeability and, one or more wells provided leakage pathways from the storage reservoir to the overlying aquifer. This scenario corresponds to a storage site with historical oil/gas production and some poorly completed legacy wells that went undetected through site evaluation, operations, and post-closure.For the aquifer systems and leakage scenarios studied here, CO2 and brine leakage are likely to drive pH below and increase total dissolved solids (TDS) above the “no-impact thresholds”; and the subsequent plumes, although small, are likely to persist for long periods of time in the absence of remediation. In these scenarios, however, risk to human health may not be significant for two reasons. First, our simulated plume volumes are much smaller than the average inter-well spacing (1–2.6wells/km2) for these representative aquifers, so the impacted groundwater would be unlikely to be pumped for drinking water. Second, even within the impacted plume volumes little water exceeds the primary maximum contamination levels. These observations point to:•The potential utility of uncertainty quantification methods to evaluate the risk of leakage and inform monitoring and corrective action plans of a potential site for long-term CO2 storage by capturing storage reservoir, leakage pathway, and aquifer heterogeneity.•The importance of establishing baseline groundwater chemistry that captures the pre-injection variability of underground sources of drinking water (USDW) above the reservoir because the EPA has adopted a “no net degradation” policy toward the protection of groundwater resources.•The need to test and develop spatially diverse monitoring techniques capable of detecting leakage early to employ effective mitigation strategies, and more importantly to add confidence to assessments used to evaluate the length of the post-injection site care. In our study, the probability of detecting plumes using existing wells to sample the groundwater chemistry was very low, because the plumes were relatively small in both aquifers.•The need to develop methodologies that prevent and/or directly detect leakage prior to reaching USDWs, because our simulations predict that even small amounts of CO2 and brine, when left unmitigated, can change USDW pH and TDS concentrations for long periods of time.

Alaskan North Slope Legacy Wells: Case Study

ABSTRACT Various State of Alaska agencies, including the Alaska Department of Environmental Conservation (ADEC), are currently investigating 136 legacy wells within the National Petroleum Reserve-Alaska (NPR-A) and surrounding lands. These legacy wells were drilled between 1944 and 1981 by federal agencies, including the United States Navy and United States Geological Survey, to explore oil reserve potential and to develop drilling techniques for Alaska's arctic. In 2004, 2010 and 2013 the Bureau of Land Management released preliminary studies describing potential environmental risks at each site. Many wells include historic reserve pits, flare pits, crude and diesel oil releases, and discarded solid waste. Tundra damage and potential residual contamination are of great concern. Due to their remote locations, information on the current status of waste is limited. Regulatory agencies are developing a cleanup plan that is appropriate for their remote, Arctic environment.

Sedimentology, stratigraphy, and reservoir properties of an unconventional, shallow, frozen petroleum reservoir in the Cretaceous Nanushuk Formation at Umiat field, North Slope, Alaska

Numerous oil and gas accumulations exist in the Brooks Range foothills of the National Petroleum Reserve in Alaska (NPRA). We use cores and well logs from 12 abandoned legacy wells at Umiat field, near the southeastern boundary of the NPRA, to characterize the sedimentology and stratigraphy of unconventional shallow frozen reservoirs in sandstones of the Cretaceous (Albian–Cenomanian) Nanushuk Formation. The Nanushuk Formation at Umiat has five facies associations: offshore and prodelta, lower shoreface, upper shoreface, delta front, and delta plain.Three stratigraphically distinct, regionally extensive Nanushuk Formation depositional systems at Umiat contain several potential petroleum reservoirs. The lower Nanushuk Formation, including a reservoir interval known informally as the lower Grandstand, primarily consists of marine mudstone and shoreface sandstones. The middle Nanushuk Formation is dominantly deltaic and contains a second major reservoir interval in the informal upper Grandstand sandstone. Both the upper Grandstand and lower Grandstand are regressive. The transgressive upper Nanushuk Formation contains an additional potential reservoir interval in shoreface sandstones of the informal Ninuluk interval. The primary reservoir intervals at Umiat field are upper shoreface and delta-front sandstones in the upper Grandstand and lower Grandstand, where increased sorting and decreased bioturbation in high-energy depositional environments affect overall permeability and permeability anisotropy.