• Energy Research

AbstractAs part of the United States Department of Energy (DOE) National Energy Technology Laboratory (NETL) sponsored project, The Quantification of Wellbore Leakage Risk Using Non-destructive Borehole Logging Techniques, the construction and integrity of a 68 year old well was studied. This study builds upon previous work examining the integrity of existing wells through shale formations. The objective of this study was to measure well integrity through potential caprocks and aid in understanding the potential leakage risk posed by old wells that intersect CO2 injection projects.The well was originally completed as a production well in the Gulf Coast region in 1945 and then plugged and abandoned in 1969. The well was re-entered and re-completed as an observation well for a CO2 injection project in 2008. It was replugged and abandoned after completing its observation role in 2013. For this study the well was logged using cement bond log and ultrasonic mapping tools, tested and sampled using a dynamic tester, and cored using a sidewall coring tool. The age of this well makes it the oldest well to be studied in this manner and this is the first well to be studied this way in the region.The results of the study indicate that much of the material behind the casing is unconsolidated cement. Logging results in many places in the well show poor isolation potential and indicate a microannulus. The logs also indicate removal of material during hydraulic testing which was confirmed by laboratory analysis. Of the six cores collected, four consisted of unconsolidated, soft, cement or rock, one consisted of heavily altered cement, and one consisted of slightly altered cement. The results of study are an interesting contrast to earlier field studies because they show an old well that lacked integrity at most of the test and sample points. However, the logging and a core sample in the squeezed zone indicate that there was zonal isolation between the injection and monitoring zones. The logging and mapping data along with the analysis of the “core” material collected provide insight into the potential leakage pathways within the well.

AbstractAbandoned wellbores may pose an important risk to the integrity of CO2 storage formations that have large numbers of existing wells and that risk needs to be better understood. Field and laboratory studies have shown that well cement can be affected by CO2 at differing levels depending on conditions. However, none of this work has looked at the initial conditions of the well (prior to CO2 exposure). Understanding the initial conditions will be important for ensuring that the potential risk of leakage from the storage formation is acceptable. The collection of baseline wellbore integrity data allows for comparison during a project and will also identify any potentially problematic wells before a leak may occur. New field data from wells must be used to begin to understand if there are field-wide similarities between existing wells and how the similarities may be used to assess field-wide leakage risk. Existing data are not sufficiently focused (multiple wells in the same field) and there has been no satisfactory method of accelerating laboratory experiments to create realistic wellbore leakage conditions.Similarities between wells in the same fields were examined as part of a project to study the baseline condition and leakage risk of existing wells. Five wells were analyzed. The wells were split between two fields in the state of Wyoming, USA. The investigation used a combination of wellbore logging and sampling tools to analyze well conditions. Logging tools were selected to provide the maximum information on the materials that were used to construct wells and provide zonal isolation. The logging suite included sonic mapping tools, ultrasonic mapping tools, dynamic testers, and sidewall coring tools. Initial results show that there are similarities between wells within the same fields.

Abstract The University of Wyoming is partnered with Los Alamos National Laboratory, Lawrence Livermore National Laboratory, Battelle, and Water system Specialists Inc. to carry out a DOE funded brine extraction storage test (BEST) project at the Rock Springs Uplift (RSU), southwest Wyoming. The BEST projects are envisioned using a two-phased approach. The initial phase is 1) to predict and monitor the differential pressure and injected fluid movement, and manage changes in formation pressure, and 2) to develop a test-bed for deploying treatment technologies for extracted brines. The RSU shows promise as a CO 2 storage location because of its favorable geologic conditions and structure. In addition, the project is located at a carbon storage site in southwest Wyoming that has been extensively characterized on the basis of data obtained from previous U.S. DOE-funded studies that have included detailed site descriptions and CO 2 storage capacity and permanence estimates. The primary objective of the project includes: • Refining 3-D reservoir structure and property models of the site that include the known structural complexity and heterogeneity of the site's subsurface conditions; • Evaluate geophysical and chemical monitoring technologies and techniques to detect and measure pressure response to injected fluid as well as track fluid migration pathways; • Analyze the feasibility of extracting formation brine water to mitigate the pressure increase from injection, as well as to modify the pressure front, resulting in the ability to manipulate the direction of the migrating pressure/CO 2 plume, and reduce the size of the Area of Review; • Develop advanced fluid flow simulation schemes to predict reservoir pressure responses and migration pathways of the injected fluid; • Implement rock mechanical property and stress calculations, combined with simulations, to help assess geomechanical impacts to the reservoir and confining layers in response to high volume CO 2 injections; • Conduct a produced brine life-cycle analysis, and develop a displaced brine water treatment, and management program; and • Propose an active reservoir management strategy that could be implemented during a field testing. The proposed field test project includes developing a field site fully capable of fluid injection, production, monitoring, and water treatment. This effort would provide for in-situ testing of plume migration and pressure management strategies, and investigate the technical feasibility of treating co-produced waters. Furthermore, the result of this effort is a better understanding of the potential effects of pressure and active brine management on the behavior of stored CO2 in the Rocky Mountain region as well as the similar saline aquifers around world, such as the huge saline aquifer in the Ordos Basin, China.

AbstractCarbon sequestration in abandoned petroleum fields may be a short-term solution to reducing anthropogenic emissions of CO2. If sequestration is adopted on a large scale, it will be important to understand how CO2 may leak out of sequestration formations. Possible avenues for leakage are abandoned wells. The results of a set of cement degradation experiments were used to get a rough estimate of the rate of degradation of the cement that is used to construct and abandon wells when it is exposed to carbonic acid. The rates that were calculated give an estimate of the time to degrade 25 mm of cement under static conditions at pH and temperature conditions that one might expect in a sequestration formation. The results of the estimate indicate that it will take tens to hundreds of thousands of years to degrade 25 mm of cement.

AbstractWellbore integrity is considered an important risk factor for leakage of CO2 and formation fluids out of geological CO2 storage sites. Quantifying the effective hydraulic parameters that control vertical migration of fluids along the wellbore involves data collection through numerous field and laboratory experiments. The vertical interference test (VIT) is a downhole test designed to measure hydraulic communication of the outside-of-casing wellbore barrier system over a selected well section. Results from these tests can be analyzed numerically to determine the average permeability of the section. Several field surveys of existing wells have resulted in 9 VIT datasets, of which three are presented here. The effective permeability estimates for the three tests span two orders of magnitude, from approximately 1 mD to more than 100 mD. When compared with companion sidewall core analyses of the cement matrix that have permeabilities in the microD range, the VIT data suggest that interfaces or defects in the cement sheath are responsible for flow. Initial analysis of the remaining 6 datasets suggests an even larger range in effective permeability values, as low as microD to more than 1 D, indicating that well permeability can be highly variable from well to well and that high values of permeability are possible. These data provide important insights into realistic wellbore integrity of typical wells in N. America, and help us constrain models for understanding and mitigating risk of leakage during CO2 storage operations.

Abstract Geologic CO2 sequestration (GCS) has received high-level attention from the global scientific community as a response to climate change due to higher concentrations of CO2 in the atmosphere. However, GCS in saline aquifers poses certain risks including CO2/brine leakage through wells or non-sealing faults into groundwater or to the earth’s surface. Understanding crucial reservoir parameters and other geologic features affecting the likelihood of these leakage occurrences will aid the decision-making process regarding GCS operations. In this study, we develop a science-based methodology for quantifying risk profiles at geologic CO2 sequestration sites as part of US DOE’s National Risk Assessment Partnership (NRAP). We apply NRAP tools to a field scale project in a fractured saline aquifer located at Kevin Dome, Montana, which is part of DOE’s Big Sky Carbon Sequestration Partnership project. Risks associated with GCS injection and monitoring are difficult to quantify due to a dearth of data and uncertainties. One solution is running a large number of numerical simulations of the primary CO2 injection reservoir, shallow reservoirs/aquifers, faults, and wells to address leakage risks and uncertainties. However, a full-physics simulation is not computationally feasible because the model is too large and requires fine spatial and temporal discretization to accurately reproduce complex multiphase flow processes. We employ the NRAP Integrated Assessment Model (NRAP-IAM), a hybrid system model developed by the US-DOE for use in performance and quantitative risk assessment of CO2 sequestration. The IAM model requires reduced order models (ROMs) developed from numerical reservoir simulations of a primary CO2 injection reservoir. The ROMs are linked with discrete components of the NRAP-IAM including shallow reservoirs/aquifers and the atmosphere through potential leakage pathways. A powerful stochastic framework allows NRAP-IAM to be used to explore complex interactions among a large number of uncertain variables and to help evaluate the likely performance of potential sequestration sites. Using the NRAP-IAM, we find that the potential amount of CO2 leakage is most sensitive to values of permeability, end-point CO2 relative permeability, hysteresis of CO2 relative permeability, capillary pressure, and permeability of confining rocks. In addition to demonstrating the application of the NRAP risk assessment tools, this work shows that GCS in the Kevin Dome has a higher probability of encountering injectivity limitations during injection of CO2 into the Middle Duperow formation than previous studies have calculated. Finally, we estimate very low risk of CO2 leakage to the atmosphere unless the quality of the legacy well completions is extremely poor.

Abstract Wellbores represent the weakest link in terms of CO 2 storage permanence. As a result, special attention to the numerous existing wells that perforate storage formations is needed. The pre-injection condition of the cement can influence the rate (and type) of alteration by the injected CO 2 plume. The condition of the existing well cement depends on a variety of factors including wellbore/formation and wellbore/brine interactions as well as the composition and type of cement placed in the well (i.e. type of admixtures used, water/solids ratio, sulfate resistant mixes, etc.). In this paper, the details of recovering wellbore cement from an older well to determine pre-injection seal integrity are described. Petrographical and chemical analyses are presented for samples of cement that were retrieved from a 19-year-old well at Teapot Dome in Wyoming. Examination revealed that the retrieved cement had altered as a result of original slurry composition and with respect to the local downhole wellbore environment. Although samples were obtained from a single well, significant differences were observed in their alteration and condition. Sulfate attack resulted in abundant ettringite formation in a cement sample taken adjacent to the Wall Creek sandstone (3060 ft), while cement taken adjacent to the Tensleep formation (5478 ft) was decalcified and enriched in magnesium, owing to reaction of calcium hydroxide in the cement with the dolomitic formation.

Abstract The existing data for wells in the Weyburn-Midale Field were used in conjunction with publicly available data to create an updated well integrity risk assessment as an aid in establishing CO 2 containment risk and developing a guide to selection of monitoring technologies for risk management. The assessment built upon an existing assessment to rank 1424 wells on 13 categories used as a proxy for likelihood of CO 2 migration and four categories used as a proxy for severity of impact of migration. The results of the assessment were used to show that both the risk posed by individual wells and risk posed by categories may be significant with respect to CO 2 migration. The location of the top of cement, quality of the casing, and type of well categories were ranked high throughout the distribution of wells with respect to likelihood of migration. The assessment of casing integrity and setting of casing through the Midale Evaporite was a differentiating factor between higher-likelihood and lower-likelihood well scores. The aquifer protection category used in assessing the severity of impact ranked high across the distribution of wells. The proximity to a water source category was a differentiating factor between higher-severity and lower-severity rankings. The wells scores and ranking categories were used to assess the value of specific monitoring tools for managing containment risks. The outcome of the study showed that both high risk wells and high-risk categories can be identified and that a monitoring program should be adopted to address both through point and area monitoring.