• 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.

Abstract Hydraulic fracturing of shale formations in the United States has led to a domestic energy boom. Currently, water is the only fracturing fluid regularly used in commercial shale oil and gas production. Industry and researchers are interested in non-aqueous working fluids due to their potential to increase production, reduce water requirements, and to minimize environmental impacts. Using a combination of new experimental and modeling data at multiple scales, we analyze the benefits and drawbacks of using CO2 as a working fluid for shale gas production. We theorize and outline potential advantages of CO2 including enhanced fracturing and fracture propagation, reduction of flow-blocking mechanisms, increased desorption of methane adsorbed in organic-rich parts of the shale, and a reduction or elimination of the deep re-injection of flow-back water that has been linked to induced seismicity and other environmental concerns. We also examine likely disadvantages including costs and safety issues associated with handling large volumes of supercritical CO2. The advantages could have a significant impact over time leading to substantially increased gas production. In addition, if CO2 proves to be an effective fracturing fluid, then shale gas formations could become a major utilization option for carbon sequestration.

Abstract Potential CO2 and brine leakage from geologic sequestration reservoirs must be quantified on a site-specific basis to predict the long-term effectiveness of geologic storage. The primary goals of this study are to develop and validate reduced-order models (ROMs) to estimate wellbore leakage rates of CO2 and brine from storage reservoirs to the surface or into overlying aquifers, and to understand how the leakage profile evolves as a function of wellbore properties and the state of the CO2 plume. A multiphase reservoir simulator is used to perform Monte Carlo simulations of CO2 and water flow along wellbores across a wide range of relevant parameters including wellbore permeability, wellbore depth, reservoir pressure and saturation. The leakage rates are used to produce validated response surfaces that can be sampled to estimate wellbore flow. Minima in flow rates seen in the response surface are shown to result from complex nonlinear phase behavior along the wellbore. Presence of a shallow aquifer can increase CO2 leakage compared to cases that only allow CO2 flow directly to the land surface. The response surfaces are converted into computationally efficient ROMs and the utility of the ROMs is demonstrated by incorporation into a system-level risk analysis tool.

a b s t r a c t This work utilizes synchrotron-based x-ray computed microtomography (x-ray CMT) imaging to quantify the volume and topology of supercritical carbon dioxide (scCO2) on a pore-scale basis throughout the primary drainage process of a 6 mm diameter Bentheimer sandstone core. Experiments were performed with brine and scCO2 at 8.3 MPa (1200 psi) and 37.5 ◦ C. Capillary pressure-saturation curves for the scCO2- brine system are presented and compared to the ambient air-brine system, and are shown to overlay one another when pressure is normalized by interfacial tension. Results are analyzed from images with a voxel resolution of 4.65 m; image-based evidence demonstrates that scCO2 invades the pore space in a capillary fingering regime at a mobility ratio M = 0.03 and capillary number Ca = 10 −8.6 to an end-of- drainage brine saturation of 9%. We provide evidence of the applicability of previous two-dimensional micromodel studies and ambient condition experiments in predicting flow regimes occurring during scCO2 injection. © 2014 Elsevier Ltd. All rights reserved.

Abstract Wellbore systems are designed to isolate fluids in the subsurface and are typically engineered for a 30–50 year service life. In the geologic sequestration of CO 2 , wellbores will have to perform for 100s of years. As a consequence, one of the key questions in the viability of sequestration is whether long-term wellbore integrity is feasible in the high-salinity, high-CO 2 fluids likely to be present in CO 2 storage reservoirs. Isolation in wellbores is usually accomplished by a combination of Portland cement and steel. In this study, we focus on predicting the corrosion rate of steel under typical CO 2 sequestration conditions. We have developed a mechanistic model for predicting corrosion rates of mild steel used in most wellbore systems. The model includes an aqueous geochemistry and an electrochemistry module. The water chemistry module uses the Pitzer formulation for activity and Duan et al.’s (2006) model for CO 2 solubility. The electrochemical module accounts for both mass transfer processes and electrochemical kinetics. The electrochemistry includes the primary oxidation reaction (the dissolution of iron) and the primary reduction reactions (the formation of H 2 gas from carbonic acid, hydrogen ion, and/or water). At high CO 2 pressures, the dominant corrosion reaction is Fe + 2H 2 CO 3 = Fe 2+ + 2HCO 3 − + H 2 (g) and is driven by CO 2 solubility rather than solution acidity. This result shows that typical buffering reactions between dissolved CO 2 and minerals (e.g., carbonates) will not significantly reduce corrosion rates in contrast to many mineral reaction rates that are strongly dependent on pH. For similar reasons, high salinity solutions reduce corrosion rates significantly mainly due to the “salting-out” effect of reduced CO 2 solubility. For example, an increase in salinity from 5 to 20 wt% salt results in a 50% reduction in corrosion rate as confirmed in our experiments. Numerical simulations are tabulated that provide predicted rates of corrosion in wellbore environments over a wide range of temperature, partial pressure of CO 2 and salt concentration.

AbstractA vital aspect to public and regulatory acceptance of carbon sequestration is assurance that groundwater resources will be protected. Theoretical and laboratory studies can, to some extent, be used to predict the consequences of leakage. However, direct observations of CO2 flowing through shallow drinking water aquifers are invaluable for informing credible risk assessments. To this end, we have sampled shallow wells in a natural analog site in New Mexico, USA, where CO2 from natural sources is upwelling from depth. We collected major ion, trace element, and isotopic (3H, 18O, and Sr) data and, coupled with laboratory experiments and reactive transport modeling, have concluded that the major control on groundwater quality at this site is not chemical reaction of CO2 with the aquifer but intrusion of saline waters upwelling with the CO2.Using reactive transport modeling based on field data, we show the difference in reactivity of the CO2 and CO2/saline water source terms, particularly with respect to carbonate mineralogy. Sr isotopes were used to investigate whether aquifer waters were affected by carbonate mineral reaction with CO2 or by saline water intrusion. Preliminary data suggest that Sr isotopes can successfully be used to discriminate between the two types of source terms at Chimayó; this technique shows promise for monitoring CCS sites.In developing predictive capabilities for future sites, it is critical to identify the solid phases and specific reactions controlling dissolved trace metal concentrations in both the presence and absence of CO2. We have conducted laboratory experiments to identify these phases and have found that some elements (e.g., U, Ca) are largely controlled by ion exchange and/or carbonate minerals. In the experiments, the concentration of some metals increases after exposure to CO2 (although concentrations remain below the U.S. EPA primary drinking water standards); we are currently extending these experiments to determine if the reactions causing the increase are reversible and, if so, on what time scales. Metal scavenging by secondary mineral precipitation, as observed at other natural analog sites, may be important at certain temporal scales.We are using the information gained from this field and laboratory study to develop predictive models for application to risk assessment at future CCS sites. The models will be particularly useful in identifying the temporal and spatial scales of water quality changes and in developing possible mitigation strategies in the case of leaks at engineered CCS sites.

•Reduced-order model development for CO2 and brine leakage along abandoned wellbores.•Coupled leakage effects are incorporated into ROMs intended for decoupled systems models.•Octree mesh refinement and sculpting reduces nodes and minimizes mesh effects.

AbstractThe geomechanical behavior of caprock and wellbore systems determines the robustness of the CO2 storage system to disturbances from stress, pressure and temperature. In this study, we conduct triaxial coreflood and x-ray tomography experiments to directly measure permeability of water and supercritical CO2 in caprock (shale and anhydrite), cement and synthetic wellbores. The observed plastic behavior and large deformation that occurred prior to distinct sample failure demonstrates substantial stress accommodation in these systems. Fracture development resulted in total sample permeability ranging from 10-1000 mD depending on sample properties and the applied stress configuration.