Wellbore integrity is a significant problem in the U.S. and worldwide, which has serious adverse environmental and energy security consequences. Wells are constructed with a cement barrier designed to last about 50 years. Indirect measurements and models are commonly used to identify wellbore damage and leakage, often producing subjective and even erroneous results. The research presented herein focuses on new technologies to improve monitoring and detection of wellbore failures (leaks) by developing a multi-step machine learning approach to localize two types of thermal defects within a wellbore model, a prototype mechatronic system for automatically drilling small diameter holes of arbitrary depth to monitor the integrity of oil and gas wells in situ, and benchtop testing and analyses to support the development of an autonomous real-time diagnostic tool to enable sensor emplacement for monitoring wellbore integrity. Each technology was supported by experimental results. This research has provided tools to aid in the detection of wellbore leaks and significantly enhanced our understanding of the interaction between small-hole drilling and wellbore materials.
The main goal of this project was to create a state-of-the-art predictive capability that screens and identifies wellbores that are at the highest risk of catastrophic failure. This capability is critical to a host of subsurface applications, including gas storage, hydrocarbon extraction and storage, geothermal energy development, and waste disposal, which depend on seal integrity to meet U.S. energy demands in a safe and secure manner. In addition to the screening tool, this project also developed several other supporting capabilities to help understand fundamental processes involved in wellbore failure. This included novel experimental methods to characterize permeability and porosity evolution during compressive failure of cement, as well as methods and capabilities for understanding two-phase flow in damaged wellbore systems, and novel fracture-resistant cements made from recycled fibers.
Leakage along wellbores is of concern for a variety of applications, including sub-surface fluid storage facilities, geothermal wells, and CO2 storage wells. We have investigated whether corroded casing is permeable to gas and can serve as a leakage pathway along wellbores. Three specimens were prepared from laboratory steel plates corroded using different mechanisms to reflect different possible field conditions and produce a variety of corrosion rates. Single-phase gas flow measurements were made under a range of gas pressures to investigate flow in both the viscous and visco-inertial flow regimes. Tests were conducted at different confining stresses (range from 3.45 to 13.79 MPa) following both loading and unloading paths. The gas flow test results suggest corroded casing can serve as a significant leakage path along the axis of a wellbore. Transmissivity was found to be sensitive to the variation in confining stress suggesting that the corrosion product is deformable. Gas slip factors and the coefficients of inertial resistance of the corrosion product were comparable to those available in the literature for other porous media. Post-test examination of the corrosion product revealed it to be a heterogeneous, mesoporous material with mostly non-uniform slit type porosity. There was no discernable difference in the composition of corrosion product from specimens corroded by different mechanisms.
In wellbores, cement plays an important role in wellbore integrity. As wells age and are stressed during their life cycle, the cement sheath may deform, altering its permeability and, perhaps compromising its integrity. In this study, we use flow measurements (calculated permeability) to provide real-time insight into damage incurred during triaxial deformation of neat cement. Cracks may be induced during deformation and their linkage may be sensed in the flow measurements. Conversely, cracks and pores may be closed during deformation, arresting fluid flow. We subjected room temperature specimens of neat Portland cement to confining pressures (0.7, 2.1, 13.8 MPa) and measured heliu m flow continuously during triaxial deformation. Axial displacement across a specimen was periodically halted to perhaps assure steady flow rate throughout the sample. We observed the apparent permeability to decrease from 0.8 to 0.7 to 0.2 μD with the imposed confining pressure increase. Each specimen, when subjected to differential stress, exhibited a slight decrease in apparent permeability, implying disconnects of flow paths. For the two lower confining pressures, apparent permeability began to increase just prior to macroscopic failure, suggesting microcrack linkage. For the 2.1 MPa confining pressure test, apparent permeability increased by a factor of three at macrofracture, and for the 0.7 MPa confining pressure test, apparent permeability increased by a factor of thirty at macrofracture. At 13.8 MPa confining pressure, apparent permeability only decreases during triaxial loading, implying that poroelastic compaction restricts flow pathways and connectivity of appropriately oriented cracks for axial flow decreases during deformation. Failure by macrofracture did not occur in this sample. Optical and scanning electron microscopy of deformed specimens indicate that pores and microcracks interact in complex manners, similar microcrack densities are observed in both 0.7 and 13.8 MPa test specimens, and pores represent both microcrack origination and localization sites. Larger pores (entrapped air voids) are sheared, flattened, and sites of crack opening. Micron-scale capillary porosity, determined using SEM image processing, is similar for all specimens. The results from these few experiments indicate that microfracturing of cement during triaxial deformation results in permeabilit y increases at low confining pressures. At the greater pressure, although microfracturing is observed, compaction and lack of microfracture interconnectivity have a greater effect on flow pathways, resulting in a permeability decrease during deformation.
Sandia National Laboratories has begun developing modeling and analysis tools of flow through the cemented port ion of a cemented annulus in a Strategic Petroleum Reserve (SPR) well since August of 201 5 . The goal of this work is to develop model s and testing procedures to diagnose the health of cemented annuli at SPR sites. In Fiscal Year 2016 (FY16), we have developed several tests and associated models that we believe are sufficient for this purpose. This report outlines progress made in FY16 and future work.
This report summarizes the work performed in the prioritization of cavern access wells for remediation and monitoring at the Bayou Choctaw Strategic Petroleum Reserve site. The grading included consideration of all 15 wells at the Bayou Choctaw site, with each active well receiving a separate grade for remediation and monitoring. Numerous factors affecting well integrity were incorporated into the grading including casing survey results, cavern pressure history, results from geomechanical simulations, and site geologic factors. The factors and grading framework used here are the same as those used in developing similar well remediation and monitoring priorities at the Big Hill, Bryan Mound, and West Hackberry Strategic Petroleum Reserve Sites.
A Hydrostatic Column Model (HCM) was developed to help differentiate between normal "tight" well behavior and small-leak behavior under nitrogen for testing the pressure integrity of crude oil storage wells at the U.S. Strategic Petroleum Reserve. This effort was motivated by steady, yet distinct, pressure behavior of a series of Big Hill caverns that have been placed under nitrogen for extended period of time. This report describes the HCM model, its functional requirements, the model structure and the verification and validation process. Different modes of operation are also described, which illustrate how the software can be used to model extended nitrogen monitoring and Mechanical Integrity Tests by predicting wellhead pressures along with nitrogen interface movements. Model verification has shown that the program runs correctly and it is implemented as intended. The cavern BH101 long term nitrogen test was used to validate the model which showed very good agreement with measured data. This supports the claim that the model is, in fact, capturing the relevant physical phenomena and can be used to make accurate predictions of both wellhead pressure and interface movements.
The abandonment of salt caverns used for brining or product storage poses a significant environmental and economic risk. Risk mitigation can in part be address ed by the process of backfilling which can improve the cavern geomechanical stability and reduce the risk o f fluid loss to the environment. This study evaluate s a currently available computational tool , Barracuda, to simulate such process es as slurry flow at high Reynolds number with high particle loading . Using Barracuda software, a parametric sequence of simu lations evaluated slurry flow at Re ynolds number up to 15000 and loading up to 25%. Li mitations come into the long time required to run these simulation s due in particular to the mesh size requirement at the jet nozzle. This study has found that slurry - jet width and centerline velocities are functions of Re ynold s number and volume fractio n The solid phase was found to spread less than the water - phase with a spreading rate smaller than 1 , dependent on the volume fraction. Particle size distribution does seem to have a large influence on the jet flow development. This study constitutes a first step to understand the behavior of highly loaded slurries and their ultimate application to cavern backfilling.
This report summarizes the work performed in the prioritization of cavern access wells for remediation and monitoring at the Bryan Mound Strategic Petroleum Reserve site. The grading included consideration of all 47 wells at the Bryan Mound site, with each well receiving a separate grade for remediation and monitoring. Numerous factors affecting well integrity were incorporated into the grading including casing survey results, cavern pressure history, results from geomechanical simulations, and site geologic factors. The factors and grading framework used here are the same as those used in developing similar well remediation and monitoring priorities at the Big Hill Strategic Petroleum Reserve Site.
This report summarizes the work performed in the prioritization of cavern access wells for remediation and monitoring at the West Hackberry Strategic Petroleum Reserve site. The grading included consideration of all 31 wells at the West Hackberry site, with each well receiving a separate grade for remediation and monitoring. Numerous factors affecting well integrity were incorporated into the grading including casing survey results, cavern pressure history, results from geomechanical simulations, and site geologic factors. The factors and grading framework used here are the same as those used in developing similar well remediation and monitoring priorities at the Big Hill and Bryan Mound Strategic Petroleum Reserve Sites.
U.S. Strategic Petroleum Reserve (SPR) oil storage cavern West Hackberry 117 was tested under extended nitrogen monitoring following a successful mechanical integrity test in order to validate a newly developed hydrostatic column model to be used to differentiate between normal "tight" well behavior and small-leak behavior under nitrogen. High resolution wireline pressure and temperature data were collected during the test period and used in conjunction with the hydrostatic column model to predict the nitrogen/oil interface and the pressure along the entire fluid column from the bradenhead flange nominally at ground surface to bottom of brine pool. Results here and for other SPR caverns have shown that wells under long term nitrogen monitoring do not necessarily pressurize with a relative rate (P N2 /P brine) of 1. The theoretical relative pressure rate depends on the well configuration, pressure and the location of the nitrogen-oil interface and varies from well to well. For the case of WH117 the predicted rates were 0.73 for well A and 0.92 for well B. The measured relative pressurization rate for well B was consistent with the model prediction, while well A rate was found to be between 0.58-0.68. A number of possible reasons for the discrepancy between the model and measured rates of well A are possible. These include modeling inaccuracy, measurement inaccuracy or the possibility of the presence of a very small leak (below the latest calculated minimum detectable leak rate).
This report summarizes the work performed in developing a framework for the prioritization of cavern access wells for remediation and monitoring at the Big Hill Strategic Petroleum Reserve site. This framework was then applied to all 28 wells at the Big Hill site with each well receiving a grade for remediation and monitoring. Numerous factors affecting well integrity were incorporated into the grading framework including casing survey results, cavern pressure history, results from geomechanical simulations, and site geologic factors. The framework was developed in a way as to be applicable to all four of the Strategic Petroleum Reserve sites.