Public data from three US states provide new insights into well integrity.

Oil and gas wells with compromised integrity are a concern because they can potentially leak hydrocarbons or other fluids into groundwater and/or the atmosphere. Most states in the United States require some form of integrity testing, but few jurisdictions mandate widespread testing and open reporting on a scale informative for leakage risk assessment. In this study, we searched 33 US state oil and gas regulatory agency databases and identified records useful for evaluating well integrity in Colorado, New Mexico, and Pennsylvania. In total, we compiled 474,621 testing records from 105,031 wells across these states into a uniform dataset. We found that 14.1% of wells tested prior to 2018 in Pennsylvania exhibited sustained casing pressure (SCP) or casing vent flow (CVF)-two indicators of compromised well integrity. Data from different hydrocarbon-producing regions within Colorado and New Mexico revealed a wider range (0.3 to 26.5%) of SCP and/or CVF occurrence than previously reported, highlighting the need to better understand regional trends in well integrity. Directional wells were more likely to exhibit SCP and/or CVF than vertical wells in Colorado and Pennsylvania, and their installation corresponded with statewide increases in SCP and/or CVF occurrence in Colorado (2005 to 2009) and Pennsylvania (2007 to 2011). Testing the ground around wells for indicators of gas leakage is not a widespread practice in the states considered. However, 3.0% of Colorado wells tested and 0.1% of New Mexico wells tested exhibited a degree of SCP sufficient to potentially induce leakage outside the well.

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.

Dissolution-Driven Permeability Reduction of a Fractured Carbonate Caprock.

Geochemical reactions may alter the permeability of leakage pathways in caprocks, which serve a critical role in confining CO2 in geologic carbon sequestration. A caprock specimen from a carbonate formation in the Michigan sedimentary Basin was fractured and studied in a high-pressure core flow experiment. Inflowing brine was saturated with CO2 at 40°C and 10 MPa, resulting in an initial pH of 4.6, and had a calcite saturation index of -0.8. Fracture permeability decreased during the experiment, but subsequent analyses did not reveal calcite precipitation. Instead, experimental observations indicate that calcite dissolution along the fracture pathway led to mobilization of less soluble mineral particles that clogged the flow path. Analyses of core sections via electron microscopy, synchrotron-based X-ray diffraction imaging, and the first application of microbeam Ca K-edge X-ray absorption near edge structure, provided evidence that these occlusions were fragments from the host rock rather than secondary precipitates. X-ray computed tomography showed a significant loss of rock mass within preferential flow paths, suggesting that dissolution also removed critical asperities and caused mechanical closure of the fracture. The decrease in fracture permeability despite a net removal of material along the fracture pathway demonstrates a nonintuitive, inverse relationship between dissolution and permeability evolution in a fractured carbonate caprock.

Probabilistic design of a near-surface CO2 leak detection system.

A methodology is developed for predicting the performance of near-surface CO(2) leak detection systems at geologic sequestration sites. The methodology integrates site characterization and modeling to predict the statistical properties of natural CO(2) fluxes, the transport of CO(2) from potential subsurface leakage points, and the detection of CO(2) surface fluxes by the monitoring network. The probability of leak detection is computed as the probability that the leakage signal is sufficient to increase the total flux beyond a statistically determined threshold. The methodology is illustrated for a highly idealized site monitored with CO(2) accumulation chamber measurements taken on a uniform grid. The TOUGH2 code is used to predict the spatial profile of surface CO(2) fluxes resulting from different leakage rates and different soil permeabilities. A response surface is fit to the TOUGH2 results to allow interpolation across a continuous range of values of permeability and leakage rate. The spatial distribution of leakage probability is assumed uniform in this application. Nonlinear, nonmonotonic relationships of network performance to soil permeability and network density are evident. In general, dense networks (with ∼10-20 m between monitors) are required to ensure a moderate to high probability of leak detection.

Miscible viscous fingering in three dimensions: fractal-to-compact crossover and interfacial roughness.

Using our standard pore-level model, we have extended our earlier study of the crossover from fractal viscous fingering to compact /linear flow at a characteristic crossover time, tau , in three dimensions to systems with as many as a 10(6) pore bodies. These larger systems enable us to investigate the flows in the fully compact/well-past-crossover regime. The center of mass of the injected fluid exhibits basically the same behavior as found earlier but with an improved characteristic time. However, our earlier study of much smaller systems was unable to study the interfacial width in the important well-past-crossover regime, ttau. Now, we can study both the time evolution and roughness of the interfacial width. The interfacial width exhibits the same fractal-to-compact crossover as the center of mass, with the same characteristic time. In the fully compact regime, ttau, the interfacial width grows approximately linearly with time so that the standard growth exponent is approximately unity, beta=1.0+/-0.1. We find that neither is the interface self-affine nor is the roughness of the interface in the compact regime consistent with an effective long-range surface tension as assumed by various theories. In fact, similar to Lévy flights, the height variations across the interface appear to be random with occasional large height variations.

Crossover from fractal capillary fingering to compact flow: The effect of stable viscosity ratios.

Using a standard pore-level model, which includes both viscous and capillary forces, we have studied the injection of a viscous, nonwetting fluid into a two-dimensional porous medium saturated with a less viscous, wetting fluid, i.e., drainage with favorable viscosity ratios, M> or =1 . We have observed a crossover from fractal capillary fingering to standard compact flow at a characteristic time, which decreases with increased capillary number and/or viscosity ratio. We have tested an earlier prediction for the dependence of this crossover upon viscosity ratio and capillary number using our data for a wide-but-physical range of capillary numbers and viscosity ratios. We find good agreement between the predicted behavior and our results from pore-level modeling. Furthermore, we show that this agreement is not affected by changes in the random distribution of pore throat radii or by changes in the coordination number, suggesting that the prediction is universal, i.e., valid for any porous medium structure, as expected from the general nature of the derivation of the prediction. Furthermore, this agreement indicates that the prediction correctly accounts for dependence of the flow upon capillary number and viscosity ratios, thereby enabling predictions for interfacial advance and width as well as saturation and fractional flow profiles. Also this agreement supports the validity of the general theoretical development lending credence to the three-dimensional predictions.

Two-phase flow in porous media: Crossover from capillary fingering to compact invasion for drainage.

It had been predicted that the capillary fingering observed at small capillary numbers should change or cross over to compact invasion at larger capillary numbers or longer times [D. Wilkinson, Phys. Rev. A 34, 1380 (1986)]. We present results from pore-level modeling in two dimensions for the average position (related to the position of the interface) of the injected fluid as well as the width of the interface between the injected, nonwetting fluid and the defending, wetting fluid. These results are entirely consistent with the predicted crossover from the fractal flow characterized by invasion percolation with trapping (IPWT) to compact/linear/stable flow, where the position of the injected fluid advances linearly with time and where the width of the interface is constant. Furthermore, our results for the characteristic time, at which the crossover occurs, agree with the predictions of Wilkinson. To focus on the effect of capillary number, we are considering only viscosity-matched flows where both fluids have the same viscosities. To our knowledge, these are the first pore-level modeling results that quantitatively test the general predictions of Wilkinson for this capillary crossover in the case of drainage. Our modeling results are used to provide closed form expressions predicting the dependence of average position and interfacial width upon capillary number and time, regardless of the size of the system. The size scaling inherent in the crossover combined with our results locating the upper and lower bounds of the crossover regime enable us to predict the location of the crossover for two-dimensional systems of different size. These predictions are compared with flow patterns from experiments in the literature. The agreement between our predictions and the experimental flow patterns indicates that the experiments exhibit the same IPWT to compact crossover observed in our modeling.

Crossover from capillary fingering to viscous fingering for immiscible unstable flow:Experiment and modeling.

Invasion percolation with trapping (IPT) and diffusion-limited aggregation (DLA) are simple fractal models, which are known to describe two-phase flow in porous media at well defined, but unphysical limits of the fluid properties and flow conditions. A decade ago, Fernandez, Rangel, and Rivero predicted a crossover from IPT (capillary fingering) to DLA (viscous fingering) for the injection of a zero-viscosity fluid as the injection velocity was increased from zero. [Phys. Rev. Lett. 67, 2958 (1991)]]. We have performed experiments in which air is injected into a glass micromodel to displace water. These experiments clearly demonstrate this crossover as the injection velocity of the air is increased. Furthermore, simulations, using our standard pore-level model, also support the predicted IPT-to-DLA crossover, as well as the predicted power-law behavior of the characteristic crossover length.

Pore-level modeling of drainage: crossover from invasion percolation fingering to compact flow.

A pore-level model of drainage, which has been quantitatively validated, is used to study the effect of increased injection rate (i.e., increased capillary number) upon the flow, with matched-viscosity fluids. For small enough capillary number, the flows from the model correctly reproduce the flows from the invasion percolation with trapping (IPWT) model. As the capillary number is increased, the early-time flows mimic those of the IPWT-model, but then deviate towards compact flow at a characteristic time that decreases as the capillary number increases. That is, the larger the capillary number, the sooner the flow crosses over from IPWT flows towards compact (linear) flows.