The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Liang, Guangyue (Research Institute of Petroleum Exploration and Development, CNPC) | Xie, Qian (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Shangqi (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Yang (Research Institute of Petroleum Exploration and Development, CNPC) | Xia, Zhaohui (Research Institute of Petroleum Exploration and Development, CNPC) | Bao, Yu (Research Institute of Petroleum Exploration and Development, CNPC) | Zhou, Jiuning (Research Institute of Petroleum Exploration and Development, CNPC)
Abstract SAGD process has been widely applied in super-heavy oil and oil sands projects. Slow vertical steam chamber growth and non-uniform conformance tends to generate lower oil rate and higher steam to oil ratio in SAGD projects, which were mainly influenced by thin pay, shale interlayers and bottom transition zone. Therefore, this paper presents screening and evaluation results of many emerging technologies to develop super-heavy oil or oil sands projects. 15 kinds of new technologies were investigated by AER reports and numerous papers. 6 of them were evaluated by numerical simulation, including multilateral injector or producer, vertical slimholes assisted SAGD process, steam drive assisted gravity drainage, offset SAGD well pair, and bottom-up gravity-assisted pressure drive, etc. Besides, the experience of field practices related to many little-known emerging technologies was extensively and deeply analyzed including single vertical well SAGD process, fishbone wedge producer, liner or tubing deployed ICD/FCD, various dilation practices in preheating or SAGD phase, movable steam splitter, re-drill injector or producer with optimized location, steam drive assisted gravity drainage, etc. Moreover, the mechanisms, detailed pilots and challenges were further summarized. For thin pay, single vertical well SAGD process aims to realize vertical multi-stage fracturing based on expansion pipe, accelerate steam chamber growth from top to the bottom, maximize the effect of gravity drainage to achieve earlier peak oil rate. For the reservoir impacted by shale laminae, steam drive assisted gravity drainage under different well spacing can be trialed. Steam circulation or stimulation, hydraulic fracturing and multilateral producer may be applied from 5m, 10m to 20-30m horizontal spacing while keep vertical spacing at 3-5m. Besides, enhancing vertical permeability, drilling vertical channels or enforcing horizontal driving force are possible solutions to overcome shale interlayers and bottom water. Dilation process assisted by waste water, polymer, chemical or low cost catalyzer in more than one hundred well pairs can reduce steam consumption in start-up process and achieve better early SAGD performance. Bottom-up gravity-assisted pressure drive process overwhelms SAGD process in terms of accelerated oil production and lower SOR in relatively low quality oil sands projects such as thin pay, shale interlayers, bottom transition zone, etc. Especially, the practices of wedge wells, multilateral injector or producer, steam drive assisted gravity drainage based on multilateral producer, and re-drill injector or producer successfully tapped the remaining oil, enhanced the peak oil rate or reduced SOR significantly. This paper presents much novel information about research advancement and field practices of many new technologies. These technologies can be effectively applied to relatively low quality heavy oil projects such as thin pay, shale interlayers, bottom transition zone, etc.
Abstract Oil and gas wells leakage is a major concern due to the associated risks. Potential issues include habitat fragmentation, soil erosion, groundwater contamination, and greenhouse gas emissions released into the atmosphere. An estimated 2 million abandoned oil and gas wells are believed to be leakage. Proper Plug and Abandonment (P&A) operations are required to ensure these wells are correctly disposed of from their useful operational life. This study aims to build an uncertainty evaluation tool to statistically classify the risk of a well from leaking based on their well information (age, location, depth, completion interval, casings, and cement). Data consists of leakage reports and available well data reports from Alberta Energy Regulator (AER) in Canada. Multiple preprocessing techniques, including balancing the data, encoding, and standardization, were implemented before training. Multiple models that included Naïve Bayes (NB), Support Vector Machine (SVM), Decision Trees (DT), Random Forest (RF), and K-Nearest Neighbors (KNN) were compared to select the best-performing for optimization. RF outperformed the other models and was tuned using hyperparameter optimization and cross-validation. The final model's average accuracy was 77.1% across all folds. Multiple evaluation metrics, including Accuracy, Confusion Matrix, Precision, Recall, and Area Under the ROC Curve (AUC), were used to assess the model and each class against the rest. Feature importance showed an even distribution across the different features used. The model presented in the study aimed to classify wells and label the leakage risk based on the well information associated with its components. This risk evaluation tool could help reduce gas emissions by 28.2% based on the results obtained. This tool can classify the wells to speed the selection process and prioritize wells with higher leakage risk to perform P&A operations and minimize emissions.
Benko, Tim (Enhance Energy) | MacGregor, Alex (Qube Technologies) | Wen, Eric (Qube Technologies (Corresponding author)) | Fox, Thomas (Highwood Emissions Management) | Moorhouse, Brendan (Highwood Emissions Management)
Summary Diverse methods have emerged for methane leak detection and repair (LDAR), alongside a growing interest in continuous monitoring (CM). Novel LDAR programs must demonstrate equivalent (or better) emissions reductions compared to conventional handheld methods to be approved by regulators and trusted by industry. We apply and test a widely accepted equivalency framework and report on a regulatory approved alternative LDAR pilot program to evaluate the performance of CM relative to conventional LDAR. The framework, which has not been formally tested to date, relies on a combination of controlled release testing, simulation modeling, and field piloting. First, controlled release testing at known emission rates is used to establish probability of detection functions and other performance metrics for the CM device. Performance metrics are then used to build a CM module in LDAR Simulator (LDAR-Sim), an open-access modeling framework. Finally, CM devices are deployed as part of a field pilot. Controlled release testing results and dispersion modeling suggest that the CM devices can reliably detect (i.e., 90% detection probability or greater) a rate of 1 kg/h (~54 scf/hr) from distances of 75–100 m with no false positive detections. A set of work practices were established using the LDAR-Sim framework. The CM program requires close-range follow-up for any detection event and is estimated by LDAR-Sim to reduce aggregate annual fugitive methane emissions by 91.8% relative to the baseline, doubling the reductions anticipated from a conventional regulatory program. For the pilot, 52 devices are deployed across 16 facilities with Enhance Energy. All devices are positioned within 100 m of monitored assets. Each time devices record a detection event, which is defined as a sustained anomaly three standard deviations above a moving average background concentration for 24 hours, 7 days, or 60 days, the operator performs a close-range follow-up inspection. Preliminary results show that the CM devices can detect leaks and that follow-up protocols are effective at immediately finding leaks and avoiding false positives. Confirmed detections include fugitive emissions such as a tank thief hatch leak and vented emissions including high-bleed pneumatics. Both types of emissions were confirmed as repaired or improved by CM. These results indicate that repairing leaks more expeditiously through faster detection can reduce emissions by up to 90%.
This one-day session will include a view of best practices for Carbon Management with a focus on fugitive methane reduction. It will include global and local examples of Carbon Regulations, give tools for de-risking regulatory compliances and field-proven methane reduction technology cases. It will be introduced within the framework of the UN's Sustainable Development Goals (SDGs) and regional Environmental and Social Metrics as proposed by governments or regulators. This is especially relevant to oil and gas production and the consequent action/strategies producers need to have in place for Regulators, Banks, Investors and Governments. In particular, the session will include two technical discussions regarding the most time-critical components of methane management compliance – fugitive emission leak detection and compressor seal vent gas measurement.
Mohammed Azizur Rahman is an associate professor in the petroleum engineering program at Texas A&M University at Qatar (TAMUQ) and an adjunct professor at Memorial University of Newfoundland, Canada. Rahman holds a PhD from the University of Alberta, Canada, received in 2010. Rahman secured around $2.5 million in research funding from organizations such as Qatar Foundation, Natural Sciences and Engineering Research Council of Canada, and Newfoundland Research & Development Corporation.He is a registered professional engineer in Alberta, Canada, and an active member of organizations such as SPE and ASME.
Khalifi, Mohammad (Imperial Oil Resources Ltd.) | Khaledi, Rahman (Lynx PetroTech Ltd, Imperial Oil retiree) | Motahhari, Hamed (Imperial Oil Resources Ltd.) | Beckman, Mark (Imperial Oil Resources Ltd.) | Wattenbarger, Robert Chick (Exxon Mobil Corporation)
Abstract Under the reservoir conditions, bitumen has minute volumes of dissolved methane that when heated through a thermal recovery process, leave the solution and can potentially accumulate in the reservoir, reducing the steam condensation temperature at the bitumen/vapor interface, thus impacting process efficiency and impeding the production rates. Accurate quantification of the rate of release of methane is crucial for understanding the underlying mechanisms and predicting the performance of the bitumen recovery process. This rate can vary between hours to weeks depending on the conditions, making their measurement significantly challenging. In this study a new testing approach and experimental setup are developed for reliable measurement of the kinetics of the rate of methane release from bitumen. A new experimental setup is designed, fabricated, and validated to measure the rate of minute volumes of methane released from bitumen. Moreover, a new analytical method is developed for modeling the complex kinetics of the release of methane from bitumen through a simple first-order reaction model with Arrhenius temperature dependency that can be incorporated into reservoir simulations without imposing a major numerical burden. Under a controlled testing environment, the methane release is initiated through imposing a sudden pressure drop to a pre-saturated bitumen/methane liquid mixture, therefore reducing the methane solubility and triggering its exsolution. To maintain the pressures at the new level, exsolved methane was then vented and measured using a precise gasometer. The results indicate that the exsolution rate is in a direct relationship with the temperature of the mixture. This could be explained by the effect of temperature on the viscosity of the liquid phase. At higher test temperatures, the methane release process was completed in several minutes, while at lower temperature conditions, the process lasted for weeks. The profiles of methane release at four different temperature conditions were then analyzed to extract the first-order reaction rate kinetic parameters that could effectively capture the behavior of exsolution over a wide range of temperature and pressure conditions. Since the kinetic parameters were obtained for the lab scale quantities of bitumen and released methane, a simulation study was conducted to scale the parameters to a simulation grid block of a size 1 meter cube. The results indicate that for the numerical simulation of highly permeable reservoirs, the kinetic parameters obtained from the laboratory experiments can be used in the simulator without further modifications or scaling.
Peng, Xiaolong (Geological Survey of Canada Calgary) | Chen, Zhuoheng (Geological Survey of Canada Calgary) | Zeng, Fanhua (University of Regina) | Yuan, Wanju (Geological Survey of Canada Calgary) | Yao, Jiangyuan (Geological Survey of Canada Calgary) | Hu, Kezhen (Geological Survey of Canada Calgary)
Abstract The current screening criteria excluded shallow formations (depth < 800 m) from the desirable CO2 geological storage sites. However, in the Athabasca oil sands area of northeast Alberta, shallow gas reservoirs have at least 500 Mt storage potential and are close to many large emitters in Alberta. This study uses Kirby gas fields as an example and examines the suitability of shallow gas reservoirs as CO2 storage sites from leaking risks associated with engineering aspects. First, the storage systems characterized by five parameters were built based on a statistical analysis of 210 gas pools in the Kirby field. Second, to capture uncertainties, 270 cases were simulated to represent the sealing-layer performances. The results were then analyzed statistically, where an information-entropy-based regression tree was generated to rank the relative importance of the parameters and leaking risk level. Third, the storage systems with multi-sealing layers were modeled to examine the effective drainage area, injectivity, and storage capacity under different drilling and injection schemes. Finally, the potential issues of carbon storage in depleted shallow gas fields were addressed. Our study suggests that the CO2 storage potential and carbon-neutral benefits of the shallow gas reservoir in the Athabasca oil sands area are underestimated for the low-carbon energy transition. The results found that the regression tree allows for screening parameters effectively for selecting storage sites from the shallow gas pools and revealed that the permeability of the sealing layers is more important than the seal thickness. For CO2 storage in shallow formations, the minimum requirements of the seal (especially for the caprock) under the safe injection pressure range are a permeability of less than 0.001 mD and a thickness higher than 35 m. Due to key characteristics of shallow gas reservoirs (high permeability and thin reservoir layers), the CO2 plume behaviors are significantly different from reported CO2 storages in desirable deep formations. The CO2 plume will spread rapidly in all directions of the reservoirs and reaches the maximum capacity quickly. A low well density of the CO2 injection network (< 0.39 wells/km) is sufficient for CO2 storage in shallow depleted gas reservoirs. Compared to the single-layer injection scheme, the multi-layer injection can relieve the early leaking risks of the mid-sealing layers and increase the injection rate to nearly 1 Mt CO2 per year. The short project life resulting from the high injection rate and small storage capacity in each gas pool makes the CCS projects of shallow reservoirs in NE Alberta more suitable for transporting CO2 using tankers or repurposing the old pipelines nearby. It also makes the small (~64.7 E4m) to medium gas reservoirs (259 E4m) with excellent top seals the desirable candidates of CO2 storage for small companies when the carbon tax reaches $170/ton in 2030. A novel workflow with an effective assessment methodology for selecting CO2 storage sites from shallow gas pools has been proposed. The results can assist geoscientists in reducing uncertainty on the estimate of CO2 capacity storage and provide practical guidance on site selection for the pre-feasibility study of CO2 storage in shallow formations.
Yang, Yun (University of Calgary) | Hamdi, Hamidreza (University of Calgary) | Clarkson, Christopher R. (University of Calgary) | Blinderman, Michael S. (Cvictus Inc.)
Abstract Injection of CO2 into subsurface coal seams is a viable technology for reducing the carbon footprint. The primary storage mechanism in coal, gas adsorption, is distinctively different from other subsurface reservoirs, providing secure and long-term storage for carbon; however, CO2 adsorption can reduce coal permeability and injectivity due to matrix swelling. In this work, a reservoir simulation study was performed to assist with the design of a field pilot for injecting CO2 into the deep Mannville coals of Alberta. The proposed field pilot consists of a vertical well for injection of CO2, and a closely spaced offset vertical well for observation (pressure measurement and fluid sampling). Extensive numerical modeling was carried out before the pilot implementation to aid with pilot design, assess injectivity, and optimize pilot operations. Because of the scarcity of reservoir information in the study area, most reservoir attributes were obtained by history-matching the Fenn Big Valley (FBV) micro-pilot (single vertical well) injection data, the closest analog field case performed in the Mannville coal. Accordingly, the reservoir simulation study was conducted in two phases: (1) testing of the numerical model setup using the FBV micro-pilot data and (2) construction of a new pilot area-specific simulation model, corresponding to the new pilot area. During the testing phase, the FBV injection well bottomhole pressure and produced gas compositions were adequately matched. During the new pilot area-specific simulation phase, a full field model (multilayer, two-well) covering a drainage area of 40000 m was constructed to represent the target coal seams and the bounding zones. Because the studied coal reservoir is considered to be geomechanically anisotropic with complex cleat systems, the anisotropic Palmer-Higgs model was integrated into the flow simulation to accurately simulate the stress-dependent permeability changes during CO2 injection. Utilizing geologic information and analog field studies, the new pilot area-specific simulation suggests that the target amount of 1500 tonnes CO2 can be securely stored in the Mannville coal seam at the planned pilot site. To optimize the injection scheme operations, and maximize injectivity, two hypothetical injection scenarios were considered: a constant-rate injection scheme at 5 tonnes per hour and a variable- rate injection scenario at a rate of up to 15 tonnes per hour. Both pre-field simulation scenarios suggest that 1500 tonnes of CO2 can be securely injected into the target coal seam (at 1500 m, with an initial permeability of 1.5 md). However, the time to inject the target amount of CO2 in the variable-rate scenario is significantly less than for the constant-rate scenario. Therefore, a variable injection rate schedule with a progressive increase of 5, 10, and 15 tonnes per hour was suggested for the actual field trial. Additionally, the effect of coal anisotropy on CO2 migration was accounted for in the well-spacing design. The simulation results demonstrate that geomechanical and permeability anisotropy do not substantially affect the CO2 distribution in the coal seam because most of the injected CO2 will be adsorbed onto the coal matrix, with a rate that is mainly controlled by diffusion (not permeability). Analysis of simulation results reveals that the simulated sweep zone at the end of 1500 tonnes CO2 injection ranges from about 42 to 50 m from the injection point. Consequently, an injection/observation well spacing of 44 m was suggested for the new pilot to ensure that the offset well (to injector) can serve as an effective subsurface monitoring well.
Abstract Injection or co-injection of solvents has been proposed as an in-situ recovery mechanism for bitumen (Gupta et al., 2002). Solvent-based recovery schemes have several potential advantages over steam-based schemes such as SAGD. These benefits include lower GHG emissions and water requirements, lower capital intensity, and lower operating costs. Additionally, solvent-based recovery schemes have been proposed to improve the quality of produced bitumen (Jossy et al., 2008). The primary mechanism for in-situ upgrading during a solvent injection process is solvent de-asphalting. Solvent de-asphalting is a proven commercial process for processing and upgrading oil in surface facilities such as refineries and upgraders. Several laboratory studies have shown that solvent de-asphalting can also occur in situ, resulting in API improvement in the produced bitumen (AITF report, 2017 and 2018, Brons and Yu, 1995). In this work the economic benefits of upgrading bitumen in-situ will be studied. It will be shown that, at a given price environment, there exists an optimum level of upgrading (as measured by °API). Generally, too little upgrading reduces the value of bitumen due to blending and transportation costs, while too much upgrading reduces bitumen yield and ultimate recovery.