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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Abstract In-situ combustion (ISC) is a technology used for enhanced oil recovery for heavy oil reservoirs. In two ISC field pilots conducted in 1970s to 1980s in Canada, 10-20% mole fraction of hydrogen (H2) was produced accidentally. This presents a potential opportunity for petroleum industry to contribute to the energy transition by producing hydrogen directly from petroleum reservoirs. However, most ISC experiments have reported no or negligible hydrogen production, and the reason remains unclear. To address this issue, this study focuses on hydrogen generation from bitumen through in-situ combustion gasification (ISCG) at a laboratory scale. CMG was used to simulate the ISCG process in a combustion tube. Kinetics from previous ISC experiments and reactions for hydrogen generation were incorporated in the models. Heavy oil, oxygen, and water were simultaneously injected into the tube at a certain temperature. The ranges of key parameters were varied and analyzed for their impact on hydrogen generation. The study found that maintaining a temperature above 400 °C is essential for hydrogen generation, with higher temperatures yielding higher hydrogen mole fractions. A maximum of 28% hydrogen mole fraction was obtained at a water-oxygen ratio of 0.0018:0.9882 (volume ratio at ambient conditions) and a temperature about 735 °C. Higher oxygen content was found to be favorable for hydrogen generation by achieving a higher temperature, while increasing nitrogen from 0 to 78% led to a decrease in hydrogen mole fraction from 28% to 0.07%. Hydrogen generation is dominated by coke gasification and water-gas shift reactions at low and high temperatures, respectively. This research provides valuable insights into the key parameters affecting hydrogen generation from bitumen at a lab scale. The potential for petroleum industry to contribute to energy transition through large-scale, low-cost hydrogen production from reservoirs is significant.
Shi, Yu (College of Petroleum Engineering, Xi ‘an Shiyou University) | Lv, Wang (College of Petroleum Engineering, Xi ‘an Shiyou University) | Zhang, Yin (College of Engineering and Mines, University of Alaska Fairbanks) | Zhu, Guangya (Research Institute of Petroleum Exploration and Development, PetroChina)
Abstract In situ formation of foamy oil has been widely utilized to improve the heavy oil recovery, especially considering its cost efficiency. Therefore, the stability and strength of generated foam actually play a crucial role on the foamy oil recovery. In this work, the effects of nanoparticles (NPs), the additives in a CO2-heavy oil system, on the so-called NPs-stabilized foam of CO2-heavy oil systems are experimentally and mathematically assessed. Specifically, a visual high temperature high pressure (HTHP) foam generator is utilized to investigate the foam stability of NPs- CO2-heavy oil system. The effects of different NPs concentrations and NPs types on the foam stability is systematically observed and analyzed with measuring the relationship between the height of foam column and time under nonequilibrium conditions. Then, a mathematical model is proposed to quantify processes of NPs-stabilized foam generation and collapse according to the experimental results. The results show that NPs of SiO2 with a size of 20-30 nm can effectively improve the foam stability and generation of CO2-heavy oil system compared with pure CO2-heavy oil foam. The concentration of NPs impose impact on the foam properties to some degree. Also, different types of NPs, SiO2, Al2O3 and MgO, on the foam stability are experimentally probed mainly to unveil the difference between metallic NPs and non-metallic NPs. Finally, the exponential functions with parameters characterizing concentration and nonequilibrium conditions are developed to quantify the foam generation and stability under nonequilibrium conditions.
Abstract In situ bitumen extraction from oil sands using thermal recovery processes has faced challenges due to reliance on steam. Additionally, the produced bitumen is highly viscous and needs to be diluted with lighter hydrocarbon products, such as field condensates, for pipeline transportation. Therefore, exploring less energy-intensive options to produce and transport bitumen economically with less environmental impact is essential. This work aimed to study the liquid-liquid equilibrium (LLE) of CO2 and bitumen at ambient temperature. First, the impact of CO2 feed mass fraction and pressure on equilibrium mixture properties are investigated. In the next step, the effect of ethyl acetate (EA) as an additive on the equilibrium properties of the mixture is studied. The equilibrium properties of the mixtures, including CO2 solubility in the heavy liquid phase, the viscosity of the heavy liquid phase, and the densities of light and heavy liquid phases, are reported. The results suggest that the viscosity of bitumen is considerably reduced by mixing it with liquid CO2 at ambient temperature. It was also shown that the bitumen viscosity could be further reduced by the addition of ethyl acetate as a co-solvent.
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.
Abstract Steam-assisted gravity drainage (SAGD) has proved to be a technically and commercially successful methodology for recovering heavy-oil in Canada. At present, there are 22 commercial SAGD projects with over 300 pads and 2,700 well pairs, contributing to nearly 1.4 million bbl/day of production. The steam growth in the steam chamber could recover up to 60% of the oil-in-place by a typical SAGD project. However, some SAGD projects are only able to present less than 20% of the recovery factor, even though they have been producing for almost decades. Currently, the steam-to-oil ratio (SOR) for most SAGD projects ranges between 2 and 4 bbl steam/bbl oil. Nevertheless, some projects are still experiencing SOR of over 4 bbl/bbl due to the aggressive steam injection. Despite the efficacious evidence and enormous contribution to oil production, many questions regarding the current SAGD project performance are still rising. The process and execution are very complex and entail great operational excellence. The thermodynamic processes (heat transfer, wettability alteration), reservoir geology (thickness, vertical conformance, steam channelling), well designs (optimal placement of the pairs, well completions), and environmental concerns (GHG emission) are also limiting factors to be detrimental to SAGD performance. Some other techniques to recuperate heavy-oil and bitumen (e.g., co-injection)—in addition to the principal SAGD—have been insinuated and employed in the projects. The efforts only presented a 5–10% of success rate. This paper focuses on extensive evaluation and analysis of the ongoing SAGD projects over the last three decades in Canada and what would be the forthcoming potential of mature SAGD. Lessons learned and limitations from historical and current SAGD applications based on the evaluation of 22 commercial SAGD projects are presented. Success and failure stories were evaluated from geological, technical, environmental, and operational points of view. The reasons behind the successful applications of existing SAGD practices were listed. In the end, suggestions were made as to the proper design of new SAGD projects and future practices in the matured fields. Some new insights for the future of mature SAGD, including "zero emission" applications using solvents and reduced emission using steam additives, are also discussed. The conclusive analyses done and the recommendations made will lead to more efficient SAGD applications (new and matured) in Canada, also providing a useful road map for the other parts of the world.
Summary Well placement optimization is one of the most crucial tasks in the petroleum industry. It often involves high risk in the presence of geological uncertainty due to a limited understanding of the subsurface reservoir. Well placement optimization is different from decision selection as countless alternatives are impossible to be enumerated in a decision model (such as the mean-variance model). In many practical applications, the decision criterion of well placement optimization is based on maximizing the risk-adjusted value (mean-variance optimization) to capture different risk attitudes. This approach regards variance as the measure of risk, and it is performed under the expected utility framework. However, investors only dislike the downside volatility below a certain benchmark. The downside-risk approach has been discussed in previous studies, in this paper, it will be introduced in the well placement optimization and discussed under the expected utility framework. It is demonstrated in a synthetic reservoir model with the consideration of spatial heterogeneity, and the comparison between the downside-risk optimization and mean-variance optimization is also presented in this example. The observation implies that well placement optimization is heavily influenced by individuals’ preference to risk. The downside-risk optimization outperforms the mean-variance optimization because it explicitly assesses risk and does not penalize high outcomes.
Fassihi, M. Reza (Beyond Carbon, LLC (Corresponding author)) | Alamatsaz, A. (ISCRG, University of Calgary) | Moore, R. G. (ISCRG, University of Calgary) | (Raj) Mehta, S. A. (ISCRG, University of Calgary) | Ursenbach, M. G. (ISCRG, University of Calgary) | Mallory, D. (ISCRG, University of Calgary) | Pereira Almao, P. (Catalysis and Adsorption for Fuels and Energy, University of Calgary) | Gupta, S. C. (Heretech Energy Inc) | Chhina, H. S. (Cenovus Energy)
Summary To understand the role of connate water as a source of hydrogen in oxidation and upgrading of bituminous oil at high temperature, heavy water (D2O) and O-18 enriched water (H2O) were used as connate water in two different in-situ combustion experiments using a conical tube. Aside from fundamental understanding of the role of such reactions in in-situ combustion, the results could also potentially help in optimizing in-situ hydrogen generation and upgrading of heavy and bituminous oil. The conical tube had previously been used for understanding the impact of air flux (AF) in sustaining the combustion front (Alamatsaz et al. 2011). Significant upgrading was observed in these tests with a produced API gravity of 35 ° compared to the original bitumen gravity of 9 °API. This paper (Part A) deals with the experimental results including a comparison between conical tube and a combustion tube (CT) results. A subsequent paper (Part B) will discuss the upgrading aspects and the mass spectrometry results.
Mukhametdinova, A. (Skolkovo Institute of Science and Technology (Corresponding author)) | Karamov, T. (Skolkovo Institute of Science and Technology) | Popov, E. (Skolkovo Institute of Science and Technology) | Burukhin, A. (Skolkovo Institute of Science and Technology) | Kozlova, E. (Skolkovo Institute of Science and Technology) | Usachev, G. (Lukoil Engineering LLC) | Cheremisin, A. (Skolkovo Institute of Science and Technology)
Summary This study summarizes the work conducted as a part of laboratory modeling of in-situ combustion (ISC) experiments on cores from carbonate heavy oil fields. Porosity, permeability, fluid saturation, thermal, and geochemical properties are crucial characteristics of the target field defining the performance of the combustion technology. Here, we report the changes in reservoir properties, porous structure, and mineral composition of the rock samples induced by the thermal exposure and registered by a set of standard and advanced experimental techniques. Most combustion tests are conducted on the crushed core pack, which does not accurately represent the reservoir properties. In this paper, we present the results of three combustion tube tests (classic ISC and consecutive hot-water treatment ISC) involving actual field core samples. Gas porosimetry, nuclear magnetic resonance (NMR), and microcomputed tomography (μCT) revealed an increase in total porosity and pore size distribution and enabled visualizing the changes in the porous core structure at nano- and microlevels. X-ray diffraction (XRD) and scanning electron microscopy (SEM) demonstrated the change in mineral composition and lithological texture as a result of dolomite decomposition; Rock-Eval pyrolysis and elemental analysis were utilized to confirm the changes in the rock matrix. Optical scanning registered the changes in thermal conductivity (TC) of samples, which is important for numerical modeling of the combustion process. The proposed core analysis has proved its efficiency in providing a complete petrophysical description of the core of a heavy oil carbonate reservoir in the framework of evaluation of the ISC application for dolomite-rich carbonates and demonstrated the different responses of rock to the ISC technology.
Hui, Gang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Gu, Fei (Department of Chemical and Petroleum Engineering, University of Calgary (Corresponding author))
Summary In recent decades, a remarkable increase in induced seismicity in the Western Canada Sedimentary Basin (WCSB) has been largely attributed to hydraulic fracturing (HF) operations in unconventional plays. However, a mitigation strategy concerning geological, geomechanical, and operational susceptibilities to HF-induced seismicity has not been well understood. This work proposes an integrated method to mitigate potential risks from HF-induced seismicity in the Duvernay play near Crooked Lake. The geological susceptibility to induced seismicity is evaluated first from site-specific formation pressure and a distance to the Precambrian basement. The regional in-situ stress and rock mechanical properties are then assessed to determine the geomechanical susceptibility to induced seismicity. Next, the operational factors are determined by comparing induced seismicity with operational parameters such as total injection fluids and proppant mass. It is found that regions with a low formation pressure (<60 MPa), a great distance from the base Duvernay to the Precambrian basement (>260 m), a low minimum principal stress (<70 MPa), and a low brittleness index (<0.45) tend to be induced-seismicity-quiescent regions. Finally, a multiple linear regression (MLR)-based approach is proposed by considering the relative importance of different parameters. The MLR analysis indicates that brittleness index, formation pressure, and total injection volume are the top three controlling factors. Three new horizontal wells are drilled and the MLR analysis of these wells using the three most important parameters is conducted. High-resolution monitoring results indicated that 95% of the induced events had a local magnitude of less than 2.0 during and after the HF operations (3-month time window and 5-km well-event distance), among which the maximum magnitude reached ML3.05 (