bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exploring Pressure Interactions Between Geological CO2 Storage Projects in Alberta Using Analytical and Numerical Simulations
Authors: Mirzayev Mammad , McCoy Sean , Cooper Joanna , Lawton Don , Jiang Liangliang 
Published: March 2024

Abstract
Deep saline aquifers are considered as attractive hosts for geological CO2 storage (GCS). The Western Canada Sedimentary Basin (WCSB) comprises numerous saline aquifers. Depending on formation geochemistry, in-situ conditions, and petrophysical properties, each formation will have different storage capacity and efficiency. There are currently 25 proposed projects in the province of Alberta that, if they were all approved with pore space tenure, would inject large volumes of CO2 at relatively large rates into the WCSB. The goal of this study is to present characterizations of potential storage formations and examine the potential for interactions between proposed projects in proximity.
We use numerical and analytical simulation to assess the evolution and interaction of pressure fields from proposed projects over time in the Wabamun Area CO2 Sequestration Project (WASP) region and infer how this affects cumulative storage capacity in the target formations. We compare the result from simple, relatively easy-to-use analytical tools against numerical simulation results to determine whether existing screening tools could accurately capture potential interactions between proximal projects. The results reveal that with increasing length of injection years, the radial extent of the CO2 pressure distribution increases as well. The analytical solution cannot accurately capture formation compressibility and variation in fluid properties, which leads to deviations from the simulated values. Nonetheless, these tools could serve as a quick method to identify areas of concern, and both can provide useful information about the likely extent of the pressure plume in a GCS project.
Critical Elements Extraction from Flowback and Produced Water: From Lab to Field
Authors: Ghanizadeh A. , Clarkson C. R. , Bader A. , Tutolo B. , Younis A. , Shabani M. 
Published: March 2024

Abstract
Flowback and produced water (FPW) from multi-fractured horizontal wells (MFHWs) are possible sources of critical elements (CE) from unconventional hydrocarbon reservoirs. The objective of this study is to compare temporal variations of CE (Li, Mg) concentrations in FPW at lab- and field-scales, with examples from prominent Canadian unconventional hydrocarbon plays. A secondary objective was to evaluate whether CE could be extracted (i.e. ‘leached’) from reservoir rocks by FPW. Quantifying elemental leaching is important for reserves evaluation and identifying the relative importance of mechanisms contributing to CE enrichment in FPW (e.g., fluid mixing vs. fluid-rock interaction).
High-temperature (150 °C), high-pressure (2200 psi) fluid-rock interaction experiments were conducted on three crushed-rock Montney (siltstones/sandstones) and Duvernay (organic/clay-rich shales) samples with variable composition, fabric, and reservoir quality. Time-lapsed fluid analysis (+30 days), using spectroscopy and ion chromatography (ICP-OES/IC) enabled observations of Li and Mg concentration profiles at the lab-scale. Lab-scale Li and Mg concentration profiles were then compared to post-fracture Li and Mg concentration profiles from multiple MFHWs completed in the Montney and Duvernay formations (public data).
At the lab-scale, maximum measured Li concentrations for the Montney and Duvernay samples were 0.27 mg/L and 0.53 mg/L, respectively. Maximum lab-scale Li recoveries were significantly (about two orders of magnitude) smaller than those measured in the field (28-72 mg/L for the Montney wells, 26-54 mg/L for the Duvernay wells). This could be attributed to the 1) dominance of the fluid mixing mechanism in the field, relative to fluid-rock interaction, 2) variable rock-water mass ratios at lab and field scales, and/or limited (initial) content of Li in the analyzed samples, amongst other factors. Lab-scale Li and Mg concentration profiles exhibited similarities to and discrepancies with those observed in the field. Notably, larger Li concentrations (up to twice) were associated with lower pH, in agreement with field observations. Interestingly, lab-scale Li and Sr concentrations appear to co-vary for the Duvernay FPW, in agreement with field observations, suggesting the possibility of using Sr as a ‘proxy element’ for predicting Li anomalies in the Duvernay FPW.
Quantifying temporal evolution of CE concentrations in FPW is essential for evaluating the feasibility of CE recovery from MFHWs and the selection of optimal Li extraction technologies over the well lifetime. This study provides the first-time comparison between lab- and field-scale temporal variations of CE concentrations in FPW for the purpose of evaluating CE extraction from unconventional hydrocarbon reservoirs.
Coupled Geomechanical Model and 3D Dynamic Flow Simulation for the Potential CO2 Injection into Deep Aquifer Siluro-Devonian Carbonate Formations, Delaware Basin
Authors: Nguyen S. T. , Tu J. , Nguyen T. C. , Ampomah W. , Simmons J. , Bui D. 
Published: March 2024

Abstract
One of the main foundations for increasing trust in geological carbon dioxide (CO2) sequestration is a geomechanical application. A complex geological process for long-term CO2 storage in deep aquifer carbonate formation would irreversibly change the assumed stable state of the sedimentary basin that evolved over millions of years. The proposed project is expected to sequester 13 MMSCFD of CO2 and H2S into Devonian and Silurian formations deeper than 16,000 feet below Lea County in New Mexico's Delaware Basin, a sub-basin of the Permian. The intensive integration of geomechanical parameters and 3D flow simulation can provide insights into storage mechanisms, migration patterns and effects on caprock integrity over 30-year injection and 100 years of shut-in.
This research illustrates the comprehensive development of a 3D structural framework on interpreted surfaces and spatial variability of porosity and permeability. The dynamic flow is subsequently furnished with the boundary parameters of relative permeability, geochemical fluid components, temperature, pressure, and injection rate to simulate gas accumulation and diffusion trends. Furthermore, the findings of geomechanical rock properties and strengths are incorporated into the dynamic model to evaluate further the impact of CO2 flow on Woodford caprock stability across injection and shut-in times.
Through 3D dynamic simulation, it is estimated that gas storage could reach 7.04 million metric tons with a maximum daily injection rate over the course of 30 years. The gas plume would migrate around 834 acres in the planned sequestration zone, or a radius of 0.64 miles from the injection well. The coupled geomechanical model and CO2 flow assist in exploring the caprock failure on Mohr-Coulomb circle analysis, shear, and tensile safety factors in both spatial and time dimensions of dynamic flow simulation. Despite the thermal effects, stress changes, and geochemical interactions that occur over the injection period, the caprock retains its elastic modulus and is assessed to be far from failures.
The study involves solving equations of motion and stress-strain relationships to determine how the caprock will respond to changes in pressure and fluid flow. The exceptional durability of Woodford Shale seal rock will promote the success of the CO2 storage in aquifer Siluro-Devonian carbonate rocks underneath New Mexico and pave the solid way for further long-term CO2 injection wells across the Delaware Basin in the coming decades.
Advances in Understanding the Wettability of the Viking Formation
Authors: Mohammadi Saman , Lan Tianyi , Dehghanpour Hassan 
Published: March 2024

Abstract
This paper presents a comprehensive laboratory protocol to evaluate and characterize the in-situ rock and fluid samples from the Viking Formation in the Western Canadian Sedimentary Basin (WCSB). The experiments are performed in four stages. In stage 1, we conduct Scanning Electron Microscopy (SEM), Energy-dispersive X-ray Spectroscopy (EDS) and X-ray Diffraction (XRD) techniques on the dry end-pieces of the plugs for pore-scale visualization and compositional analysis. In stage 2, we measure the contact angle (CA) of the equilibrated oil and brine droplets on the surface of the rock samples in the presence of air, and that of the equilibrated oil droplets on oil-saturated rock samples immersed in brine and DIW (deionized water). In stage 3, we perform co-current spontaneous imbibition experiments on a set of twin plugs to compare the rate of brine and oil uptake by capillary suction. In stage 4, we conduct counter-current imbibition experiments on oil-saturated plugs to evaluate oil recovery by DIW and brine.
Co-current spontaneous imbibition results show excess brine uptake compared with oil during the early times (first 120 hours). The XRD results show the presence of 11.66 wt. % pore-filling clay minerals (10 wt.% kaolinite and 1.66 wt. % illite) in the selected rock samples. These clay minerals are dispersed in the pore structure of the selected rock samples, as observed in the SEM images taken from these samples. Therefore, it can be concluded that water adsorption by pore-filling clay minerals is the main reason for the excess brine uptake compared with oil at the early times. Although brine imbibes faster and more than oil at the early times, the final imbibed volume of oil is higher than brine, which indicates the presence of small hydrophobic pores with more affinity towards oil than brine. The CA of the equilibrated oil droplet on the surface of the oil-saturated reservoir rock immersed in brine is 114.0°, while that in DIW is 70.43°, indicating that DIW enhances the water-wetness of the reservoir rock by 43.6°. The results of the counter-current imbibition experiments on the oil-saturated plugs show that oil recovery by DIW is 33% of the initial oil volume in the plug, which is 5% more oil than that by the reservoir brine, primarily due to more significant osmotic potential.
A Study of DME-Steam Co-Injection Using a Large-Scale Physical Model
Authors: Amer H. , Sheng K. , Okuno R. , Filstein A. , French M. , Sanchez J. , Al-Gawfi A. , Nakutnyy P. 
Published: March 2024

Abstract
Dimethyl ether (DME) as a water-soluble solvent has been studied as a potential additive to steam for improving the energy efficiency of steam-assisted gravity drainage (SAGD). The main objective of this research was to study in-situ flow characteristics and energy efficiency of DME-SAGD using a large-scale physical model. Results from DME-SAGD were compared with the control experiment of SAGD with no solvent injection using the same experimental setup. The main novelty of this research lies in the experimental data that demonstrated enhanced bitumen drainage by DME-SAGD in comparison to SAGD.
The experiment was conducted in a cylindrical pressure vessel with a diameter of 0.425 m and a length of 1.22 m, which contained a sand pack with a porosity of 0.34 and a permeability of 5.0 D. The DME-SAGD experiment used a DME concentration of 10 mol% and a steam co-injection rate of 27.6 cm3/min [cold-water equivalent (CWE)] at 3000 kPa. Temperature distributions within the sand pack, along with injection and production histories, were recorded during the experiment. Subsequently, numerical simulations were performed to history-match the experimental data, and the calibrated simulation model was used to analyze details of compositional flow characteristics.
Results showed that the 10 mol% DME-SAGD experiment yielded a recovery factor of 92.7% in 4.2 days, and the SAGD experiment yielded a recovery factor of 68.6% in 6.0 days, for both of which the first 2 days were the preheating and the steam-only injection (SAGD) stages. The peak rate of bitumen production was 43.8 mL/min in the DME-SAGD experiment, which was more than twice greater than the peak rates observed in the SAGD experiment. The substantially increased rate of bitumen production resulted in a cumulative steam-to-oil ratio in DME-SAGD that was less than half of that in SAGD.
Analysis of experimental results indicated that the solubility of DME in the aqueous and oleic phases caused different flow characteristics between DME-SAGD and SAGD. For example, the oleic and aqueous phases were more uniformly distributed in the sand pack in the former. Simulations indicated that DME-SAGD had a uniform distribution of greater grid-scale Bond numbers and increased oleic-phase mobilities in comparison to SAGD.
Impact of Impurities on the Economic Assessment of Carbon Dioxide Capture, Transport, and Storage
Authors: Seo Kwangduk , Choi Yoojin , Lee Kun Sang 
Published: March 2024

Abstract
The study proposes a techno-economic evaluation of geological storage of CO2 coupled with enhanced oil recovery based on the composition and price of the CO2 stream. A compositional reservoir model was developed to analyze the effect of CO2 and impurities on oil recovery and storage efficiency. The results indicate that most impurities increase the minimum miscibility pressure between the injected gas and the reservoir fluid. The higher the impurity content of the CO2, the lower the sweep and displacement efficiencies, which decreased oil recovery, while the amount of stored CO2 compared to the injected carbon increased. According to an economic analysis that includes capture, transportation, and storage, the net present values (NPVs) from CO2 composition scenarios ranging from 77.4% to 99.9% are almost identical. However, a sensitivity analysis of the economic parameters indicated that NPV is sensitive to the price of oil, discount rates, and tax policy.
Pore-Scale Investigation of Caprock Integrity in Underground Hydrogen Storage
Authors: Wang Hai , Chen Shengnan , Deng Peng , Wang Muming , Xu Zhengxiao 
Published: March 2024

Abstract
This study investigates the sealing capacity of shale caprocks for underground storage of hydrogen (H2) utilizing mercury intrusion capillary pressure (MICP) data of caprock samples. The research explores the influence of capillary forces on gas leakage through caprocks and evaluates the effectiveness of caprocks in confining H2 and CO2. Results indicate that the interfacial tension between H2 and water/brine is significantly higher than that between CO2 and water/brine, leading to greater column heights for H2 (ranging from 59 to 667 meters) compared to CO2 (ranging from 20 to 500 meters). Additionally, the study reveals that thicker caprock layers significantly reduce the rate of gas leakage, with CO2 exhibiting higher mass leakage rates due to its larger molar mass and lower interfacial tension compared to H2. Furthermore, while the capillary bundle model estimates higher leakage rates, the pore network model, accounting for the shielding effect of small channels, predicts lower leakage rates, demonstrating its potential for more accurate estimations. The findings highlight the potential of shale caprocks as effective barriers for H2 and CO2 storage, emphasizing the importance of capillary forces and caprock thickness in mitigating gas leakage.
Investigating the Effect of Carbon Dioxide Concentration on Hydrate Formation Risk from Water Alternating Gas (WAG) Changeover Operations
Authors: Moghaddam F. Sahari , Abdi M. Abedinzadegan , James L. A. 
Published: March 2024

Abstract
Hydrate formation is a flow assurance challenge for offshore oil and gas operations with subsea pipelines, wells, and tiebacks. In Water-Alternating-Gas (WAG) operations, hydrates can form within the injection wells when switching from water-to-gas and vice versa. This study investigates hydrate formation in a WAG injection well under water-to-gas and gas-to-water changeover operations. Compositional changes, temperature, and required thermodynamic inhibitor are evaluated within the injector well where hydrate formation is likely.
The simulation study is conducted on a representative offshore field at a seabed depth of 124 m and temperature of 3ºC. The dynamic multiphase flow simulator was used for the WAG simulation and fluid modeling. The subcooling is evaluated to detect potential hydrate formation. After determining the hydrate risk zones for water-to-gas and gas-to-water operations through detecting the regions with positive values of subcooling where the fluids can be exposed to hydrate formation, the effects of gas composition (CO2 content) change, and methanol injection on the subcooling profile are evaluated.
Simulation results indicated a higher risk of hydrate formation after the start of water injection in gas-to-water during an offshore injection well changeover operation due to slower fluid displacement. In both cases, after starting the injection operation the subcooling is reduced significantly for the entire well. However, in the water-to-gas changeover, the sections of the well that had water and gas were outside the hydrate formation region after 1 hour of gas injection. For a water injection rate of 2,300 m3/day, 1 MSm3/d of gas was adequate to displace the entire water column in the well into the reservoir in the water-to-gas changeover operation. For gas-to-water changeover operation, full displacement of the gas occurred after 11 hours and 9 hours for the base natural gas case and the natural water with NG (CO2 44 wt%) case, respectively. Methanol slug injection (5 m3) at the end of the water injection inhibited hydrate formation for the entire length of the well. Fluid model simulations indicate that changing the CO2 composition (5-44 wt%) has a noticeable effect on the phase envelope and shifts the hydrate curve up to 2ºC.
Few previous studies have investigated WAG changeover operations with the effect of CO2 and methanol concentrations on hydrate formation. One study found hydrate formation risk in water-to-gas operations based on onshore well with no attention to the impact of thermodynamic inhibitors and gas composition. This study investigates the hydrate formation risk, the impact of natural gas (NG) composition (CO2, 5-44 wt%), and the applicability of methanol in WAG changeover operations in an offshore well.
Introducing a New Hybrid Data-Physics Architecture for Production Forecasting in Unconventional Wells
Authors: Matoorian R. , Malaieri M. , Shor R. , Aguilera R. 
Published: March 2024

Abstract
This research presents a new architecture and implementation to overcome inherent challenges in leveraging machine learning (ML) for evaluating production performance in unconventional wells. By implementing a hybrid data-physics architecture (HDP), our goal is to effectively address several persistent hurdles, including generalizability limitations across diverse samples, the necessity for extensive training datasets, and the discrepancies between model predictions and fundamental physical principles. These fundamental constraints form the focal points of our comprehensive investigation.
This new HDP architecture seamlessly integrates a physics-based equation into the framework of a deep neural network model. The training dataset encompasses a wide array of influencing factors on production rates, encompassing information that may not readily conform to conventional physical equations. This sophisticated approach enables the inclusion of supplementary data, thereby significantly enhancing the precision of production forecasts. As a result, these data points are adeptly employed to derive the model's underlying physical parameters, leading to highly accurate production rate calculations. Once these parameters are estimated with minimal error, the trained model exhibits exceptional proficiency in forecasting both short-term and long-term production rates consistently.
To thoroughly evaluate the efficacy of the developed architecture, an extensive assessment was conducted using unconventional wells situated in the Duvernay resource within the western Canadian sedimentary basin (WCSB). This evaluation spanned three different methodologies to compute future production rates: with physical decline curve equations including Arps, Power Law, and Duong, with data-driven modeling where production rate forecasted with different powerful ML techniques including Random Forest, Ada-Boost, and K-Nearest Neighbors, and finally with HDP modeling. The results compared with different statistical metrics across all evaluated scenarios, the hybrid model consistently exhibited superior precision in production forecasting.
A noteworthy advantage intrinsic to the new hybrid architecture is its remarkable capacity to generate more accurate predictions without requiring extensive sample points for training. This characteristic proves especially advantageous for newly established wells with limited production histories. Moreover, the predictive outcomes yielded by the hybrid model demonstrate a strong alignment with fundamental physical models, thereby validating its applicability across both short-term and long-term production forecasting contexts.
Synergizing Hybrid Agile-Scrum and CRISP-DM Approaches in Data Science Project Management
Authors: Amirian E. , Abdollahzadeh A. , Sulaiman N. 
Published: March 2024

Abstract
Delivering a data science project encompasses several hurdles that need to be addressed. As the project matures, the business requirements may change over time. In addition, uncertainties associated with data integrity, quantity, and quality can have an impact on the success of the project. The effectiveness of advanced analytics and algorithms that is changing depending on the complexity of the project and ambiguities in project values potentially will lead to adverse effects on deliverables and task prioritization.
Agile-scrum framework enables projects with time-boxed iterations (sprints). It also introduces delivery through increments (MVPs) that assist in reaching the overall aim or vision of the product. However, backlog prioritization and sequence of tasks is not bounded by any criteria and depends fully on product owner’s understanding of product goal and value. On the other hand, CRISP-DM is a solid place to start for advising developers on the steps and tasks needed to build a data science product. It enables exploratory and discovery work through iterations to satisfy the requirements of the data science project. However, the lack of time element within the process might cause infinite iterative cycles and delay delivery to customers.
At Petronas, we have integrated a hybrid strategy that envelops the CRISP-DM process within defined time-limited sprints. The process flow from CRISP-DM can help to plan which tasks to be assigned in which sprint. Properly assigned scrum team roles will ensure proper establishment of scrum. Furthermore, conducting scrum events will enable effective and productive customers engagement. Periodic inspection of scrum artifacts will also ensure alignment with product goals.
This hybrid approach demonstrates how the change in requirements can be strategically addressed by utilizing the Agile-Scrum CRISP-DM methodology while ensuring that the product goal is achieved. It also highlights how Agile-Scrum ensures successful delivery of product, maximizing product value, and customer satisfaction, while CRISP-DM can guide us in planning for data science project sprints.